QuickLinks -- Click here to rapidly navigate through this document

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, 2010
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, 2010 there were
1,565,489,162 Common Shares issued and
outstanding

 

Preferred Shares, Series A

 

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


ANNUAL INFORMATION FORM


ANNUAL INFORMATION FORM DATED MARCH 3, 2011

 
 
 

LOGO

 
 
 
 
 
 

ANNUAL INFORMATION FORM DATED MARCH 3, 2011

TABLE OF CONTENTS

TABLE OF CONTENTS   i
GLOSSARY OF TERMS   1
CONVERSION TABLE   4
PRESENTATION OF INFORMATION   4
FORWARD-LOOKING STATEMENTS   4
ACCOUNTING MATTERS   5
CORPORATE STRUCTURE   6
Name and Incorporation   6
Inter-Corporate Relationships   7
GENERAL DEVELOPMENT OF THE BUSINESS   8
Overview   8
Three-Year History by Segment   9
  Oil Sands   9
  Natural Gas   11
  International and Offshore   11
  Refining and Marketing   13
  Other Suncor Businesses   15
  Forward-Looking Information   15
NARRATIVE DESCRIPTION OF SUNCOR'S BUSINESSES   16
Oil Sands   16
  Operations   16
  Transportation   16
  Principal Products   17
  Sales of Synthetic Crude Oil, Bitumen and Diesel   18
  Competitive Conditions   18
  Seasonal Impacts   18
  Environmental Compliance   18
Natural Gas   19
  Marketing, Pipeline and Other Operations   19
  Principal Products   20
  Competitive Conditions   20
  Seasonal Impacts   20
  Environmental Compliance   20
International and Offshore   20
  Exploration and Production   21
  Principal Products   23
  Sales of Conventional Crude Oil and Natural Gas   23
  Competitive Conditions   23
  Seasonal Impacts   24
  Environmental Compliance   24
Refining and Marketing   24
  Refining and Product Supply Operations   24
  Transportation and Distribution   25
  Marketing Operations   26
  Principal Products   27
  Competitive Conditions   27
  Environmental Compliance   27
Other Suncor Businesses   27
Significant Policies   28
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION   29
INDUSTRY CONDITIONS   54
Pricing and Marketing – Oil and Natural Gas   54
Pipeline Capacity   54
Royalties and Incentives   54
  Canada – General   54
  Alberta   55
  East Coast Canada   56
  Production Sharing Contracts   57
Land Tenure   57
Environmental Regulation   57
Climate Change Regulation   58
RISK FACTORS   60
DIVIDENDS   69
DESCRIPTION OF CAPITAL STRUCTURE   69
General Description of Capital Structure   69
Constraints   69
Ratings   69
MARKET FOR SECURITIES   71
Price Range and Trading Volume of Common Shares   71
  Toronto Stock Exchange   71
  New York Stock Exchange   71
Options to Purchase Common Shares   71
DIRECTORS AND EXECUTIVE OFFICERS   72
Directors   72
Executive Officers   74
Cease Trade Orders, Bankruptcies, Penalties or Sanctions   75
Conflicts of Interest   75
SUNCOR EMPLOYEES   76
AUDIT COMMITTEE INFORMATION   76
LEGAL PROCEEDINGS AND REGULATORY ACTIONS   78
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS   78
TRANSFER AGENT AND REGISTRAR   78
MATERIAL CONTRACTS   79
INTERESTS OF EXPERTS   79
DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NEW YORK STOCK EXCHANGE   79
ADDITIONAL INFORMATION   79
SCHEDULE "A" – AUDIT COMMITTEE MANDATE   A-1
SCHEDULE "B" – SUNCOR ENERGY INC. POLICY AND PROCEDURES FOR PRE-APPROVAL OF AUDIT AND NON-AUDIT SERVICES   B-1
SCHEDULE "C" – FORM 51-101F2 REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR   C-1
SCHEDULE "D" – FORM 51-101F2 REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR   D-1
SCHEDULE "E" – FORM 51-101F3 REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION   E-1

i    SUNCOR ENERGY INC. 2011 ANNUAL INFORMATION FORM



GLOSSARY OF TERMS

In this Annual Information Form (AIF), references to "we", "our", "us", "Suncor" or "the company" mean Suncor Energy Inc., its subsidiaries, partnerships and joint venture investments unless the context otherwise requires. References to "legacy Suncor" and "legacy Petro-Canada" refer to the applicable entity prior to the August 1, 2009 effective date of the merger between legacy Suncor and legacy Petro-Canada.

