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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549


FORM 40-F

(Check One)

 

o

   Registration statement pursuant to Section 12 of the Securities Exchange Act of 1934
 

  or
 

ý

   Annual report pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934

 

For fiscal year ended:
Commission File Number:

   December 31, 2013
No. 1-12384		    

SUNCOR ENERGY INC.
(Exact name of registrant as specified in its charter)

Canada
(Province or other
jurisdiction of incorporation
or organization)

   1311,1321,2911,
4613,5171,5172
(Primary standard industrial
classification code number,
if applicable)		   98-0343201
(I.R.S. employer
identification number, if
applicable)

150 - 6th Avenue S.W.
Box 2844
Calgary, Alberta, Canada T2P 3E3
(403) 296-8000

(Address and telephone number of registrant's principal executive office)

CT Corporation System
111 Eighth Avenue
New York, New York, U.S.A. 10011
(212) 894-8940

(Name, address and telephone number of agent for service in the United States)

   

Securities registered pursuant to Section 12(b) of the Act:

 

Title of each class:

   Name of each exchange on which
registered:
 

Common shares

  

New York Stock Exchange

Securities registered or to be registered pursuant to Section 12(g) of the Act:

None

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:

None

For annual reports, indicate by check mark the information filed with this form:

 

ý

   Annual Information Form   ý   Annual Audited Financial Statements

Indicate the number of outstanding shares of each of the issuer's classes of capital or common stock as of the close of the period covered by the annual report:

 

Common Shares

   As of December 31, 2013 there were
1,478,315,069 Common Shares issued and
outstanding
 

Preferred Shares

  

None

        Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the proceeding 12 months (or for such shorter period that the registrant was required to file such reports); and (2) has been subject to such filing requirements in the past 90 days.

Yes

   ý   No   o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes

   o   No   o


INCORPORATION BY REFERENCE

        The Registrant's Annual Information Form dated February 28, 2014, included in this annual report on Form 40-F, and Audited Consolidated Financial Statements and Management's Discussion and Analysis for the year ended December 31, 2013, included as Exhibit 99-1 and Exhibit 99-2, respectively, to this annual report on Form 40-F, are incorporated by reference into and as an exhibit to, as applicable, each of the Registrant's Registration Statements under the Securities Act of 1933: Form S-8 (File No. 333-87604), Form S-8 (File No. 333-112234), Form S-8 (File No. 333-118648), Form S-8 (File No. 333-124415), Form S-8 (File No. 333-149532), Form S-8 (File No. 333-161021), Form S-8 (File No. 333-161029) and Form F-9 (File No. 333-181421).


ANNUAL INFORMATION FORM

GRAPHIC

ANNUAL INFORMATION FORM DATED FEBRUARY 28, 2014

TABLE OF CONTENTS

1   Advisories
2   Glossary of Terms and Abbreviations
2   Common Industry Terms
5   Common Abbreviations
5   Conversion Table
6   Corporate Structure
6   Name and Incorporation
6   Intercorporate Relationships
8   General Development of the Business
8   Overview
10   Three-Year History
12   Narrative Description of Suncor's Businesses
12   Oil Sands
17   Exploration and Production
23   Refining and Marketing
26   Other Suncor Businesses
28   Suncor Employees
29   Significant Policies
31   Statement of Reserves Data and Other Oil and Gas Information
32   Oil and Gas Reserves Tables and Notes
39   Future Net Revenues Tables and Notes
47   Additional Information Relating to Reserves Data
55   Contingent Resources
60   Industry Conditions
66   Risk Factors
76   Dividends
77   Description of Capital Structure
79   Market for Securities
80   Directors and Executive Officers
85   Audit Committee Information
87   Legal Proceedings and Regulatory Actions
87   Interest of Management and Others in Material Transactions
87   Transfer Agent and Registrar
87   Material Contracts
87   Interests of Experts
88   Disclosure Pursuant to the Requirements of the New York Stock Exchange
88   Additional Information
89   Advisory – Forward-Looking Information
    Schedules
A-1   Schedule "A" – Audit Committee Mandate
B-1   Schedule "B" – Suncor Energy Inc. Policy and Procedures for Pre-Approval of Audit and Non-Audit Services
C-1   Schedule "C" – Form 51-101F2 Report on Reserves Data by Independent Qualified Reserves Evaluator or Auditor
D-1   Schedule "D" – Form 51-101F2 Report on Reserves Data by Independent Qualified Reserves Evaluator or Auditor
E-1   Schedule "E" – Form 51-101F3 Report of Management and Directors on Reserves Data and Other Information


ADVISORIES

In this Annual Information Form (AIF), references to "we", "our", "us", "Suncor" or "the company" mean Suncor Energy Inc., its subsidiaries, partnerships and joint arrangements, unless the context otherwise requires. References to the "Board of Directors" or the "Board" mean the Board of Directors of Suncor Energy Inc.

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. Certain amounts in prior years may have been reclassified to conform to the current year's presentation.

References to our 2013 audited Consolidated Financial Statements mean Suncor's audited Consolidated Financial Statements prepared in accordance with Canadian generally accepted accounting principles (GAAP), which is within the framework of International Financial Reporting Standards (IFRS), the notes and the auditors' report, as at and for each year in the two-year period ended December 31, 2013. References to our MD&A mean Suncor's Management's Discussion and Analysis, dated February 24, 2014.

This AIF 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 document in the Risk Factors section, many of which are beyond the company's control. Users of this information are cautioned that actual results may differ materially. Refer to the Advisory – Forward-Looking Information section of this AIF for information on other risk factors and material assumptions underlying our forward-looking information.

Information contained in or otherwise accessible through Suncor's website www.suncor.com does not form a part of this AIF and is not incorporated into the AIF by reference.

SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014    1

GLOSSARY OF TERMS AND ABBREVIATIONS

Common Industry Terms

Products

Hydrocarbons are solids, liquids or gas made up of compounds of carbon and hydrogen, in varying proportions.

Crude oil is a mixture of pentanes (lighter hydrocarbons) and heavier hydrocarbons that exists in the liquid phase in reservoirs and remains liquid at atmospheric pressure and temperature. Crude oil may contain small amounts of sulphur and other non-hydrocarbons, but does not include liquids obtained in the processing of natural gas.

Natural gas is a mixture of lighter hydrocarbons, which, at atmospheric conditions of temperature and pressure, is in a gaseous state.

Natural gas liquids (NGLs) are hydrocarbon components that can be recovered from natural gas as liquids, including, but not limited to, ethane, propane, butanes, pentanes, plus condensate and small quantities of non-hydrocarbons. Liquefied petroleum gas (LPG) includes propane and/or butane.

Oil and gas exploration and development processes

Development costs are costs incurred to obtain access to reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas from reserves.

Exploration costs are costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects that may contain oil and gas reserves.

Field is a defined geographical area consisting of one or more pools containing hydrocarbons.

Reservoir is a porous and permeable subsurface rock formation that contains a separate accumulation of petroleum that is confined by impermeable rock or water barriers and is characterized by a single pressure system.

Wells:

2   SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014

Production processes

Capacity is the annual average output that may be achieved from a processing facility, such as an upgrader, refinery or natural gas processing plant, under ideal operating conditions and in accordance with current design specifications.

Debottleneck refers to the process of increasing the production capacity of existing facilities through modification of existing equipment to remove throughput restrictions or inefficiencies.

Downstream refers to the refining of crude oil and the selling and distribution of refined products in retail and wholesale channels.

Feedstock generally refers either to i) the bitumen required in the production of SCO for the company's oil sands operations, or ii) crude oil and/or other components required in the production of refined petroleum product for the company's downstream operations.

In situ refers to methods of extracting bitumen or heavy crude oil from deep deposits of oil sands by means other than surface mining.

Overburden is the material overlying oil sands that must be removed before mining, which consists of muskeg, glacial deposits and sand. Overburden is removed before mining and on an ongoing basis to expose ore.

Production sharing contracts (PSC) are a common type of contract, outside North America, signed between a government and a resource extraction company that states how much of the resource produced each party will receive and which parties are responsible for the development and operation of the resource. The resource extraction company does not obtain title to the product; however, the company is subject to the upstream risks and rewards. An exploration and production sharing agreement (EPSA) is a form of PSC, which also states which parties are responsible for exploration activities.

Steam-assisted gravity drainage (SAGD) is an enhanced oil recovery technology for producing heavy crude oil and bitumen. It is an advanced form of steam stimulation in which a pair of horizontal wells are drilled into the oil reservoir, a few metres above the other. Low pressure steam is continuously injected into the upper wellbore to heat the oil in the reservoir and reduce its viscosity, causing the heated oil to drain into the lower wellbore, from which it is extracted.

Steam-to-oil ratio (SOR) is a metric used to quantify the efficiency of an in situ oil recovery process, which measures the cubic metres of water (converted to steam) required to produce one cubic metre of oil. A lower ratio indicates more efficient use of steam.

Tailings Reduction Operations (TROTM) is a process involving rapidly converting fluid fine tailings into a solid landscape suitable for reclamation. In this process, mature fine tailings are mixed with a polymer flocculent and deposited in thin layers over sand beaches with shallow slopes. The resulting product is a dry material that is capable of being reclaimed in place or moved to another location for final reclamation.

Utilization is the average use of capacity, and includes the impact of planned and unplanned facility outages and maintenance. More specifically, refinery utilization is the amount of crude oil and natural gas plant liquids that are run through crude distillation units, expressed as a percentage of the capacity of these units.

SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014    3

Upgrading is the two-stage process by which bitumen or heavy crude oil is converted into SCO.

Upstream refers to the exploration, development and production of conventional crude oil, bitumen or natural gas.

Reserves and resources

Please refer to the Definitions for Reserves Data Tables section of the Statement of Reserves Data and Other Oil and Gas Information in this AIF.

4   SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014

Common Abbreviations

The following is a list of abbreviations that may be used in this AIF:

Measurement
     
bbl(s)   barrel(s)
bbls/d   barrels per day
mbbls/d   thousands of barrels per day
mmbbls   millions of barrels
     
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
mmboe   millions of barrels of oil equivalent
     
mcf   thousands of cubic feet of natural gas
mcf/d   thousands of cubic feet of natural gas per day
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
bcf   billions of cubic feet of natural gas
     
GJ   gigajoules
mmbtu   millions of British thermal units
     
m3   cubic metres
m3/d   cubic metres per day
km   kilometres
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

Products, Markets and Processes
     
WTI   West Texas Intermediate
WCS   Western Canadian Select
NGL(s)   natural gas liquid(s)
LPG   liquefied petroleum gas
SCO   synthetic crude oil
NYMEX   New York Mercantile Exchange
     
TSX   Toronto Stock Exchange
NYSE   New York Stock Exchange
     
SAGD   steam-assisted gravity drainage
PSC   production sharing contract
EPSA   exploration and production sharing agreement

Suncor converts certain natural gas volumes to boe, boe/d, mboe, mmboe or mboe/d on the basis of six mcf to one boe. Any figure presented in boe, mboe, mmboe or mboe/d may be misleading, particularly if used in isolation. A conversion ratio of one bbl of crude oil or NGL 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, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

Conversion Table(1)(2)

1 m3 liquids = 6.29 barrels   1 tonne = 0.984 tons (long)
1 m3 natural gas = 35.49 cubic feet   1 tonne = 1.102 tons (short)
1 m3 overburden = 1.31 cubic yards   1 kilometre = 0.62 miles
    1 hectare = 2.5 acres
(1)
Conversion using the above factors on rounded numbers appearing in this AIF may produce small differences from reported amounts.

(2)
Some information in this AIF is set forth in metric units and some in imperial units.

SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014    5

CORPORATE STRUCTURE

Name and Incorporation

Suncor Energy Inc. (formerly Suncor Inc.) was originally formed by the amalgamation under the Canada Business Corporations Act on August 22, 1979, of Sun Oil Company Limited, incorporated in 1923, and Great Canadian Oil Sands Limited, incorporated in 1953. On January 1, 1989, we further amalgamated with a wholly owned subsidiary under the Canada Business Corporations Act. We amended our articles in 1995 to move our registered office from Toronto, Ontario, to Calgary, Alberta, and again in April 1997 to adopt our current name, "Suncor Energy Inc.". In April 1997, May 2000, May 2002, and May 2008 we amended our article to divide the issued and outstanding shares on a two-for-one basis.

Pursuant to an arrangement which was completed effective August 1, 2009, Suncor amalgamated with Petro-Canada to form a single corporation continuing under the name "Suncor Energy Inc.", referred to in this document as the "merger". The arrangement was effected pursuant to the Canada Business Corporations Act.

Our registered and head office is located at 150 – 6th Avenue S.W., Calgary, Alberta, T2P 3E3.

Intercorporate Relationships

Material subsidiaries, each of which was owned 100%, directly or indirectly, by the company as at December 31, 2013 are as follows:

Name   Jurisdiction Where Organized   Description  
Canadian operations          
Suncor Energy Oil Sands Limited Partnership   Canada   This partnership holds most of the company's oil sands assets.  
Suncor Energy Ventures Partnership   Canada   This partnership holds the company's interest in the Syncrude joint arrangement.  
Suncor Energy Products Inc.   Canada   A subsidiary of Suncor Energy Inc. that holds interests in the company's energy marketing and renewable energy businesses, and which is a partner of Suncor Energy Products Partnership.  
Suncor Energy Products Partnership   Canada   This partnership holds substantially all of the company's Canadian refining and marketing assets.  
Suncor Energy Marketing Inc.   Canada   A subsidiary of Suncor Energy Products Inc. through which production from our upstream North American businesses is marketed. Through this subsidiary, we also administer Suncor's energy trading activities, market certain third-party products, procure crude oil feedstock and natural gas for our downstream business, and procure and market NGLs and LPG for our downstream business.  
U.S. operations          
Suncor Energy (U.S.A.) Holdings Inc.   U.S.   A subsidiary of Suncor Energy Inc. that holds the majority of our U.S. interests.  
Suncor Energy (U.S.A.) Marketing Inc.   U.S.   A subsidiary of Suncor Energy (U.S.A.) Holdings Inc. 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.   U.S.   A subsidiary of Suncor Energy (U.S.A.) Holdings Inc. through which our U.S. refining and marketing operations are conducted.  

6   SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014

International operations          
3908968 Canada Inc.   Canada   A subsidiary of Suncor Energy Inc. that holds certain of our international interests.  
Suncor Energy UK Holdings Ltd.   U.K.   A subsidiary of 3908968 Canada Inc. that holds certain of our U.K. interests.  
Suncor Energy UK Limited   U.K.   A subsidiary of Suncor Energy UK Holdings Ltd. through which certain of our operations are conducted in the U.K.  
Petro-Canada Cooperative Holding U.A.   The Netherlands   A subsidiary of 3908968 Canada Inc. that holds certain of our international interests.  
Petro-Canada (International) Holdings B.V.   The Netherlands   A subsidiary of Petro-Canada Cooperative Holding U.A. that holds certain of our international interests.  
Suncor Energy Germany GmbH   Germany   A subsidiary of Petro-Canada (International) Holdings B.V. that holds the majority of our interests in Libya.  
Suncor Energy Oil (North Africa) GmbH   Germany   A subsidiary of Suncor Energy Germany GmbH through which the majority of our Libya operations are conducted.  

The company's remaining subsidiaries each accounted for (i) less than 10% of the company's consolidated assets as at December 31, 2013, and (ii) less than 10% of the company's consolidated operating revenues for the fiscal year ended December 31, 2013. In aggregate, the remaining subsidiaries accounted for less than 20% of each of (i) and (ii) described above.

SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014    7

GENERAL DEVELOPMENT OF THE BUSINESS

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.

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 (TROTM) 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 the date hereof, 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.

8   SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014

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.

SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014    9

Three-Year History

2011

•
Exploration and Production segment created. In January, Suncor announced organizational changes that included the former International and Offshore and Natural Gas business divisions merging into a single organization primarily focused on conventional production, which includes both onshore and offshore operations.

•
Ethanol plant expansion completed. In January, Suncor completed the expansion of its ethanol plant in Ontario that doubled production capacity to 400 million litres per year, making it the largest biofuels production facility in Canada.

•
Operations in Libya temporarily suspended. In response to political unrest and sanctions in Libya in the first quarter of 2011, the operator of the company's joint operations in Libya shut in production. As a result, Suncor suspended all exploration activities and declared force majeure under its EPSAs. Sanctions in Libya were eventually lifted when the country transitioned to a new government, and the operator was able to restart production from all major producing fields in the first quarter of 2012. Production has since been suspended again due to the closure of export terminal operations at eastern Libyan seaports as a result of political unrest that began earlier in 2013.

•
Successful completion of the Upgrader 2 turnaround. During the second quarter, the company completed the largest turnaround at its Upgrader 2 facilities in the company's history.

•
New wind farms commissioned. In May, Suncor commissioned the eight-turbine, 20-MW Kent Breeze wind power project in southwest Ontario. In November, Suncor commissioned the 55-turbine, 88-MW Wintering Hills wind power project in southern Alberta.

•
Development of Golden Eagle approved. In the third quarter, the field development plan for Golden Eagle in the U.K. sector of the North Sea was approved. The company anticipates first production late in 2014 or early 2015.

•
North Steepbank extension. In December, the company started mining ore from the North Steepbank area at its Oil Sands Base operations. The opening of this new area enabled Suncor to access additional oil sands ore, decrease overall haul distances and decrease mine congestion.

•
Operations in Syria suspended. In December, sanctions were introduced that resulted in Suncor declaring force majeure under its contractual obligations and suspending its operations in Syria. Consequently, the company ceased recording all production and revenue associated with its Syrian assets. During 2012, the company received proceeds from risk mitigation instruments related to its Syrian assets, which are subject to a provisional repayment should operations in Syria resume.

2012

•
Steve Williams appointed as Chief Executive Officer. In December 2011, Steve Williams, formerly Suncor's Chief Operating Officer (COO), was appointed president and a member of the company's Board of Directors, and assumed the role of Chief Executive Officer (CEO) in May 2012. Prior to becoming COO, Mr. Williams served as Executive Vice President, Oil Sands for four years where he was responsible for leading Suncor's Oil Sands Operations through a significant period of growth. Mr. Williams replaced Suncor's long-standing CEO, Rick George, who retired in May after more than 20 years leading the company.

•
TROTM operations commissioned. Suncor completed installation of its tailings management assets. Infrastructure included pipes, pumphouses and fluid transfer barges that (a) pump tailings water from extraction plants to a sand placement area, (b) pump mature fine tailings from the sand placement area to a tailings pond for TROTM treatment, and (c) pump treated water from tailings ponds back to extraction plants for use in production processes. Through the TROTM process, mature fine tailings are converted more rapidly into a solid material suitable for reclamation. As a result of this new technology and the company's capital investment to reconfigure its tailing operations, Suncor has cancelled plans for five additional tailings ponds.

•
Off-station maintenance at East Coast Canada assets. The Floating Production, Storage and Offloading (FPSO) vessels for both Terra Nova and White Rose were disconnected and transported to docking facilities for planned maintenance. The water injection swivel was replaced on the Terra Nova FPSO, while the propulsion system was repaired on the White Rose FPSO. The off-station maintenance program for Terra Nova also allowed the company to replace subsea infrastructure to help mitigate hydrogen sulphide (H2S) issues.

•
Growth at Firebag. Production from Firebag increased to 104 mbbls/d, approximately 75% higher than the 2011 production level. In 2012, Firebag Stage 3 central processing facilities commissioned in the previous year reached design capacity approximately one year after first oil was brought on-stream. Stage 4 central processing facilities were commissioned in 2012, with

10   SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014

•
MNU commences operations. The Millennium Naphtha Unit (MNU), which consists of a hydrogen plant and a naphtha hydrotreating unit, began operating at design rates. The MNU has increased sweet SCO production capacity, primarily through a naphtha hydrotreating unit, and stabilized secondary upgrading processes by providing flexibility with respect to hydrogen production during planned or unplanned maintenance.

•
Oil Sands logistics infrastructure brought into service. The company brought into service the Wood Buffalo pipeline, which connects the company's Athabasca terminal at the base plant in Fort McMurray to other third-party pipeline infrastructure in Cheecham, Alberta, and four storage tanks in Hardisty, Alberta, which are connected to the Enbridge mainline pipeline.

•
Hebron project receives sanction. In December, the co-owners of the Hebron project located offshore Newfoundland and Labrador sanctioned a development plan that includes a concrete gravity-based structure (GBS) supporting an integrated topsides deck to be used for production, drilling and accommodations. Suncor has a 22.729% interest in the Hebron project. The estimated gross oil production capacity for Hebron is 150 mbbls/d.

2013

•
Voyageur oil sands upgrader project not proceeding. In March, Suncor announced its intention not to proceed with the Voyageur upgrader project in response to changed market conditions that challenged the project economics. Suncor acquired Total E&P Canada Ltd's (Total E&P) interest in the Voyageur Upgrader Limited Partnership (VULP) for $515 million to gain full control of the partnership's assets, including a hot bitumen blending facility and tankage used to support the company's growing Oil Sands Operations.

•
Majority of conventional natural gas business in Western Canada sold. Suncor sold its conventional natural gas business in Western Canada with an effective date of January 1, 2013. The transaction closed September 26, 2013 for gross proceeds of $1 billion, before closing adjustments and other closing costs. The sale included properties situated across multiple regions in Alberta, northeast British Columbia and southern Saskatchewan but excluded the majority of Suncor's unconventional natural gas properties in the Kobes region (Montney formation) of northeast British Columbia and unconventional oil properties in the Wilson Creek area (Cardium formation) of central Alberta.

•
Suncor constructs wetland. A reclamation milestone was reached with the planting of a fen wetland at Oil Sands Base. A fen is a specific type of peat-accumulating wetland. Suncor is one of the first companies in the world to attempt reconstruction of this type of wetland. Construction of the fen's underlying watershed was completed in January 2013, and vegetation was planted during the spring and summer.

•
Firebag ramp-up completed. Firebag production in 2013 increased by approximately 40% over 2012 production levels as Stage 4 ramp-up was completed. The complex ended 2013 achieving daily production rates of approximately 95% of nameplate capacity of 180 mbbls/d.

•
Hot bitumen infrastructure commissioned. Suncor initiated a number of debottlenecking projects across Oil Sands Operations, including the completion of an insulated bitumen pipeline from Firebag to the Athabasca terminal. Combined with blending facilities at the Athabasca terminal and diluent import capabilities, Suncor increased the takeaway capacity of bitumen and unlocked production in mining.

•
Fort Hills project sanctioned. In October, Suncor and project co-owners agreed unanimously to proceed with the Fort Hills oil sands mining project. The project is scheduled to produce first oil by the fourth quarter of 2017 and is expected to achieve 90% of its planned production capacity of 180 mbbls/d (73 mbbls/d net to Suncor) within its first year.

•
Libya production shut in. Export terminal operations at Libyan seaports were closed during the latter half of 2013 due to political unrest in the country. Production was shut in during this period; however, Suncor was able to continue progress on its exploration program.

•
Rail offloading facility complete. Construction of a rail offloading facility to enable receipt of inland crudes at the Montreal refinery was completed in the fourth quarter of 2013. The Montreal refinery received its first shipment in early December with volumes expected to increase to approximately 35 mbbls/d in the first quarter of 2014.

•
Successful completion of Upgrader 1 turnaround. Suncor successfully executed planned maintenance across its operations, including a seven-week turnaround at Upgrader 1, which was the largest turnaround in the company's history. The next scheduled turnaround at Oil Sands Operations is not until 2016.

SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014    11

NARRATIVE DESCRIPTION OF SUNCOR'S BUSINESSES

Oil Sands

For a discussion of the environmental and other regulatory conditions, and competitive conditions and seasonal impacts affecting our Oil Sands segment, refer to the Industry Conditions and Risk Factors sections of this AIF.

Oil Sands Base Operations

Our integrated Oil Sands Base operations, located in the Wood Buffalo region of northeast Alberta, involve numerous activities:

•
Mining and Extraction
•
Upgrading
•
Utilities
•
Maintenance
•
Reclamation

Oil Sands Base Assets

Mining and Extraction

Suncor pioneered the commercial development of the Athabasca oil sands beginning in 1962, achieving first production in 1967. The original mining area is essentially depleted, and, for several years, bitumen was mined almost exclusively from the Millennium area, which began production in 2001. The company began mining from the North Steepbank area in 2011. During 2013, the company mined approximately 151 million tonnes of bitumen ore (2012 – 151 million tonnes). During 2013, Suncor processed an average of 270 mbbls/d of mined bitumen in its extraction facilities (2012 – 266 mbbls/d).

Upgrading

Suncor's upgrading facilities consist of two upgraders – Upgrader 1, which has a primary upgrading capacity of approximately 110 mbbls/d of SCO, and Upgrader 2, which has a primary upgrading capacity of approximately 240 mbbls/d of SCO. Suncor's secondary upgrading facilities consist of three hydrogen plants, three naphtha hydrotreaters, two gas oil hydrotreaters, one diesel hydrotreater and one kero hydrotreater.

During 2013, Suncor averaged 283 mbbls/d of upgraded (SCO and diesel) production, sourced from bitumen

12   SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014


provided by both mining and extraction and in situ operations.

Other Mining Leases

Suncor owns several other oil sands leases, including those known as Voyageur South and Audet, which it believes can be developed using mining techniques. Suncor undertakes exploratory drilling programs on such leases from time-to-time, as part of its mine replacement projects. Suncor holds a 100% working interest in both Voyageur South and Audet.

The Voyageur South project is in the early stages of planning and the development timing for the project is currently under assessment. Development options are currently being prepared for review in 2014.

In Situ Operations

Suncor's In Situ operations, Firebag and MacKay River, use SAGD technology to produce bitumen from oil sands deposits that are too deep to be mined economically.

•
The SAGD process
•
Central processing facilities
•
Power and steam generation
•
Maintenance and feedstock supply

In Situ Assets

Firebag

Production from Suncor's Firebag operations commenced in 2004. Suncor's Firebag complex consists of four central processing facilities with total bitumen processing capacity of approximately 180 mbbls/d. Actual production from Firebag varies based on steaming and ramp-up periods for new wells, planned and unplanned maintenance, reservoir conditions and other factors.

As at December 31, 2013, Firebag had nine well pads in operation with 119 SAGD well pairs and 18 infill wells either producing or on initial steam injection. Central processing facilities have been designed to be flexible as to which well pads supply bitumen. Steam generated at the various facilities can be used at multiple well pads. In addition, Firebag includes five cogeneration units that generate steam, which are capable of producing 425 MW of electricity made up of Firebag site power load of 110 MW and exports of 315 MW. There are also 13 OTSGs at the site for additional steam generation.

As of December 31, 2013, the cumulative SOR at Firebag was 3.3 (2012 – 3.4).

MacKay River

Production from MacKay River commenced in 2002. As at December 31, 2013, MacKay River included six well pads with 74 well pairs either producing or on initial steam injection. The MacKay River central processing facilities have bitumen processing capacity of approximately 30 mbbls/d. A third party owns the on-site cogeneration unit that is used to generate steam and electricity which Suncor operates under a commercial agreement. There are also four OTSGs at the site for additional steam generation. The company has commenced a debottlenecking project of existing central processing facilities that is expected to

SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014    13

increase existing bitumen processing capacity to approximately 38 mbbls/d by 2015.

As at December 31, 2013, the cumulative SOR at MacKay River was 2.6 (2012 – 2.5).

Suncor has regulatory approval for additional bitumen production from MacKay River and adjacent Dover lands, and is currently evaluating an expansion to increase bitumen processing capacity through an additional central processing facility. Suncor continues to work towards a 2014 sanction decision of an additional central processing facility at MacKay River, which is targeted to have an initial design capacity of approximately 20 mbbls/d and first oil in 2017.

Other In Situ Leases

Suncor owns several other oil sands leases, including those known as Meadow Creek, Lewis, Chard and Kirby. Suncor believes these leases can be developed using in situ techniques on which it may undertake exploratory drilling. In 2013, Suncor drilled 50 core holes at Lewis and 66 gross core holes at Meadow Creek. Plans for winter 2014 drilling include an additional 55 core holes at Lewis and 37 core holes at Meadow Creek. Suncor holds a 100% working interest in Lewis and a 75% working interest in Meadow Creek.

Starting with Meadow Creek, Suncor is commencing a greenfield growth plan with a concept to grow new In Situ reservoirs using a replication strategy to build standardized surface facilities, well pads and infrastructure on a program basis. The winter exploratory drilling programs are designed to identify sufficient resources to fill facilities associated with the replication strategy.

Oil Sands Joint Arrangements

Syncrude

Suncor holds a 12% interest in the Syncrude joint arrangement, located near Fort McMurray, which includes mining operations at Mildred Lake North and Aurora North. Syncrude also has regulatory approval to develop the Aurora South oil sands mining leases. In 2012, the Syncrude co-owners announced a plan to develop two mining areas adjacent to the current mine, subject to final sanctioning and regulatory approvals, which would consequently extend the life of Mildred Lake by approximately ten years. The plan proposes to use existing mining and extraction facilities. Syncrude expects to make regulatory applications for these areas in 2014.

Syncrude began producing in 1978 and is operated by Syncrude Canada Ltd. (SCL). In 2006, SCL entered into a comprehensive management services agreement with Imperial Oil Resources (Imperial Oil) to provide operational, technical and business management services. This agreement has an initial term of ten years and includes renewal provisions.

Syncrude mining operations use truck, shovel and pipeline systems, similar to those at Oil Sands Base. Extraction and upgrading technologies at Syncrude are similar to those used at Oil Sands Base, with the exception that Syncrude uses a fluid coking process that involves the continuous thermal cracking of the heaviest hydrocarbons. At Mildred Lake, electricity is provided by a utility plant fuelled by off-gas from upgrading operations and natural gas. At Aurora North, Syncrude operates two 80-MW gas turbine power plants.

Syncrude produces a single sweet synthetic light crude product. Marketing of this product is the responsibility of the individual co-owners.

Land reclamation activities are similar to those at Oil Sands Base; however, certain aspects of the tailings management processes are different. Syncrude's tailings plan uses the following: freshwater capping, a composite tails mixture of fine tails and gypsum, and plans for centrifuge technology that separates water from tailings.

In 2013, Suncor's share of Syncrude production averaged 32 mbbls/d (2012 – 34 mbbls/d).

Fort Hills

Fort Hills is an oil sands mining area comprising leases on the east side of the Athabasca River, north of Oil Sands Base operations. Designs for the Fort Hills mining project plan for 180 mbbls/d of bitumen production (gross). Suncor originally acquired a 60% working interest in Fort Hills through the merger with Petro-Canada, but disposed of 19.2% as part of transactions with Total E&P. Suncor now holds a 40.8% working interest in the Fort Hills project. Suncor is the contract operator for the Fort Hills project. The company's share of the post-sanction project costs are estimated to be $5.5 billion. Approximately 15% of the company's 2014 capital budget has been allocated to this project. Project activities in 2014 are expected to focus on detailed engineering, procurement and ramp-up of field construction activities.

Other Assets

Joslyn is the oil sands mining area comprising leases southwest of Fort Hills and on the west side of the Athabasca River. Total E&P is the operator. Preliminary designs for the Joslyn North mining project plan for 157 mbbls/d of bitumen production (gross). Suncor acquired a 36.75% working interest in this asset as a result of transactions with Total E&P. Suncor plans to provide an update on the targeted timing for a sanction decision on the Joslyn project when available.

14   SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014

New Technology

Technology is a fundamental component to Suncor's business. Suncor has pioneered commercial oil sands development and continues to advance technology through innovation and collaboration to improve efficiencies, lower costs and increase environmental performance.

Suncor is working on several new in situ technology projects that are proceeding with the next phase of field testing. Examples of Suncor's new technology projects include:

•
Electric Submersible Pumps (ESPs) – Suncor is working with vendors on technology to improve equipment performance in SAGD.

•
N-SOLVTM – Evolving toward waterless recovery by using a warm solvent to extract bitumen efficiently, sustainably and economically.

•
Steam Assisted Gravity Drainage Less Intensive Technology Enhanced (SAGD LITE) – Field trials are underway to evaluate technologies such as solvent addition, surfactant addition, flow control devices and injection control devices to improve cost, SORs, and timely recovery and productivity.

Suncor is a member of Canada's Oil Sands Innovation Alliance (COSIA) which is a group of oil sands producers brought together to accelerate environmental performance improvement through collaboration.

Sales of Principal Products

Primary markets for SCO and bitumen production from Suncor's Oil Sands segment, which is sold to and subsequently marketed by Suncor's Energy Trading business, include refining operations in Alberta, Ontario, the U.S. Midwest and the U.S. Rocky Mountain regions. Commencing in 2014, production is also being sold to markets in the U.S. Gulf Coast. Diesel production from upgrading operations is sold primarily in Western Canada, marketed by Suncor's Refining and Marketing business.

For bitumen production from In Situ operations, Suncor's marketing strategy allows it to take advantage of changes in market conditions by either: a) upgrading the bitumen directly at our Oil Sands Base facilities; b) upgrading bitumen at Suncor's Edmonton refinery; or c) selling diluted bitumen directly to third parties. Increased bitumen sales may also be required during outages of upgrading facilities. During 2013, approximately 55% or 94 mbbls/d (2012 – 63% or 83 mbbls/d) of In Situ bitumen production was processed by Oil Sands Base upgrading facilities.

    2013   2012  
   
 
Sales Volumes and Operating Revenues – Principal Products   mbbls/d   % operating
revenues		   mbbls/d   % operating
revenues		  
Sweet – Light sweet SCO and diesel (including Syncrude)   147.9   43   152.7   47  
Sour – Light sour SCO and bitumen   241.9   51   205.6   48  
Non-proprietary, byproducts and other operating revenues(1)   n/a   6   n/a   5  
    389.8       358.3      
(1)
Operating revenues include sales of non-proprietary volumes, primarily third-party diluent purchased to support sales of bitumen that is required when the company is unable to meet diluent demands internally, as well as revenues associated with excess power from cogeneration units.

SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014    15

In the normal course of business, Suncor enters into long-term strategic sales agreements for its proprietary sour SCO, which contain varying terms with respect to pricing, volume, expiry and terminations.

Distribution of Products

Production from Oil Sands Operations is gathered into Suncor's Fort McMurray facilities at the Athabasca Terminal, which is operated by Enbridge Inc. (Enbridge). Suncor has various arrangements with Enbridge at this facility to store SCO, diluted bitumen and diesel. Product moves from the Athabasca Terminal in the following ways:

•
To Edmonton via the Oil Sands pipeline, which is owned by Suncor and operated by the Refining and Marketing segment. At Edmonton, the product is sold to local refiners, including Suncor, or transferred onto the Enbridge Mainline system or the TransMountain Pipeline system.

•
To Cheecham, Alberta, on the Enbridge Athabasca Pipeline or the Enbridge Wood Buffalo Pipeline. From Cheecham, the Enbridge Athabasca Pipeline continues to Hardisty, Alberta.

•
To Edmonton via the Enbridge Waupisoo Pipeline, originating at Cheecham.

From Hardisty, where Suncor owns storage capacity with additional capacity under contract, Suncor has various options for delivering product to customers:

•
To Suncor's Commerce City refinery via the Express and Platte pipelines. Suncor owns and operates a pipeline that is connected to the Commerce City refinery, which originates from the Guernsey, Wyoming station that is part of the Platte pipeline.

•
To Suncor's Sarnia refinery on the Enbridge Mainline and Lakehead systems.

•
Through the Enbridge Mainline system, crude can reach most major refining hubs via the Enbridge Mainline, Express/Platte and Keystone pipeline systems.

Commencing in 2014, Suncor has begun shipping heavy crude on TransCanada's Gulf Coast Pipeline, providing the company with more than 50 mbbls/d of heavy crude shipping capacity to the U.S. Gulf Coast and another outlet for the growing bitumen production at Firebag.

Natural gas is used in the production of SCO and bitumen. Natural gas is delivered to Oil Sands Base and In Situ facilities via the Nova Gas Transmission Limited (NGTL) pipeline system. Suncor also transports natural gas to Oil Sands Base facilities on the company-owned and operated Albersun Pipeline, which extends approximately 300 km south of Oil Sands Base facilities and is connected to the NGTL.

Oil Sands Base facilities are readily accessible by public road. MacKay River facilities are accessible by a combination of public and private roads. Firebag facilities are accessible by air and private road.

Royalty Agreements

Oil Sands Base and Syncrude

New oil sands projects are subject to the New Royalty Framework issued by the Government of Alberta, and regulated by the Oil Sands Royalty Regulation 2009 (OSRR 2009), and supporting regulations, which were approved in 2008.

As part of the New Royalty Framework, Suncor entered into the Suncor Royalty Amending Agreement (Suncor RAA) with the Government of Alberta in January 2008 for royalties pertaining to its Oil Sands Base operations. For the period from January 1, 2010 to December 31, 2015, royalty rates are based on a sliding scale (depending on the Canadian dollar equivalent for WTI) from 25% to 30% of R – C (Revenue-Cost), where R is gross revenues, net of bitumen quality adjustments and transportation costs, and C is allowable costs including allowable capital expenditures, which excludes substantially all operating and capital expenditures associated with upgrading facilities. The minimum royalty rate is 1.0% to 1.2% of R. In 2013, Suncor incurred royalties at Oil Sands Base mining operations at a rate of 30% of R – C (2012 – 30% of R – C).

In 2008, the Alberta government and the co-owners of Syncrude reached an agreement for the implementation of the New Royalty Framework for the Syncrude project (similar to the Suncor RAA). Under the new terms, Syncrude will continue paying the greater of 1% gross revenue, or 25% of net revenue, until the end of 2015. For 2013, the royalty rate was 25% of net revenue (2012 – 25%). As part of its agreement, Syncrude also exercised its option to transition to a bitumen-based royalty from an SCO-based royalty. In addition, the co-owners of Syncrude agreed to pay an additional royalty of $975 million over a six-year period starting in 2010, which is contingent on achieving certain production levels.

As part of the implementation of the New Royalty Framework, the Alberta government enacted the BVM Regulations effective January 1, 2009 to determine the value of bitumen for royalty purposes. The Crown notified Suncor that the BVM Regulation would apply to Oil Sands base mining operations for purposes of the Suncor RAA (Suncor BVM). In 2009, Suncor provided notice to the Crown that the Suncor BVM was non-compliant with the Suncor RAA. In December 2010, the Alberta Minister of Energy notified Suncor of the modifications to the Suncor BVM, providing for bitumen quality adjustments not previously recognized and adjustments for transportation.

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With respect to the bitumen quality adjustments, Suncor filed a Notice of Commencement of Arbitration with the Alberta government on January 29, 2011 pursuant to the dispute resolution provisions of the Suncor RAA. In December 2013, Suncor reached an agreement with the Alberta government to settle all unresolved royalty issues under the Suncor RAA.

The co-owners of Syncrude also filed a non-compliance notice with the Alberta government, citing that reasonable adjustments in the determination of the bitumen value were not considered by the government. In December 2013, the Syncrude co-owners reached an agreement with the Alberta government to settle unresolved royalty issues under the Syncrude RAA.

Under these modified settlement agreements, certain provisions of the BVM Regulation, including the floor price limitations, will apply for the term. A floor price is applied when prices for Canadian heavy oil are discounted relative to heavy oil prices at the U.S. Gulf Coast.

In 2013, Oil Sands royalties (excluding Syncrude) were approximately 7% (2012 – 6%) of Oil Sands operating revenues (excluding Syncrude). In 2013, Suncor incurred royalties on Syncrude operations averaging approximately 5% of Syncrude operating revenues before royalties (2012 – 6%).

Beginning on January 1, 2016, Suncor's Oil Sands Base and Syncrude operations will be subject to the generic royalty regime that is currently in place for all other oil sands royalty projects in Alberta, including Suncor's In Situ operations, as described below.

In Situ

Under the New Royalty Framework, royalties on Suncor's Firebag and MacKay River projects are based on a sliding-scale rate of 25% to 40% of R – C, subject to a minimum royalty within a range of 1% to 9% of R. Revenues used in royalty formulas are driven primarily by benchmark prices for WCS, while sliding-scale percentages in royalty formulas depend on prices for WTI from Cdn$55/bbl to the maximum rate at a WTI price of Cdn$120/bbl. A project remains subject to the minimum royalty (the pre-payout phase) until the project's cumulative gross revenues exceed its cumulative costs, including an annual investment allowance (the post-payout phase). In 2013, Suncor incurred minimum royalties at a rate of 7% of R for MacKay River (2012 – 6% of R) and royalties averaging 7% of R for Firebag (2012 – 6%), which continues in the pre-payout phase.

Exploration and Production

For a discussion of the environmental and other regulatory conditions, competitive conditions, foreign operations and seasonal impacts affecting our Exploration and Production segment, refer to the Industry Conditions and Risk Factors sections of this AIF.

East Coast Canada – Assets and Operations

Based in St. John's, Newfoundland and Labrador, this business includes interests in three producing fields and future developments and extensions. Suncor is also involved in exploration drilling for new opportunities. Suncor is the only company in this region with interests in every field currently in production.

Terra Nova

The Terra Nova oilfield is approximately 350 km southeast of St. John's. Terra Nova was discovered in 1984, and was the second oilfield to be developed offshore Newfoundland and Labrador. Operated by Suncor, the production system uses an FPSO vessel that is moored on location, and has gross production capacity of 180 mbbls/d (net 68 mbbls/d to Suncor) and oil storage capacity of 960 mbbls. Terra Nova was the first harsh environment development in North America to use a FPSO vessel. Actual annual production levels are lower than production capacity, reflecting current reservoir capability, including natural declines, gas and water injection and production limits, and asset and facility reliability. Production from Terra Nova began in January 2002. At December 31, 2013, there were 29 wells: 17 oil production wells, nine water injection wells and three gas injection wells. In 2013, Suncor's share of Terra Nova production averaged 14 mbbls/d compared to 9 mbbls/d in 2012. The company commenced off-station maintenance of the Terra Nova facility in late September 2013 for ten weeks to repair a mooring chain and perform preventive maintenance on the remaining eight chains. Production was reinstated in early December 2013. In comparison, the facility was off-line for approximately 27 weeks in 2012 as part of a dockside planned maintenance program.

SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014    17

Current development plans for Terra Nova include a production well and a water injection well that the company anticipates will add production and mitigate natural declines from the reservoir. In addition, in 2014, the company plans to perform maintenance on several production wells and to reinstate a second flowline to a subsea drill centre.

Field production is transported by shuttle tanker from the FPSO and either delivered directly to customers (if tanker schedules permit) or to the Newfoundland transshipment terminal in Placentia Bay, where it is subsequently loaded onto tankers for transport to markets in Eastern Canada or the U.S. Suncor has a 14% ownership interest in the transshipment facility and is part of a group of companies that share the operation of marine transportation assets for East Coast Canada.

Hibernia and the Hibernia Southern Extension Unit (HSEU)

The Hibernia oilfield, encompassing the Hibernia and Ben Nevis Avalon reservoirs, is approximately 315 km southeast of St. John's and was the first field to be developed in the Jeanne d'Arc Basin. Operated by Hibernia Management and Development Company Ltd., an ExxonMobil-managed company, the production system is a fixed GBS that sits on the ocean floor, and has gross production capacity of 230 mbbls/d (net 46 mbbls/d to Suncor) and oil storage capacity of 1,300 mbbls. Actual production levels are lower, reflecting current reservoir capability, including natural declines, gas and water injection and production limits, and asset and facility reliability. Hibernia commenced production in November 1997. At December 31, 2013, there were 62 wells in operation: 37 oil production wells, 14 single-zone water injection wells, six dual-zone water injection wells and five gas injection wells. In 2013, Suncor's share of Hibernia production averaged 27 mbbls/d (2012 – 26 mbbls/d). Hibernia uses the same transshipment terminal and similar system of shuttle tankers that are used for Terra Nova.

In 2010, final agreements were signed between the Hibernia co-venturers and the Government of Newfoundland and Labrador that established the fiscal, equity and operational principles for the development of the HSEU. During 2011, the first two development wells were completed from the GBS platform and are producing oil. The third production well has been drilled and will commence oil production in the first quarter of 2014. Current development plans include drilling up to two additional production wells from the GBS platform and six water injection wells in a subsea, excavated drill centre. Subsea infrastructure was installed in late 2013 and drilling of the first subsea water injection well began in early 2014. The number of production and injection wells required may be revised as the development proceeds and uncertainties regarding reservoir capability are resolved. Production from the HSEU is not expected to reach higher rates until 2015 when several planned water injection wells are completed.

White Rose and the White Rose Extensions

White Rose is approximately 350 km southeast of St. John's. Operated by Husky Oil Operations Limited, White Rose uses a FPSO vessel and has gross production capacity of 140 mbbls/d (net 39 mbbls/d to Suncor) and oil storage capacity of 940 mbbls. Actual annual production levels are lower than production capacity, reflecting current reservoir capability, including natural declines, gas and water injection and production limits, and asset and facility reliability. Production from White Rose began in November 2005. At December 31, 2013, there were 33 wells in operation: 15 oil production wells, 15 water injection wells and three gas storage wells. In 2013, Suncor's share of White Rose production averaged 15 mbbls/d (2012 – 12 mbbls/d). White Rose uses the same transshipment terminal and the same system of shuttle tankers that are used for Hibernia and Terra Nova.

In 2007, the White Rose co-venturers signed an agreement with the Province of Newfoundland and Labrador for the development of the White Rose Extensions, which include the South White Rose Extension, North Amethyst and West White Rose satellite fields. In May 2010, first oil was achieved in North Amethyst, and development drilling is ongoing. Development of the West White Rose field has been divided into two stages. The first stage was approved in 2010 and first oil was achieved in 2011.

In October 2013, the co-owners reached an agreement with the Government of Newfoundland and Labrador which resulted in amendments to the terms of the 2007 White Rose Expansion Project Framework Agreement, enabling the second stage development of West White Rose using a Wellhead Platform. Detailed engineering design for this project is currently underway and sanction is planned for the second half of 2014. Development of the South White Rose Extension began in 2013 with the installation of subsea gas injection infrastructure. Oil production and water injection infrastructure will be installed in 2014, and first oil for the South White Rose Extension is expected in late 2014 or early 2015.

Hebron

Discovered in 1980, the Hebron oilfield is located 340 km southeast of St. John's. The project is operated by ExxonMobil Canada Properties. On December 31, 2012, the Hebron co-owners announced project sanction. Development of the Hebron project includes the construction of a concrete GBS that supports an integrated topsides deck to be used for production, drilling and accommodations. Development plans include 1,200 mbbls of oil storage capacity and 52 well slots with a gross oil

18   SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014

production capacity of 150 mbbls/d (net 34 mbbls/d to Suncor). Detailed engineering and construction of the gravity-based structure and topsides fabrication progressed according to plan during 2013. First oil is expected in 2017. Suncor's share of the post-sanction project cost estimate provided by the project operator is approximately $2.8 billion.

Other Assets

The Ballicatters discovery, located 22 km northeast of Hibernia, was completed in 2011 and is comprised of gas and oil. The licence is operated by Suncor. In September 2013, the Canada-Newfoundland and Labrador Offshore Petroleum Board issued two Significant Discovery Licences (SDL 1051 and SDL 1052) for the Ballicatters discovery. Potential options to commercialize the discovery are currently being evaluated.

Suncor continues to pursue opportunities offshore Newfoundland and Labrador. The company holds interests in 50 other significant discovery licences and six other exploration licences offshore Newfoundland and Labrador.

International – Assets and Operations

Buzzard – North Sea

The Buzzard oilfield is located in the Outer Moray Firth, 95 km northeast of Aberdeen, Scotland. Operated by Nexen Petroleum U.K. Limited, a subsidiary of China National Offshore Oil Corporation Limited (CNOOC), the Buzzard facilities have gross installed production capacity of approximately 220 mbbls/d (net 66 mbbls/d to Suncor) of oil and 80 mmcf/d (net 24 mmcf/d to Suncor) of natural gas. Actual annual production levels are lower than production capacity, reflecting current reservoir capability, including natural declines, water injection limits, gas and water production limits, and asset and infrastructure reliability. Buzzard commenced production in January 2007. Buzzard consists of four bridge-linked platforms supporting wellhead facilities, production facilities, living quarters and utilities, and sulphur handling. At December 31, 2013, there were 45 wells: 33 oil and gas production wells and 12 water injection wells. In 2013, Suncor's share of Buzzard production averaged 56 mboe/d (2012 – 48 mboe/d).

In 2013, Buzzard completed three oil and gas development wells, which are intended to mitigate natural declines from the reservoir.

Crude oil is transported via the third-party operated Forties Pipeline System to the Kinneil terminal in Scotland. Natural gas is transported via the third-party operated Frigg Pipeline to the St. Fergus gas terminal in Scotland.

Golden Eagle – North Sea

During 2011, Golden Eagle received regulatory approval from the U.K. Department of Energy and Climate Change and sanction from the project's co-owners. This development is approximately 20 km north of the Buzzard oilfield and consists of the unitization of the Peregrine, Hobby, Golden Eagle and Solitaire areas. The development plan incorporates a combined production, utilities and accommodation platform, linked to a separate wellhead platform, with an initial gross production capacity of 70 mboe/d (net 19 mboe/d to Suncor) from 21 development wells. In 2013, activities at Golden Eagle included the installation of two platform jackets and the wellhead topside, and the start of development drilling. The operator, Nexen Petroleum U.K. Ltd., estimates that the gross development cost will be £2 billion (Cdn$3.5 billion) and £0.6 billion (Cdn$1.0 billion) net to Suncor. First production is expected late in 2014 or early 2015. The Golden Eagle co-owners also hold adjacent exploration licences and continue to explore the region.

Other Assets – North Sea

Other Suncor exploration and appraisal initiatives in the North Sea include:

•
Beta discovery (Norway) – Suncor is the operator for the PL375, PL375b and PL375c licences, in which it has a 70% interest. The company drilled the first exploration well in early 2010, encountering hydrocarbons. An appraisal well was drilled and tested later in 2010 with positive results. However, a third well drilled into a separate fault block did not encounter hydrocarbons. The company will continue to evaluate the Beta discovery by interpreting 3D seismic data acquired in 2013 and with further drilling starting in 2014. The Beta licences also contain other exploration opportunities.

•
Butch discovery (Norway) – In 2011, Centrica plc, the operator for the PL405 licence in which Suncor has a 30% interest, drilled an exploration well resulting in a discovery, followed by a sidetrack well to assess the lateral extent of the hydrocarbons. Early in 2012, a second sidetrack well was attempted but abandoned, due to well instability, before reaching its intended depth. In December 2013, the operator, began drilling the first of two additional wells on the licence to explore for oil in separate fault blocks from the discovery.

•
Myrhauk prospect (Norway) – Suncor has a 20% interest in the PL539 licence, operated by Premier Oil plc. The operator has planned an exploration well for late 2014.

•
Romeo discovery (U.K.) – During the second half of 2012 and into early 2013, the company was the

SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014    19

•
Scotney prospect (U.K.) – In 2013, Suncor, as operator, drilled a well in Block 20/05b to comply with a work commitment for the licence, in which it has a 32.86% interest. This well was completed in late April 2013 with no hydrocarbons encountered.

•
Lily prospect (U.K.) – During the fourth quarter of 2013, the operator for the P928 20/1S licence, in which Suncor has a 29.89% interest, drilled an exploration well but did not encounter hydrocarbons.

•
Blackjack prospect (U.K.) – During the second half of 2013, the operator of the P300 14/26a licence, in which Suncor has a 26.69% interest, conducted a site survey for a planned exploration well, which is scheduled to commence drilling during the first quarter of 2014.

Suncor continues to pursue other opportunities in the North Sea, the Norwegian Sea and the Barents Sea. The company holds interests in 30 exploration licences in the U.K. and Norwegian sectors of these areas.

Libya

In Libya, Suncor is signatory to seven EPSAs with the Libya National Oil Corporation (NOC). Five of the seven EPSAs contain producing fields and exploration prospects; the remaining two are exploration EPSAs that do not contain producing fields, one of which is being relinquished because the exploration program was not successful. Together, Suncor and the NOC jointly design and implement the development and redevelopment of existing fields in the Sirte Basin. Existing reserves are associated with five separate agreements which contain five primary producing fields. Under the EPSAs, the company pays 100% of the exploration costs, 50% of the development costs and 12% of the operating costs, and recovers these costs through a 12% share of a production cost recovery mechanism. Any petroleum remaining after cost recovery is referred to as excess petroleum, and is shared between Suncor and the NOC based on several factors. Suncor's share of the excess petroleum can range from 4% to 85%. The EPSAs expire on December 31, 2032, but include an initial five-year extension through the end of 2037. In 2013, Suncor's share of production in Libya averaged 21 mbbls/d, (2012 – 42 mbbls/d). Libya is a member of the Organization of Petroleum Exporting Countries (OPEC) and is subject to quotas that can affect the company's production in Libya.

For the period from March to September 2011, the operator for the joint operation, Harouge Oil Operations BV (Harouge), shut in production as a result of political unrest that began in February 2011. In March 2011, Suncor declared force majeure under its EPSAs. Suncor exited development force majeure in December 2011 and exploration force majeure in June 2012, and production resumed to previous rates.

In July 2013, operations in Libya were again disrupted as political unrest resulted in the closure of seaport terminals. Production has been shut in since July 2013 and Suncor has not lifted production or recognized a sale since May 2013. Some seaports, largely on the country's western coast, were reopened in late December 2013, but eastern seaports, including the Ras Lanuf and Es Sider terminals through which Suncor's crude is exported, are still closed. As a result of this extended loss of production and uncertainty on timing of return to operations in Libya, Suncor recorded an after-tax impairment charge of $101 million against these assets in the fourth quarter of 2013.

Despite the seaport closures, Suncor continued exploration activities in 2013. During the year, two suspended wells and four additional exploration and appraisal wells were completed. Hydrocarbons were discovered in three of the wells, while the other three wells were assessed as dry holes.

During 2013, exploration force majeure extension agreements were signed by NOC and Suncor, relating to the 2011 force majeure situation, extending the exploration period from December 31, 2012 until April 12, 2014. In early 2014, an additional one-year extension to April 12, 2015, was approved by the NOC, with the formal extension agreements to follow later in 2014. The terms of the ESPAs allow for further extensions to be negotiated. The estimated cost of Suncor's remaining exploration work program commitment at December 31, 2013 is US$349 million.

At December 31, 2013, the company had an outstanding obligation of US$74 million for a signature bonus relating to Petro-Canada's ratification of the Libyan EPSAs in 2008.

Syria

In December 2011, amid continuing unrest in Syria, sanctions were introduced and Suncor declared force majeure under its contractual obligations and suspended its operations in the country. Suncor withdrew its expatriate staff and undertook measures to maintain support for its Syrian employees. Consequently, the company has ceased recording all production and revenue associated with its Syrian assets. Since 2011, Suncor has not been able to monitor the status of any of its assets in the country, including whether certain facilities have suffered damages.

Located in the Central Syrian Gas Basin, the Ebla project includes all hydrocarbons in the Ash Shaer and Cherrife

20   SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014


development areas, which cover more than 300,000 acres. Suncor conducts its Syrian operations pursuant to a PSC, under which the company is a co-owner of the Ebla project with the General Petroleum Corporation (GPC). Under the PSC, the company pays 100% of the development costs and recovers these costs from a 40% share of production after deduction for royalties of 12.5%. This petroleum revenue is referred to as Cost Recovery petroleum. The amount by which Cost Recovery petroleum exceeds recoverable cost is referred to as Excess Cost Recovery petroleum; 50% of this amount is due to the GPC and the remaining 50% is shared between Suncor and the GPC according to a profit-sharing schedule. The Ebla PSC expires in April 2035, but includes a five-year extension subject to GPC approval. First commercial gas production from Ebla was achieved in April 2010 and first oil was achieved in December 2010.

The Ebla project comprised six natural gas wells in the Ash Shaer field, a gas gathering and compression station, approximately 80 km of pipeline, and a gas treatment plant. The facility is designed to produce 97 mmcf/d of natural gas, along with related LPG and condensate volumes. The company has a contracted volume of 80 mmcf/d. Natural gas was delivered into the Syrian national gas grid for domestic electrical power generation. The Ebla project also included three crude oil wells.

In 2012, the company recorded an impairment charge against its Syrian assets as a result of the uncertainty about the company's future in the country. Later in the year, the company received proceeds from risk mitigation instruments related to its Syrian assets, which are subject to a provisional repayment should operations in Syria resume and loss of value is determined not to be permanent.

Suncor impaired the remaining carrying value of its Syrian assets in the fourth quarter of 2013, resulting in an after-tax impairment charge of $422 million, as there has been no resolution of the political situation resulting in rising uncertainty with respect to the company's return to operations. Concurrently, the company recognized risk mitigation proceeds, received in 2012, of $300 million ($223 million after-tax) in net earnings. These were previously recorded as a long-term provision.

North America Onshore – Assets and Operations

The North America Onshore business explores for, develops and produces natural gas, NGLs, crude oil and byproducts in Western Canada. After the merger with Petro-Canada, the strategy for this business focused on liquids-rich and unconventional sources. As a result, the company divested a number of non-core assets in this business area throughout 2010 and early 2011 and, in 2013, sold the majority of its remaining conventional natural gas business for $1 billion prior to closing adjustments and other closing costs. Following these disposals, the retained assets produce approximately 3 mboe/d of gas and 2 mbbl/d of liquids.

Natural gas extracted from the wellhead requires further processing. Suncor currently operates one natural gas processing plant at Wilson Creek (52.17% working interest ownership), with total licensed capacity of 34.6 mmcf/d, (18.1 mmcf/d net). Capacity not utilized by the company's own production is optimized through processing agreements with third-party producers.

Natural gas production from Alberta is typically sold at the Nova Inventory Transfer point (NIT), which is one of the largest natural gas trading hubs in North America. Natural gas at NIT generally receives a daily or monthly average AECO (Alberta) spot price. Natural gas production from B.C. is typically sold at Station 2, part of the Spectra B.C. transmission system, and receives the Station 2 Gas Daily Index price. Suncor holds firm capacity on the TransCanada PipeLines Gas Transmission Northwest Pipeline (GTN). The GTN firm capacity enables Suncor to deliver natural gas to the Pacific Northwest and California markets.

Crude oil production from North America Onshore assets is shipped on pipelines operated by independent pipeline companies. In most sales arrangements, Suncor is responsible for transportation to the point of sale.

In addition, Suncor holds assets that allow the company to explore long-term supply opportunities in northern frontier areas, such as the Arctic Islands.

Sales of Principal Products

Oil and gas production from East Coast Canada, the North Sea, and from North America Onshore is either marketed by our Energy Trading business, acting as a marketing agent or sold to our Energy Trading business, which then markets the products to customers under direct sales arrangements. Suncor does not typically enter into long-term supply arrangements to sell its production from its Exploration and Production segment. Contracts for these direct sales arrangements are of varied terms, with a majority having terms of one year or less, and incorporate pricing that is generally determined on a daily or monthly basis in relation to a specified market reference price.

In Libya, prior to the shut in of production, crude oil was marketed by the NOC on behalf of Suncor. In Syria, prior to the suspension of operations, the company entered into purchase and sale agreements with the Syrian government for all hydrocarbon production from the Ebla project.

SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014    21

Exploration and Production Sales Summary:

    2013   2012
   
 
Sales Volumes   mboe/d   % operating
revenues		   mboe/d   % operating
revenues		  
East Coast Canada                  
  Crude oil   55.9   40   46.7   33  
International                  
  Crude oil and NGLs   75.2   53   88.5   59  
  Natural gas   1.2   0   1.0   1  
North America Onshore                  
  Crude oil and NGLs   5.3   3   5.6   3  
  Natural gas   32.0   4   48.3   4  
Total Exploration and Production                  
  Crude oil and NGLs   136.4   96   140.8   95  
  Natural gas   33.2   4   49.3   5  

Royalties

East Coast Canada

The Terra Nova royalty consists of a sliding-scale, basic royalty payable throughout the project's life, with two tiers of incremental royalties, which became payable upon the achievement of specified levels of profitability. The basic royalty is now capped at 10% of gross field revenue, based on the project reaching a specified cumulative production level. The tier one royalty is 30% of net revenue, and became payable in 2005. Net revenue is gross revenue adjusted for eligible operating and capital costs. The tier two royalty, equal to 12.5% of net revenue, became payable in 2008. During 2013, Terra Nova royalties averaged 12% of gross revenue (2012 – 36%) and decreased primarily due to higher deductible costs in 2013.

The Hibernia royalty agreement for production from the original oilfields and the AA Block consists of a sliding-scale gross royalty, two tiers of incremental royalty, and an additional net profits interest (NPI). The basic royalty is now capped at 5% of gross revenue, as the project has reached a specified cumulative production level. The tier one royalty, which became payable in 2009, is 30% of net revenue. The tier two royalty is 12.5% of net revenue, but has not yet been triggered. Production from the AA Block, which commenced in late 2009, attracts an additional tier three royalty of 12.5% of net revenue. The NPI, which also became payable in 2009, is an additional 10% of net revenue. Limited production from the HSEU began in 2011. The HSEU has a similar royalty structure (gross, tier one and tier two) to that described above for Hibernia. Currently, Suncor is subject to a 5% gross royalty. HSEU production will be subject to an additional tier three royalty that ranges between 2.5% and 7.5% of net revenue, depending on the price for WTI. The HSEU tier three royalty will coincide with the triggering of the tier one net royalty. During 2013, Hibernia (including the HSEU) royalties and NPI combined to average 36% of gross revenue (2012 – 35%).

The White Rose royalty for the base project consists of a sliding-scale basic royalty payable, with two tiers of incremental royalties, which became payable upon the achievement of specified levels of profitability. The basic royalty is now capped at 7.5% of gross field revenue, based on the base project reaching a specified cumulative production level. The tier one royalty is 20% of net revenue, and became payable in 2007. The tier two royalty, equal to 10% of net revenue, became payable in 2008. The royalty for production from the White Rose Extensions is similar to the base project, except that there is an additional tier three royalty, equal to 6.5% of net revenue, which is payable if WTI is greater than Cdn$50/bbl. Currently, the White Rose Extensions are only subject to a 2.5% gross royalty. During 2013, total White Rose royalties averaged 16% of gross revenue (2012 – 12%).

International

There are no royalties on oil and gas production from the North Sea; however, in the U.K., oil and gas profits are subject to a 62% income tax rate. For operations in Libya and Syria, all government interests, except for income taxes, are presented as royalties.

North America Onshore

Royalties for Suncor's North America Onshore production in Alberta are regulated primarily by the Natural Gas Royalty Regulation 2009, and by the Petroleum Royalty Regulation

22   SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014

2009. Royalties for natural gas and oil production are set by a sliding-scale formula ranging from 5% to 36% for natural gas, and 0% to 40% for conventional crude oil. Rates are dependent on well depth, production rates, price, and quality of the natural gas and crude oil. New wells receive an initial maximum rate of 5%, subject to volume and credit caps. In Alberta, costs for gathering, compressing, and processing the provincial government share of gas and NGLs are allowable deductions from gross royalties payable. Royalties for NGLs are determined based on the prescribed reference prices multiplied by flat rates of 30% for propane and butane, and 40% for pentanes.

Royalties for Suncor's North America Onshore production in B.C. are regulated primarily by the Petroleum and Natural Gas Royalty and Freehold Production Tax Regulation. Royalty formulas (rates) for natural gas production are different based on the date the well was drilled. Gas rates start as low as 9%, and are subject to a sliding scale with a maximum royalty rate of 27% as prices increase. B.C. provides royalty adjustments for deep drilling, lower production rates, and unique production methods. In B.C., field expenses (gathering, compression and processing) are allowed as cost of services deductions from gross royalties. Plant processing costs are included as adjustments to the provincial government valuation price. Royalties on NGLs are assessed at a flat rate of 20% of revenues.

During 2013, royalties for North America Onshore production averaged 10% of gross revenue (2012 – 7%).

Refining and Marketing

For a discussion of the environmental and other regulatory conditions, and competitive conditions and seasonal impacts affecting our Refining and Marketing segment, refer to the Industry Conditions and Risk Factors sections of this AIF.

Operations – Refining and Product Supply

Eastern North America

The Montreal refinery has a crude oil capacity of 137 mbbls/d, processing primarily foreign conventional crude oil, with a flexible configuration that allows processing of light, sour and heavy grades of crude oil, as well as intermediate feedstock. Crude oil is procured from the market on a spot basis or under contracts that can be terminated on short notice. Crude oil for the refinery is largely supplied via the Portland-Montreal Pipeline and to a lesser extent, by rail and marine transportation. With the commissioning of the rail offloading facility in the fourth quarter of 2013, the Montreal refinery has also started to receive inland crudes. Rail volumes are expected to increase to 35 mbbls/d by the end of the first quarter of 2014.

Production yield from the Montreal refinery includes gasoline, distillate, asphalt and petrochemicals, which are distributed primarily across Quebec and Ontario. The Montreal refinery also produces feedstock for Suncor's lubricants plant. Refined products are delivered to distribution terminals in Ontario via the Trans-Northern Pipeline and delivered to customers directly by truck, rail and marine vessel.

The Sarnia refinery has a crude oil capacity of 85 mbbls/d, processing both SCO from the company's Oil Sands operations and conventional crude oil purchased from third parties on a spot basis or under contracts that can be terminated on short notice. Crude oil is supplied to the Sarnia refinery primarily via the Enbridge Mainline and Lakehead pipeline systems. Suncor procures conventional crude oil feedstock primarily from Western Canada and has the ability to supplement supply with purchases from the U.S.

Production yield from the Sarnia refinery includes gasoline, distillate and petrochemicals, which are primarily distributed in Ontario. Refined products are delivered to distribution terminals in Ontario via the Sun-Canadian Pipeline, or delivered to customers directly via marine vessel and rail. The Sarnia refinery also has limited access to pipelines delivering refined products into the U.S.

To meet the demands of Suncor's marketing network in Eastern North America, the company also purchases gasoline and distillate from other refiners. Suncor enters into reciprocal exchange arrangements with other refiners in Eastern North America, primarily for gasoline and distillate, as a means of minimizing transportation costs and balancing product availability. Specialty products, such as asphalt and petrochemicals, are also exported to customers in the U.S.

Suncor holds a 51% interest in ParaChem Chemicals L.P. (ParaChem), which owns and operates a petrochemicals plant located adjacent to the Montreal refinery. Feedstock for the plant includes xylene and toluene produced by the Montreal and Sarnia refineries. The plant primarily produces paraxylene, which is used by customers to manufacture polyester textiles and plastic bottles. Paraxylene production was approximately 355,000 metric tonnes in 2013 (2012 – 362,000 metric tonnes). ParaChem also produces benzene, hydrogen and heavy aromatics. Benzene production is delivered back to the Montreal refinery to be marketed with production from that facility.

Suncor's lubricants plant produces specialty lubricants and waxes that are marketed in Canada and internationally. The facility is the largest producer of lubricant base stocks in Canada. In 2013, the plant produced approximately 804 million litres of lubricant base stocks. Feedstock for the lubricants facility comes from Suncor's Montreal refinery and other purchase contracts.

SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014    23


Western North America

Effective January 1, 2014, Suncor increased the nameplate capacity of the Edmonton refinery to 142 mbbls/d from 140 mbbls/d, due to demonstrated reliability and continuous improvement in operating efficiency. The Edmonton refinery has the potential to run entirely on feedstock sourced from oil sands and heavy crude oil from Alberta. Crude oil is supplied to the refinery via company-owned and third-party pipelines.

Feedstock is supplied from Suncor's Oil Sands Operations, Syncrude operations (including volumes purchased by Suncor from other co-owners' share of production) and other producers from the Athabasca and Cold Lake regions of Alberta. The refinery can process approximately 41 mbbls/d of blended feedstock (comprised of 29 mbbls/d of bitumen and 12 mbbls/d of diluent) and process approximately 44 mbbls/d of sour SCO. The refinery can also process approximately 57 mbbls/d of sweet SCO through its synthetic train.

Production yield from the Edmonton refinery includes primarily gasoline and distillate, which are delivered to distribution terminals across Western Canada via the Alberta Products Pipeline, the TransMountain Pipeline and the Enbridge pipeline system, as well as via truck and rail.

The Commerce City refinery has a crude oil capacity of 98 mbbls/d. The refinery processes primarily conventional crude oil, but also has the capability of processing up to 15 mbbls/d of sour SCO from Suncor's Oil Sands Base operations. A majority of crude feedstock is supplied from sources in the U.S., primarily the Rocky Mountain region, while the remainder is purchased from Canadian sources. Crude oil purchase contracts have terms ranging from month-to-month to multi-year. Approximately 58% of crude oil supplied to the refinery is transported via pipeline, with the remainder transported via truck.

Production yield from the Commerce City refinery includes primarily gasoline, distillate and asphalt. The majority of the refined products are sold to commercial and wholesale customers in Colorado and Wyoming, and a retail network in Colorado. Refined products are distributed by truck, rail, and pipeline.

To support the supply and demand balance in the Vancouver area, Suncor imports and exports finished products through its Burrard distribution terminal located on the west coast of B.C. Suncor also enters into reciprocal exchange arrangements with other refiners in Western North America as a means of minimizing transportation costs and balancing product availability.

Refinery Throughputs, Utilizations and Yields

The following tables summarize the crude feedstock, utilizations and production yield mix for Suncor's refineries for the years ended December 31, 2013 and 2012. Refinery utilizations include the impacts of planned and unplanned maintenance events.

Average Daily Crude Throughput           Montreal           Sarnia           Edmonton           Commerce City  
(mbbls/d, except as noted)   2013   2012   2013   2012   2013   2012   2013   2012  
Oil Sands Base sweet synthetic   —   —   28.0   14.5   45.5   47.6   —   0.2  
Oil Sands Base sour synthetic   —   —   11.3   22.7   59.3   49.9   8.0   8.3  
Other synthetic   —   —   11.6   8.3   23.6   39.2   8.9   —  
East Coast Canada light conventional(1)   14.6   21.6   —   —   —   —   —   —  
Other light conventional   94.2   84.8   24.8   0.8   0.5   0.6   72.1   60.2  
Sour conventional   0.2   4.7   —   22.2   —   —   11.3   —  
Heavy conventional   16.7   18.0   —   —   —   0.6   —   27.0  
Total   125.7   129.1   75.7   68.5   128.9   137.9   100.3   95.7  
Utilization(2) (%)   92   94   89   81   92   102   102   98  
(1)
Includes purchases of Suncor and third-party shares of production from East Coast Canada oilfields.

(2)
Refinery utilizations based on crude 2013 processing capacities (in mbbls/d): Montreal – 137; Sarnia – 85; Edmonton – 140; and Commerce City – 98.
 
Refined Petroleum Production Yield Mix           Montreal           Sarnia           Edmonton           Commerce City  
(%)   2013   2012   2013   2012   2013   2012   2013   2012  
Gasoline   41   41   39   39   43   43   49   47  
Distillates   37   35   46   46   52   52   35   34  
Other   22   24   15   15   5   5   16   19  

24   SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014

Distribution Terminals and Pipelines

Suncor owns and operates 13 major refined product terminals across Canada (including terminals adjacent to refineries) and two product terminals in Colorado. Combined with access to facilities under long-term contractual arrangements with other parties, Suncor's North American assets are sufficient to meet the Refining and Marketing segment's current storage and distribution needs.

Suncor has ownership interests in the following pipelines:

Pipeline   Ownership   Type   Origin   Destinations  
Portland-Montreal Pipeline   23.8%   Crude oil   Portland, Maine   Montreal, Quebec  
Trans-Northern Pipeline   33.3%   Refined product   Montreal, Quebec   Ontario – Ottawa, Toronto & Oakville  
Sun-Canadian Pipeline   55.0%   Refined product   Sarnia, Ontario   Ontario – Toronto, London & Hamilton  
Alberta Products Pipeline   35.0%   Refined product   Edmonton, Alberta   Calgary, Alberta  
Rocky Mountain Crude Pipeline   100.0%   Crude oil   Guernsey, Wyoming   Denver, Colorado  
Centennial Pipeline   100.0%   Crude oil   Guernsey, Wyoming   Cheyenne, Wyoming  

Operations – Marketing

Suncor's retail service station network operates nationally in Canada primarily under the Petro-CanadaTM brand. As at December 31, 2013, this retail service station network consisted of 1,454 outlets across Canada. In addition to marketing through proprietary retail outlets, refined products are marketed through independent dealers and joint arrangements. Suncor's Canadian retail network had annual sales of gasoline motor fuels averaging approximately 4.8 million litres per site in 2013 (2012 – 4.8 million litres per site) and attracted an estimated 18% share (2012 – 17% share) of the national retail market.

Suncor's Colorado retail network consists of 44 owned outlets and product supply agreements with a larger network of Shell®-branded sites and Phillips 66®-branded sites in Colorado.

Marketing activities also generate non-petroleum revenues from convenience stores and car washes.

Suncor's wholesale operations sell refined products into farm, home heating, paving, small industrial, commercial and truck markets. Through its PETRO-PASS network, Suncor is a national marketer to the commercial road transport segment in Canada. Suncor also sells large volumes of refined products directly to large industrial and commercial customers and independent marketers.

Retail Summary:

    As at December 31  
Locations   2013   2012  
Retail Service Stations – Canada          
  Petro-CanadaTM-branded   1 454   1 458  
  SunocoTM-branded   7   7  
    1 461   1 465  
Retail Service Stations – Colorado          
  Shell®-branded retail service stations   38   38  
  Phillips 66®-branded retail service stations   6   6  
    44   44  
Wholesale Cardlock Sites – Canada          
  Petro-CanadaTM-branded cardlock sites (PETRO-PASS)   259   246  

SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014    25

 
    2013
   2012
Sales Volumes   thousands
of m3/d		   % operating
revenues		   thousands
of m3/d		   % operating
revenues		  
Gasoline (includes motor and aviation gasoline)                  
  Eastern North America   18.4       19.8      
  Western North America   20.9       20.4      
    39.3   46   40.2   47  
Distillates (includes diesel and heating oils, and aviation jet fuels)                  
  Eastern North America   14.2       12.0      
  Western North America   19.2       19.0      
    33.4   40   31.0   39  
Other (includes heavy fuel oil, asphalts, lubricants, petrochemicals, other)                  
  Eastern North America   9.1       9.8      
  Western North America   4.5       4.6      
    13.6   14   14.4   14  
    86.3       85.6      

Sales volumes for specific products are moderately impacted by seasonal cycles: gasoline sales are typically higher during the summer driving season; heating oil sales are typically higher during the winter season; diesel sales are typically higher during the drilling season at the beginning of the year in Western Canada, and during agricultural planting and harvest seasons in early spring and late summer, respectively; and asphalt sales are typically higher during the construction paving period. Suncor has the flexibility to modify refinery inputs and outputs to match production yields with anticipated product demands.

Sales volumes can also be impacted when refineries undergo planned maintenance events, which reduce production. Suncor is able to partially mitigate this impact through its integrated facilities: the Edmonton refinery and Oil Sands Base upgrading facilities, and the Sarnia and Montreal refineries. In addition, Suncor may purchase refined products from third-party suppliers.

Other Suncor Businesses

Energy Trading

Suncor's Energy Trading business is organized around five main commodity groups – crude oil, natural gas, sulphur, petroleum coke and electricity. Energy Trading provides commodity supply, transportation and pricing solutions. Our customers include mid-to large-sized commercial and industrial consumers, utility companies and energy producers.

The Energy Trading business supports the company's Oil Sands production by 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. The Energy Trading business has entered into arrangements for other midstream infrastructure, such as pipeline, storage capacity and rail access, to optimize delivery of existing and future growth production, while generating trading earnings on select strategies and opportunities.

In the fourth quarter of 2013, following the completion of a rail offloading facility in Montreal, the Energy Trading business commenced rail shipments of non-proprietary crude to the Montreal refinery. This enabled the Montreal refinery to take advantage of the price differentials between inland and global crudes. A second rail offloading facility is planned for Tracy, Québec. It is envisioned that this will enable access to eastern tide waters for Oil Sands product and could commence as early as the second quarter of 2014.

Renewable Energy

Since 2006, Suncor has invested in Canada's emerging biofuels industry. Suncor operates Canada's largest ethanol facility, the St. Clair Ethanol plant in the Sarnia-Lambton region of Ontario. The ethanol plant has a production capacity of 400 million litres per year. In 2013, the plant produced 415.0 million litres of ethanol (2012 – 412.5 million litres).

26   SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014

In addition, Suncor's renewable energy interests include six wind power projects in operation. Suncor's wind farms have a gross generating capacity of 255 MW and avoid carbon dioxide (CO2) equivalent emissions of approximately 395,000 tonnes each year, compared with traditional power generation sources. Suncor continues to evaluate new opportunities to build its renewable energy portfolio with potential wind power project sites that are in various stages of the evaluation process. In December 2013, the Adelaide project received regulatory approval and construction is expected to commence in the second quarter of 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's operating wind power projects:

Wind Power Projects       Ownership
Interest (%)		   Size (MW)   Turbines   Commissioned  
Operated by Suncor                      
  Wintering Hills   Drumheller, Alberta   70.0   88   55   2011  
  Kent Breeze   Thamesville, Ontario   100.0   20   8   2011  
Non-operated                      
  Ripley   Ripley, Ontario   50.0   76   38   2007  
  Chin Chute   Taber, Alberta   33.3   30   20   2006  
  Magrath   Magrath, Alberta   33.3   30   20   2004  
  SunBridge   Gull Lake, Saskatchewan   50.0   11   17   2002  

SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014    27

SUNCOR EMPLOYEES

The following table shows the distribution of employees among Suncor's business units and corporate office.

As of December 31   2013   2012  
Oil Sands   6 310   6 015  
Exploration and Production   479   719  
Refining and Marketing   3 265   3 175  
Corporate, Energy Trading and Renewable Energy   3 892   4 023  
Total   13 946   13 932  

Corporate includes employees from our Major Projects group, which supports the business units. In addition to our employees, the company also uses independent contractors to supply a range of services.

Approximately 35% of the company's employees were covered by collective agreements at the end of 2013. Unifor, a new union created by the merger of the Communications, Energy and Paperworkers Union and the Canadian Auto Workers Union, represented the majority of these employees. Three-year collective agreements with approximately 4,250 employees in the company's Oil Sands, In Situ, refinery, lubricants and terminal operations were negotiated in 2013. The collective agreement with Unifor covering approximately 60 employees on Terra Nova expired September 30, 2013 and a renewal is currently being negotiated. A second collective agreement with the Teamsters Union, covering approximately 30 employees for the company's British Columbia terminals and warehouses, expired January 31, 2014 and a renewal is currently being negotiated. Collective agreements with the United Steel Workers representing approximately 250 employees at the Commerce City refinery and with the Sunoco Employees' Bargaining Association representing approximately 200 employees at the Sarnia refinery, will expire January 31, 2015 and February 28, 2015, respectively.

28   SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014

SIGNIFICANT POLICIES

Suncor has a Standards of Business Conduct Code (the Code), which applies to Suncor's directors, officers, employees and contract workers. The Code requires strict compliance with legal requirements and sets Suncor's standards for the ethical conduct of our business. Topics addressed in the Code include competition, conflict of interest, the protection and proper use of corporate assets and opportunities, confidentiality, disclosure of material information, trading in shares and securities, communications to the public, improper payments, harassment, fair dealing in trade relations, and accounting, reporting and business controls. The Code is supported by detailed policy guidance and standards and a Code compliance program, under which every Suncor director, officer, employee and contract worker is required to annually read a summary of the Code and affirm that he or she has reviewed the summary, affirm that he or she understands the requirements of the Code, and provide confirmation of his or her compliance with the Code during the preceding year. Compliance is then reported to Suncor's Audit Committee.

Suncor has a Human Rights Policy, which affirms Suncor's responsibility to respect human rights and ensures that Suncor is not complicit in human rights abuses. Suncor is subject to the laws of the countries in which it operates and is committed to complying with all such laws while honouring international human rights principles, such as those described in the Universal Declaration of Human Rights and the Voluntary Principles on Security and Human Rights. The policy includes principles committed to a harassment-free and violence-free working environment, which respects the cultures, customs and values of the communities in which we operate. The policy makes it clear that the scope of Suncor's human rights due diligence includes its own operations and, where we can influence our third-party business relationships, the operations of others.

Suncor has a Stakeholder Relations Policy, which reflects Suncor's values. The policy provides that Suncor is committed to developing and maintaining positive, meaningful relationships with stakeholders in all of its operating areas and provides Suncor's principles for guiding the development of stakeholder relations (respect, responsibility, transparency, timeliness and mutual benefit). The policy makes it clear that successful stakeholder engagement fosters informed decision-making, resolving issues with timely, cost-effective and mutually beneficial solutions and supporting shared learning.

Suncor has an Aboriginal Affairs Policy, which affirms Suncor's desire to work in collaboration with Canada's Aboriginal Peoples to develop a thriving energy industry that allows Aboriginal communities to be vibrant, diversified and sustainable. The policy provides a consistent approach to the company's relationships with Canada's Aboriginal Peoples and outlines Suncor's responsibilities and commitments, and is intended to guide Suncor's business decisions on a day-to-day basis. Suncor is committed to working closely with Canada's Aboriginal Peoples and communities to build and maintain effective, long-term and mutually beneficial relationships. The policy makes it clear that responsible development takes into account Aboriginal issues and concerns about the effects, positive and negative, of energy development on communities and their traditional and current uses of lands and resources.

Suncor remains committed to reducing overall greenhouse gas (GHG) emissions intensity, in addition to other goals related to improving energy efficiency, reducing water use, increasing land reclamation and reducing air emissions. We actively work to mitigate our environmental impact, including taking action to reduce GHG emissions, investing in renewable forms of energy such as wind power and biofuels, accelerating land reclamation, installing new emissions abatement equipment, investing in technology research and development and pursuing other opportunities, both internally as well as through joint initiatives, such as our role in COSIA. The Environment, Health, Safety and Sustainable Development Committee of the Board of Directors meets quarterly to review Suncor's effectiveness in meeting its obligations pertaining to EH&S. The committee also reviews the effectiveness with which Suncor establishes appropriate EH&S policies, including environmental performance, given legal, industry and community standards. Management systems are maintained by this committee to implement such policies and ensure compliance.

Suncor has an Environment, Health and Safety (EH&S) policy, which affirms Suncor's aspirations to be a sustainable energy company by meeting or exceeding the environmental, social and economic expectations of our current and future stakeholders. The policy reflects Suncor's belief that our EH&S efforts are complementary and interdependent with our economic and social performance. The policy makes it clear that Suncor management is responsible for ensuring that employees under their direction are competent to manage their EH&S responsibilities and are knowledgeable of the hazards and risks associated with their jobs, and that all Suncor employees and contractors are accountable for compliance with relevant acts, codes, regulations, standards and procedures, and for their own personal safety and the safety of their co-workers. To support and highlight the goals of the EH&S policy, Suncor holds an Annual President's Operational Excellence Awards, which honour employees and contractors who demonstrate an exceptional commitment to health and safety. The awards ceremony highlights progress on safety initiatives and provides educational opportunities for all employees.

SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014    29

The aforementioned policies are reviewed annually and are available on the company's intranet and external website. Additional workshops and training sessions are also conducted as warranted throughout the year. In addition, information regarding the policies is provided for employees primarily though feature articles on the company's intranet or employee newsletter. The Aboriginal Affairs Policy has Cree and Dene audio translations. Regular training is provided for employees and contract workers whose roles require interaction with the respective stakeholder group.

30   SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014

STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION

Date of Statement

The Statement of Reserves Data and Other Oil and Gas Information outlined below is dated February 28, 2014, with an effective date of December 31, 2013. The preparation date of the information is as of February 21, 2014.

Disclosure of Reserves Data

As a Canadian issuer, Suncor is subject to the reporting requirements of Canadian securities regulatory authorities, including the reporting of our reserves data in accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (NI 51-101).

The reserves data set forth in this section of the AIF for Suncor's Mining and In Situ operations is based upon evaluations conducted by GLJ Petroleum Consultants Ltd. (GLJ) with an effective date of December 31, 2013, contained in their reports (the GLJ Reports). The reserves data set forth below for all other reserves, which includes Suncor's interests in its conventional assets offshore Newfoundland and Labrador (East Coast Canada), conventional assets offshore the U.K. (North Sea), conventional assets in Libya (Other International), and its natural gas and tight oil assets primarily located in Western Canada (North America Onshore), is based upon evaluations conducted by Sproule Associates Limited or Sproule International Limited (collectively, Sproule) with an effective date of December 31, 2013, contained in their reports (the Sproule Reports). Each of GLJ and Sproule (collectively, the Evaluators) are independent qualified reserves evaluators as defined in NI 51-101. All factual data supplied to the Evaluators was accepted as presented.

The reserves data summarizes Suncor's SCO, bitumen, light and medium oil, natural gas and NGL reserves and the net present values of future net revenues for these reserves using forecast prices and costs (unless otherwise indicated) prior to provision for interest, general and administrative expense, and certain abandonment and reclamation costs. Future net revenues are presented on before-tax and after-tax bases.

Advisories – Future Net Revenues

It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. There is no guarantee that the estimates for SCO, bitumen, light and medium oil, natural gas and NGL reserves provided herein will be recovered. Actual SCO, bitumen, light and medium oil, natural gas and NGL reserves may be greater than or less than the estimates provided herein. Readers should review the definitions and information contained in the Notes to Reserves Data Tables, Definitions for Reserves Data Tables and Notes to Future Net Revenues Tables discussion in conjunction with the following notes and tables.

Significant Factors or Uncertainties Affecting Reserves Data

The evaluation of reserves is a continuous process, one that can be significantly impacted by a variety of internal and external influences. Revisions are often required as a result of newly acquired technical data, technology improvements, or changes in historical performance, pricing, economic conditions, market availability and regulatory requirements. Additional technical information regarding geology, reservoir properties and reservoir fluid properties are obtained through seismic programs, drilling programs, updated reservoir performance studies and analysis, and production history, and may result in revisions to reserves. Pricing, market availability and economic conditions affect the profitability of reserves exploitation. Depending on the current business environment, higher commodity prices may result in higher reserves by making more projects economically viable or extending their economic life, while lower commodity prices may result in lower reserves, although this generally does not result for assets under PSCs. Regulatory changes, including royalty regimes and environmental regulations, cannot be predicted but may have positive or negative effects on reserves. Future technology improvements would be expected to have a favourable impact on the economics of reserves development and exploitation, and therefore result in an increase to reserves.

While the above factors, and many others, can be considered, certain judgments and assumptions are always required. As new information becomes available, these areas are reviewed and revised accordingly.

For more information as to the risks involved when estimating reserves and resources, see the Risk Factors – Uncertainty of Reserves and Resources Estimates section in this AIF.

SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014    31

Oil and Gas Reserves Tables and Notes

Summary of Oil and Gas Reserves(1)(2)(3)
as at December 31, 2013
(forecast prices and costs)

    SCO(4)   Bitumen   Light &
Medium Oil		   Natural Gas(5)   NGLs   Total  

 
 
(mmbbls)
 
(mmbbls)
 
(mmbbls)
 
(bcf)
 
(mmbbls)
 
(mmboe)
 

 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Proved Developed Producing                                                  
  Mining   1 863   1 670   —   —   —   —   —   —   —   —   1 863   1 670  
  In Situ   151   143   167   152   —   —   —   —   —   —   318   295  
  East Coast Canada   —   —   —   —   41   30   —   —   —   —   41   30  
  North America Onshore   —   —   —   —   2   1   42   35   1   1   10   8  
Total Canada   2 014   1 812   167   152   43   32   42   35   1   1   2 232   2 003  
North Sea   —   —   —   —   79   79   2   2   —   —   79   79  
Other International   —   —   —   —   —   —   —   —   —   —   —   —  
Total Proved Developed Producing   2 014   1 812   167   152   121   110   45   38   1   1   2 311   2 082  
Proved Developed Non-Producing                                                  
  Mining   —   —   —   —   —   —   —   —   —   —   —   —  
  In Situ   —   —   —   —   —   —   —   —   —   —   —   —  
  East Coast Canada   —   —   —   —   —   —   —   —   —   —   —   —  
  North America Onshore   —   —   —   —   —   —   3   3   —   —   1   1  
Total Canada   —   —   —   —   —   —   3   3   —   —   1   1  
North Sea   —   —   —   —   4   4   —   —   —   —   4   4  
Other International   —   —   —   —   149   54   —   —   —   —   149   54  
Total Proved Developed Non-Producing   —   —   —   —   152   58   4   4   —   —   153   58  
Proved Undeveloped                                                  
  Mining   —   —   845   764   —   —   —   —   —   —   845   764  
  In Situ   564   497   875   749   —   —   —   —   —   —   1 439   1 245  
  East Coast Canada   —   —   —   —   26   18   —   —   —   —   26   18  
  North America Onshore   —   —   —   —   2   1   4   4   —   —   2   2  
Total Canada   564   497   1 720   1 512   27   20   4   4   —   —   2 312   2 029  
North Sea   —   —   —   —   25   25   1   1   —   —   25   25  
Other International   —   —   —   —   3   1   —   —   —   —   3   1  
Total Proved Undeveloped   564   497   1 720   1 512   55   45   5   5   —   —   2 340   2 055  
Proved                                                  
  Mining   1 863   1 670   845   764   —   —   —   —   —   —   2 707   2 433  
  In Situ   715   639   1 043   901   —   —   —   —   —   —   1 758   1 540  
  East Coast Canada   —   —   —   —   67   48   —   —   —   —   67   48  
  North America Onshore   —   —   —   —   3   3   50   42   1   1   13   11  
Total Canada   2 578   2 309   1 887   1 665   70   51   50   42   1   1   4 544   4 033  
North Sea   —   —   —   —   107   107   4   4   —   —   108   108  
Other International   —   —   —   —   151   55   —   —   —   —   151   55  
Total Proved   2 578   2 309   1 887   1 665   329   213   54   46   1   1   4 804   4 195  
Probable                                                  
  Mining   520   459   397   339   —   —   —   —   —   —   916   798  
  In Situ   1 092   901   457   355   —   —   —   —   —   —   1 550   1 256  
  East Coast Canada   —   —   —   —   279   215   —   —   —   —   279   215  
  North America Onshore   —   —   —   —   2   2   36   31   1   1   9   7  
Total Canada   1 612   1 360   854   694   281   217   36   31   1   1   2 754   2 277  
North Sea   —   —   —   —   36   36   2   2   —   —   37   37  
Other International   —   —   —   —   112   40   —   —   —   —   112   40  
Total Probable   1 612   1 360   854   694   429   293   39   33   1   1   2 902   2 354  
Proved Plus Probable                                                  
  Mining   2 382   2 129   1 241   1 103   —   —   —   —   —   —   3 624   3 232  
  In Situ   1 807   1 541   1 500   1 256   —   —   —   —   —   —   3 307   2 797  
  East Coast Canada   —   —   —   —   346   263   —   —   —   —   346   263  
  North America Onshore   —   —   —   —   5   4   86   73   2   2   21   18  
Total Canada   4 189   3 669   2 741   2 359   351   268   86   73   2   2   7 298   6 310  
North Sea   —   —   —   —   144   144   7   7   —   —   145   145  
Other International   —   —   —   —   263   95   —   —   —   —   263   95  
Total Proved Plus Probable   4 189   3 669   2 741   2 359   758   506   92   80   2   2   7 706   6 549  

Please see Notes (1) through (5) at the end of the reserves data section for important information about volumes in this table.

32   SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014

Summary of Oil and Gas Reserves(1)(2)(3)
as at December 31, 2013
(constant prices and costs)

    SCO(4)   Bitumen   Light &
Medium Oil		   Natural Gas(5)   NGLs   Total  

 
 
(mmbbls)
 
(mmbbls)
 
(mmbbls)
 
(bcf)
 
(mmbbls)
 
(mmboe)
 

 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Proved Developed Producing                                                  
  Mining   1 863   1 660   —   —   —   —   —   —   —   —   1 863   1 660  
  In Situ   151   144   167   153   —   —   —   —   —   —   318   297  
  East Coast Canada   —   —   —   —   41   30   —   —   —   —   41   30  
  North America Onshore   —   —   —   —   2   1   36   32   1   1   8   7  
Total Canada   2 014   1 804   167   153   43   31   36   32   1   1   2 231   1 995  
North Sea   —   —   —   —   79   79   2   2   —   —   80   80  
Other International   —   —   —   —   —   —   —   —   —   —   —   —  
Total Proved Developed Producing   2 014   1 804   167   153   122   111   39   34   1   1   2 311   2 075  
Proved Developed Non-Producing                                                  
  Mining   —   —   —   —   —   —   —   —   —   —   —   —  
  In Situ   —   —   —   —   —   —   —   —   —   —   —   —  
  East Coast Canada   —   —   —   —   —   —   —   —   —   —   —   —  
  North America Onshore   —   —   —   —   —   —   3   3   —   —   1   1  
Total Canada   —   —   —   —   —   —   3   3   —   —   1   1  
North Sea   —   —   —   —   4   4   —   —   —   —   4   4  
Other International   —   —   —   —   150   55   —   —   —   —   150   55  
Total Proved Developed Non-Producing   —   —   —   —   154   59   4   4   —   —   155   60  
Proved Undeveloped                                                  
  Mining   —   —   845   790   —   —   —   —   —   —   845   790  
  In Situ   564   516   876   776   —   —   —   —   —   —   1 439   1 292  
  East Coast Canada   —   —   —   —   26   18   —   —   —   —   26   18  
  North America Onshore   —   —   —   —   2   2   5   4   —   —   3   3  
Total Canada   564   516   1 720   1 566   28   20   5   4   —   —   2 312   2 102  
North Sea   —   —   —   —   25   25   1   1   —   —   26   26  
Other International   —   —   —   —   3   1   —   —   —   —   3   1  
Total Proved Undeveloped   564   516   1 720   1 566   56   46   6   6   —   —   2 340   2 129  
Proved                                                  
  Mining   1 863   1 660   845   790   —   —   —   —   —   —   2 707   2 450  
  In Situ   715   660   1 043   929   —   —   —   —   —   —   1 758   1 590  
  East Coast Canada   —   —   —   —   67   47   —   —   —   —   67   47  
  North America Onshore   —   —   —   —   4   3   44   39   1   1   12   11  
Total Canada   2 577   2 321   1 888   1 719   70   51   44   39   1   1   4 544   4 098  
North Sea   —   —   —   —   108   108   4   4   —   —   109   109  
Other International   —   —   —   —   153   56   —   —   —   —   153   56  
Total Proved   2 577   2 321   1 888   1 719   332   215   48   44   1   1   4 806   4 263  
Probable                                                  
  Mining   520   462   397   344   —   —   —   —   —   —   916   806  
  In Situ   1 092   891   457   388   —   —   —   —   —   —   1 550   1 279  
  East Coast Canada   —   —   —   —   279   211   —   —   —   —   279   211  
  North America Onshore   —   —   —   —   2   2   32   30   1   1   8   8  
Total Canada   1 612   1 353   854   732   281   213   32   30   1   1   2 753   2 303  
North Sea   —   —   —   —   36   36   2   2   —   —   36   36  
Other International   —   —   —   —   110   33   —   —   —   —   110   33  
Total Probable   1 612   1 353   854   732   427   282   34   33   1   1   2 900   2 372  
Proved Plus Probable                                                  
  Mining   2 382   2 122   1 241   1 133   —   —   —   —   —   —   3 624   3 255  
  In Situ   1 807   1 551   1 500   1 318   —   —   —   —   —   —   3 307   2 869  
  East Coast Canada   —   —   —   —   346   258   —   —   —   —   346   258  
  North America Onshore   —   —   —   —   6   5   76   70   2   1   20   18  
Total Canada   4 189   3 673   2 742   2 451   352   264   76   70   2   1   7 297   6 401  
North Sea   —   —   —   —   144   144   7   7   —   —   146   145  
Other International   —   —   —   —   263   89   —   —   —   —   263   89  
Total Proved Plus Probable   4 189   3 673   2 742   2 451   759   497   83   76   2   1   7 705   6 635  

Please see Notes (1) through (5) at the end of the reserves data section for important information about volumes in this table.

SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014    33

Reconciliation of Gross Oil Reserves(1)(2)(3)
as at December 31, 2013
(forecast prices and costs)

    SCO(4)
   Bitumen
   Light & Medium Oil
    Proved   Probable   Proved
Plus
Probable		   Proved   Probable   Proved
Plus
Probable		   Proved   Probable   Proved
Plus
Probable		    
   
    mmbbls   mmbbls   mmbbls   mmbbls   mmbbls   mmbbls   mmbbls   mmbbls   mmbbls    
December 31, 2012                                        
  Mining   1 958   539   2 497   —   —   —   —   —   —    
  In Situ   665   1 060   1 725   964   695   1 659   —   —   —    
  East Coast Canada   —   —   —   —   —   —   76   268   344    
  North America Onshore   —   —   —   —   —   —   11   4   15    
Total Canada   2 623   1 599   4 222   964   695   1 659   87   272   359    
North Sea   —   —   —   —   —   —   124   43   167    
Other International   —   —   —   —   —   —   151   117   268    
Total   2 623   1 599   4 222   964   695   1 659   362   432   794    
Extensions & Improved Recovery(6)                                        
  Mining   —   —   —   845   397   1 241   —   —   —    
  In Situ   76   (66 ) 10   74   (69 ) 5   —   —   —    
  East Coast Canada   —   —   —   —   —   —   —   21   21    
  North America Onshore   —   —   —   —   —   —   2   1   3    
Total Canada   76   (66 ) 10   919   327   1 246   2   22   24    
North Sea   —   —   —   —   —   —   —   —   —    
Other International   —   —   —   —   —   —   —   1   1    
Total   76   (66 ) 10   919   327   1 246   3   22   25    
Technical Revisions(7)                                        
  Mining   (7 ) (19 ) (26 ) —   —   —   —   —   —    
  In Situ   4   98   102   30   (168 ) (139 ) —   —   —    
  East Coast Canada   —   —   —   —   —   —   11   (10 ) 1    
  North America Onshore   —   —   —   —   —   —   1   —   —    
Total Canada   (2 ) 79   76   30   (168 ) (139 ) 12   (10 ) 1    
North Sea   —   —   —   —   —   —   3   (7 ) (3 )  
Other International   —   —   —   —   —   —   8   (6 ) 2    
Total   (2 ) 79   76   30   (168 ) (139 ) 23   (23 ) —    
Discoveries(8)                                        
  Mining   —   —   —   —   —   —   —   —   —    
  In Situ   —   —   —   —   —   —   —   —   —    
  East Coast Canada   —   —   —   —   —   —   —   —   —    
  North America Onshore   —   —   —   —   —   —   —   —   —    
Total Canada   —   —   —   —   —   —   —   —   —    
North Sea   —   —   —   —   —   —   —   —   —    
Other International   —   —   —   —   —   —   —   —   —    
Total   —   —   —   —   —   —   —   —   —    

Please see Notes (1) through (8) at the end of the reserves data section for important information about volumes in this table.

34   SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014

Reconciliation of Gross Oil Reserves(1)(2)(3) (continued)
as at December 31, 2013
(forecast prices and costs)

    SCO(4)
   Bitumen
   Light & Medium Oil
    Proved   Probable   Proved
Plus
Probable		   Proved   Probable   Proved
Plus
Probable		   Proved   Probable   Proved
Plus
Probable		    
   
    mmbbls   mmbbls   mmbbls   mmbbls   mmbbls   mmbbls   mmbbls   mmbbls   mmbbls    
Acquisitions                                        
  Mining   —   —   —   —   —   —   —   —   —    
  In Situ   —   —   —   —   —   —   —   —   —    
  East Coast Canada   —   —   —   —   —   —   —   —   —    
  North America Onshore   —   —   —   —   —   —   —   —   —    
Total Canada   —   —   —   —   —   —   —   —   —    
North Sea   —   —   —   —   —   —   —   —   —    
Other International   —   —   —   —   —   —   —   —   —    
Total   —   —   —   —   —   —   —   —   —    
Dispositions                                        
  Mining   —   —   —   —   —   —   —   —   —    
  In Situ   —   —   —   —   —   —   —   —   —    
  East Coast Canada   —   —   —   —   —   —   —   —   —    
  North America Onshore   —   —   —   —   —   —   (10 ) (2 ) (12 )  
Total Canada   —   —   —   —   —   —   (10 ) (2 ) (12 )  
North Sea   —   —   —   —   —   —   —   —   —    
Other International   —   —   —   —   —   —   —   —   —    
Total   —   —   —   —   —   —   (10 ) (2 ) (12 )  
Economic Factors (9)                                        
  Mining   —   —   —   —   —   —   —   —   —    
  In Situ   —   —   —   —   —   —   —   —   —    
  East Coast Canada   —   —   —   —   —   —   —   —   —    
  North America Onshore   —   —   —   —   —   —   —   —   —    
Total Canada   —   —   —   —   —   —   —   —   —    
North Sea   —   —   —   —   —   —   —   —   —    
Other International   —   —   —   —   —   —   —   —   —    
Total   —   —   —   —   —   —   —   —   —    
Production                                        
  Mining   (89 ) —   (89 ) —   —   —   —   —   —    
  In Situ   (30 ) —   (30 ) (25 ) —   (25 ) —   —   —    
  East Coast Canada   —   —   —   —   —   —   (21 ) —   (21 )  
  North America Onshore   —   —   —   —   —   —   (1 ) —   (1 )  
Total Canada   (119 ) —   (119 ) (25 ) —   (25 ) (22 ) —   (22 )  
North Sea   —   —   —   —   —   —   (20 ) —   (20 )  
Other International   —   —   —   —   —   —   (8 ) —   (8 )  
Total   (119 ) —   (119 ) (25 ) —   (25 ) (49 ) —   (49 )  
December 31, 2013                                        
  Mining   1 863   520   2 382   845   397   1 241   —   —   —    
  In Situ   715   1 092   1 807   1 043   457   1 500   —   —   —    
  East Coast Canada   —   —   —   —   —   —   67   279   346    
  North America Onshore   —   —   —   —   —   —   3   2   5    
Total Canada   2 577   1 612   4 189   1 887   854   2 741   70   281   351    
North Sea   —   —   —   —   —   —   107   36   144    
Other International   —   —   —   —   —   —   151   112   263    
Total   2 577   1 612   4 189   1 887   854   2 741   329   429   758    

Please see Notes (1) through (9) at the end of the reserves data section for important information about volumes in this table.

SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014    35

Reconciliation of Natural Gas and NGL Reserves(1)(2)
as at December 31, 2013
(forecast prices and costs)

    Natural Gas(5)
   NGLs
    Proved   Probable   Proved
Plus
Probable		   Proved   Probable   Proved
Plus
Probable		    
   
    bcf   bcf   bcf   mmbbls   mmbbls   mmbbls    
December 31, 2012                            
Canada – North America Onshore   854   265   1 119   8   3   10    
North Sea   5   4   9   —   —   —    
Total   859   268   1 128   8   3   11    
Extensions & Improved Recovery(6)                            
Canada – North America Onshore   6   13   19   —   —   1    
North Sea   —   —   —   —   —   —    
Total   6   13   19   —   —   1    
Technical Revisions(7)                            
Canada – North America Onshore   6   (2 ) 4   —   —   —    
North Sea   2   (1 ) —   —   —   —    
Total   8   (3 ) 4   —   —   —    
Discoveries(8)                            
Canada – North America Onshore   —   —   —   —   —   —    
North Sea   —   —   —   —   —   —    
Total   —   —   —   —   —   —    
Acquisitions                            
Canada – North America Onshore   —   —   —   —   —   —    
North Sea   —   —   —   —   —   —    
Total   —   —   —   —   —   —    
Dispositions                            
Canada – North America Onshore   (748 ) (244 ) (992 ) (6 ) (2 ) (9 )  
North Sea   —   —   —   —   —   —    
Total   (748 ) (244 ) (992 ) (6 ) (2 ) (9 )  
Economic Factors(9)                            
Canada – North America Onshore   —   4   5   —   —   —    
North Sea   —   —   —   —   —   —    
Total   —   4   5   —   —   —    
Production                            
Canada – North America Onshore   (69 ) —   (69 ) (1 ) —   (1 )  
North Sea   (3 ) —   (3 ) —   —   —    
Total   (72 ) —   (72 ) (1 ) —   (1 )  
December 31, 2013                            
Canada – North America Onshore   50   36   86   1   1   2    
North Sea   4   2   7   —   —   —    
Total   54   39   92   1   1   2    

Please see Notes (1) through (9) at the end of the reserves data section for important information about volumes in this table.

36   SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014

Notes to Reserves Data Tables
as at December 31, 2013

(1)
See the Notes to Future Net Revenues Tables discussion for information on forecast and constant prices and costs.

(2)
Reserves data tables may not add due to rounding.

(3)
Other International includes quantities of crude oil in Libya, which are expected to be produced under EPSAs. Under these EPSAs, net proved and probable reserves have been determined using the economic interest method. See the Definitions for Reserves Data Tables.

(4)
SCO reserves figures include the company's diesel sales volumes.

(5)
Includes associated and non-associated gas (combined).

(6)
Extensions and Improved Recovery are additions to the reserves resulting from step-out drilling, infill drilling and implementation of improved recovery schemes. Negative volumes for probable reserves result from the initial recognition of proved reserves for reserves previously assigned as probable reserves.

(7)
Technical Revisions include changes in previous estimates resulting from new technical data or revised interpretations.

(8)
Discoveries are additions to reserves in reservoirs where no reserves were previously booked.

(9)
Economic Factors are changes due primarily to price forecasts, inflation rates or regulatory changes.

Definitions for Reserves Data Tables

In the tables set forth above and elsewhere in this AIF, the following definitions and other notes are applicable:

Gross means:

(a)
in relation to Suncor's interest in production, reserves and contingent resources, Suncor's working interest (operated and non-operated) share before deduction of royalties and without including any royalty interests of Suncor;

(b)
in relation to wells, the total number of wells in which Suncor has a working interest; and

(c)
in relation to properties, the total area of properties in which Suncor has an interest.

Net means:

(a)
in relation to Suncor's interest in production, reserves and contingent resources, Suncor's working interest (operated and non-operated) share after deduction of royalty obligations, plus the company's royalty interests in production, reserves or contingent resources;

(b)
in relation to wells, the number of wells obtained by aggregating Suncor's working interest in each of the company's gross wells; and

(c)
in relation to Suncor's interest in a property, the total area in which Suncor has an interest multiplied by the working interest owned by Suncor.

Reserves Categories

The oil, NGL and natural gas reserves estimates presented are based on the definitions and guidelines contained in the Canadian Oil and Gas Evaluation (COGE) Handbook. A summary of those definitions is set forth below.

Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on analyses of drilling, geological, geophysical and engineering data, the use of established technology, and specified economic conditions, which are generally accepted as being reasonable.

Reserves are classified according to the degree of certainty associated with the estimates:

Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

Other criteria that must also be met for the categorization of reserves are provided in the COGE Handbook.

Proved and probable reserves categories may be divided into developed and undeveloped categories:

Developed reserves are those reserves that are expected to be recovered (i) from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (for example, when compared to the cost of drilling a well) to put the reserves on production, or (ii) through installed extraction equipment and infrastructure that is operational at the time of the reserves estimate, if the extraction is by means not involving a well. The developed category may be subdivided into producing and non-producing.

(a)
Developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut in, they must have

SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014    37

(b)
Developed non-producing reserves are those reserves that either have not been on production, or have previously been on production but are shut in, and the date of resumption of production is unknown.

Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves category (proved or probable) to which they are assigned.

In multi-well pools, it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to subdivide the developed reserves for the pool between developed producing and developed non-producing. This allocation should be based on the evaluator's assessment as to the reserves that will be recovered from specific wells, facilities and completion intervals in the pool and their respective development and production status.

In the economic interest method used for PSCs, Suncor's share of profit revenue plus cost recovery revenue is divided by the associated oil or gas price forecast to determine Suncor's net volume entitlement, or entitlement reserves. The entitlement reserves are then adjusted to include reserves relating to income taxes payable by the national oil company on behalf of Suncor. Under this method, reported reserves will increase as commodity prices decrease (and vice versa), since the production barrels necessary to achieve cost recovery change with the prevailing commodity prices.

Levels of Certainty for Reported Reserves

The qualitative certainty levels referred to in the definitions above are applicable to individual reserves entities (which refers to the lowest level at which reserves calculations are performed) and to reported reserves (which refers to the highest level sum of individual entity estimates for which reserves are presented). Reported reserves should target the following levels of certainty under a specific set of economic conditions:

(a)
at least a 90% probability that the quantities actually recovered will equal or exceed the estimated proved reserves; and

(b)
at least a 50% probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves.

A quantitative measure of the certainty levels pertaining to estimates prepared for the various reserves categories provides a clearer understanding of the associated risks and uncertainties. However, the majority of reserves estimates are prepared using deterministic methods that do not provide a mathematically derived quantitative measure of probability. In principle, there should be no difference between estimates prepared using probabilistic or deterministic methods. Additional clarification of certainty levels associated with reserves estimates and the effect of aggregation is provided in the COGE Handbook.

38   SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014

Future Net Revenues Tables and Notes(1)

Net Present Value of Future Net Revenues Before Income Taxes
as at December 31, 2013
(forecast prices and costs)

    (in $ millions, discounted at % per year)   Unit Value    
   
 
    0%   5%   10%   15%   20%   ($/boe)    
Proved Developed Producing                            
  Mining   42 653   27 208   19 172   14 594   11 765   11.48    
  In Situ   8 800   7 600   6 673   5 939   5 347   22.62    
  East Coast Canada   1 718   1 648   1 565   1 485   1 413   51.82    
  North America Onshore   179   152   131   115   103   16.59    
Total Canada   53 350   36 609   27 541   22 133   18 628   13.75    
North Sea   6 077   5 131   4 456   3 958   3 577   56.30    
Other International   —   —   —   —   —   —    
Total Proved Developed Producing   59 427   41 740   31 997   26 091   22 206   15.37    
Proved Developed Non-Producing                            
  Mining   —   —   —   —   —   —    
  In Situ   —   —   —   —   —   —    
  East Coast Canada   —   —   —   —   —   —    
  North America Onshore   11   8   6   5   4   9.72    
Total Canada   11   8   6   5   4   9.72    
North Sea   301   246   210   184   165   54.00    
Other International   4 940   3 666   2 884   2 365   1 997   53.69    
Total Proved Developed Non-Producing   5 252   3 920   3 101   2 554   2 166   53.23    
Proved Undeveloped                            
  Mining   10 603   1 085   (1 751 ) (2 709 ) (3 036 ) (2.29 )  
  In Situ   30 387   13 972   7 064   3 814   2 127   5.67    
  East Coast Canada   1 127   920   781   681   606   43.30    
  North America Onshore   67   41   25   15   8   11.35    
Total Canada   42 184   16 018   6 119   1 801   (295 ) 3.02    
North Sea   1 596   1 272   1 023   829   675   40.78    
Other International   69   44   28   17   10   30.93    
Total Proved Undeveloped   43 849   17 334   7 170   2 647   390   3.49    
Proved                            
  Mining   53 256   28 293   17 421   11 885   8 729   7.16    
  In Situ   39 187   21 572   13 736   9 753   7 474   8.92    
  East Coast Canada   2 845   2 569   2 346   2 167   2 019   48.63    
  North America Onshore   257   201   162   135   115   15.12    
Total Canada   95 544   52 635   33 665   23 939   18 338   8.35    
North Sea   7 974   6 650   5 689   4 971   4 417   52.62    
Other International   5 009   3 710   2 912   2 382   2 007   53.31    
Total Proved   108 528   62 994   42 267   31 292   24 762   10.07    
Probable                            
  Mining   33 760   10 492   5 025   3 115   2 234   6.30    
  In Situ   64 266   16 632   6 407   3 463   2 314   5.10    
  East Coast Canada   15 373   9 020   5 829   4 013   2 885   27.11    
  North America Onshore   187   108   66   43   29   8.96    
Total Canada   113 587   36 252   17 327   10 634   7 461   7.61    
North Sea   3 441   2 424   1 811   1 416   1 146   49.14    
Other International   4 593   2 500   1 520   1 009   717   37.70    
Total Probable   121 620   41 176   20 658   13 059   9 324   8.78    
Proved Plus Probable                            
  Mining   87 016   38 785   22 446   15 000   10 963   6.95    
  In Situ   103 452   38 204   20 143   13 216   9 788   7.20    
  East Coast Canada   18 218   11 588   8 175   6 180   4 904   31.05    
  North America Onshore   444   309   228   178   144   12.61    
Total Canada   209 131   88 886   50 992   34 573   25 799   8.08    
North Sea   11 415   9 073   7 500   6 387   5 563   51.73    
Other International   9 602   6 210   4 433   3 391   2 724   46.68    
Total Proved Plus Probable   230 148   104 170   62 925   44 351   34 086   9.61    

Please see Notes (1) and (2) at the end of the Future Net Revenues tables for important information.

SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014    39

Net Present Value of Future Net Revenues After Income Taxes
as at December 31, 2013
(forecast prices and costs)

    (in $ millions, discounted at % per year)    
   
    0%   5%   10%   15%   20%    
Proved Developed Producing                        
  Mining   32 682   20 624   14 426   10 932   8 791    
  In Situ   7 360   6 349   5 571   4 957   4 464    
  East Coast Canada   1 414   1 361   1 292   1 225   1 164    
  North America Onshore   179   152   131   115   103    
Total Canada   41 635   28 487   21 420   17 229   14 521    
North Sea   1 891   1 602   1 391   1 235   1 116    
Other International   —   —   —   —   —    
Total Proved Developed Producing   43 526   30 088   22 811   18 464   15 638    
Proved Developed Non-Producing                        
  Mining   —   —   —   —   —    
  In Situ   —   —   —   —   —    
  East Coast Canada   —   —   —   —   —    
  North America Onshore   11   8   6   5   4    
Total Canada   11   8   6   5   4    
North Sea   114   96   84   75   68    
Other International   1 753   1 324   1 059   882   756    
Total Proved Developed Non-Producing   1 877   1 428   1 149   962   828    
Proved Undeveloped                        
  Mining   8 725   886   (1 461 ) (2 256 ) (2 528 )  
  In Situ   22 399   9 872   4 724   2 358   1 157    
  East Coast Canada   902   716   594   508   445    
  North America Onshore   67   41   25   15   8    
Total Canada   32 093   11 515   3 882   625   (917 )  
North Sea   611   498   409   337   278    
Other International   24   15   10   6   3    
Total Proved Undeveloped   32 728   12 028   4 300   968   (636 )  
Proved                        
  Mining   41 407   21 510   12 965   8 676   6 263    
  In Situ   29 759   16 221   10 295   7 315   5 621    
  East Coast Canada   2 316   2 077   1 886   1 733   1 609    
  North America Onshore   257   201   162   135   115    
Total Canada   73 739   40 009   25 308   17 859   13 608    
North Sea   2 615   2 196   1 883   1 646   1 463    
Other International   1 776   1 339   1 069   888   759    
Total Proved   78 131   43 544   28 260   20 394   15 830    
Probable                        
  Mining   25 171   7 700   3 631   2 228   1 589    
  In Situ   47 475   12 066   4 626   2 506   1 675    
  East Coast Canada   11 427   6 610   4 180   2 795   1 937    
  North America Onshore   187   108   66   43   29    
Total Canada   84 260   26 484   12 503   7 572   5 229    
North Sea   1 326   961   737   589   487    
Other International   1 607   888   547   368   265    
Total Probable   87 194   28 333   13 787   8 529   5 980    
Proved Plus Probable                        
  Mining   66 578   29 210   16 596   10 904   7 852    
  In Situ   77 234   28 287   14 921   9 822   7 296    
  East Coast Canada   13 743   8 687   6 065   4 528   3 546    
  North America Onshore   444   309   228   178   144    
Total Canada   158 000   66 493   37 810   25 431   18 837    
North Sea   3 942   3 157   2 620   2 235   1 949    
Other International   3 384   2 227   1 616   1 256   1 024    
Total Proved Plus Probable   165 325   71 878   42 046   28 923   21 810    

40   SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014

Total Future Net Revenues
as at December 31, 2013
(forecast prices and costs)

(in $ millions, undiscounted)   Revenue   Royalties   Operating
Costs		   Development
Costs		   Abandonment
Expenses		   Future Net
Revenues Before
Deducting
Future
Income Tax
Expenses		   Future
Income Tax
Expenses		   Future Net
Revenues After
Deducting
Future
Income Tax
Expenses		  
Proved Developed Producing                                  
  Mining   203 321   21 344   101 174   38 150   —   42 653   9 971   32 682  
  In Situ   25 287   1 704   11 741   2 852   190   8 800   1 440   7 360  
  East Coast Canada   4 550   1 227   1 077   157   371   1 718   303   1 414  
  North America Onshore   465   68   188   1   29   179   —   179  
Total Canada   233 623   24 343   114 180   41 160   590   53 350   11 714   41 635  
North Sea   8 823   —   2 373   223   149   6 077   4 187   1 891  
Other International   —   —   —   —   —   —   —   —  
Total Proved Developed Producing   242 446   24 343   116 553   41 383   739   59 427   15 901   43 526  
Proved Developed Non-Producing                                  
  Mining   —   —   —   —   —   —   —   —  
  In Situ   —   —   —   —   —   —   —   —  
  East Coast Canada   —   —   —   —   —   —   —   —  
  North America Onshore   24   1   9   3   1   10   —   10  
Total Canada   24   1   9   3   1   10   —   10  
North Sea   435   —   132   —   3   301   187   114  
Other International   6 105   —   772   371   22   4 940   3 188   1 753  
Total Proved Developed Non-Producing   6 565   1   913   374   26   5 252   3 374   1 877  
Proved Undeveloped                                  
  Mining   70 289   6 977   39 752   12 957   —   10 603   1 878   8 725  
  In Situ   134 949   18 567   53 411   31 817   766   30 387   7 988   22 399  
  East Coast Canada   2 835   831   527   317   33   1 127   225   902  
  North America Onshore   208   26   50   61   3   67   —   67  
Total Canada   208 280   26 401   93 740   45 152   803   42 184   10 091   32 093  
North Sea   2 720   —   518   561   45   1 596   985   611  
Other International   102   —   7   25   0   69   45   24  
Total Proved Undeveloped   211 102   26 401   94 265   45 738   849   43 849   11 121   32 728  
Proved                                  
  Mining   273 610   28 321   140 926   51 107   —   53 256   11 849   41 407  
  In Situ   160 236   20 271   65 152   34 669   956   39 187   9 428   29 759  
  East Coast Canada   7 385   2 058   1 604   474   405   2 845   528   2 316  
  North America Onshore   697   95   247   65   33   257   —   257  
Total Canada   441 927   50 745   207 929   86 316   1 394   95 544   21 805   73 739  
North Sea   11 978   —   3 023   784   197   7 974   5 359   2 615  
Other International   6 207   —   779   395   23   5 009   3 233   1 776  
Total Proved   460 113   50 745   211 732   87 495   1 613   108 528   30 397   78 131  
Probable                                  
  Mining   124 256   16 094   58 898   15 504   —   33 760   8 588   25 171  
  In Situ   227 832   40 307   79 246   43 319   694   64 266   16 791   47 475  
  East Coast Canada   30 811   7 108   4 214   3 916   201   15 373   3 947   11 427  
  North America Onshore   532   76   205   54   10   187   —   187  
Total Canada   383 432   63 585   142 563   62 792   905   113 587   29 325   84 260  
North Sea   4 205   —   676   65   24   3 441   2 115   1 326  
Other International   4 945   —   281   68   3   4 593   2 985   1 607  
Total Probable   392 583   63 585   143 520   62 925   932   121 620   34 425   87 194  
Proved Plus Probable                                  
  Mining   397 866   44 415   199 824   66 611   —   87 016   20 437   66 578  
  In Situ   388 068   60 578   144 399   77 988   1 650   103 452   26 218   77 234  
  East Coast Canada   38 196   9 165   5 818   4 390   606   18 218   4 475   13 743  
  North America Onshore   1 229   171   452   119   43   444   —   444  
Total Canada   825 359   114 330   350 492   149 108   2 299   209 131   51 130   158 000  
North Sea   16 184   —   3 699   849   221   11 415   7 473   3 942  
Other International   11 152   —   1 061   464   25   9 602   6 219   3 384  
Total Proved Plus Probable   852 695   114 330   355 252   150 420   2 545   230 148   64 822   165 325  

SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014    41

Future Net Revenues by Production Group
as at December 31, 2013
(forecast prices and costs)

(before income taxes, discounted at 10% per year)   $ millions   $/boe(3)  
Proved Developed Producing          
  Unconventional – Mining   19 172   11.48  
  Unconventional – In Situ   6 673   22.62  
Total Unconventional(4)   25 845   13.15  
Light & Medium Oil(5)   6 083   54.96  
Natural Gas(6)   69   10.50  
Total Proved Developed Producing   31 997   15.37  
Proved          
  Unconventional – Mining   17 421   7.16  
  Unconventional – In Situ   13 736   8.92  
Total Unconventional(4)   31 157   7.84  
Light & Medium Oil(5)   11 036   51.62  
Natural Gas(6)   74   9.27  
Total Proved   42 267   10.07  
Proved Plus Probable          
  Unconventional – Mining   22 446   6.95  
  Unconventional – In Situ   20 143   7.20  
Total Unconventional(4)   42 589   7.07  
Light & Medium Oil(5)   20 230   39.86  
Natural Gas(6)   106   7.73  
Total Proved Plus Probable   62 925   9.61  
(1)
Figures may not add due to rounding.

(2)
Unit values are future net revenues before deducting estimated cash income taxes payable, discounted at 10%, using net reserves.

(3)
Per unit values are based on the company's net reserves.

(4)
Total Unconventional includes SCO and bitumen.

(5)
Light & Medium Oil includes associated byproducts, including solution gas and NGLs.

(6)
Natural gas includes associated byproducts, including oil and NGLs.

42   SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014

Notes to Future Net Revenues Tables

In Situ Future Net Revenues

Future net revenues for In Situ properties reflect the flexibility of Suncor's operations which allows production from these properties to be either upgraded to SCO or sold as non-upgraded bitumen. The proportion of upgraded production is based on estimated available upgrading capacity and can vary depending on unplanned maintenance, fluctuations in production from mining and extraction operations, or changes in the company's overall Oil Sands development strategy, including with respect to planned upgrading capacity.

Future net revenues disclosed above include the estimated uplift to the future sales price and the associated upgrader operating and sustaining capital costs of upgrading approximately 35% of Firebag bitumen production to SCO, from 2014 to 2022, approximately 40% to 2033, and escalating thereafter. These factors translate to a $2.1 billion increase in future net revenues (total proved plus probable reserves, before tax, discounted at 10%) from In Situ production relative to the scenario where none of the bitumen is upgraded.

Revenues associated with excess power generated from our cogeneration facilities are included to the extent that all or a portion of a cogeneration unit is necessary for the operation of the In Situ property. All other revenue related to excess power generation is excluded from the evaluation for In Situ properties, as it does not represent revenues directly generated from oil and gas activities.

Prices Realized

For prices realized by Suncor during 2013, please see the Production History section contained within this Statement of Reserves Data and Other Oil and Gas Information.

Forecast Prices and Costs

Crude oil, natural gas and other important benchmark reference pricing, as well as inflation and exchange rates utilized in the GLJ Reports and the Sproule Reports, are as per GLJ's price forecast dated January 1, 2014, as set out below. To the extent that there are fixed or presently determinable future prices or costs to which Suncor is legally bound by contractual or other obligations to supply a physical product, including those for an extension period of a contract that is likely to be extended, those prices or costs have been incorporated into the forecast prices as applied to the pertinent properties. The forecast cost and price assumptions include increases in wellhead selling prices, take into account inflation with respect to future operating and capital costs, and assume the continuance of current laws and regulations. Price adjustments relating to factors such as product quality and transportation were applied on an individual property basis in cash flow calculations.

Forecast prices included a US$/Cdn$ exchange rate of 0.95, a Cdn$/€ exchange rate of 1.42 in 2014 and 1.40 thereafter, and a Cdn$/£ exchange rate of 1.67 in 2014 and 1.65 thereafter. Forecast costs included a 2% inflation factor, except for costs for Mining, which included 4% inflation for 2015 to 2016, 3% inflation for 2017 and 2% thereafter.

Constant Prices and Costs

For purposes of comparison to those issuers who are required to report reserves estimates using constant prices and costs in accordance with the rules and regulations of the U.S. Securities and Exchange Commission (SEC), Suncor also presents reserves estimates using constant prices and costs. Benchmark prices used for the purpose of disclosing supplementary reserves estimates under constant pricing assumptions are also set out in the table below. Prices are based on the arithmetic average of the first-day-of-the-month price for the product for each month of 2013.

Constant prices included a US$/Cdn$ exchange rate of 0.97, a Cdn$/€ exchange rate of 1.36 and a Cdn$/£ exchange rate of 1.61.

SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014    43

Prices Impacting Reserves Tables(1)

Forecast   Brent
North Sea(2)		   WTI
Cushing
Oklahoma		   WCS
Hardisty
Alberta(3)		   Light
Sweet
Edmonton
Alberta(4)		   Pentanes
Plus
Edmonton
Alberta(5)		   AECO
Gas(6)		   B.C. Gas
Westcoast
Station 2(7)		   National
Balancing
Point
North Sea(8)		  
Year   US$/bbl   US$/bbl   Cdn$/bbl   Cdn$/bbl   Cdn$/bbl   Cdn$/mmbtu   Cdn$/mmbtu   Cdn$/mmbtu  
2014   107.50   97.50   75.60   92.76   105.20   4.03   3.88   11.32  
2015   107.50   97.50   79.36   97.37   107.11   4.26   4.11   11.32  
2016   105.00   97.50   81.50   100.00   107.00   4.50   4.35   11.05  
2017   102.50   97.50   81.50   100.00   107.00   4.74   4.59   10.79  
2018   102.50   97.50   81.50   100.00   107.00   4.97   4.82   10.79  
2019   102.50   97.50   81.50   100.00   107.00   5.21   5.06   10.79  
2020   102.50   98.54   82.13   100.77   107.82   5.33   5.18   10.79  
2021   103.38   100.51   83.76   102.78   109.97   5.44   5.29   10.88  
2022   105.45   102.52   85.44   104.83   112.17   5.55   5.40   11.10  
2023   107.56   104.57   87.14   106.93   114.41   5.66   5.51   11.32  
2024+   +2.0%/year   +2.0%/year   +2.0%/year   +2.0%/year   +2.0%/year   +2.0%/year   +2.0%/year   +2.0%/year  
 
Constant   US$/bbl   US$/bbl   Cdn$/bbl   Cdn$/bbl   Cdn$/bbl   Cdn$/mmbtu   Cdn$/mmbtu   Cdn$/mmbtu  
All years   109.05   96.90   73.66   91.50   103.39   3.10   3.06   10.74  
(1)
Each price from the GLJ forecast was adjusted for quality differentials and transportation costs applicable to the specific product and evaluation area.

(2)
Price used when determining light and medium oil reserves presented as East Coast Canada reserves, North Sea reserves and Other International reserves.

(3)
Price used when determining bitumen reserves presented as In Situ and Mining reserves, as well as for determining bitumen pricing for royalty calculation purposes.

(4)
Price used when determining SCO reserves presented as In Situ and Mining reserves, and light and medium oil reserves presented as North America Onshore reserves.

(5)
Price used when determining the cost of diluent associated with bitumen reserves presented as In Situ and Mining reserves, as well as for determining bitumen pricing for royalty calculation purposes. A bitumen/diluent ratio of approximately two to three barrels of bitumen for one barrel of diluent was used. Price also used when determining certain NGL reserves.

(6)
Price used when determining natural gas reserves in Alberta presented as North America Onshore reserves. Price also used when determining natural gas input costs for the production of SCO and bitumen reserves.

(7)
Price used when determining natural gas reserves in B.C. presented as North America Onshore reserves.

(8)
Price used when determining natural gas reserves presented as North Sea reserves.

Disclosure of After-Tax Net Present Values of Future Net Revenue

Values presented in the table for Net Present Value of Future Net Revenues After Income Taxes reflect income tax burdens of assets at an individual asset level (for Mining, In Situ and East Coast Canada) or at a business area or legal entity level (for North Sea and North America Onshore) based on tax pools associated with that business area or legal entity. Income taxes for Other International assets are determined by their respective EPSAs. Suncor's actual corporate legal entity structure for income taxes and income tax planning has not been considered, and, therefore, the total value for income taxes presented in the table may not provide an estimate of the value at the corporate entity level, which may be significantly different. The 2013 audited Consolidated Financial Statements and the MD&A should be consulted for information on income taxes at the corporate entity level.

44   SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014

Future Development Costs
as at December 31, 2013
(forecast prices and costs)

($ millions)   2014   2015   2016   2017   2018   Remainder   Total   Discounted
At 10%		  
Proved                                  
  Mining   3 141   3 785   3 641   2 780   1 927   35 833   51 107   23 816  
  In Situ   1 333   1 013   926   1 026   1 052   29 319   34 669   12 471  
  East Coast Canada   241   47   14   50   17   106   475   380  
  North America Onshore   18   14   22   11   —   —   65   54  
Total Canada   4 733   4 859   4 603   3 867   2 996   65 258   86 316   36 721  
North Sea   352   210   56   12   10   144   784   661  
Other International   64   37   27   20   13   234   395   220  
Total Proved   5 149   5 106   4 686   3 899   3 019   65 636   87 495   37 602  
Proved Plus Probable                                  
  Mining   3 220   3 869   3 729   2 895   2 046   50 852   66 611   26 119  
  In Situ   1 418   1 274   1 182   830   1 227   72 056   77 987   15 047  
  East Coast Canada   1 238   814   667   390   251   1 030   4 390   3 331  
  North America Onshore   50   18   32   19   —   —   119   102  
Total Canada   5 926   5 975   5 610   4 134   3 524   123 938   149 107   44 599  
North Sea   386   233   56   13   10   151   849   716  
Other International   64   37   31   23   13   296   464   234  
Total Proved Plus Probable   6 376   6 245   5 697   4 170   3 547   124 385   150 420   45 549  

Development costs include costs associated with both developed and undeveloped reserves. Significant development activities and costs for 2014 are expected to include:

•
For Mining, development of tailings management facilities and water management assets for Oil Sands Base and development of tailings management facilities and costs for mine train replacements at Syncrude. Remaining development costs for Oil Sands Base and Syncrude relate to capital investments that maintain the production capacity of existing facilities, including, but not limited to, major maintenance at Syncrude, routine maintenance, truck and shovel replacement, the replenishment of catalysts in hydrotreating units at the upgraders and improvements to utilities, roads and other facilities. Development activities for Fort Hills are expected to focus on detailed engineering, procurement, and ramp-up of field construction activities.

•
For both Firebag and MacKay River operations within In Situ, the drilling of new well pairs and the design and construction of new well pads that are expected to maintain existing production levels in future years. Development activities for Firebag also include infill well drilling. Development activities at MacKay River are also expected to include a facility debottleneck, which is expected to increase production capacity by 20% to 38,000 bbls/d by the end of 2015.

•
For East Coast Canada, construction and development drilling activities at Hebron, development drilling at Terra Nova, White Rose, Hibernia, and HSEU, installation of subsea infrastructure for the South White Rose Extension, and continuation of H2S remediation activities at Terra Nova.

•
For North Sea, at Buzzard, development drilling and facility upgrades, and at Golden Eagle, development drilling and the installation of subsea infrastructure.

•
For North America Onshore, the development of the Wilson Creek field in the Cardium oil formation.

•
For Other International, development drilling, and upgrades and maintenance to facilities in Libya.

Management currently believes existing cash balances, internally generated cash flows and existing credit facilities are sufficient to fund future development costs. There can be no guarantee that funds will be available or that Suncor

SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014    45


will allocate funding to develop all of the reserves attributed in the GLJ Reports and the Sproule Reports. Failure to develop those reserves would have a negative impact on future cash flow from operating activities.

The interest or other costs of external funding are not included in the reserves and future net revenue estimates and would reduce reserves and future net revenue to some degree depending upon the funding sources utilized. Suncor does not anticipate that interest or other funding costs would make development of any property uneconomic.

Abandonment and Reclamation Costs

The company completes an annual review of its abandonment and reclamation costs as they relate to its overall operations. This review considers the nature of Suncor's forecasted production and development plans, consistent with that assumed in our long-range planning, where determinable, for liabilities associated with its upstream operations as at December 31, 2013. Where no legal liability or constructive obligation for reclamation exists, potential costs have been excluded from the company's abandonment and reclamation cost estimates. Estimates are based on the anticipated method and extent of restoration, consistent with legal requirements, technological advances and the possible future use of the site.

At December 31, 2013, Suncor estimated its undiscounted, uninflated abandonment and reclamation costs, net of estimated salvage value, for surface leases, wells, facilities and pipelines pertaining to its upstream assets to be approximately $7.8 billion (discounted at 10%, approximately $2.1 billion). Suncor estimates that it will incur $1.1 billion of its identified abandonment and reclamation costs during the next three years (undiscounted: 2014 – $0.4 billion, 2015 – $0.4 billion, 2016 – $0.4 billion), over 77% of which is associated with Oil Sands mining operations. This cost estimate does not include the company's estimated abandonment and reclamation costs for its Refining and Marketing assets ($0.2 billion, undiscounted and uninflated).

Approximately $2.5 billion (undiscounted) has been deducted as abandonment costs in estimating the future net revenues from proved plus probable reserves. This $2.5 billion represents the abandonment obligation for approximately 2,200 net production wells and approximately 2,000 net service and other wells, including a forecasted number of future wells for undeveloped reserves related to in situ and conventional activities that are not included in Suncor's $7.8 billion total.

Abandonment and reclamation costs included in Suncor's $7.8 billion total that are excluded from the determination of future net revenues from reserves include, but are not limited to, costs related to the reclamation of disturbed land from oil sands mining activities, the treatment of oil sands tailings, the decommissioning of oil sands and natural gas processing facilities and well pads, lease sites and the abandonment of wells for which no reserves have been assigned.

46   SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014

Additional Information Relating to Reserves Data

Gross Proved and Probable Undeveloped Reserves

The tables below outline the gross proved and probable undeveloped reserves and represent undeveloped reserves additions, resulting from acquisitions, discoveries, infill drilling, improved recovery and/or extensions pertaining to the year in which the events first occurred.

Gross Proved Undeveloped Reserves
(forecast prices and costs)

    Prior   2011   2012   2013  
   
 
 
 
    First
Attributed		   Total at
December 31
2010		   First
Attributed		   Total at
December 31
2011		   First
Attributed		   Total at
December 31
2012		   First
Attributed		   Total at
December 31
2013		  
SCO (mmbbls)                                  
  Mining   —   —   —   —   —   —   —   —  
  In Situ   651   651   —   502   46   493   75   564  
Total SCO   651   651   —   502   46   493   75   564  
Bitumen (mmbbls)                                  
  Mining   —   —   —   —   —   —   845   845  
  In Situ   360   360   315   661   64   785   74   875  
Total Bitumen   360   360   315   661   64   785   918   1 720  
Light & Medium Oil (mmbbls)                                  
  East Coast Canada   28   28   1   27   4   32   —   26  
  North America Onshore(1)   —   —   —   —   —   —   2   2  
Total Canada   28   28   1   27   4   32   2   27  
North Sea   19   19   25   43   —   32   —   25  
Other International(2)   6   6   2   6   4   4   —   5  
Total Light & Medium Oil   53   53   28   76   7   67   2   57  
Natural Gas (bcf)                                  
North America Onshore – Canada(1)   118   118   2   79   —   80   4   4  
North Sea   1   1   2   3   —   2   —   1  
Other International(2)   —   —   —   —   —   —   —   —  
Total Natural Gas   119   119   4   81   —   82   4   5  
NGLs (mmbbls)                                  
North America Onshore – Canada(1)   —   —   —   —   —   —   —   —  
North Sea   —   —   —   —   —   —   —   —  
Other International(2)   —   —   —   —   —   —   —   —  
Total NGLs   —   —   —   —   —   —   —   —  
Total (mmboe)   1 084   1 084   343   1 253   117   1 359   996   2 342  

SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014    47

Gross Probable Undeveloped Reserves
(forecast prices and costs)

    Prior   2011   2012   2013  
   
 
 
 
    First
Attributed		   Total at
December 31
2010		   First
Attributed		   Total at
December 31
2011		   First
Attributed		   Total at
December 31
2012		   First
Attributed		   Total at
December 31
2013		  
SCO (mmbbls)                                  
  Mining   215   215   —   263   —   260   —   265  
  In Situ   400   400   916   1 212   —   1 043   —   1 074  
Total SCO   615   615   916   1 475   —   1 303   —   1 339  
Bitumen (mmbbls)                                  
  Mining   37   37   —   —   —   —   397   397  
  In Situ   1 835   1 835   38   669   —   594   —   369  
Total Bitumen   1 872   1 872   38   669   —   594   397   766  
Light & Medium Oil (mmbbls)                                  
  East Coast Canada   85   85   143   217   4   222   21   235  
  North America Onshore(1)   4   4   1   2   —   —   1   1  
Total Canada   89   89   144   219   5   222   22   236  
North Sea   15   15   14   17   2   33   —   23  
Other International(2)   11   11   4   14   8   8   —   9  
Total Light & Medium Oil   115   115   161   251   14   262   22   267  
Natural Gas (bcf)                                  
North America Onshore – Canada(1)   136   136   3   87   1   49   15   19  
North Sea   1   1   1   2   —   3   —   2  
Other International(2)   240   240   221   347   —   —   —   —  
Total Natural Gas   377   377   226   436   1   52   15   21  
NGLs (mmbbls)                                  
North America Onshore – Canada(1)   1   1   —   1   —   1   —   —  
North Sea   —   —   —   —   —   —   —   —  
Other International(2)   8   8   6   11   —   —   —   —  
Total NGLs   9   9   6   12   —   1   —   —  
Total (mmboe)   2 673   2 673   1 159   2 480   14   2 170   422   2 376  
(1)
North America Onshore – Canada includes additional properties previously held by Suncor and subsequently disposed of in 2011 and 2013.

(2)
Other International includes additional properties held by Suncor in Syria which were classified as contingent resources in 2012.

(3)
Figures above may not add due to rounding.

48   SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014

Undeveloped In Situ reserves, which constitute approximately 61% of Suncor's gross proved undeveloped reserves and 61% of Suncor's gross probable undeveloped reserves, will take several years to develop. Undeveloped In Situ reserves have been assigned to reserves areas which are not classified as developed producing. Where supported by core hole wells, proved undeveloped reserves have been attributed to regions within 1.2 km from currently drilled or near-term planned production wells, where Alberta Energy Regulator (AER) approval is pending, and in the case of Firebag, also within 2.4 km from producing wells. Management uses integrated plans to forecast future development. These detailed plans align current production, processing and pipeline capacities, capital spending commitments and future development for the next ten years, and are reviewed and updated annually for internal and external factors affecting planned activity. The timing associated with developing undeveloped reserves is a function of the forecasts of the declining production from existing In Situ wells. Suncor has delineated In Situ reserves to a high degree of certainty through seismic data and core hole drilling, consistent with COGE Handbook guidelines. In most cases, proved reserves have been drilled to a density of 16 wells per section, which is in excess of the eight wells per section required for regulatory approval. In order to determine the economic cutoffs of undeveloped reserves, geological information is tested against existing production analogues that use established technology.

Undeveloped Mining reserves constitute approximately 36% of Suncor's gross proved undeveloped reserves and 28% of Suncor's gross probable undeveloped reserves, and relate to the Fort Hills mining area and Syncrude Aurora South mining area, which have regulatory approvals substantially in place and are well-delineated by core hole drilling. First oil for the Fort Hills mining area is expected by the fourth quarter of 2017. The co-owners of Syncrude do not expect that the Aurora South mining area will come on-stream before 2024, when production from the Mildred Lake mining area is expected to be complete.

Undeveloped conventional (light and medium oil, natural gas and NGLs) reserves constitute approximately 3% of Suncor's gross proved undeveloped reserves and approximately 11% of Suncor's gross probable undeveloped reserves. Undeveloped conventional reserves primarily relate to the company's offshore assets at East Coast Canada, mainly associated with Hebron which is currently under development (first oil expected in 2017), and underdrilled or undrilled fault blocks related to extension areas in Hibernia, White Rose and Terra Nova. In developing these reserves, Suncor considers existing facility capacity, capital allocation plans and remaining recoverable resources availability. Accordingly, in some cases, it will take longer than two years to develop all of the currently assigned undeveloped conventional reserves. Suncor plans to develop the majority of the conventional proved undeveloped reserves over the next five years and the majority of the conventional probable undeveloped reserves over the next seven years.

Properties with no Attributed Reserves

The following table is a summary of properties to which no reserves are attributed as at December 31, 2013. For lands in which Suncor holds interests in different formations under the same surface area pursuant to separate leases, the area has been counted for each lease.

Country   Gross
Hectares		   Net
Hectares		  
Canada   4 478 244   3 316 732  
Libya   2 950 978   1 339 489  
U.S. – Alaska   1 106 288   368 726  
Norway   648 876   240 847  
Syria(1)   345 194   345 194  
U.K.   127 141   45 454  
Australia (overriding royalty interest only)   113 027   —  
Total   9 769 748   5 656 442  
(1)
Does not include hectares for lands associated with reserves that were reclassified to contingent resources in 2012 as a result of the suspension of operations.

SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014    49

Suncor's undeveloped petroleum assets include exploration properties in a very preliminary phase of evaluation, to discovery areas where tenure to the property is held indefinitely on the basis of hydrocarbon test results, but where economic development is not currently possible or has not yet been sanctioned. Certain Mining and In Situ properties may be in a mature phase of evaluation, where a significant amount of development has occurred; however, reserves cannot be attributed due to one or more contingencies, such as project sanction. In many cases where reserves are not attributed to lands containing one or more discovery wells, the key limiting factor is the lack of available production infrastructure. Each year, as part of the company's management process to review the economic viability of its properties, some properties are selected for further development activities, while others are temporarily deferred, sold, swapped or relinquished back to the mineral rights' owner.

In 2014, Suncor's rights to 135,696 net hectares in Canada, 3,565 net hectares in Alaska and 129,258 net hectares in Norway are scheduled to expire. Substantial portions of expiring lands may have their tenure continued beyond 2014 through the conduct of work programs and/or the payment of prescribed fees to the rights' owner. No land tenure expiries are scheduled to occur for either Mining or In Situ properties for 2014.

Oil and Gas Properties and Wells

The following table is a summary of oil and gas wells associated with the company's operations as at December 31, 2013.

    Oil Wells   Natural Gas Wells  
   
 
    Producing   Non-Producing(1)(2)   Producing   Non-Producing(1)(2)  
   
 
 
 
    Gross   Net   Gross   Net   Gross   Net   Gross   Net  
Alberta – In Situ(3)   213   213.0   58   58.0   —   —   —   —  
Alberta – Conventional   50   32.5   3   2.7   55   26.6   7   4.6  
British Columbia   —   —   —   —   38   33.2   6   4.9  
Newfoundland   63   16.3   5   1.3   —   —   —   —  
North Sea   33   9.9   2   0.6   —   —   —   —  
Other International(4)   —   —   419   211.1   —   —   6   6.0  
Total   359   271.7   487   273.7   93   59.8   19   15.5  
(1)
Non-producing wells include, but are not limited to, wells where there is no near-term plan for abandonment, wells where drilling has finished, but the well has not been completed, wells requiring maintenance or workover where the resumption of production is not known, and wells that have been shut in and the date of resumption of production is not known with reasonable certainty.

(2)
Non-producing wells do not necessarily lead to classification of non-producing reserves, which are described subsequently in this description.

(3)
SAGD well pairs are counted as one well. Wells where steam injection has commenced are classified as producing.

(4)
Other International includes wells associated with the company's suspended operations in Syria. There are no reserves associated with wells in Syria, only contingent resources. The number assumes that no wells have been damaged since Suncor exited the country in December 2011.

There are no producing wells associated with Mining properties. Suncor has no proved developed non-producing reserves or probable developed non-producing reserves in its Mining reserves.

For In Situ properties, proved non-producing reserves and probable non-producing reserves are associated with wells that have been drilled within the last two years, which require further capital for completion and tie in to facilities to bring the wells on-stream. This capital requirement is significant enough that the reserves are not classified as developed.

Proved plus probable developed non-producing reserves for North America Onshore, East Coast and North Sea are primarily associated with recently drilled development wells to be brought on production in 2014.

For Other International, non-producing reserves are associated with wells in Libya that are suspended due to political unrest in the country, which resulted in the closure of export terminal operations at eastern Libyan seaports. Production in Libya was shut in as at December 31, 2013, and as such, all associated reserves were classified as non-producing with the assumption that production would resume on April 1, 2014.

50   SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014

Costs Incurred

The table below summarizes the company's capital expenditures related to its oil and gas activities for the year ended December 31, 2013.

($ millions)   Exploration
Costs		   Proved
Property
Acquisition
Costs		   Unproved
Property
Acquisition
Costs		   Development
Costs		   Other
Costs(1)		   Total  
Canada – Mining and In Situ   196   —   —   3 881   36   4 113  
Canada – East Coast Canada and North America Onshore   14   —   2   979   —   995  
Total Canada   210   —   2   4 860   36   5 108  
North Sea   190   —   —   270   —   460  
Other International   104   —   —   45   —   149  
Total   504   —   2   5 175   36   5 717  
(1)
Other Costs includes infrastructure for pipelines and storage tanks to support marketing logistics and flexibility.

SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014    51

Exploration and Development Activities

The table below outlines the gross and net exploratory and development wells the company completed during the year ended December 31, 2013.

    Exploratory Wells(1)   Development Wells  
   
 
Total number of wells completed   Gross   Net   Gross   Net  
Canada – Oil Sands                  
  Oil   —   —   35   35.0  
  Service(2)   10   10.0   52   52.0  
  Stratigraphic Test(3)   187   74.0   539   292.6  
  Total   197   84.0   626   379.6  
Canada – East Coast Canada and North America Onshore                  
  Oil   2   0.6   9   4.3  
  Natural Gas(4)   —   —   5   5.0  
  Dry Hole   —   —   2   0.4  
  Service(2)   —   —   3   0.7  
  Total   2   0.6   19   10.4  
North Sea                  
  Oil   2   0.8   3   0.9  
  Dry Hole   1   0.3   1   0.3  
  Stratigraphic Test(3)   —   —   —   —  
  Total   3   1.1   4   1.2  
Other International                  
  Oil   2   1.0   2   1.0  
  Dry Hole   3   1.5   —   —  
  Total   5   2.5   2   1.0  
(1)
Exploratory wells for Oil Sands include activity related to technology pilot projects.

(2)
Service wells for Oil Sands include the injection well in a SAGD well pair, in addition to observation and disposal wells. Service wells for East Coast Canada include water injection wells.

(3)
Stratigraphic test wells for Oil Sands include core hole drilling wells. Stratigraphic test wells for offshore properties include appraisal wells.

(4)
Natural Gas wells do not reflect four wells drilled in properties that were included as part of the sale of the majority of the company's conventional Natural Gas business, which was effective on January 1, 2013.

Significant exploration and development activities in 2013 included:

•
For Mining, core hole drilling programs and other survey work at Oil Sands Base and Syncrude to provide additional information on areas the company expects to mine in the near term.

•
For In Situ, the drilling of new well pairs and infill wells at Firebag and MacKay River that are expected to assist in maintaining production levels in future years, core hole drilling programs at MacKay River, Meadow Creek, Firebag and Lewis to further delineate resources, and activity to start up pilot technology projects.

•
For East Coast Canada, exploration drilling for Terra Nova and White Rose Extensions, and development drilling for Hibernia, White Rose and the White Rose Extensions.

•
For North Sea, exploration drilling for the Romeo, Scotney and Lily prospects, and development, including an appraisal well at Buzzard, all of which are in the U.K. sector of the North Sea.

•
For Other International, exploration and oil development wells in Libya.

•
For North America Onshore, development drilling of the Wilson Creek field in the Cardium oil formation and the Kobes/Altares area in the Montney shale gas formation.

52   SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014

Production History

The table below outlines the company's historical production information, by product type. Average price realized is net of transportation costs, but before royalties.

    Three months ended in 2013    
   
    Mar 31   Jun 30   Sept 30   Dec 31    
Canada – Oil Sands(1)                    
  Total production (mbbls/d)   389.0   309.4   423.6   446.5    
  Total In Situ bitumen production (mbbls/d)   165.5   157.5   181.9   182.4    
                     
  ($/bbl)                    
  Average price realized   79.76   85.87   99.49   73.34    
  Royalties   (4.94 ) (3.30 ) (10.05 ) (4.91 )  
  Total cash operating costs   (35.36 ) (46.09 ) (33.76 ) (37.09 )  
  In Situ cash operating costs   (16.80 ) (16.70 ) (15.15 ) (17.50 )  
Canada – Light & Medium Oil                    
  Total production (mbbls/d)   58.4   57.8   62.4   46.3    
                     
  ($/bbl)                    
  Average price realized   112.57   103.68   116.94   116.48    
  Royalties   (26.61 ) (23.70 ) (30.23 ) (32.77 )  
  Production costs   (9.05 ) (11.44 ) (9.46 ) (15.90 )  
  Netback   76.91   68.54   77.25   67.81    
Canada – Natural Gas(2)                    
  Total production (mmcfe/d)   309   289   273   27    
                     
  ($/mcfe)                    
  Average price realized   4.66   5.30   4.28   6.92    
  Royalties   (0.58 ) (0.49 ) (0.37 ) (0.52 )  
  Production costs   (1.43 ) (1.82 ) (1.84 ) (1.75 )  
  Netback   2.65   2.99   2.07   4.65    
North Sea – Light & Medium Oil(3)                    
  Total production (mboe/d)   55.3   57.8   50.4   59.8    
                     
  ($/boe)                    
  Average price realized   110.94   99.77   111.00   108.53    
  Royalties   —   —   —   —    
  Production costs   (5.80 ) (6.29 ) (7.64 ) (4.94 )  
  Netback   105.14   93.48   103.36   103.59    
Other International – Light & Medium Oil                     
  Total production (mboe/d)   41.9   27.0   13.1   1.0    
                     
  ($/boe)                    
  Average price realized   110.36   104.21   —   —    
  Royalties   (41.81 ) (79.56 ) —   —    
  Production costs   (3.34 ) (3.47 ) —   —    
  Netback   65.21   21.18   —   —    
(1)
Suncor measures cash operating cost on a production volumes basis for its Oil Sands Operations, which includes more expenses than production costs. For this reason, a netback calculation for SCO and bitumen is not presented in this table. Amounts presented include results from the company's share in the Syncrude joint operation.

(2)
Volumes include NGLs and crude oil from North America Onshore operations.

(3)
Volumes include field production for associated gas and NGLs.

SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014    53

The following table provides the production volumes for each of Suncor's significant fields for the year ended December 31, 2013.

    SCO   Bitumen   Light &
Medium Oil		  
   
    mbbls/d   mbbls/d   mbbls/d  
Mining – Suncor   209.7   —   —  
Mining – Syncrude   32.0   —   —  
Firebag   70.1   53.0   —  
MacKay River   2.8   24.9   —  
Buzzard   —   —   55.8  
Hibernia   —   —   27.1  
White Rose   —   —   14.9  
Terra Nova   —   —   14.2  
Total   314.6   77.9   112.0  

Production Estimates

The table below outlines the production estimates for 2014 that are included in the estimates of gross proved reserves and gross probable reserves as at December 31, 2013. Production estimates for 2014 for proved plus probable reserves, evaluated as at December 31, 2013: from Suncor's mining operations (excluding Syncrude) are 252.8 mbbls/d of SCO, approximately 40% of total estimated production for 2014; and from Firebag are 155.9 mbbls/d of SCO and bitumen, approximately 25% of total estimated production for 2014.

    SCO   Bitumen   Light &
Medium Oil		   Natural Gas   NGLs  

 
 
(mbbls/d)
 
(mbbls/d)
 
(mbbls/d)
 
(mmcf/d)
 
(mbbls/d)
 

 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Canada                                          
Proved   322.9   301.5   113.0   105.2   49.4   35.6   17.3   15.3   0.4   0.3  
Probable   16.3   14.3   25.4   23.7   20.1   15.7   7.5   7.2   0.1   0.1  
Proved Plus Probable   339.2   315.8   138.4   128.9   69.4   51.3   24.8   22.5   0.5   0.4  
North Sea                                          
Proved   —   —   —   —   38.5   38.5   3.7   3.7   0.3   0.3  
Probable   —   —   —   —   4.6   4.6   0.9   0.9   0.1   0.1  
Proved Plus Probable   —   —   —   —   43.1   43.1   4.6   4.6   0.4   0.4  
Other International                                          
Proved   —   —   —   —   30.9   5.8   —   —   —   —  
Probable   —   —   —   —   —   —   —   —   —   —  
Proved Plus Probable   —   —   —   —   30.9   5.8   —   —   —   —  
Total                                          
Proved   322.9   301.5   113.0   105.2   118.7   79.9   21.0   19.0   0.7   0.6  
Probable   16.3   14.3   25.4   23.7   24.7   20.3   8.4   8.1   0.2   0.2  
Proved Plus Probable   339.2   315.8   138.4   128.9   143.4   100.2   29.4   27.1   0.9   0.8  

54   SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014

Work Commitments

The practice of governments requiring companies to pledge to carry out work commitments in exchange for the right to carry out exploration for and development of hydrocarbons is common, particularly in unexplored or lightly explored regions of the world. The following table shows the estimated values of work commitments Suncor has made in regard to the lands it holds as at December 31, 2013. These commitments run through 2015 and are primarily for conducting seismic programs and drilling exploration wells.

Country/Area
($ millions)		   2014   Total  
Canada   18   24  
North Sea   66   176  
Other International   67   371  

Forward Contracts and Transportation Obligations

Suncor may use financial derivatives to manage its exposure to fluctuations in commodity prices; however, Suncor did not consider any financial derivative transactions to be material in 2013. A description of Suncor's use of such instruments is provided in the 2013 audited Consolidated Financial Statements and related MD&A for the year ended December 31, 2013.

Tax Horizon

In 2013, Suncor was subject to cash tax in the majority of the local jurisdictions in which it generates earnings, including earnings related to its Canadian, North Sea and Other International production. Commencing in 2013, the company was cash taxable in Canada on the majority of its Canadian earnings.

Contingent Resources

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 recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters, or lack of infrastructure or markets. 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.

GLJ conducted independent assessments of Best Estimate contingent resources volumes for all of Suncor's Mining properties and its Firebag, Meadow Creek and Steepbank In Situ properties. For remaining In Situ properties, including MacKay River, GLJ audited assessments of Best Estimate contingent resources volumes (approximately 45% of In Situ contingent resources) prepared by Suncor's internal qualified reserves evaluators. Sproule Unconventional Limited conducted an independent assessment of Suncor's Best Estimate contingent resources contained in the Montney shale formation of northeast B.C., with an effective date of June 30, 2013. Best Estimate contingent resources for remaining conventional properties were prepared by Suncor's internal qualified reserves evaluators without independent audit or review. All contingent resources estimates were conducted in accordance with the COGE Handbook. The effective date of Suncor's best estimate of contingent resources is as of December 31, 2013, except in the case of the contingent resources contained in the Montney shale formation of northeast B.C., which is as at June 30, 2013, and in the case of Syria, which is as at December 31, 2011.

In 2011, the company's assets in Syria were impacted by political unrest and international sanctions. As a result, volumes previously reported as reserves based on an evaluation conducted by Sproule with an effective date of December 31, 2011 were reclassified to contingent resources in 2012. As the situation in Syria has persisted throughout 2013, the company has not been able to update any information used by Sproule since the 2011 evaluation. The contingent resources estimate for Syria assumes that there has been no production subsequent to Sproule's 2011 evaluation and that infrastructure, including wells and pipelines, existing at December 31, 2011, exist at December 31, 2013. Therefore, these contingent resources are subject to uncertainty arising from any new information or change in circumstances, such as production, changes in asset performance or development activities, about which Suncor and Sproule are unaware.

There is no certainty that all or any portion of the contingent resources will be commercially viable to produce, or as to the timing of any such development. The economic viability of the contingent resources is dependent upon pricing and economic conditions. Estimates of contingent resources have not been adjusted for risk based

SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014    55


on the chance of development. Significant factors that may change contingent resources estimates include further delineation drilling, future technology improvements, and additional processing capacity.

Generally, the contingencies which may currently prevent the classification of the contingent resources as reserves include:

•
The need for higher density core hole drilling to improve the certainty of Mining and In Situ resources;

•
The need for further facility design and the associated uncertainty in development costs and timelines;

•
The preparation of firm development plans and regulatory applications (including associated reservoir studies and delineation drilling);

•
Regulatory approvals; and

•
Board, management or partner approval, as applicable, to proceed with development.

The additional facility design work, development plans, reservoir studies and delineation drilling are often completed in the course of preparing the company's application for regulatory approvals. Once there is a high level of certainty of receiving all regulatory, corporate and co-owner approvals, as applicable, and all other contingencies are removed, the resources may then be reclassified as reserves.

Also, the company has assumed that some Mining and In Situ contingent resources will be upgraded and sold as SCO. To the extent that these volumes are not upgraded, but rather sold as bitumen, contingent resources volumes reported would be lower for SCO and higher for bitumen, and total contingent resources volumes would be higher, because of the yield factor applied to bitumen volumes when upgraded into SCO. Conversely, to the extent that more volumes are upgraded, total contingent resources volumes would be lower.

Suncor's Best Estimate of gross contingent resources are set out in the table below. Gross contingent resource means Suncor's working interest (operated and non-operated) share before deduction of royalties and without including any royalty interests of Suncor.

    SCO   Bitumen   Light &
Medium Oil		   Natural Gas   NGLs   Total(5)  
   
Best Estimate Contingent Resources   mmbbls   mmbbls   mmbbls   bcf   mmbbls   mmboe  
  Mining   4 610   813   —   —   —   5 423  
  In Situ   6 070   7 309   —   —   —   13 379  
  East Coast Canada   —   —   222   2 678   —   668  
  North America Onshore(1)(2)   —   —   35   16 620   238   3 043  
Total Canada(5)   10 680   8 122   256   19 298   238   22 514  
North America Onshore – U.S.   —   —   —   449   —   75  
North Sea(3)   —   —   52   103   —   69  
Other International(4)   —   —   397   985   27   588  
As at December 31, 2013(5)   10 680   8 122   705   20 836   265   23 245  
As at December 31, 2012   11 001   8 109   759   20 205   250   23 486  
(1)
Includes offshore fields in the Arctic Islands.

(2)
Includes contingent resources for the Montney shale formation of northeast B.C., with an effective date of June 30, 2013. The contingent resources associated with this formation include 8,075 bcf of Natural Gas and 214 mmbbls of NGLs.

(3)
Includes offshore Norway and the U.K.

(4)
Includes contingent resources for Syria of approximately 206 mmboe. A portion of these contingent resources were previously classified as reserves as at December 31, 2011, based on a reserves evaluation prepared by Sproule with an effective date of December 31, 2011. These reserves have been reclassified as contingent resources as a result of Suncor's suspension of operations in Syria and the resources have an effective date of December 31, 2011.

(5)
Figures may not add due to rounding.

Contingent resources decreased to 23,245 mmboe at December 31, 2013 from 23,486 mmboe at December 31, 2012, due primarily to the transfer of bitumen volumes related to the Fort Hills mining project to proved plus probable reserves in 2013 upon receipt of project sanction, partially offset by an increase in the company's In Situ contingent resources due to property acquisitions and additional drilling that added bitumen contingent resources primarily at the company's Lewis property.

56   SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014

Generally, the timing for the economic assessments of contingent resources will be determined by Suncor's long-term resource development plan and its forecast for economic conditions. Management uses integrated plans to forecast future development of resources. These plans align current and planned production, current and forecasted market conditions, processing and pipeline capacities, capital spending commitments and related future development plans. These plans are reviewed and updated annually for internal and external factors affecting these planned activities. In particular, as Suncor's Oil Sands reserves base depletes, the company anticipates that it will look to develop its other Mining and In Situ properties, at which time the assessment of the economic viability of specific properties with contingent resources will be made.

Details of Suncor's contingent resources and a categorization of the contingencies ascribed to these resources are provided below.

Mining Contingent Resources

Mining contingent resources comprise approximately 23% of Suncor's total contingent resources, with 74% of these contingent resources related to properties in which Suncor has a 100% working interest and the remainder forming part of joint arrangements where Suncor has working interests varying from 12% to 40.8%.

Economic Contingencies

The economic status of Suncor's Mining contingent resources is currently undetermined and is dependent on the company's long-term resource development plan and its forecast for economic conditions. Prior to reserves being assigned, these contingent resources require the completion of further resource studies and delineation drilling, and the preparation of development plans and facility designs.

Non-Technical Contingencies

The reclassification of Mining contingent resources to reserves is largely contingent upon an assessment that development will be sanctioned and commence within a reasonable time frame. The Joslyn North mining project has substantially all regulatory approvals in place. However, the project has recently applied for regulatory approval of an amended project development plan. As a result, it is Suncor's view that the development of these contingent resources in the near term is not sufficiently assured to support reclassification to reserves.

Suncor's remaining Mining contingent resources are primarily contingent upon regulatory permits which must be obtained before project sanction decisions by Suncor's Board of Directors and/or co-owners, as applicable, are considered.

In Situ Contingent Resources

In Situ contingent resources comprise approximately 58% of Suncor's total contingent resources, with approximately 85% of these contingent resources related to properties in which Suncor has a 100% working interest and the remainder forming part of joint arrangements where Suncor has working interests varying from 10% to 75%. These contingent resources are all in the Athabasca oil sands area. All In Situ contingent resources are associated with clastic or sandstone formations in the Fort McMurray oil sands area, and approximately 85% of the contingent resources are in, or adjacent to, existing Firebag or MacKay River operations.

The primary risk associated with developing In Situ contingent resources relates to actual reservoir performance versus performance estimated based on geological data. The geological data varies substantially as a result of the density of core holes used in the analyses. The density can be as low as one well per section, and as high as 16 wells per section.

Suncor also owns mineral rights in 288 sections of the Grosmont carbonate formation, all at a 100% working interest. Core hole drilling completed on these sections has identified bitumen in the Grosmont, Upper Ireton and Nisku carbonate formations. In addition, Suncor has acquired data from numerous third-party pilots currently in operation in Grosmont carbonates. However, Suncor has not recognized any contingent resources in carbonate formations, as the viability of potential recovery processes in Suncor's carbonate interests has not yet been established.

Economic Contingencies

The economic status of In Situ contingent resources is currently undetermined; however, the company anticipates that the contingent resources will be economic to develop under current market conditions. Technical net pay cutoffs are consistent with, and based upon, the same economic conditions as those used in the determination of proved plus probable reserves for Firebag and MacKay River, or are analogous to existing in situ operations successfully developed by other entities in the oil sands industry. Suncor anticipates that its In Situ contingent resources will be recoverable using established SAGD processes.

Contingent resources have been assigned to certain sections associated with Firebag and MacKay River. These volumes have not been classified as reserves in part because drilling density is inadequate for reliable mapping of effective pay intervals. However, the company has two-dimensional and three-dimensional seismic control, minimum mapped effective pay thicknesses of 15 metres for Firebag and 14 metres for MacKay River, and drilling density greater than or equal to one vertical well per

SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014    57


section (except when that section is bound by sections with greater than or equal to one well per section). The company expects that an assessment of the economic viability of these resources will be undertaken when drilling density has increased such that it is adequate for reliable mapping of effective pay intervals and as the company's long-term plans require additional bitumen to keep existing processing capacities associated with Firebag and MacKay River operations full.

Contingent resources for other In Situ properties (Chard, Kirby, Lewis, Meadow Creek and MacKay River) were assigned to sections with core holes, or lands within two legal subdivisions of a delineation well and net continuous bitumen pay greater than ten to 15 metres, depending on the horizon and property. Within the Athabasca oil sands region, economic production has been demonstrated at these thicknesses. Prior to reserves being assigned, these contingent resources require the completion of further reservoir studies and delineation drilling, and the preparation of development plans and facility designs. The company expects that an assessment of the economic viability of these contingent resources will be undertaken as the company's long-term plans for its upgrading facilities require additional bitumen.

Non-Technical Contingencies

The reclassification of In Situ contingent resources to reserves is also largely contingent upon an assessment that development will be sanctioned and commence within a reasonable time frame. Certain contingent resources associated with Firebag and MacKay River have regulatory approvals in place, but final investment decisions are subject to detailed assessments of economic viability and approval by Suncor's Board. For remaining In Situ contingent resources, the company must still obtain regulatory approvals and project sanction by Suncor's Board and/or co-owners, as applicable.

Other Contingent Resources

Other contingent resources are associated with Suncor's Exploration and Production segment. These other contingent resources comprise approximately 19% of Suncor's total contingent resources and are anticipated to be recoverable using established technologies. These other contingent resources primarily include:

•
For North America Onshore, resources in the Montney formation in northeast B.C., the Wilson Creek area in Alberta, the Arctic Islands, the Mackenzie Delta and Corridor, and the Alaska Foothills.

•
For East Coast Canada, extensions of existing producing oilfields, natural gas resources associated with existing producing oilfields, and other hydrocarbon accumulations that are not currently producing, including those offshore Newfoundland and Labrador.

•
For North Sea, discoveries offshore Norway and the U.K, including the Northern Terrace area, and an extension from Buzzard.

•
For Other International, volumes associated with the company's suspended operations in Syria and, in Libya, undeveloped portions within existing producing fields and other discovered hydrocarbon accumulations that are not currently producing.

Economic Contingencies

Except as noted below, the economic status of other contingent resources is undetermined. In general, further reservoir studies and delineation drilling, and preparation of development plans and facility designs are required to make a determination as to whether these contingent resources would be economic under current conditions.

For North America Onshore, contingent resources associated with the Wilson Creek Cardium tight oil play have been determined to be economic. The economic viability of contingent resources in the Montney shale gas formation are undetermined and there are currently no near-term plans for development. The economic status of contingent resources associated with certain fields in the Arctic Islands is undetermined, but some may be economic provided the natural gas resources are able to be delivered to markets outside of North America. Remaining North America Onshore contingent resources are primarily in geographically remote areas and are currently sub-economic due to lack of processing and transportation infrastructure in these areas. These remote areas require commitments to identify the existence of sufficient resources for economic development, following which construction of processing facilities and/or transportation infrastructure would be required, which is not anticipated to occur within the next five years.

For East Coast Canada, contingent resources for Hebron and some for Terra Nova have been determined to be economic. The company anticipates that it will assess the economic viability of contingent resources for Hibernia and White Rose within the next five years, and that these contingent resources will be economic to develop under current market conditions. Timing for completion of economic evaluation of remaining contingent resources is not anticipated to occur within the next five years.

For the North Sea, contingent resources are in the appraisal stage. The economic status of these contingent resources is undetermined, but the company anticipates that it will assess their economic viability within the next five years and that these contingent resources will be economic to develop under current market conditions.

58   SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014

For Other International, contingent resources in Libya associated with developed fields are economic, while the economic viability of resources associated with fields that are not developed is undetermined, but the company anticipates that it will complete economic assessments for these fields in the next five years.

Non-Technical Contingencies

The reclassification of contingent resources associated with the Exploration and Production segment to reserves is contingent upon the receipt of appropriate regulatory approvals, and an assessment that development will be sanctioned by Suncor's Board and co-owners, as applicable, and commence within a reasonable time frame. Contingent resources for some North America Onshore properties in geographically remote areas are also contingent upon the development of a suitable regulatory framework.

As a result of the suspension of Suncor's operations in Syria, volumes classified as reserves at December 31, 2011 are classified as contingent resources at December 31, 2013. For these resources to be reclassified as reserves, sanctions that are applicable to Suncor and that were initiated as a result of political unrest in Syria must be lifted, and the overall political environment must improve and stabilize so that the company can resume business in Syria. In addition, if infrastructure such as pipes and wells were damaged as a result of the political unrest, then the infrastructure will potentially need to be repaired or rebuilt in order to reclassify the resources as reserves.

SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014    59

INDUSTRY CONDITIONS

The oil and natural gas industry is subject to extensive controls and regulations governing its operations (including land tenure, exploration, environmental, development, production, refining, transportation and marketing) imposed by legislation enacted by various levels of government, and, with respect to export and taxation of oil and natural gas, by agreements among the governments of Canada and Alberta, among others, as well as the governments of the United States and other foreign jurisdictions in which we operate, all of which should be carefully considered by investors in the oil and gas industry. All current legislation is a matter of public record, and the company is unable to predict what additional legislation or amendments may be enacted. All governments have the ability to change legislation. Suncor may engage in the discussion on proposed changes to ensure Suncor's interests are recognized. The following discussion outlines some of the principal aspects of legislation, regulations and agreements governing Suncor's operations.

Pricing, Marketing and Exporting Crude Oil and Natural Gas

The producers of oil are entitled to negotiate sales and purchase agreements directly with oil purchasers. Most agreements are linked to global oil prices. Global oil prices are set by daily, weekly and monthly physical and financial transactions for crude oil around the world. Those prices are primarily based on worldwide fundamentals of supply and demand. Specific prices depend in part on oil quality, prices of competing fuels, distance to the markets, the value of refined products, the supply/demand balance, and other contractual terms. In Canada, oil exporters are also entitled to enter into export contracts. If the term of an export contract exceeds one year for light crude oil or exceeds two years for heavy crude oil (to a maximum of 25 years), the exporter is required to obtain an export licence from the National Energy Board (NEB). If the term of an export contract does not exceed one year for light crude oil or does not exceed two years for heavy crude oil, the exporter is required to obtain an order approving such export from the NEB.

The price of natural gas is also determined by negotiation between buyers and sellers. Natural gas exported from Canada is subject to regulation by the NEB and the Government of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts continue to meet certain other criteria prescribed by the NEB and the Government of Canada. Natural gas export contracts with a term that exceeds two years (to a maximum of 25 years) require the exporter to obtain an export licence from the NEB. Natural gas (other than propane, butane and ethane) export contracts for volumes of more than 30,000 m3/d with a term that does not exceed two years, or export contracts for volumes of 30,000 m3/d or less for a term of two to 20 years, must be made pursuant to an NEB order. The Government of Alberta also regulates the volume of natural gas that may be removed from the province for consumption elsewhere based on such factors as reserves availability, transportation arrangements, and market considerations.

Internationally, prices for crude oil and natural gas fluctuate in response to changes in the supply of and demand for crude oil and natural gas, market uncertainty and a variety of other factors beyond Suncor's control. These factors include, but are not limited to, the actions of OPEC, world economic conditions, government regulation, political developments, the foreign supply of oil, the price of foreign imports, the availability of alternate fuel sources and weather conditions.

Pipeline Capacity

Although pipeline expansions are ongoing, the apportionment of capacity on pipeline systems can occur from time-to-time, due to pipeline and downstream operating problems, affecting the ability to market crude oil and natural gas. Most of the current apportionments, however, are due to significant demand which far exceeds current pipeline capacity. Oil and natural gas producers in North America and, particularly in Canada, currently receive discounted prices for their production relative to certain international prices, due to constraints on the ability to transport and sell such products to international markets.

Recently, pipeline capacity to support the growth of the oil and natural gas industry in Canada has been the subject of political and environmental debate. Suncor supports the responsible development of additional pipeline infrastructure that would open access to other markets.

Royalties, Incentives and Income Taxes

Canada

In addition to federal regulation, each province has legislation and regulations governing land tenure, royalties, production rates, environmental protection, and other matters. The royalty regime is a significant factor in the profitability of SCO, bitumen, crude oil, NGL and natural gas production. Royalties on production from lands other than Crown lands are determined by negotiations between the mineral freehold owner and the lessee, although production from such lands may be subject to certain provincial taxes. Crown royalties are determined by governmental regulation, which are subject to change as a result of numerous factors, including political considerations, and are generally calculated as a percentage of revenues received from the value of the gross production. The royalty rate generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date, method of

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recovery, depth of well, and the type or quality of the petroleum product produced. Other royalties and royalty-like interests are, from time-to-time, carved out of the owner's working interest through non-public transactions. These are often referred to as overriding royalties, gross overriding royalties, net profits interests or net carried interests.

Occasionally, the governments of the western Canadian provinces create incentive programs for exploration and development. Such programs provide for royalty rate reductions, royalty holidays and tax credits, and are generally introduced when commodity prices are low. The programs are designed to encourage exploration and development activity by improving earnings and cash flow within the industry. Royalty holidays and reductions would reduce the amount of Crown royalties paid by oil and gas producers to the provincial governments and would increase the net income and funds from operations of such producers.

The Canadian federal corporate income tax rate levied on taxable income was 15% for active business income, including resource income. The average provincial income tax rate for Suncor in 2013 was 10.64%.

Other Jurisdictions

Operations in the U.S. are subject to the U.S. federal tax rate of 35% and various state-level taxes, primarily 4.63% in Colorado.

There are no royalties on production from the U.K. sector of the North Sea; however, the income tax rate on oil and gas profits is 62%.

Suncor earns refundable tax credits related to eligible exploration spending in Norway at a rate of 78%.

Amounts presented in the 2013 audited Consolidated Financial Statements as royalties for production from our Libya operations are determined pursuant to EPSAs. The amounts calculated reflect the difference between Suncor's working interest in the particular project and the net revenue attributable to Suncor under the terms of the respective EPSAs. All government interests in these operations, except for income taxes, are presented as royalties.

Under our EPSAs in Libya, income taxes are payable. Suncor prepares corporate income tax declarations that are processed by the NOC who, in turn, obtains a tax clearance certificate from tax authorities that is forwarded to Suncor. The NOC remits taxes on Suncor's behalf. Until tax certificates are received, Suncor records both an income tax payable to the taxation authority and an offsetting receivable from the NOC.

Land Tenure

In Canada, petroleum, bitumen and natural gas located in the western provinces are owned predominantly by the respective provincial governments. Provincial governments grant rights to explore for and produce oil and natural gas pursuant to leases, licences and permits for varying terms, and on conditions set forth in provincial legislation, including requirements to perform specific work or make payments. Oil and natural gas located in such provinces can also be privately owned, and rights to explore for and produce such oil and natural gas are granted by lease on such terms and conditions as negotiated. In frontier areas of Canada, the mineral rights are primarily owned by the Canadian federal government, which, either directly or through shared jurisdiction agreements with the relevant provincial authorities, grants tenure in the form of exploration, significant discovery and production licences.

In many other international jurisdictions, petroleum and natural gas are most commonly owned by national governments that grant rights in the form of exploration licences and permits, production licences, PSCs and other similar forms of tenure. In all cases, Suncor's right to explore, develop and produce petroleum and natural gas is subject to ongoing compliance with the regulatory requirements established by the relevant country.

Environmental Regulation

The company is subject to environmental regulation under a variety of Canadian, U.S., U.K. and other foreign, federal, provincial, territorial, state and municipal laws and regulations. These regulatory regimes are laws of general application that apply to Suncor and other companies in the energy industry. The regulatory regimes require Suncor to obtain operating licences and permits in order to operate, and impose certain standards and controls on activities relating to mining, oil and gas exploration, development and production, and the refining, distribution and marketing of petroleum products and petrochemicals. Environmental assessments and regulatory approvals are generally required before initiating most new major projects or undertaking significant changes to existing operations. In addition, this legislation requires that the company abandon and reclaim mine, well and facility sites to the satisfaction of regulatory authorities and, in some cases, this burden may remain with the company even after disposition of an asset to a third party. Compliance with such legislation can require significant expenditures, and a breach of these requirements may result in suspension or revocation of necessary licences and authorizations, civil liability for pollution damage, and the imposition of material fines and penalties. In addition to these specific, known requirements, Suncor expects future changes to environmental legislation, including anticipated legislation for air pollution (Criteria Air Contaminants) and GHG

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emissions that will impose further requirements on companies operating in the energy industry.

A number of statutes, regulations and frameworks are under development or have been issued by various provincial regulators that oversee oil sands development, including the Joint Canada-Alberta Implementation Plan for Oil Sands Monitoring, and the Lower Athabasca Regional Plan (LARP) that implements a land-use regime in the Athabasca oil sands region. These statutes, regulations and frameworks relate to such issues as tailings management, water use, air emissions and land use. While the financial implications of statutes, regulations and frameworks under development are not yet known, the company is committed to working with the appropriate regulatory bodies as they develop new policies, and to fully complying with all existing and new statutes, regulations and frameworks as they apply to the company's operations.

In general, there remains uncertainty around the outcomes and impacts of climate change and environmental laws and regulations, whether currently in force or enacted in the future. It is not currently possible to predict the nature of any future requirements or the impact on the company and its business, financial condition, results of operations and cash flow. We continue to actively work to mitigate our environmental impact, including taking action to reduce GHG emissions, investing in renewable forms of energy such as wind power and biofuels, continuing land reclamation activities, installing new emissions abatement equipment, investing in research and development and working to advance other environmental technologies such as carbon capture and sequestration.

The scope of recent environmental regulation and initiatives has had an impact on many areas important to Suncor's operations, some of which are summarized in the following subsections:

Climate Change

Suncor operates in many jurisdictions that have regulated, or have proposed to regulate, industrial GHG emissions. Those jurisdictions that have regulated GHG emissions generally support policies based on (i) caps on the intensity of GHG emissions including absolute GHG emissions limits, (ii) a cap-and-trade system, (iii) a tax, (iv) a hybrid of a tax and a cap-and-trade system, and (v) policies including other measures such as low carbon fuel and renewable fuel standards. Suncor participates in the consultation process for the design of proposed regulations and other efforts to harmonize regulations across jurisdictions within North America, both directly with government and indirectly through industry associations.

International Climate Change Agreements and Treaties

In 2012, the Government of Canada announced that it would not sign up for the second Kyoto Commitment Period commencing 2013. However, Canada has committed, pursuant to an agreement at the United Nations Framework Convention on Climate Change Conference of the Parties (UNFCCC COP) held in Copenhagen, Denmark, in 2009 (Copenhagen Accord), to reducing its GHG emissions by 17% below 2005 levels by 2020, in line with the reduction commitment made by the U.S. The Copenhagen Accord does not contain any binding commitments for reducing CO2 emissions, nor does it include any discussion of compliance mechanisms. The 2013 UNFCCC COP, held in Warsaw, Poland, continued to focus on creating a process and plan for all UN members to get to an agreement on 2020 commitments by the 2015 UNFCC COP to be held in Paris. Countries were asked to either pledge emissions reductions or contribute financially.

Canadian Federal GHG Regulations

The Government of Canada has already implemented regulation on two of Canada's largest sources of emissions, being transportation and thermal electricity generated from coal (which includes petroleum coke). In line with the U.S., Canada has adopted a renewable fuels standard, mandating that 5% of gasoline supply come from renewable sources such as ethanol and that 2% of diesel supply come from bio-diesel. The Canadian federal government continues to address emissions of specific sectors of the economy and is engaged in negotiations with the Canadian oil and gas industry on proposed regulations for the sector while ensuring the industry remains globally competitive. It is expected that provincial governments will enter into equivalency agreements for their own regulations with regard to a future federal regulation.

Canadian Provincial GHG Regulations

In the absence of a federal GHG emissions policy, various Canadian provinces have responded with their own GHG emissions reduction targets and passed legislation enabling regulation of large GHG emitters. Suncor is committed to fully complying with existing regulations and will continue to constructively engage the appropriate governmental bodies in meaningful dialogue in an effort to develop a harmonized system which focuses on achieving actual reduction goals and sustainable resource development.

In July 2007, pursuant to the Specified Gas Emitters Regulation (SGER) enacted under the Climate Change and Emissions Management Act (Alberta), facilities in Alberta, emitting more than 100,000 tonnes of CO2 equivalent (CO2e) per year are subject to intensity limits

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(GHG emissions per unit of production) and are required to reduce their intensity limits by 12% from an established baseline. With the divestiture of the Hanlan gas processing plant in 2013, four facilities now operated by Suncor in Alberta (Oil Sands Base plants, MacKay River operations, Firebag operations and the Edmonton refinery) are subject to, and continue to comply with, this legislation. For 2012, the total cost to comply with the SGER was approximately $20.5 million based on $15/tonne of CO2e. Compliance under the SGER was achieved through reduced emissions per unit of production, and purchase and retirement of offset credits and payments to Alberta's Climate Change and Emissions Management Fund (Alberta Technology Fund). For 2014, the total compliance costs to Suncor are estimated to be between $20 million and $25 million, based on a cost of $15/tonne of CO2e. The SGER is set to expire in September 2014. The Alberta government has indicated that the regulation will likely be renewed although any renewal may include changes such as increased intensity limits, decreased emissions thresholds and increased costs to the Alberta Technology Fund beyond the current $15/tonne of CO2e.

Several Canadian provinces (including British Columbia, Ontario and Quebec) are members of the Western Climate Initiative (WCI), a multi-jurisdictional partnership, whose members also include individual U.S. states, created in 2007 to address climate change.

The Province of British Columbia enacted a carbon tax in 2008, which began at $10/tonne of CO2e and escalated by $5/tonne per year until 2012 when it reached its maximum of $30/tonne. This carbon tax is revenue neutral, in that revenues are recycled back to taxpayers via tax reductions, and is applied on consumption. Under these regulations, Suncor's natural gas production and gathering facilities in B.C. are classified as one facility, which in aggregate in prior years has exceeded the 25,000 tonne threshold that requires the reporting of emissions to be verified by third parties. As a result of Suncor's divestiture of various natural gas assets in 2013, the threshold for third-party verification is no longer met, but reporting of emission levels on its remaining properties remains a requirement. Similarly, Suncor's refined product distribution terminals in B.C. are required to report emissions, but do not exceed the threshold that requires third-party verification.

In 2007, Quebec introduced a tax on hydrocarbon production and imports, with the revenues going into a Green Fund, to support transit and other emissions-reducing projects. This tax impacts Suncor's refining and marketing activities in the province.

Suncor's Montreal refinery is subject to Quebec's cap-and-trade system for GHG emissions because it produces more than 25,000 tonnes of CO2e per year. Emitters must verify their emissions during specified compliance periods (the first period having commenced January 1, 2013 and ending December 31, 2014), and must either reduce their emissions or purchase eligible compliance mechanisms to cover their emissions above a specified cap. Quebec is responsible for setting the cap for the province and allocating allowances to emitters in its jurisdiction. As of January 1, 2014, Quebec's cap-and-trade system became formally linked to the WCI. Allowances and offsets are fungible across the WCI, such that Quebec-issued allowances and offsets can be bought and sold with the larger trading system, which currently consists solely of Quebec and California. It is anticipated that the Green Fund will eventually be replaced by the cap-and-trade system.

Ontario continues to consult with stakeholders on the development of a GHG reduction program for Ontario's industrial sector, intended to achieve equivalency with federal government regulation. Suncor's assets in Ontario include a refinery, a biofuel plant and a lubricants plant.

U.S. GHG Regulations

In an effort to build a green economy, the current administration of the United States has supported a clean energy standard that would reduce GHG emissions from the power sector and increase the use of cleaner sources of energy, including natural gas, nuclear power and "clean" coal. It is expected that the President's Administration will work to advance his 2013 Climate Action Plan to reduce GHG emissions. In the absence of other federal legislation on GHG emissions, the current administration of the United States is endorsing the U.S. Environmental Protection Agency (EPA) to regulate GHG emissions under the Clean Air Act, starting with the thermal power sector. The implications of the oil and gas industry being regulated under the EPA and the timing of such regulation remain unknown. In the meantime, the EPA has implemented a mandatory GHG reporting rule for all large facilities (emitting greater than 25,000 tonnes of CO2e per year), which includes Suncor's Commerce City refinery.

The EPA has also mandated Renewable Fuel Standards 2, which encourages ethanol blending of up to 15% from the current 10% limit. Several factors will impact the ability of refiners and producers to achieve these requirements, including the lead time required for fleet turnover, the ability of retail stations to simultaneously provide both 10% and 15% fuels, and the inherent liability for ensuring consumers use the appropriate fuel for their vehicle.

The State of California has passed AB32, which provides for a Low Carbon Fuel Standard (LCFS). In December 2011, the United States District Court ruled against California's LCFS, stating that it was in violation of the Commerce Clause of the United States Constitution. The State of California successfully appealed the ruling in 2013. The

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State of California is now considering different compliance pathways for regulated parties.

International Regulations

Phase III (2008-2012) of the European Union Emissions Trading Scheme (EU ETS), which is applicable until 2020, impacts Suncor's non-operated offshore assets in the U.K. and Norway sectors of the North Sea. The EU ETS requires that member countries set emissions limits for installations in their country covered by the scheme and assigns such installations an emissions cap. Installations may meet their cap by reducing emissions or by buying allowances from other participants. Phase III will include a transition from gratis allocation to auctioning allowances.

Land Use

In 2012, the Government of Alberta approved the LARP, which covers land-use restrictions in the Lower Athabasca region of Alberta, which includes leases in Suncor's Oil Sands segment. The LARP, developed as part of the Land-Use Framework (LUF) under the Alberta Land Stewardship Act, identifies new conservation areas, as well as management frameworks to ensure the continued regional quality of air, surface water and groundwater. The new conservation areas do not overlap any of Suncor's leases. The management frameworks formalize a number of regulatory tools that are already used by the government to manage environmental aspects of oil sands development, including the use of environmental cumulative effects management on a regional scale, and may require Suncor to have greater participation in the evaluation of environmental issues. The frameworks include the following:

•
Air quality. The framework is designed to maintain flexibility and to manage cumulative effects of development on air quality within the region, setting triggers and limits for nitrogen dioxide (NO2) and sulphur dioxide (SO2). The framework includes ambient air quality triggers and limits. Regulatory actions will occur when triggers or limits are reached or exceeded.

•
Surface water quality. The framework builds on, but does not replace, existing provincial legislation and policy on water quality, and provides a framework in which to monitor and manage long-term, cumulative changes in water quality within the Lower Athabasca River. The framework includes quality limits and triggers for various indicators, based on existing Alberta, Canadian Council of Ministers of the Environment, Health Canada and U.S. EPA guidelines. Regulatory actions will occur when triggers or limits are reached or exceeded.

•
Groundwater. The framework aims to manage non-saline groundwater resources in a sustainable manner and protect resources from contamination and over-use. The framework aims to ensure timely detection of key changes to indicators and describes the management response that will be initiated if triggers or limits, including site-specific measures, are reached or exceeded.

Reclamation and Tailings

In February 2009, the Energy Resources Conservation Board (ERCB), now the Alberta Energy Regulator or AER, of Alberta released Directive 74 Tailings Performance Criteria and Requirements for Oil Sands Mining Schemes. The directive establishes performance criteria for tailings operations and requirements for the approval, monitoring and reporting of tailings ponds and plans. Suncor's new tailings management strategy – TROTM – was approved by the ERCB in June 2010. Suncor's mine plan is designed to facilitate the implementation of TROTM by providing space for the drying of tailings and ensuring adequate storage capacity for tailings from the Millennium and North Steepbank areas. Syncrude's tailings management plan was approved by the ERCB in 2010 and incorporates a multi-pronged approach that includes freshwater capping, composite tailings technology (accelerates water from tailings with additives), and the separation of water and tailings through the use of centrifuges.

The Government of Alberta also has in place the Mine Financial Security Program (MFSP), which holds oil sands miners responsible for all aspects of the remediation and surface reclamation work at their mine sites, and for the custody of the site until a reclamation certificate has been issued by the government. The MFSP requires a base amount of security for each project in the form of letters of credit, which would provide the funds necessary to safely secure the site. Suncor is in compliance with the MFSP. Additional security may be required under other conditions, such as failure to meet current reclamation plans, or when the estimated remaining production life of the mine reaches certain levels; however, Suncor has not been required to provide any additional security. The MFSP has been designed by the Government of Alberta to include a periodic review of the program to ensure it is functioning properly and provide early warning of any potential risks.

Hydraulic Fracturing

Hydraulic fracturing is the process of pumping a fluid or a gas under pressure down a well, which causes the surrounding rock to crack or fracture. The fluid, typically consisting of water, sand, chemicals and other additives, flows into the cracks where the sand remains to keep the cracks open and allow natural gas or liquids to be recovered. Fracturing fluids are produced back to the surface through the wellbore and are stored for reuse or

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future disposal in accordance with regional regulations, which may include injection into underground wells.

The Government of Canada manages the use of chemicals through its Chemical Management Plan and New Substances Program. Some provinces require the details of fracturing fluids to be submitted to regulators. In Alberta, the AER requires that all fracturing operations submit information regarding the quantity of fluids and additives, and other Provinces of Canada have, or have indicated that they will in the future, apply similar reporting requirements.

While hydraulic fracturing has been in use for some time, the proliferation of fracturing in recent years to access hydrocarbons in unconventional reservoirs, such as shale formations, has raised concerns about the interaction of fracturing fluids with the water supply, and the possibility of seismic events.

Joint Controls /Alberta Implementation Plan for Oil Sands Monitoring

Canada and Alberta recently adopted the Joint Controls /Alberta Implementation Plan for Oil Sands Monitoring (Monitoring Plan). The intent of the Monitoring Plan is to provide a scientifically credible, integrated approach to environmental monitoring, including an improved understanding of the cumulative environmental impact of oil sands development. The total costs to the industry of enhanced monitoring under the Monitoring Plan have been estimated at approximately $50 million per year. The cost to Suncor under the Monitoring Plan are estimated at approximately $10 million per year.

Industry Collaboration Initiatives

For areas of environmental concern, the need for energy companies to increase collaboration with each other, and with their respective stakeholders, is a particularly critical issue for the oil sands industry.

As part of the Oil Sands Leadership Initiative (OSLI), Suncor worked closely with other companies in an effort to make tangible improvements to environmental, social and economic performance in the oil sands industry. These companies came together to pool financial resources and expertise. OSLI focused on land stewardship, water use, technology innovation and sustainable communities. OSLI has been superseded by the Canadian Oil Sands Innovation Alliance (COSIA). COSIA has 13 oil sands member companies and is committed to collaborative action to accelerate improvements in environmental performance, including tailings, water, land and GHG emissions. COSIA will build on the work of OSLI and other collaborative networks to share knowledge and expertise about new technologies and innovation related to environmental performance.

In addition, Suncor and six other oil sands mining companies announced the creation of the Oil Sands Tailings Consortium in December 2010, and agreed to work together in a unified effort to advance tailings management. This initiative is now part of the COSIA. Each company has pledged to share its existing tailings research and technology, and to remove barriers to collaborating on future tailings research and development. In turn, the companies are committing to future research investments to further accelerate tailings technology advances.

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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 risks, including Suncor's 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 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 products 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 writeoffs 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 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

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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 startup – a failure of the facility to meet agreed performance targets, including operating costs, efficiency, yield and maintenance costs.

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

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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 SORs 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 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 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.

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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 CO2 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/tonne of CO2e 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 LCFS legislation could pose a significant barrier to Suncor's 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

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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 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 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 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.

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 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

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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.

Market Access

Suncor anticipates higher production of bitumen in future years, due mainly to production growth from debottlenecking at both MacKay River and Firebag operations as well as MacKay River Stage 2. Due to its high viscosity, bitumen is blended with a light diluent or SCO and sold as a heavy crude oil. The markets for heavy crude are more limited than those for light crude, making them more susceptible to supply and demand changes and imbalances (whether as a result of pipeline constraints or otherwise). Heavy crude oil generally receives lower market prices than light crude, due principally to the lower quality and value of the refined product yield, and the higher cost to transport the more viscous product on pipelines, and this price differential can be amplified due to supply and demand imbalances, as has been experienced in recent years with pipeline constraints and the inability to efficiently bring products to market. The price differential between light crude and WCS is particularly important for Suncor. The market price for WCS is influenced by regional supply and demand factors, including the availability and price of diluent, and by the availability and cost of accessing primary markets through pipeline systems.

Constrained market access for oil sands production due to insufficient pipeline takeaway capacity, growing inland production and refinery outages create risk of widening differentials or shut-in of production that could have a material adverse effect on our business, financial condition, results of operations and cash flow. In addition, oil and natural gas producers in North America, and particularly in Canada, currently receive discounted prices for their production relative to certain international prices, due to constraints on the ability to transport and sell such products to international markets. A failure to resolve such constraints may result in continued discounted or reduced commodity prices realized by oil and natural gas producers such as Suncor.

Third-Party Service Providers

Suncor is reliant on the operational integrity of a large number of third-party service providers, including input and output commodity transport (pipelines, rail, trucking, marine) and utilities associated with various Suncor facilities. Recent incidents around commodity transportation in North America have highlighted the nature of this risk generally; a disruption in service by one of these third parties can also have a dramatic impact on Suncor's operations. Pipeline constraints that affect takeaway capacity or supply of inputs could impact our ability to produce at capacity levels. Disruptions in pipeline service could adversely affect commodity prices, Suncor's price realizations, refining operations and sales volumes, or limit our ability to deliver production. These interruptions may be caused by the inability of the pipeline to operate or by the oversupply of feedstock into the system that exceeds pipeline capacity. There can be no certainty that short-term operational constraints on pipeline systems arising from pipeline interruption and/or increased supply of crude oil will not occur. In addition, planned or unplanned shutdowns or closures of our refinery customers may limit our availability to deliver feedstock. All of these events could have negative implications on Suncor's business, financial condition, results of operations and cash flow.

Foreign Operations

The company has operations in a number of countries with different political, economic and social systems. As a result, the company's operations and related assets are subject to a number of risks and other uncertainties arising from foreign government sovereignty over the company's international operations, which may include, among other things:

•
Currency restrictions and exchange rate fluctuations;

•
Loss of revenue, property and equipment as a result of expropriation, nationalization, war, insurrection and geopolitical and other political risks;

•
Increases in taxes and government royalties;

•
Compliance with existing and emerging anti-corruption laws, including the Foreign Corrupt Practices Act (United States), the Corruption of Foreign Officials Act (Canada) and the United Kingdom Bribery Act;

•
Renegotiation of contracts with government entities and quasi-government agencies, including risks around ongoing negotiations in Libya with the NOC related to the periods in which Suncor was in force majeure under its EPSAs;

•
Changes in laws and policies governing operations of foreign-based companies; and

•
Economic and legal sanctions (such as restrictions against countries experiencing political violence, or countries that other governments may deem to sponsor terrorism).

If a dispute arises in the company's foreign operations, the company may be subject to the exclusive jurisdiction of foreign courts or may not be able to subject foreign persons to the jurisdiction of a court in Canada or the

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U.S. In addition, as a result of activities in these areas and a continuing evolution of an international framework for corporate responsibility and accountability for international crimes, the company could also be exposed to potential claims for alleged breaches of international law.

In response to international sanctions and escalating political unrest in Syria, Suncor declared force majeure in December 2011, withdrew its expatriate staff and stopped recording production from Syria. Since this time, the company's prospects for resuming operations in Syria have not improved. As a result, Suncor recorded impairment charges against its assets in Syria in 2012 and then completely impaired the assets in 2013. In 2013, the company also recorded an after-tax impairment charge of $101 million against its assets in Libya due to an extended loss of production, and uncertainty around return to operations arising from continued political unrest which began in mid-2013. There is no assurance as to if or when Suncor's operations in either Syria or Libya will resume or return to previous levels. Further, Suncor has not received signed agreements for the exploration period extension to April 12, 2015 under its Libyan EPSAs. Until these signed agreements are received, there remains a risk that Suncor's exploration period is not extended.

The impact that future potential terrorist attacks, regional hostilities or political violence may have on the oil and gas industry, and on our operations in particular, is not known at this time. This uncertainty may affect operations in unpredictable ways, including disruptions of fuel supplies and markets, particularly crude oil, and the possibility that infrastructure facilities, including pipelines, production facilities, processing plants and refineries, could be direct targets of, or collateral damage of, an act of terror, political violence or war. Suncor may be required to incur significant costs in the future to safeguard our assets against terrorist activities or to remediate potential damage to our facilities. There can be no assurance that Suncor will be successful in protecting itself against these risks and the related financial consequences.

Co-owner Management

Suncor has entered into joint arrangements and other contractual arrangements with third parties with respect to certain of its projects where other entities operate assets in which Suncor has ownership or other interests. Suncor's dependence on its co-owners and its constrained ability to influence operations and associated costs could materially adversely affect Suncor's business, financial condition, results of operations and cash flow. The success and timing of Suncor's activities on assets and projects operated by others, or developed jointly with others, depend upon a number of factors that are outside of Suncor's control, including the timing and amount of capital expenditures, the timing and amount of operational and maintenance expenditures, the operator's expertise, financial resources and risk management practices, the approval of other participants, and the selection of technology.

These co-owners may have objectives and interests that do not coincide with and may conflict with Suncor's interests. Major capital decisions affecting joint arrangements may require agreement among the co-owners, while certain operational decisions may be made solely at the discretion of the operator of the applicable assets. While the partners generally seek consensus with respect to major decisions concerning the direction and operation of the assets and the development of projects, no assurance can be provided that the future demands or expectations of the parties relating to such assets and projects will be met satisfactorily or in a timely manner. Failure to satisfactorily meet demands or expectations by all of the parties may affect our participation in the operation of such assets or in the development of such projects, our ability to obtain or maintain necessary licences or approvals, or the timing for undertaking various activities. In addition, disputes may arise pertaining to the timing and/or capital commitments with respect to projects that are being jointly developed, which could materially adversely affect the development of such projects and Suncor's business and operations.

EH&S Regulatory Non-Compliance

The company is required to comply with a large number of EH&S regulations under a variety of Canadian, U.S., U.K. and other foreign, federal, provincial, territorial, state and municipal laws and regulations, some of which are described in the Industry Conditions – Environmental Regulation section of this AIF. Failure to comply with these regulations may result in the imposition of fines and penalties, production constraints, reputational damage, operating and growth permit applications, censure, liability for cleanup costs and damages, and the loss of important licences and permits, which could also have a material adverse effect on Suncor's business, financial condition, results of operations and cash flow. Compliance can be affected by the loss of skilled staff, inadequate internal processes and compliance auditing.

Permit Approvals

Before proceeding with most major projects, including significant changes to existing operations, Suncor must obtain various federal, provincial or state permits and regulatory approvals. Suncor must also obtain licences to operate certain assets. These processes can involve, among other things, stakeholder consultation, environmental impact assessments and public hearings, and may be subject to conditions, including security deposit obligations and other commitments. Suncor can also be indirectly impacted by a third party's inability to obtain regulatory approval for a shared infrastructure project.

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Failure to obtain or maintain regulatory approvals, or failure to obtain them on a timely basis or on satisfactory terms, could result in delays, abandonment or restructuring of projects and increased costs, all of which could have a material adverse effect on Suncor's business, financial condition, results of operations and cash flow.

Energy Trading and Risk Management Activities and the Exposure to Counterparties

The nature of Suncor's energy trading and risk management activities, which may make use of derivative financial instruments to hedge its commodity price and other market risks, creates exposure to significant financial risks, which include, but are not limited to, the following:

•
Movements in prices or values could result in a financial loss to the company;

•
A lack of counterparties, due to market conditions or other circumstances, could leave us unable to liquidate or offset a position, or unable to do so at or near the previous market price;

•
We may not receive funds or instruments from our counterparty at the expected time;

•
The counterparty could fail to perform an obligation owed to us;

•
Loss as a result of human error or deficiency in our systems or controls; and

•
Loss as a result of contracts being unenforceable or transactions being inadequately documented.

In the normal course of business, the company enters into contractual relationships with counterparties in the energy industry and other industries, including counterparties for interest rate, foreign exchange and commodity hedging arrangements. If such counterparties do not fulfil their contractual obligations, the company may suffer losses, may have to proceed on a sole risk basis, may have to forego opportunities or may have to relinquish leases or blocks.

Suncor has adopted a Trading Risk Management Policy (the Trading Policy), which requires all trading activities to occur in the group responsible for trading, so that trading risks can be properly monitored, controlled and reported. The Board has set the trading commodities, trading term limits, value-at-risk limits and stop-loss limits under the Trading Policy. Any changes to the foregoing require Board approval. The Board reviews and monitors Suncor's compliance with the Trading Policy through the Audit Committee, which receives a quarterly report that summarizes Suncor's trading activities and provides an assessment of Suncor's financial exposure to risk from these activities.

The terms of derivative financial instruments may also limit the benefit of favourable changes in commodity prices, interest rates and currency values and may result in financial or opportunity loss due to delivery commitments, royalty rates and counterparty risks associated with the contracts.

While the company limits its exposure to any one counterparty to a level that management deems to be reasonable, losses due to counterparties failing to fulfil their contractual obligations may have a material adverse effect on Suncor's business, financial condition, results of operations and cash flow.

Royalties

Royalties can be impacted by changes in crude oil and natural gas pricing, production volumes, foreign exchange rates, and capital and operating costs by changes to existing legislation or PSCs, and by results of regulatory audits of prior year filings and other unexpected events. The final determination of these events may have a material impact on royalties payable to provincial and local governments and on the company's royalties expense.

Technology Risk

There are risks associated with growth and other capital projects that rely largely or partly on new technologies and the incorporation of such technologies into new or existing operations, particularly as the results of the application of new technologies may differ from simulated or test environments. The success of projects incorporating new technologies cannot be assured. Advantages accrue to companies that can develop and adopt emerging technologies in advance of competitors. The inability to develop and monitor new technologies may impact the company's ability to develop its new or existing operations in a competitive or profitable manner.

Current SAGD technologies for in situ recovery of heavy oil and bitumen are energy intensive, requiring significant consumption of natural gas and other fuels in the production of the steam used in the recovery process. The amount of steam required in the production process can also vary and impact costs. The performance of the reservoir can also impact the timing and levels of production using this technology.

Exchange Rate Fluctuations

Our Consolidated Financial Statements are presented in Canadian dollars. The majority of Suncor's revenues from the sale of oil and natural gas are based on prices that are determined by, or referenced to, U.S. dollar benchmark prices, while the majority of Suncor's expenditures are realized in Canadian dollars. The company also holds substantial amounts of U.S. dollar debt. Suncor's results, therefore, can be affected significantly by the exchange rates between the Canadian dollar and the U.S. dollar. The company also undertakes operations administered through

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international subsidiaries and, so, to a lesser extent, Suncor's results can be affected by the exchange rates between the Canadian dollar and the euro, and the Canadian dollar and the British pound. These exchange rates may vary substantially and may give rise to favourable or unfavourable foreign currency exposure, which could have a material adverse effect on Suncor's business, financial condition, results of operations and cash flow.

Labour Relations

Hourly employees at our Oil Sands facilities near Fort McMurray, Alberta, all of our refineries, certain of our lubricants operations, certain of our terminalling and distribution operations, and our Terra Nova FPSO are represented by labour unions or employee associations. Approximately 30% of our employees are members of Unifor. Any work interruptions involving our employees, contract trades utilized in our projects or operations, or any jointly owned facilities operated by another entity could have a material adverse effect on Suncor's business, financial condition, results of operations and cash flow.

Reliance on Key Personnel

Our success, in a large measure, is dependent on certain key personnel. The loss of services from such key personnel could have a material adverse effect on the company. The contributions of the existing management team to the immediate and near-term operations of the company are likely to continue to be of central importance for the foreseeable future. In addition, the competition for qualified personnel in the oil and natural gas industry is intense, and there can be no assurance that we will be able to continue to attract and retain all personnel necessary for the development and operation of our business.

Uncertainty of Reserves and Resources Estimates

The reserves and contingent resources estimates included in this AIF represent estimates only. 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. In general, estimates of economically recoverable reserves and the future net cash flow from these assets are based upon a number of variable factors and assumptions, such as historical production from the properties, the assumed effect of regulation by governmental agencies, pricing assumptions, the timing and amount of capital expenditures, future royalties, future operating costs, and yield rates for upgraded production of synthetic crude oil from bitumen – all of which may vary considerably from actual results. The accuracy of any reserves and resources estimates is a matter of interpretation and judgment and is a function of the quality and quantity of available data, which may have been gathered over time.

Reserves and resources estimates are based upon a geological assessment, including drilling and laboratory tests. Mining reserves and resources estimates also consider production capacity and upgrading yields, mine plans, operating life and regulatory constraints. In Situ reserves and resources estimates are also based upon the testing of core samples and seismic operations and demonstrated commercial success of in situ processes. Our actual production, revenues, royalties, taxes, and development and operating expenditures with respect to our reserves will vary from such estimates, and such variances could be material. Production performance subsequent to the date of the estimate may justify revision, either upward or downward, if material.

The reserves evaluations are based in part on the assumed success of activities we intend to undertake in future years. The reserves and estimated cash flow to be derived from the reserves contained in the reserves evaluations will be reduced to the extent that such activities do not achieve the level of success assumed in the reserves evaluations. The reserves evaluations are effective as of a specific effective date and have not been updated, and thus do not reflect changes in our reserves since that date.

For these reasons, estimates of the economically recoverable reserves and resources attributable to any particular group of properties, and classification of such reserves and resources based on the risk of recovery, prepared by different engineers or by the same engineers at different times, may vary.

Interest Rate Risk

We are exposed to fluctuations in short-term Canadian and U.S. interest rates as Suncor maintains a portion of its debt capacity in revolving and floating rate bank facilities and commercial paper, and invests surplus cash in short-term debt instruments. We are also exposed to interest rate risk when debt instruments are maturing and require refinancing, or when new debt capital needs to be raised.

Capital Markets

Suncor expects that future capital expenditures will be financed out of cash generated from operations and borrowings. This ability is dependent on, among other factors, commodity prices, the overall state of the capital markets and investor appetite for investments in the energy industry generally and our securities in particular.

The market events and conditions witnessed over the past several years, including disruptions in international credit markets and other financial systems and the deterioration of global economic conditions, have caused significant volatility in commodity prices and increases in the rates at

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which we are able to borrow funds for our capital programs. The continued uncertainty in the global economic situation means that the company, along with all other oil and gas entities, may continue to face restricted access to capital and increased borrowing costs. To the extent that external sources of capital become limited or unavailable or available on unfavourable terms, our ability to make capital investments and maintain existing properties may be constrained, and, as a result, Suncor's business, financial condition, results of operations and cash flow may be materially adversely affected.

We believe that we have sufficient funds available to fund our planned capital expenditures for 2014. If cash flow from operations is lower than expected, if capital expenditures in 2014 exceed current estimates, or if we incur major unanticipated expenses related to the development or maintenance of our existing assets, Suncor may need to re-evaluate its capital program or seek additional capital. Choosing not to obtain the financing necessary for our capital expenditure plans may result in a delay in the planned development of production from our operations and strand significant capital, while increasing costs to keep projects in safe mode. Choosing to seek additional capital might adversely affect our credit ratings. Either of these events could have a material adverse effect on Suncor's business, financial condition, results of operations and cash flow.

Issuance of Debt and Debt Covenants

From time-to-time, we may finance capital expenditures in whole or in part with debt, which may increase our debt levels above industry standards for oil and gas companies of similar size. Depending on future development plans, we may require additional debt financing that may not be available or, if available, may not be available on favourable terms, including higher interest rates and fees. Neither the Articles of Suncor (the Articles) nor its bylaws limit the amount of indebtedness that we may incur; however, we are subject to covenants in our existing bank facilities and seek to avoid an unfavourable cost of debt. The level of our indebtedness, from time-to-time, could impair our ability to obtain additional financing on a timely basis to take advantage of business opportunities that may arise and could negatively affect our credit ratings, which could have a material adverse effect on Suncor's business, financial condition, results of operations and cash flow.

We are required to comply with financial and operating covenants under these credit facilities and debt securities. We routinely review the covenants based on actual and forecast results and have the ability to make changes to our development plans, capital structure and/or dividend policy to comply with covenants under the credit facilities. If Suncor does not comply with the covenants under its credit facilities and debt securities, repayment could be required and/or the company's access to capital could be restricted or only be available on unfavourable terms, all of which could have a material adverse effect on Suncor's business, financial condition, results of operations and cash flow.

Suncor's debt instruments are rated by various credit rating agencies. These ratings affect Suncor's ability to gain access to reasonably priced debt financing. If any of Suncor's credit rating agencies downgrade Suncor's debt instruments, it may restrict Suncor's ability to issue debt and may also increase the cost of borrowing, including under existing credit facilities.

Rating agencies regularly evaluate the company and our subsidiaries. Their ratings of our long-term and short-term debt are based on a number of factors, including our financial strength, as well as factors not entirely within our control, including conditions affecting the oil and gas industry generally, and the wider state of the economy. We cannot be assured that one or more of our credit ratings will not be downgraded. Our borrowing costs and ability to raise funds are directly impacted by our credit ratings. In addition, credit ratings may be important to customers or counterparties when we compete in certain markets and when we seek to engage in certain transactions, including transactions involving over-the-counter derivatives.

A credit-rating downgrade could potentially limit our access to private and public credit markets and increase the costs of borrowing under existing facilities. A reduction in our credit ratings also could have a significant impact on certain trading revenues, particularly in those businesses where counterparty creditworthiness is critical. It could trigger collateralization requirements related to physical and financial derivative liabilities with certain marketing counterparties and facility construction contracts. The occurrence of any of the foregoing could adversely affect our ability to execute portions of our business strategy and could have a material adverse effect on our liquidity and capital position.

Dividends

Our payment of future dividends on our common shares will be dependent on, among other things, our financial condition, results of operations, cash flow, the need for funds to finance ongoing operations, debt covenants and other business considerations as the company's Board considers relevant. There can be no assurance that we will continue to pay dividends in the future, at current levels, or at all.

Competition

The global petroleum industry is highly competitive in many aspects, including the exploration for and the development of new sources of supply, the acquisition of crude oil and natural gas interests, and the refining, distribution and

SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014    75

marketing of refined petroleum products. We compete in virtually every aspect of our business with other energy companies. The petroleum industry also competes with other industries in supplying energy, fuel and related products to consumers. We believe the primary competition for our crude oil production is other major international oil and natural gas producers and integrated companies.

For Suncor's Oil Sands segment, a number of other companies have entered, or have indicated their intention to enter, the oil sands business and begin producing bitumen and SCO, or expand their existing operations. It is difficult to assess the number, level of production and ultimate timing of all potential new projects or when existing production levels may increase. During recent years, a global focus on the oil sands through increasing industry consolidation that has created competitors with financial capacity has significantly increased the supply of bitumen, SCO and heavy crude oil in the marketplace. The impact of this level of activity on regional infrastructure, including pipelines, has placed stress on the availability and cost of all resources required to build and run new and existing oil sands operations.

For Suncor's Refining and Marketing businesses, management expects that fluctuations in demand for refined products, margin volatility and overall marketplace competitiveness will continue. In addition, to the extent that our downstream business unit participates in new product markets, it could be exposed to margin risk and volatility from either cost and/or selling price fluctuations.

Land Claims

First Nations people have claimed Aboriginal title and rights to portions of Western Canada. In addition, First Nations people have filed claims against industry participants relating in part to land claims, which may affect our business. At the present time, we are unable to assess the effect, if any, that these land claims may have on our business.

Control Environment

Based on their evaluation as of December 31, 2013, our CEO and Interim Chief Financial Officer concluded that our 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 our 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 controls over financial reporting and will make any modifications from time-to-time as deemed necessary.

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

Based on their inherent limitations, disclosure controls and procedures and internal controls 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.

DIVIDENDS

The Board of Directors has established a policy of paying dividends on a quarterly basis. We review our dividend policy from time-to-time with regard to our financial position, financing requirements for growth, cash flow and other factors which our Board of Directors considers relevant. The Board approved an increase in the quarterly dividend to $0.20 per share from $0.13 per share in the second quarter of 2013. In February 2014, the Board of Directors approved a per share increase of $0.03 to Suncor's quarterly dividend to $0.23 per common share. Dividends are paid subject to applicable law, if, as and when declared by the Board.

Year ended December 31   2013   2012   2011  
Cash dividends per common share ($)   0.73   0.50   0.43  

76   SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014

DESCRIPTION OF CAPITAL STRUCTURE

The company's authorized share capital is comprised of an unlimited number of common shares, an unlimited number of preferred shares issuable in series designated as senior preferred shares, and an unlimited number of preferred shares issuable in series designated as junior preferred shares.

As at December 31, 2013, there were 1,478,315,069 common shares issued and outstanding. To the knowledge of the Board of Directors and executive officers of Suncor, no person beneficially owns, or exercises control or direction over, securities carrying 10% or more of the voting rights attached to any class of voting securities of the company. The holders of common shares are entitled to attend all meetings of shareholders and vote at any such meeting on the basis of one vote for each common share held. As no senior preferred shares or junior preferred shares are issued and outstanding, common shareholders are entitled to receive any dividend declared by the Board on the common shares and to participate in a distribution of the company's assets among its shareholders for the purpose of winding up its affairs. The holders of the common shares shall be entitled to share equally, share for share, in all distributions of such assets.

Petro-Canada Public Participation Act

The Petro-Canada Public Participation Act requires that the Articles of Suncor include certain restrictions on the ownership and voting of voting shares of the company. The common shares of Suncor are voting shares. No person, together with associates of that person, may subscribe for, have transferred to that person, hold, beneficially own or control otherwise than by way of security only, or vote in the aggregate, voting shares of Suncor to which are attached more than 20% of the votes attached to all outstanding voting shares of Suncor. Additional restrictions include provisions for suspension of voting rights, forfeiture of dividends, prohibitions against share transfer, compulsory sale of shares, and redemption and suspension of other shareholder rights. The Board may at any time require holders of, or subscribers for, voting shares, and certain other persons, to furnish statutory declarations as to ownership of voting shares and certain other matters relevant to the enforcement of the restrictions. Suncor is prohibited from accepting any subscription for, and issuing or registering a transfer of, any voting shares if a contravention of the individual ownership restrictions results.

Suncor's Articles, as required by the Petro-Canada Public Participation Act, also include provisions requiring Suncor to maintain its head office in Calgary, Alberta; prohibiting Suncor from selling, transferring or otherwise disposing of all or substantially all of its assets in one transaction, or several related transactions, to any one person or group of associated persons, or to non-residents, other than by way of security only in connection with the financing of Suncor; and requiring Suncor to ensure (and to adopt, from time-to-time, policies describing the manner in which Suncor will fulfil the requirement to ensure) that any member of the public can, in either official language of Canada (English or French), communicate with and obtain available services from Suncor's head office and any other facilities where Suncor determines there is significant demand for communication with, and services from, that facility in that language.

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. 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 for growth projects or access to the capital markets, may affect the company's ability, and the cost, to enter into normal course derivative or hedging transactions and may require the company to post additional collateral under certain contracts.

The following table shows the ratings issued by the rating agencies noted therein as of December 31, 2013. The credit ratings are not recommendations to purchase, hold or sell the debt securities inasmuch as such ratings do not comment as to the market price or suitability for a particular investor. Any rating may not remain in effect for any given period of time or may be revised or withdrawn entirely by a rating agency in the future if, in its judgment, circumstances so warrant.

    Senior
Unsecured		   Outlook   Cdn
Commercial
Paper
Program		   US
Commercial
Paper
Program		  
Standard & Poor's (S&P)   BBB+   Stable   A-1 (low)   A-2  
Dominion Bond Rating Service (DBRS)   A (low)   Stable   R-1 (low)   R-1 (low)  
Moody's Investors Service (Moody's)   Baa1   Stable   Not rated   P-2  

SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014    77

S&P credit ratings on long-term debt are on a rating scale that ranges from AAA to D, representing the range of such securities rated from highest to lowest quality. A rating of BBB by S&P is the fourth highest of 10 categories and indicates that the obligor had adequate capacity to meet its financial commitments. However, adverse economic conditions or changing circumstances are more likely to lead to a weakened capacity of the obligor to meet its financial commitment on the obligation. The addition of a plus (+) or minus (-) designation after the rating indicates the relative standing within a particular rating category. S&P credit ratings on commercial paper are on a short-term debt rating scale that ranges from A-1 to D, representing the range of such securities rated from highest to lowest quality. A Canadian rating by S&P of A-1 (low) is the third highest of eight categories and a US rating of A-2 is the second highest of six categories, indicating a slightly higher susceptibility to the adverse effects of changes in circumstances and economic conditions, although the obligor's capacity to meet its financial commitment on the obligation is satisfactory.

DBRS credit ratings on long-term debt are on a rating scale that ranges from AAA to D, representing the range of such securities rated from highest to lowest. A rating of A by DBRS is the third highest of 10 categories and is assigned to debt securities considered to be of good credit quality, with the capacity for the payment of financial obligations being substantial, but of a lesser credit quality than an AA rating. Entities in the A category may be vulnerable to future events, but qualifying negative factors are considered manageable. All rating categories other than AAA and D also contain designations for (high) and (low). The absence of either a (high) or (low) designation indicates the rating is in the middle of the category. The assignment of a (high) or (low) designation within a rating category indicates relative standing within that category. DBRS's credit ratings on commercial paper are on a short-term debt rating scale that ranges from R-1 (high) to D, representing the range of such securities rated from highest to lowest quality. A rating of R-1 (low) by DBRS is the third highest of 10 categories and is assigned to debt securities considered to be of good credit quality. The capacity for the payment of short-term financial obligations as they become due is substantial, with overall strength not as favourable as higher rating categories. Entities in this category may be vulnerable to future events, but qualifying negative factors are considered manageable. The R-1 and R-2 commercial paper categories are denoted by (high), (middle) and (low) designations.

Moody's credit ratings are on a long-term debt rating scale that ranges from Aaa to C, which represents the range from highest to lowest quality of such securities rated. A rating of Baa by Moody's is the fourth highest of nine categories. Obligations rated Baa are subject to moderate credit risk. They are considered medium grade and, as such, may possess certain speculative characteristics. For certain ratings, Moody's appends numerical modifiers 1, 2 or 3 to each generic rating classification. The modifier 1 indicates that the obligation ranks in the higher end of its generic rating category; the modifier 2 indicates a mid-range ranking; and the modifier 3 indicates a ranking in the lower end of that generic rating category. A rating of P-2 by Moody's for commercial paper is the second highest of four rating categories and indicates a strong ability to repay short-term obligations.

Suncor has paid each of S&P, DBRS and Moody's their customary fees in connection with the provision of the above ratings. Suncor has not made any payments to S&P, DBRS or Moody's in the past two years for services unrelated to the provision of such ratings.

78   SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014

MARKET FOR SECURITIES

Our common shares are listed on the TSX in Canada and on the NYSE in the U.S. The price ranges and the volumes traded on the TSX for the year ended December 31, 2013, are as follows:

TSX

    Price Range (Cdn$)
   Trading Volume  
    High   Low   (000s)  
2013              
January   34.80   33.01   59 296  
February   34.55   30.70   69 971  
March   31.99   30.22   68 772  
April   31.44   27.50   83 966  
May   33.30   30.36   112 344  
June   32.02   29.85   85 764  
July   33.50   30.79   61 754  
August   36.76   32.78   58 751  
September   37.63   35.71   58 701  
October   38.56   35.61   54 509  
November   38.27   35.85   54 542  
December   37.81   35.21   53 796  

For information in respect of options to purchase common shares of Suncor and common shares issued upon the exercise of options, see the Share Capital note to the 2013 audited Consolidated Financial Statements, which is incorporated by reference into this AIF.

SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014    79

DIRECTORS AND EXECUTIVE OFFICERS

Directors

The following individuals are directors of Suncor on the date hereof. The term of each director is from the date of the meeting at which he or she is elected or appointed until the next annual meeting of shareholders or until a successor is elected or appointed.

Suncor Directors
Name and Jurisdiction of Residence		   Period Served and
Independence		   Biography  
Mel E. Benson(1)(2)
Alberta, Canada		   Director since 2000
Independent		   Mel Benson is president of Mel E. Benson Management Services Inc., an international consulting firm working in various countries with a focus on First Nations/corporate negotiations. Mr. Benson is also part owner of the private oil and gas company Tenax Energy Inc. and sits on the board of the Fort McKay Group of Companies, a community trust organization, as well as ECM Energy Services, Inc., based in Phoenix, Arizona. Mr. Benson retired from Exxon International and Imperial Oil Canada in 2000 after a long career as an operations manager and senior member of project management. While based in Houston, Texas, Mr. Benson worked on international projects based in Africa and the former Soviet Union. Mr. Benson recently became a member of the community advisory board for the Alberta Land Institute through the University of Alberta. Mr. Benson is a member of Beaver Lake Cree Nation, located in northeast Alberta.  
Dominic D`Alessandro(3)(4)
Ontario, Canada		   Director since 2009
Independent		   Dominic D'Alessandro was president and chief executive officer of Manulife Financial Corporation from 1994 to 2009 and is currently a director of CGI Group Inc. and Canadian Imperial Bank of Commerce (CIBC)(5). For his many business accomplishments, Mr. D'Alessandro was recognized as Canada's Most Respected CEO in 2004 and CEO of the Year in 2002, and was inducted into the Insurance Hall of Fame in 2008. Mr. D'Alessandro is an Officer of the Order of Canada and has been appointed as a Commendatore of the Order of the Star of Italy. In 2009, he received the Woodrow Wilson Award for Corporate Citizenship and in 2005 was granted the Horatio Alger Award for community leadership. Mr. D'Alessandro is a FCA, and holds a Bachelor of Science from Concordia University in Montreal. He has also been awarded honorary doctorates from York University, the University of Ottawa, Ryerson University and Concordia University.  
John T. Ferguson
Alberta, Canada		   Director since 1995
Independent		   John Ferguson is founder and chairman of the board of Princeton Developments Ltd. and Princeton Ventures Ltd. Mr. Ferguson is also a director of Fountain Tire Ltd. and Strategy Summit Ltd. In addition, he is a member of the Order of Canada, an advisory member of the Canadian Institute for Advanced Research, Honorary Colonel – South Alberta Light Horse, a member of the Advisory Council for Promoting Women on Boards, chancellor emeritus and chairman emeritus of the University of Alberta and chair of the advisory board of the Peter Lougheed Leadership Initiative. Mr. Ferguson is a fellow of the Alberta Institute of Chartered Accountants and of the Institute of Corporate Directors.  

80   SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014

W. Douglas Ford(1)(4)
Florida, USA		   Director since 2004
Independent		   W. Douglas Ford was chief executive, refining and marketing for BP p.l.c. (BP) from 1998 to 2002 and was responsible for the refining, marketing and transportation network of BP as well as the aviation fuels business, the marine business and BP shipping. Mr. Ford currently serves as a director of USG Corporation (USG)(6) and Air Products and Chemicals, Inc. He is also a member of the board of trustees of the University of Notre Dame.  
John D. Gass
Florida, USA		   Director since 2014
Independent		   John Gass is former vice president, Chevron Corporation, a major integrated oil and gas company, and former president, Chevron Gas and Midstream, positions he held from 2003 until his retirement in 2012. He has extensive international experience, having served in a diverse series of operational positions in the oil and gas industry with increasing responsibility throughout his career. Mr. Gass serves as a director of Southwestern Energy Co. and Weatherford International Ltd. He is also on the board of visitors for the Vanderbilt School of Engineering and is a member of the advisory board for the Vanderbilt Eye Institute. Mr. Gass graduated from Vanderbilt University in Nashville, Tennessee, with a bachelor's degree in civil engineering. He also holds a master's degree in civil engineering from Tulane University in New Orleans, Louisiana. A resident of Florida, he is a member of the American Society of Civil Engineers and the Society of Petroleum Engineers.  
Paul Haseldonckx(2)(3)
Essen, Germany		   Director since 2002
(Petro-Canada 2002 to July 31, 2009)
Independent		   Paul Haseldonckx was a member of the management board of Veba Oel AG (Veba), Germany's largest downstream oil and gas company, including Aral AG gas stations in Europe. Mr. Haseldonckx represented Veba's interests at the board of the Cerro Negro joint venture, an in situ oil sands development including an upgrader, during the construction and early production phase. Mr. Haseldonckx holds a Master of Science and has completed Executive Programs at INSEAD, Fontainebleau and IMD, Lausanne.  
John R. Huff(1)(2)
Texas, USA		   Director since 1998
Independent		   John Huff is chairman of Oceaneering International Inc., an oilfield services company. He also serves as a director of KBR Inc. and as a director of Hi Crush Partners LP.  

SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014    81

Jacques Lamarre(2)(3)
Quebec, Canada		   Director since 2009
Independent		   Jacques Lamarre is past president and chief executive officer of SNC-Lavalin, a position he held from May 1996 until his retirement in May 2009. Mr. Lamarre is an Officer of the Order of Canada and a founding member and past chair of the Commonwealth Business Council. He is also past chair of the board of directors of the Conference Board of Canada and a founding member of the World Economic Forum's Governors for Engineering & Construction. Currently, he serves as a director of PPP Canada Inc. and is a member of the Engineering Institute of Canada, Engineers Canada and the Ordre des ingénieurs du Québec. Mr. Lamarre holds a Bachelor of Arts and a Bachelor of Arts and Science in Civil Engineering from Université Laval in Quebec City. He also completed Harvard University's Executive Development Program. In addition, Mr. Lamarre holds honorary doctorates from the University of Waterloo, the University of Moncton and Université Laval. Among others, he has previously served on the board of the Royal Bank of Canada.  
Maureen McCaw(1)(2)
Alberta, Canada		   Director since 2004
(Petro-Canada 2004 to July 31, 2009)
Independent		   Maureen McCaw is past executive vice-president (Edmonton) of Leger Marketing, formerly Criterion Research Corp., a company she founded in 1986. Ms. McCaw holds a Bachelor of Arts from the University of Alberta and an Institute of Corporate Directors certification (ICD.D). In addition to being president of Tinnakilly Inc. and a managing partner at Prism Ventures, Ms. McCaw is a director of the Canadian Broadcasting Corporation, and the Edmonton International Airport, and a member of the Alberta Securities Commission. Ms. McCaw also serves on a number of Alberta boards and advisory committees, including the Nature Conservancy of Canada (Alberta) and the Epcor Community Essentials Council and is past chair of the Edmonton Chamber of Commerce.  
Michael W. O'Brien(3)(4)
Alberta, Canada		   Director since 2002
Independent		   Michael O'Brien served as executive vice president, corporate development, and chief financial officer of Suncor Energy Inc. before retiring in 2002. Mr. O'Brien is lead director of Shaw Communications Inc. In addition, he is past chair of the board of trustees for the Nature Conservancy Canada, past chair of the Canadian Petroleum Products Institute and past chair of Canada's Voluntary Challenge for Global Climate Change. He has previously served on the boards of Teresen Inc., Primewest Energy Inc. and CRA International.  
James Simpson(1)(4)
Alberta, Canada		   Director since 2004
(Petro -Canada 2004 to July 31, 2009)
Independent		   James Simpson is past president of Chevron Canada Resources (oil and gas). He serves as lead director for Canadian Utilities Limited and is on its Corporate Governance, Nomination, Compensation and Succession Committee, as well as being the chairman for its Audit Committee and Risk Review Committee. Mr. Simpson holds a Bachelor of Science and Master of Science, and graduated from the Program for Senior Executives at M.I.T.'s Sloan School of Business. He is also past chairman of the Canadian Association of Petroleum Producers and past vice chairman of the Canadian Association of the World Petroleum Congresses.  

82   SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014

Eira M. Thomas(3)(4)
British Columbia, Canada		   Director since 2006
Independent		   Eira Thomas is a Canadian geologist with over 20 years of experience in the Canadian diamond business, including her previous roles as vice president of Aber Resources, now Dominion Diamond Corp., and as founder and CEO of Stornoway Diamond Corp. Currently, Ms. Thomas is chief executive officer and a director of Kaminak Gold Corporation, and a director of Lucara Diamond Corp. and Dundee Precious Metals Inc. (Dundee)(7). She also serves on the board of the Prospectors and Developers Association of Canada.  
Steven W. Williams
Alberta, Canada		   Director since December 2011
Non-independent, management		   Steve Williams has served as the President of Suncor Energy Inc. since December 2011 and as Chief Executive Officer of Suncor Energy Inc. since May 2012. Mr. Williams is a fellow of the Institution of Chemical Engineers and is a member of the Institute of Directors. He is also one of twelve founding CEOs in Canada's Oil Sands Innovation Alliance, a member of the Canadian Council of Chief Executives and a member of the Business Advisory Council, School of Business at the University of Alberta.  
Michael M. Wilson
Alberta, Canada		   Director since 2014
Independent		   Michael Wilson is former president and chief executive officer of Agrium Inc., a retail supplier of agricultural products and services and a wholesale producer and marketer of agricultural nutrients, which is headquartered in Calgary, a position he held from 2003 until his retirement in 2013. He previously served as executive vice president and chief operating officer. Mr. Wilson has significant experience in the petrochemical industry, serving as president of Methanex Corporation, and holding various positions with increasing responsibility in North America and Asia with Dow Chemical Company. Mr. Wilson has a bachelor's degree in chemical engineering from the University of Waterloo and currently serves on the boards of Agrium Inc. (Agrium)(8), Celestica Inc. and Finning International Inc. He is also the chair of the Calgary Prostate Cancer Foundation.  
(1)
Human Resources and Compensation Committee

(2)
Environment, Health, Safety and Sustainable Development Committee

(3)
Audit Committee

(4)
Governance Committee

(5)
Mr. D'Alessandro has indicated that he will not stand for re-election as a director of CIBC at CIBC's next annual meeting.

(6)
Mr. Ford has indicated that he will not stand for re-election as a director of USG at USG's next annual meeting.

(7)
Ms. Thomas has indicated that she will not stand for re-election as a director of Dundee at Dundee's next annual meeting scheduled for May 7, 2014.

(8)
Mr. Wilson has indicated that he will not stand for re-election as a director of Agrium at Agrium's next annual meeting.

SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014    83

Executive Officers

The following individuals are the executive officers of Suncor:

Name   Jurisdiction of Residence   Office  
Steven W. Williams   Alberta, Canada   President and Chief Executive Officer  
Stephen D.L. Reynish   Alberta, Canada   Executive Vice President, Strategy & Corporate Development and Interim Chief Financial Officer  
Eric Axford   Alberta, Canada   Executive Vice President, Business Services  
Mark Little   Alberta, Canada   Executive Vice President, Upstream  
Mike MacSween   Alberta, Canada   Executive Vice President, Major Projects  
Kris Smith   Ontario, Canada   Executive Vice President, Refining and Marketing  
Paul Gardner   Alberta, Canada   Senior Vice President, Human Resources  
Janice Odegaard   Alberta, Canada   Senior Vice President, General Counsel and Corporate Secretary  

As at February 24, 2014, the directors and executive officers of Suncor as a group beneficially owned, or controlled or directed, directly or indirectly, common shares of Suncor representing 0.05% of outstanding common shares.

Cease Trade Orders, Bankruptcies, Penalties or Sanctions

As at the date hereof, no director or executive officer of Suncor is or has been within the last ten years a director, chief executive officer or chief financial officer of a company that:

(a)
was the subject of a cease trade or similar order, or an order that denied the relevant company access to any exemption under securities legislation that was in effect for a period of more than 30 consecutive days while the director or executive officer was acting in that capacity; or

(b)
was subject to a cease trade order or similar order, or an order that denied the relevant company access to any exemption under securities legislation that was in effect for a period of more than 30 consecutive days, that was issued after the director or executive officer ceased to be a director, chief executive officer or chief financial officer and which resulted from an event that occurred while that person was acting in that capacity.

As at the date hereof, no director or executive officer of Suncor, or any of their respective personal holding companies, nor any shareholders holding a sufficient number of securities to affect materially the control of Suncor:

(a)
is, or has been within the last ten years, a director or executive officer of any company (including Suncor) that, while that person was acting in that capacity, or within a year of that person ceasing to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets, other than Mr. Ford, a director of Suncor who is currently a director of USG Corporation, which was in bankruptcy protection until June 2006 and who was also a director of United Airlines (until February 2006), which was in Chapter 11 bankruptcy protection until February 2006; or

(b)
has, within the last ten years, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or become subject to or instituted any proceedings, arrangement or compromise with creditors, or had a receiver, receiver manager or trustee appointed to hold the assets of the director, executive officer or shareholder.

No director or executive officer of Suncor has been subject to:

(a)
any penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory authority or has entered into a settlement agreement with a securities regulatory authority; or

(b)
any other penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor in making an investment decision.

84   SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014

AUDIT COMMITTEE INFORMATION

The Audit Committee Mandate is attached as Schedule "A" to this AIF.

Composition of the Audit Committee

The Audit Committee is comprised of Mr. O'Brien (Chairman), Mr. D'Alessandro, Mr. Lamarre, Mr. Haseldonckx and Ms. Thomas. All members are independent and financially literate. The education and expertise of each member is described in the Directors and Executive Officers section of this AIF.

For the purpose of making appointments to the company's Audit Committee, and in addition to the independence requirements, all directors nominated to the Audit Committee must meet the test of financial literacy as determined in the judgment of the Board of Directors. Also, at least one director so nominated must meet the test of financial expert as determined in the judgment of the Board of Directors. The designated financial experts on the Audit Committee are Mr. O'Brien and Mr. D'Alessandro.

Financial Literacy

Financial literacy can be generally defined as the ability to read and understand a balance sheet, an income statement and a cash flow statement. In assessing a potential appointee's level of financial literacy, the Board of Directors must evaluate the totality of the individual's education and experience, including:

•
the level of the person's accounting or financial education, including whether the person has earned an advanced degree in finance or accounting;

•
whether the person is a professional accountant, or the equivalent, in good standing, and the length of time that the person actively has practiced as a professional accountant, or the equivalent;

•
whether the person is certified or otherwise identified as having accounting or financial experience by a recognized private body that establishes and administers standards in respect of such expertise, whether that person is in good standing with the recognized private body, and the length of time that the person has been actively certified or identified as having this expertise;

•
whether the person has served as a principal financial officer, controller or principal accounting officer of a corporation that, at the time the person held such position, was required to file reports pursuant to securities laws and, if so, for how long;

•
the person's specific duties while serving as a public accountant, auditor, principal financial officer, controller, principal accounting officer or position involving the performance of similar functions;

•
the person's level of familiarity and experience with all applicable laws and regulations regarding the preparation of financial statements that must be included in reports filed under securities laws;

•
the level and amount of the person's direct experience reviewing, preparing, auditing or analyzing financial statements that must be included in reports filed under provisions of securities laws;

•
the person's past or current membership on one or more audit committees of companies that, at the time the person held such membership, were required to file reports pursuant to provisions of securities laws;

•
the person's level of familiarity and experience with the use and analysis of financial statements of public companies; and

•
whether the person has any other relevant qualifications or experience that would assist him or her in understanding and evaluating the company's financial statements and other financial information and to make knowledgeable and thorough inquiries whether the financial statements fairly present the financial condition, results of operations and cash flows of the company in accordance with generally accepted accounting principles, or whether the financial statements and other financial information, taken together, fairly present the financial condition, results of operations and cash flows of the company.

Audit Committee Financial Expert

An "Audit Committee Financial Expert" means a person who, in the judgment of the Board of Directors, has the following attributes:

(a)
an understanding of Canadian generally accepted accounting principles and financial statements;

(b)
the ability to assess the general application of such principles in connection with the accounting for estimates, accruals, and provisions;

(c)
experience preparing, auditing, analyzing or evaluating financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of issues that can reasonably be expected to be raised by Suncor's financial statements, or experience actively supervising one or more persons engaged in such activities;

(d)
an understanding of internal controls and procedures for financial reporting; and

(e)
an understanding of audit committee functions.

SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014    85

A person shall have acquired the attributes referred to in items (a) through (e) above through:

(a)
education and experience as a principal financial officer, principal accounting officer, controller, public accountant or auditor, or experience in one or more positions that involve the performance of similar functions;

(b)
experience actively supervising a principal financial officer, principal accounting officer, controller, public accountant, auditor or person performing similar functions;

(c)
experience overseeing or assessing the performance of companies or public accountants with respect to the preparation, auditing or evaluation of financial statements; or

(d)
other relevant experience.

Audit Committee Pre-Approval Policies for Non-Audit Services

Our Audit Committee has considered whether the provision of services other than audit services is compatible with maintaining our auditors' independence and has a policy governing the provision of these services. A copy of our policy relating to Audit Committee approval of fees paid to our auditors, in compliance with the Sarbanes-Oxley Act of 2002 and applicable Canadian law, is attached as Schedule "B" to this AIF.

Fees Paid to Auditors

Fees paid or payable to PricewaterhouseCoopers LLP, the company's auditors are as follows:

($ thousands)   2013   2012  
Audit Fees   6 108   5 904  
Audit-Related Fees   519   429  
Tax Fees   50   50  
All Other fees   60   125  
Total   6 737   6 508  

Audit Fees were paid, or are payable, for professional services rendered by the auditors for the audit of Suncor's annual financial statements, or services provided in connection with statutory and regulatory filings or engagements. Audit-Related Fees were paid for professional services rendered by the auditors for the review of quarterly financial statements and for the preparation of reports on specified procedures as they relate to audits of joint arrangements and attest services not required by statute or regulation. Tax Fees for corporate tax filings and tax planning were paid in a foreign jurisdiction where Suncor has limited activity. All Other Fees were subscriptions to auditor-provided and supported tools. All services described beside the captions "Audit Fees", "Audit-Related Fees", "Tax Fees" and "All Other Fees" were approved by the Audit Committee in compliance with paragraph (c)(7)(i) of Rule 2-01 of Regulation S-X under the U.S. Securities and Exchange Act of 1934, as amended (the Exchange Act). None of the fees described above were approved by the Audit Committee pursuant to paragraph (c)(7)(i)(C) of Regulation S-X under the Exchange Act.

86   SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

There are no legal proceedings in respect of which we are or were a party to, or in respect of which any of our property is or was the subject during the year ended December 31, 2013, nor are there any such proceedings known by us to be contemplated, that involve a claim for damages exceeding 10% of our current assets. In addition, there have not been any (a) penalties or sanctions imposed against the company by a court relating to securities legislation or by a securities regulatory authority during the year ended December 31, 2013, (b) any other penalties or sanctions imposed by a court or regulatory body against the company that would likely be considered important to a reasonable investor in making an investment decision, or (c) settlement agreements entered into by the company before a court relating to securities legislation or with a securities regulatory authority during the year ended December 31, 2013.

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

No director or executive officer, or any associate or affiliate of these persons has, or has had, any material interest, direct or indirect, in any transaction or any proposed transaction that has materially affected or is reasonably expected to materially affect us within the three most recently completed financial years or during the current financial year.

TRANSFER AGENT AND REGISTRAR

The transfer agent and registrar for our common shares is Computershare Trust Company of Canada at its principal offices in Calgary, Alberta, Montreal, Quebec, Toronto, Ontario and Vancouver, British Columbia and Computershare Trust Company Inc. in Denver, Colorado.

MATERIAL CONTRACTS

During the year ended December 31, 2013, we have not entered into any contracts, nor are there any contracts still in effect, that are material to our business, other than contracts entered into in the ordinary course of business, which are not required to be filed by Section 12.2 of National Instrument 51-102 Continuous Disclosure Obligations.

INTERESTS OF EXPERTS

Reserves and resources estimates contained in this AIF are based in part upon reports prepared by GLJ and Sproule, Suncor's independent qualified reserves evaluators. As at the date hereof, none of the partners, employees or consultants of GLJ or Sproule, respectively, as a group, through registered or beneficial interests, direct or indirect, held or are entitled to receive more than 1% of any class of our outstanding securities, including the securities of our associates and affiliates.

The company's independent auditors are PricewaterhouseCoopers LLP, Chartered Accountants, who have issued an independent auditor's report dated February 24, 2014 in respect of the Corporation's Consolidated Financial Statements, which comprise the Consolidated Balance Sheets as at December 31, 2013 and December 31, 2012 and the Consolidated Statements of Comprehensive Income, Changes in Shareholders' Equity and Cash Flows for the years ended December 31, 2013 and December 31, 2012, and the related notes, and the Corporation's internal control over financial reporting as at December 31, 2013. PricewaterhouseCoopers LLP has advised that they are independent with respect to the company within the meaning of the Rules of Professional Conduct of the Institute of Chartered Accountants of Alberta and the rules of the United States Securities and Exchange Commission.

SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014    87

DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NEW YORK
STOCK EXCHANGE

As a Canadian issuer listed on the NYSE, we are not required to comply with most of the NYSE's rules and instead may comply with Canadian requirements. As a foreign private issuer, we are only required to comply with four of the NYSE's rules. These rules provide that: (i) Suncor must have an audit committee that satisfies the requirements of Rule 10A-3 under the Exchange Act; (ii) the Chief Executive Officer of Suncor must promptly notify the NYSE in writing after an executive officer becomes aware of any material non-compliance with the applicable NYSE rules; (iii) Suncor must provide a brief description of any significant differences between our corporate governance practices and those followed by U.S. companies listed under the NYSE; and (iv) Suncor must provide annual, and as required, written affirmations of compliance with applicable NYSE Corporate Governance rules. The company has disclosed in its 2014 management proxy circular, which is available on our website at www.suncor.com, that, in certain instances, it is not required to obtain shareholder approval for material amendments to equity compensation plans and that Suncor, while in compliance with the independence requirements of applicable securities laws in Canada (specifically National Instrument 52-110 Audit Committees) and the U.S. (specifically Rule 10A-3 of the Exchange Act), it has not adopted, and is not required to adopt, the director independence standards contained in Section 303A.02 of the NYSE's Listed Company Manual, including with respect to its audit committee and compensation committee. The Board has not adopted, nor is it required to adopt, procedures to implement Section 303A.05(c)(iv) of the NYSE's Listed Company Manual in respect of compensation committee advisor independence. Except as described herein, the company is in compliance with the NYSE Corporate Governance standards in all other significant respects.

ADDITIONAL INFORMATION

Additional information, including directors' and officers' remuneration and indebtedness, principal holders of our securities, and securities authorized for issuance under equity compensation plans, where applicable, is contained in our most recent management proxy circular for our most recent annual meeting of our shareholders that involved the election of directors. Additional financial information is provided in our 2013 audited Consolidated Financial Statements for our most recently completed financial year and in the MD&A.

Further information about Suncor, filed with Canadian securities commissions and the SEC, including periodic quarterly and annual reports and the 40-F is available online on SEDAR at www.sedar.com and on EDGAR at www.sec.gov. In addition, our Standards of Business Conduct Code is available online at www.suncor.com. Information contained in or otherwise accessible through our website does not form part of this AIF, and is not incorporated into the AIF by reference.

88   SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014

ADVISORY – FORWARD-LOOKING INFORMATION

This AIF contains certain forward-looking information and forward-looking statements (collectively referred to herein as "forward-looking statements") within the meaning of applicable Canadian and U.S. securities laws. Forward-looking statements and other information is 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 AIF include references to:

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

•
The continuation of the debottlenecking project of existing central processing facilities at MacKay River in 2014 that will increase bitumen processing capacity by 20% by the end of 2015 to a total capacity of 38 mbbls/d; and

•
The TROTM process is expected to accelerate and improve the company's tailings management processes, eliminate the need for new tailings ponds at existing mining operations, and, in the years ahead, reduce the number of tailings ponds presently in operation.

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

•
The next scheduled turnaround at Oil Sands Operations is in 2016; and

•
At Terra Nova, the company plans to perform maintenance on several production wells and to reinstate a second flowline to a subsea drill centre in 2014.

Suncor's expectations about where future capital expenditures will be directed, the timing for completion of growth and other significant projects, and the results of such projects, including:

•
The company's expectations that the Voyageur South and Audet leases can be developed using mining techniques;

•
The company's expectations that the Meadow Creek, Lewis, Chard and Kirby leases can be developed using in situ techniques and that the company may undertake exploratory drilling programs;

•
That the company plans to drill 50 core holes at Lewis and 66 core holes at Meadow Creek in winter 2014;

•
The company plans to work towards a 2014 sanction decision of an additional central processing facility at MacKay River, which is targeted to have an initial design capacity of approximately 20 mbbls/d and first oil in 2017;

•
Plans for centrifuge technology at Syncrude that separates water from tailings;

•
The Fort Hills mining project is expected to produce first oil by the fourth quarter 2017 and is expected to achieve 90% of its planned production capacity of 180 mbbls/d (73 mbbls/d net to Suncor) within its first year;

•
The company's expected share of costs for the Fort Hills project are $5.5 billion and project activities for 2014 are expected to focus on detailed engineering, procurement and ramp-up of field construction activities;

•
Plans for the Joslyn North mining project, including 157 mbbls/d of bitumen production (gross);

•
Development plans for Terra Nova, which will include a production well and a water injection well that the company anticipates will add production and mitigate natural declines from the reservoir;

•
Development plans for the HSEU, which include drilling up to two additional production wells from the GBS platform and six water injection wells and that production from the HSEU is not expected to reach higher rates until 2015 when the planned water injection wells are completed;

•
That the number of production and injection wells required at HSEU may need to be revised as development proceeds and uncertainties about reservoir capability are resolved;

•
Development plans for the White Rose Extensions, including that the sanction is planned for the second half of 2014, that water injection infrastructure will be

SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014    89

•
Plans for Hebron that include a concrete GBS, integrated topsides deck, 1,200 mbbls of oil storage capacity, 52 well slots and a gross oil production capacity of 150 mbbls/d (net 34 mbbls/d to Suncor);

•
Suncor's share of the post-sanction project costs for the Hebron project will be approximately $2.8 billion and first oil is expected in 2017;

•
That three oil and gas development wells drilled at Buzzard in 2013 will mitigate natural declines from the reservoir;

•
Development plans for Golden Eagle, which include an initial gross production capacity of 70 mboe/d (19 mboe/d net to Suncor) from 21 development wells, gross development costs of £2 billion (Cdn$3.5 billion), (£0.6 billion (Cdn$1.0 billion) net to Suncor), and the company's expectations that first production will occur late in 2014 or early 2015;

•
Plans for the continued evaluation of and further appraisal drilling in 2014 for the Beta discovery;

•
Plans to commence drilling on an exploration well at the Myrhauk prospect late in 2014 and the Blackjack prospect during the first quarter of 2014;

•
That Suncor's estimated cost remaining on its Libya exploration work program committed at December 31, 2013 was US$349 million;

•
Suncor's expectation that rail transport to Montreal will increase to approximately 35 mbbls/d by the end of 2014;

•
The company expects to commission a second rail offloading facility in Tracy, Québec which is expected to enable access to eastern tide-waters for Oil Sands product and could commence as early as the second quarter of 2014; and

•
The company's expectation that construction of the Adelaide wind project will commence in the second quarter of 2014, that the Cedar Point project will continue to progress through the regulatory process in 2014, and that the two projects will add 140 MW of gross installed capacity, increasing the gross installed capacity of Suncor's wind projects by 55%.

Also:

•
The plan by Syncrude owners to develop mining areas adjacent to the current mine that would extend the life for Mildred Lake by approximately ten years, and that Syncrude expects to make regulatory applications for these areas in 2014;

•
The co-owners of Syncrude do not expect that the Aurora South mining area will come on-stream before 2024, when production from the Mildred Lake mining area is expected to be complete;

•
Suncor's plans to continue to pursue other opportunities in the North Sea, the Norwegian Sea and the Barents Sea;

•
Suncor's plans to continue to pursue opportunities in offshore Newfoundland and Labrador;

•
The compliance costs to Suncor in relation to SGER for 2014 are expected to be between $20 million and $25 million;

•
Significant development activities and costs anticipated to occur or be incurred in 2014;

•
Anticipated abandonment and reclamation costs;

•
Anticipated royalty and income tax rates and the impact of these rates on Suncor;

•
Anticipated effects of environmental and climate change legislation;

•
Suncor's plans around its reserves and resources;

•
Suncor's expectations that it will continue to engage the appropriate governmental bodies in meaningful dialogue in an effort to develop a harmonized system for GHG emissions regulations that focuses on achieving actual reduction goals and sustainable resource development;

•
Suncor's belief that it will have sufficient funds available to fund its planned expenditures for 2014;

•
Suncor's belief that existing cash balances, internally generated cash flows and existing credit facilities are sufficient to fund future development costs and that interest or other funding costs would not make development of any property uneconomical; and

•
Suncor's belief that it will be able to successfully defend its original filing position in relation to certain derivative contracts so that ultimately no increased income tax payable will result from CRA's position.

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

90   SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014


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, 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; and 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

SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014    91


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 AIF and in our MD&A. 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.

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SCHEDULE "A"
AUDIT COMMITTEE MANDATE

The Audit Committee

The bylaws of Suncor Energy Inc. provide that the Board of Directors may establish Board committees to whom certain duties may be delegated by the Board. The Board has established, among others, the Audit Committee, and has approved this mandate, which sets out the objectives, functions and responsibilities of the Audit Committee.

Objectives

The Audit Committee assists the Board of Directors by:

•
Monitoring the effectiveness and integrity of the Corporation's financial reporting systems, management information systems and internal control systems, and by monitoring financial reports and other financial matters.

•
Selecting, monitoring and reviewing the independence and effectiveness of, and where appropriate replacing, subject to shareholder approval as required by law, external auditors, and ensuring that external auditors are ultimately accountable to the Board of Directors and to the shareholders of the Corporation.

•
Reviewing the effectiveness of the internal auditors, excluding the Operations Integrity Audit department, which is specifically within the mandate of the Environment, Health & Safety Committee (references throughout this mandate to "Internal Audit" shall not include the Operations Integrity Audit department); and

•
Approving on behalf of the Board of Directors certain financial matters as delegated by the Board, including the matters outlined in this mandate.

The Committee does not have decision-making authority, except in the very limited circumstances described herein or where and to the extent that such authority is expressly delegated by the Board of Directors. The Committee conveys its findings and recommendations to the Board of Directors for consideration and, where required, decision by the Board of Directors.

Constitution

The Terms of Reference of Suncor's Board of Directors set out requirements for the composition of Board Committees and the qualifications for committee membership, and specify that the Chair and membership of the committees are determined annually by the Board. As required by Suncor's by-laws, unless otherwise determined by resolution of the Board of Directors, a majority of the members of a committee constitute a quorum for meetings of committees, and, in all other respects, each committee determines its own rules of procedure.

Functions and Responsibilities

The Audit Committee has the following functions and responsibilities:

Internal Controls

1.
Inquire as to the adequacy of the Corporation's system of internal controls, and review the evaluation of internal controls by Internal Auditors, and the evaluation of financial and internal controls by external auditors.

2.
Review management's monitoring of compliance with the Corporation's Standards of Business Conduct Code.

3.
Establish procedures for the confidential submission by employees of complaints relating to any concerns with accounting, internal control, auditing or Standards of Business Conduct Code matters, and periodically review a summary of complaints and their related resolution.

4.
Review the findings of any significant examination by regulatory agencies concerning the Corporation's financial matters.

5.
Periodically review management's governance processes for information technology resources, to assess their effectiveness in addressing the integrity, the protection and the security of the Corporation's electronic information systems and records.

6.
Review the management practices overseeing officers' expenses and perquisites.

External and Internal Auditors

7.
Evaluate the performance of the external auditors and initiate and approve the engagement or termination of the external auditors, subject to shareholder approval as required by applicable law.

8.
Review the audit scope and approach of the external auditors, and approve their terms of engagement and fees.

9.
Review any relationships or services that may impact the objectivity and independence of the external auditor, including annual review of the auditor's written statement of all relationships between the auditor (including its affiliates) and the Corporation; review and approve all engagements for non-audit services to be provided by external auditors or their affiliates.

10.
Review the external auditor's quality control procedures including any material issues raised by the most recent quality control review or peer review and any issues raised by a government authority or professional authority investigation of the external auditor, providing details on actions taken by the firm to address such issues.

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11.
Review and approve the appointment or termination of the Head of Internal Audit, annually review a summary of the remuneration of the Head of Internal Audit, and periodically review the performance and effectiveness of the Internal Audit function including compliance with The Institute of Internal Auditors' International Professional Practices Framework for Internal Auditing.

12.
Review the Internal Audit Department Charter, and the plans, activities, organizational structure and qualifications of the Internal Auditors, and monitor the department's independence.

13.
Provide an open avenue of communication between management, the Internal Auditors or the external auditors, and the Board of Directors.

Financial Reporting and other Public Disclosure

14.
Review the external auditor's management comment letter and management's responses thereto, and inquire as to any disagreements between management and external auditors or restrictions imposed by management on external auditors. Review any unadjusted differences brought to the attention of management by the external auditor and the resolution thereof.

15.
Review with management and the external auditors the financial materials and other disclosure documents referred to in paragraph 16, including any significant financial reporting issues, the presentation and impact of significant risks and uncertainties, and key estimates and judgements of management that may be material to financial reporting, including alternative treatments and their impacts.

16.
Review and approve the Corporation's interim consolidated financial statements and accompanying management's discussion and analysis ("MD&A"). Review and make recommendations to the Board of Directors on approval of the Corporation's annual audited financial statements and MD&A, Annual Information Form and Form 40-F. Review other material annual and quarterly disclosure documents or regulatory filings containing or accompanying audited or unaudited financial information.

17.
Authorize any changes to the categories of documents and information requiring audit committee review or approval prior to external disclosure, as set out in the Corporation's policy on external communication and disclosure of material information.

18.
Review any change in the Corporation's accounting policies.

19.
Review with legal counsel any legal matters having a significant impact on the financial reports.

Oil and Gas Reserves

20.
Review with reasonable frequency Suncor's procedures for:

(A)
the disclosure, in accordance with applicable law, of information with respect to Suncor's oil and gas activities, including procedures for complying with applicable disclosure requirements;

(B)
providing information to the qualified reserves evaluators (the "Evaluators") engaged annually by Suncor to evaluate Suncor's reserves data for the purpose of public disclosure of such data in accordance with applicable law.

21.
Annually approve the appointment and terms of engagement of the Evaluators, including the qualifications and independence of the Evaluators; review and approve any proposed change in the appointment of the Evaluators, and the reasons for such proposed change, including whether there have been disputes between the Evaluators and management.

22.
Annually review Suncor's reserves data and the report of the Evaluators thereon; annually review and make recommendations to the Board of Directors on the approval of (i) the content and filing by the Company of a statement of reserves data (the "Statement") and the report thereon of management and the directors to be included in or filed with the Statement, and (ii) the filing of the report of the Evaluators to be included in or filed with the Statement, all in accordance with applicable law.

Risk Management

23.
Periodically review the policies and practices of the Corporation respecting cash management, financial derivatives, financing, credit, insurance, taxation, commodities trading and related matters. Oversee the Board's risk management governance model by conducting periodic reviews with the objective of appropriately reflecting the principal risks of the Corporation's business in the mandate of the Board and its committees. Conduct periodic review of and provide oversight on the specific Suncor Principal Risks which have been delegated to the Committee for oversight.

Pension Plan

24.
Review the assets, financial performance, funding status, investment strategy and actuarial reports of the Corporation's pension plan including the terms of engagement of the plan's actuary and fund manager.

SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014    A-2

Security

25.
Review on a summary basis any significant physical security management, IT security or business recovery risks and strategies to address such risks.

Other Matters

26.
Conduct any independent investigations into any matters which come under its scope of responsibilities.

27.
Review any recommended appointees to the office of Chief Financial Officer.

28.
Review and/or approve other financial matters delegated specifically to it by the Board of Directors.

Reporting to the Board

29.
Report to the Board of Directors on the activities of the Audit Committee with respect to the foregoing matters as required at each Board meeting and at any other time deemed appropriate by the Committee or upon request of the Board of Directors.

Approved by resolution of the Board of Directors on November 19, 2013

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SCHEDULE "B" – SUNCOR ENERGY INC. POLICY AND PROCEDURES
FOR PRE-APPROVAL OF AUDIT AND NON-AUDIT SERVICES

Pursuant to the Sarbanes-Oxley Act of 2002 and Multilateral Instrument 52-110, the Securities and Exchange Commission (SEC) and the Ontario Securities Commission respectively have adopted final rules relating to audit committees and auditor independence. These rules require the Audit Committee of Suncor Energy Inc ("Suncor") to be responsible for the appointment, compensation, retention and oversight of the work of its independent auditor. The Audit Committee must also pre-approve any audit and non-audit services performed by the independent auditor or such services must be entered into pursuant to pre-approval policies and procedures established by the Audit Committee pursuant to this policy.

I.     Statement of Policy

The Audit Committee has adopted this Policy and Procedures for Pre-Approval of Audit and Non-Audit Services (the Policy), which sets forth the procedures and the conditions pursuant to which services proposed to be performed by the independent auditor will be pre-approved. The procedures outlined in this Policy are applicable to all Audit, Audit-Related, Tax Services and All Other Services provided by the independent auditor.

II.    Responsibility

Responsibility for the implementation of this Policy rests with the Audit Committee. The Audit Committee delegates its responsibility for administration of this policy to management. The Audit Committee shall not delegate its responsibilities to pre-approve services performed by the independent auditor to management.

III.   Definitions

For the purpose of these policies and procedures and any pre-approvals:

(a)
Audit Services include services that are a necessary part of the annual audit process and any activity that is a necessary procedure used by the auditor in reaching an opinion on the financial statements as is required under generally accepted auditing standards (GAAS), including technical reviews to reach audit judgment on accounting standards. The term Audit Services is broader than those services strictly required to perform an audit pursuant to GAAS and include such services as:

(i)
The issuance of comfort letters and consents in connections with offerings of securities;

(ii)
The performance of domestic and foreign statutory audits;

(iii)
Attest services required by statute or regulation;

(iv)
Internal control reviews; and

(v)
Assistance with and review of documents filed with the Canadian Securities Administrators, the SEC and other regulators having jurisdiction over Suncor and its subsidiaries, and responding to comments from such regulators;

(b)
Audit-Related Services are assurance (e.g. due diligence services) and related services traditionally performed by the external auditors, which are reasonably related to the performance of the audit or review of financial statements and not categorized under Audit Services for disclosure purposes.
(c)
Tax Services include, but are not limited to, services related to the preparation of corporate and/or personal tax filings, tax due diligence as it pertains to mergers, acquisitions and/or divestitures, and tax planning; and

(d)
All Other Services consist of any other work that is neither an Audit Service, nor an Audit-Related Service nor a Tax Service, the provision of which by the independent auditor is not expressly prohibited by Rule 2-01(c)(7) of Regulation S-X under the Securities and Exchange Act of 1934, as amended. (See Appendix A for a summary of the prohibited services.)

SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014    B-1

IV.   General Policy

The following general policy applies to all services provided by the independent auditor.

•
All services to be provided by the independent auditor will require specific pre-approval by the Audit Committee. The Audit Committee will not approve engaging the independent auditor for services that can reasonably be classified as Tax Services or All Other Services unless a compelling business case can be made for retaining the independent auditor instead of another service provider.

•
The Audit Committee will not provide pre-approval for services to be provided in excess of twelve months from the date of the pre-approval, unless the Audit Committee specifically provides for a different period.

•
The Audit Committee has delegated authority to pre-approve services with an estimated cost not exceeding $100,000 in accordance with this Policy to the Chairman of the Audit Committee. The delegate member of the Audit Committee must report any pre-approval decision to the Audit Committee at its next meeting.

•
The Chairman of the Audit Committee may delegate his authority to pre-approve services to another sitting member of the Audit Committee provided that the recipient has also been delegated the authority to act as Chairman of the Audit Committee in the Chairman's absence. A resolution of the Audit Committee is required to evidence the Chairman's delegation of authority to another Audit Committee member under this policy.

•
The Audit Committee will, from time to time, but no less than annually, review and pre-approve the services that may be provided by the independent auditor.

•
The Audit Committee must establish pre-approval fee levels for services provided by the independent auditor on an annual basis. On at least a quarterly basis, the Audit Committee will be provided with a detailed summary of fees paid to the independent auditor and the nature of the services provided, and a forecast of fees and services that are expected to be provided during the remainder of the fiscal year.

•
The Audit Committee will not approve engaging the independent auditor to provide any prohibited non-audit services as set forth in Appendix A.

•
The Audit Committee shall evidence their pre-approval for services to be provided by the independent auditor as follows:

(a)
In situations where the Chairman of the Audit Committee pre-approves work under his delegation of authority, the Chairman will evidence his pre-approval by signing and dating the pre-approval request form, attached as Appendix B. If it is not practicable for the Chairman to complete the form and transmit it to the Company prior to engagement of the independent audit, the Chairman may provide verbal or email approval of the engagement, followed up by completion of the request form at the first practical opportunity.

(b)
In all other situations, a resolution of the Audit Committee is required.

•
All audit and non-audit services to be provided by the independent auditors shall be provided pursuant to an engagement letter that shall:

(a)
Be in writing and signed by the auditors;

(b)
Specify the particular services to be provided;

(c)
Specify the period in which the services will be performed;

(d)
Specify the estimated total fees to be paid, which shall not exceed the estimated total fees approved by the Audit Committee pursuant to these procedures, prior to application of the 10% overrun; and

(e)
Include a confirmation by the auditors that the services are not within a category of services the provision of which would impair their independence under applicable law and Canadian and U.S. generally accepted accounting standards.

•
The Audit Committee pre-approval permits an overrun of fees pertaining to a particular engagement of no greater than 10% of the estimate identified in the associated engagement letter. The intent of the overrun authorization is to ensure on an interim basis only, that services can continue pending a review of the fee estimate, and, if required, further Audit Committee approval of the overrun. If an overrun is expected to exceed the 10% threshold, as soon as the overrun is identified, the Audit Committee or its designate must be notified and an additional pre-approval must be obtained prior to the engagement continuing.

B-2   SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014

V.    Responsibilities of External Auditors

To support the independence process, the independent auditors will:

(a)
Confirm in each engagement letter that performance of the work will not impair independence;

(b)
Satisfy the Audit Committee that they have in place comprehensive internal policies and processes to ensure adherence, worldwide, to independence requirements, including robust monitoring and communications;

(c)
Provide communication and confirmation to the Audit Committee regarding independence on at least a quarterly basis;

(d)
Maintain registration by the Canadian Public Accountability Board and the U.S. Public Company Accounting Oversight Board; and

(e)
Review their partner rotation plan and advise the Audit Committee on an annual basis.

In addition, the external auditors will:

(f)
Provide regular, detailed fee reporting including balances in the work in progress account; and

(g)
Monitor fees and notify the Audit Committee as soon as a potential overrun is identified.

VI.   Disclosures

Suncor will, as required by applicable law, annually disclose its pre-approval policies and procedures, and will provide the required disclosure concerning the amounts of audit fees, audit-related fees, tax fees and all other fees paid to its outside auditors in its filings with the SEC.

Approved and Accepted April 28, 2004

SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014    B-3

Appendix A – Prohibited Non-Audit Services

An external auditor is not independent if, at any point during the audit and professional engagement period, the auditor provides the following non-audit services to an audit client.

Bookkeeping or other services related to the accounting records or financial statements of the audit client. Any service, unless it is reasonable to conclude that the results of these services will not be subject to audit procedures during an audit of Suncor's financial statements, including:

•
Maintaining or preparing the audit client's accounting records;

•
Preparing Suncor's financial statements that are filed with the SEC or that form the basis of financial statements filed with the SEC; or

•
Preparing or originating source data underlying Suncor's financial statements.

Financial information systems design and implementation. Any service, unless it is reasonable to conclude that the results of these services will not be subject to audit procedures during an audit of Suncor's financial statements, including:

•
Directly or indirectly operating, or supervising the operation of, Suncor's information systems or managing Suncor's local area network; or

•
Designing or implementing a hardware or software system that aggregates source data underlying the financial statements or generates information that is significant to Suncor's financial statements or other financial information systems taken as a whole.

Appraisal or valuation services, fairness opinions or contribution-in-kind reports. Any appraisal service, valuation service or any service involving a fairness opinion or contribution-in-kind report for Suncor, unless it is reasonable to conclude that the results of these services will not be subject to audit procedures during an audit of Suncor's financial statements.

Actuarial services. Any actuarially-oriented advisory service involving the determination of amounts recorded in the financial statements and related accounts for Suncor other than assisting Suncor in understanding the methods, models, assumptions, and inputs used in computing an amount, unless it is reasonable to conclude that the results of these services will not be subject to audit procedures during an audit of Suncor's financial statements.

Internal audit outsourcing services. Any internal audit service that has been outsourced by Suncor that relates to Suncor's internal accounting controls, financial systems or financial statements, unless it is reasonable to conclude that the result of these services will not be subject to audit procedures during an audit of Suncor's financial statements.

Management functions. Acting, temporarily or permanently, as a director, officer, or employee of Suncor, or performing any decision-making, supervisory, or ongoing monitoring function for Suncor.

Human resources. Any of the following:

•
Searching for or seeking out prospective candidates for managerial, executive, or director positions;

•
Engaging in psychological testing, or other formal testing or evaluation programs;

•
Undertaking reference checks of prospective candidates for an executive or director position;

•
Acting as a negotiator on Suncor's behalf, such as determining position, status or title, compensation, fringe benefits, or other conditions of employment; or

•
Recommending, or advising Suncor to hire a specific candidate for a specific job (except that an accounting firm may, upon request by Suncor, interview candidates and advise Suncor on the candidate's competence for financial accounting, administrative, or control positions).

Broker-dealer, investment adviser or investment banking services. Acting as a broker-dealer (registered or unregistered), promoter, or underwriter, on behalf of Suncor, making investment decisions on behalf of Suncor or otherwise having discretionary authority over Suncor's investments, executing a transaction to buy or sell Suncor's investment, or having custody of Suncor's assets, such as taking temporary possession of securities purchased by Suncor.

Legal services. Providing any service to Suncor that, under circumstances in which the service is provided, could be provided only by someone licensed, admitted, or otherwise qualified to practice law in the jurisdiction in which the service is prohibited.

Expert services unrelated to the audit. Providing an expert opinion or other expert service for Suncor, or Suncor's legal representative, for the purpose of advocating Suncor's interest in litigation or in a regulatory or administrative proceeding or investigation. In any litigation or regulatory or administrative proceeding or investigation, an accountant's independence shall not be deemed to be impaired if the accountant provides factual accounts, including testimony, of work performed or explains the positions taken or conclusions reached during the performance of any service provided by the accountant for Suncor.

B-4   SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014

Appendix B – Pre-Approval Request Form

NATURE OF WORK   ESTIMATED FEES
(Cdn$)
     
     
     
     
Total    
 
 
 
 
 
Date   Signature

SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014    B-5

SCHEDULE "C" – FORM 51-101F2 REPORT ON RESERVES DATA BY
INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR

To the Board of Directors of Suncor Energy Inc. (the "Company"):

1.
We have evaluated the Company's reserves data as at December 31, 2013. The reserves data are estimates of proved reserves and probable reserves and related future net revenues as at December 31, 2013, estimated using forecast prices and costs.

2.
The reserves data are the responsibility of the Company's management. Our responsibility is to express an opinion on the reserves data based on our evaluation.
3.
Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions presented in the COGE Handbook.

4.
The following table sets forth the estimated future net revenues (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Company evaluated by us for the year ended December 31, 2013, and identifies the respective portions thereof that we have evaluated and reported on to the Company's management and Board of Directors:
Independent Qualified   Description and
Preparation Date of		   Location of Reserves
(Country or Foreign		   Net Present Value of Future Net
Revenues Before Income Taxes
($ millions, discounted at 10%)
Reserves Evaluator   Evaluation Report   Geographic Area)   Audited   Evaluated   Reviewed   Total  
GLJ Petroleum Consultants Ltd.   Oil Sands In Situ
January 22, 2014		   Canada   —   20 143   —   20 143  
GLJ Petroleum Consultants Ltd.   Oil Sands Mining
January 8, 2014		   Canada   —   22 446   —   22 446  
            —   42 589   —   42 589  
5.
In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook, consistently applied. We express no opinion on the reserves data that we reviewed but did not audit or evaluate.

6.
We have no responsibility to update our reports referred to in paragraph 4 for events and circumstances occurring after their respective preparation dates.

7.
Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material.

EXECUTED as to our report referred to above:

GLJ Petroleum Consultants Ltd., Calgary, Alberta, Canada, February 28, 2014

"Caralyn P. Bennett"

Caralyn P. Bennett, P.Eng.
Vice-President

C-1   SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014

SCHEDULE "D" – FORM 51-101F2 REPORT ON RESERVES DATA BY
INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR

To the Board of Directors of Suncor Energy Inc. (the "Company"):

1.
We have evaluated the Company's reserves data as at December 31, 2013. The reserves data are estimates of proved reserves and probable reserves and related future net revenues as at December 31, 2013, estimated using forecast prices and costs.

2.
The reserves data are the responsibility of the Company's management. Our responsibility is to express an opinion on the reserves data based on our evaluation.
3.
Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions presented in the COGE Handbook.

4.
The following table sets forth the estimated future net revenues (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Company evaluated by us for the year ended December 31, 2013, and identifies the respective portions thereof that we have evaluated and reported on to the Company's management and Board of Directors:
Independent Qualified   Description and
Preparation Date of		   Location of Reserves
(Country or Foreign		   Net Present Value of Future Net
Revenues Before Income Taxes
($ millions, discounted at 10%)
Reserves Evaluator   Evaluation Report   Geographic Area)   Audited   Evaluated   Reviewed   Total  
Sproule Associates Limited   East Coast Canada
February 21, 2014		   Newfoundland Offshore, Canada   —   8 175   —   8 175  
Sproule Associates Limited   North America Onshore
February 21, 2014		   Western Canada   —   228   —   228  
Sproule International Limited   North Sea
February 21, 2014		   North Sea, United Kingdom   —   7 500   —   7 500  
Sproule International Limited   Other International
February 21, 2014		   Libya   —   4 433   —   4 433  
            —   20 336   —   20 336  
5.
In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook, consistently applied. We express no opinion on the reserves data that we reviewed but did not audit or evaluate.

6.
We have no responsibility to update our reports referred to in paragraph 4 for events and circumstances occurring after their respective preparation dates.

7.
Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material.

EXECUTED as to our report referred to above:

Sproule Associates Limited and Sproule International Limited, Calgary, Alberta, Canada, February 28, 2014

"Harry J. Helwerda"

Harry J. Helwerda, P.Eng., FEC, FGC (Hon.)
President & Chief Operating Officer and Director

SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014    D-1

SCHEDULE "E" – FORM 51-101F3 REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION

Management of Suncor Energy Inc. (the "Company") are responsible for the preparation and disclosure of information with respect to the Company's oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data, which are estimates of proved reserves and probable reserves and related future net revenues as at December 31, 2013, estimated using forecast prices and costs.

Independent qualified reserves evaluators have evaluated the Company's reserves data. The reports of the independent qualified reserves evaluators will be filed with securities regulatory authorities concurrently with this report.

The Audit Committee of the Board of Directors of the Company has:

(a)
reviewed the Company's procedures for providing information to the independent qualified reserves evaluators;

(b)
met with the independent qualified reserves evaluators to determine whether any restrictions affected the ability of the independent qualified reserves evaluators to report without reservation; and

(c)
reviewed the reserves data with management and the independent qualified reserves evaluators.

The Audit Committee of the Board of Directors has reviewed the Company's procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with management. The Board of Directors has, on the recommendation of the Audit Committee, approved:

(a)
the content and filing with securities regulatory authorities of Form 51-101F1 containing reserves data and other oil and gas information;

(b)
the filing of Form 51-101F2 which is the report of the independent qualified reserves evaluators on the reserves data; and

(c)
the content and filing of this report.

Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material.

"Steven W. Williams"
STEVEN W. WILLIAMS
President and Chief Executive Officer

"Stephen D.L. Reynish"
STEPHEN D.L. REYNISH
Interim Chief Financial Officer

"John T. Ferguson"
JOHN T. FERGUSON
Chairman of the Board of Directors

"Michael W. O'Brien"
MICHAEL W. O'BRIEN
Chair of the Audit Committee

February 28, 2014

E-1   SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014

LOGO

 
 
 
 
 
 
 
 
 
 

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

Suncor.com


 UNDERTAKING AND CONSENT TO SERVICE OF PROCESS

A.    Undertaking

        Suncor Energy Inc. (the "Registrant") undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the staff of the Securities and Exchange Commission ("SEC"), and to furnish promptly, when requested to do so by the SEC staff, information relating to the securities in relation to which the obligation to file an annual report on Form 40-F arises, or transactions in said securities.

B.    Consent to Service of Process

        The Registrant has filed previously with the SEC a Form F-X in connection with the Common Shares.


DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROL OVER FINANCIAL REPORTING

        See pages 83 and 84 of Exhibit 99-1 and page 72 of Exhibit 99-2.


ATTESTATION REPORT OF THE REGISTERED PUBLIC ACCOUNTING FIRM

        See pages 85 and 86 of Exhibit 99-1.


AUDIT COMMITTEE FINANCIAL EXPERT

        See pages 85 and 86 of Annual Information Form.


CODE OF ETHICS

        See pages 29 and 30 of Annual Information Form.


FEES PAID TO PRINCIPAL ACCOUNTANT

        See page 86 of Annual Information Form.


AUDIT COMMITTEE PRE-APPROVAL POLICIES

        See Schedule "B" of Annual Information Form.


APPROVAL OF NON-AUDIT SERVICES

        See Schedule "B" of Annual Information Form.


OFF-BALANCE SHEET ARRANGEMENTS

        See page 59 of Exhibit 99-2.


TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS

        See page 59 of Exhibit 99-2.


IDENTIFICATION OF THE AUDIT COMMITTEE

        See page 85 of Annual Information Form.


SIGNATURES

        Pursuant to the requirements of the Exchange Act, the registrant certifies that it meets all of the requirements for filing on Form 40-F and has duly caused this annual report to be signed on its behalf by the undersigned, thereto duly authorized.

  SUNCOR ENERGY INC.

DATE: February 28, 2014

        

 

PER:

  

/s/ STEVEN D.L. REYNISH

Steven D.L. Reynish
Interim Chief Financial Officer


EXHIBIT INDEX

Exhibit No.
  Description
 

99-1

   Audited Consolidated Financial Statements of Suncor Energy Inc. for the fiscal year ended December 31, 2013
 

99-2

  

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

99-3

  

Consent of PricewaterhouseCoopers LLP
 

99-4

  

Consent of GLJ Petroleum Consultants Ltd.
 

99-5

  

Consent of Sproule Associates Limited, Sproule Unconventional Limited and Sproule International Limited
 

99-6

  

Certificate of Chief Executive Officer Pursuant to Exchange Act Rules 13a-14(a) or 15d-14(a)
 

99-7

  

Certificate of the Chief Financial Officer Pursuant to Exchange Act Rules 13a-14(a) or 15d-14(a)
 

99-8

  

Certificate of the Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Enacted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 

99-9

  

Certificate of the Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Enacted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002



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INCORPORATION BY REFERENCE
ANNUAL INFORMATION FORM
UNDERTAKING AND CONSENT TO SERVICE OF PROCESS
DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROL OVER FINANCIAL REPORTING
ATTESTATION REPORT OF THE REGISTERED PUBLIC ACCOUNTING FIRM
AUDIT COMMITTEE FINANCIAL EXPERT
CODE OF ETHICS
FEES PAID TO PRINCIPAL ACCOUNTANT
AUDIT COMMITTEE PRE-APPROVAL POLICIES
APPROVAL OF NON-AUDIT SERVICES
OFF-BALANCE SHEET ARRANGEMENTS
TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS
IDENTIFICATION OF THE AUDIT COMMITTEE
SIGNATURES
EXHIBIT INDEX