Barrel of oil equivalent (boe)

Suncor converts certain natural gas volumes to barrels (bbls) of oil equivalent (boe), thousands of barrels of oil equivalent (mboe), mboe per day (mboe/d) or millions of barrels of oil equivalent (mmboe) on the basis of one barrel (bbl) to six thousand cubic feet and daily production is presented as barrels of oil equivalent per day (boe/d). Boe, mboe and mmboe may be misleading, particularly if used in isolation. A conversion ratio of one barrel of crude oil or natural gas liquids to six thousand cubic feet 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.

Bcf

Billions of cubic feet.

Bitumen/heavy crude oil

A naturally occurring viscous mixture, consisting mainly of pentanes and heavier hydrocarbons, which is not recoverable at a commercial rate in its naturally occurring viscous state through a well without using enhanced recovery methods. When extracted, bitumen/heavy crude oil may be upgraded into crude oil and other petroleum products.

Bpd

Barrels per day.

Capacity

Maximum annual average output that may be achieved from a facility in ideal operating conditions in accordance with current design specifications.

Conventional crude oil

Crude oil produced through wells by standard industry recovery methods.

Conventional natural gas

Natural gas produced from all geological strata, including associated, non-associated and solution gas, but excluding coal bed methane and shale gas.

Crude oil

Unrefined liquid hydrocarbons, excluding natural gas liquids.

Development costs

Includes all costs associated with moving reserves from other classes such as "proved undeveloped" and "probable" to the "proved developed" class.

Exploration and Production Sharing Agreements (EPSAs)

See production sharing contracts.

Feedstock

In the oil sands business, feedstock generally refers to raw bitumen required in the production of synthetic crude oil. In the downstream business, feedstock refers to crude oil and/or other components required in the production of refined products.

SUNCOR ENERGY INC. 2011 ANNUAL INFORMATION FORM 1


Field

A defined geographical area consisting of one or more pools containing hydrocarbons.

Finding costs

Includes the cost of and investment in undeveloped land, geological and geophysical activities, exploratory drilling and direct administrative costs necessary to discover crude oil and natural gas reserves.

GBP

The pound sterling, commonly called the pound (£), is the official currency of the United Kingdom.

Heavy fuel oil

Residue from refining of conventional crude oil that remains after lighter products such as gasoline, petrochemicals and heating oils have been extracted. This product traditionally sells at less than the cost of crude oil.

In situ

In situ or "in place" refers to methods of extracting heavy crude oil from deep deposits of oil sands by drilling with minimal disturbance of the ground cover.

Mbbls/d

Thousands of barrels per day.

MMbbls

Millions of barrels.

MMbtu

Millions of british thermal units.

Mcf

Thousands of cubic feet.

MMcf/d

Millions of cubic feet per day.

Mcfe or MMcfe

Suncor converts certain crude oil and natural gas liquids volumes to thousands of cubic feet equivalent of natural gas (Mcfe) and millions of cubic feet equivalent of natural gas (MMcfe) on the basis of one barrel to six thousand cubic feet, and daily production is presented as millions of cubic feet equivalent per day (MMcfe/d). Mcfe and MMcfe may be misleading, particularly if used in isolation. A conversion ratio of one barrel of crude oil or natural gas liquids to six thousand cubic feet 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.

Natural gas

Hydrocarbons that at atmospheric conditions of temperature and pressure are in a gaseous state.

Natural gas liquids (NGLs)

Those 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.

Overburden

Material overlying oil sands that must be removed before mining, and that consists of muskeg, glacial deposits and sand.

2 SUNCOR ENERGY INC. 2011 ANNUAL INFORMATION FORM


Oil sands

Oil sands are a naturally occurring mixture of water, sand, clay and bitumen – a very heavy crude oil.

Production Sharing Contracts (PSCs)

A common type of contract signed between a government and a resource extraction company that states how much of the resource extracted from the country each party will receive and which parties are responsible for the development and operation of the resources. The company conducts its operations in Syria pursuant to PSCs.

An Exploration Production and Sharing Agreement (EPSA) is a form of PSC, which also states which parties are responsible for exploration activities. The company conducts its operations in Libya pursuant to EPSAs.

Reservoir

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.

Steam Assisted Gravity Drainage (SAGD)

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, one a few metres above the other. Low pressure steam is continuously injected into the upper wellbore to heat the oil and reduce its viscosity, causing the heated oil to drain into the lower wellbore, where it is pumped out.

Synthetic crude oil (SCO)

A mixture of hydrocarbons derived by upgrading (thermal cracking and purification) of crude bitumen from oil sands that may contain sulphur or other non-hydrocarbon compounds and has many similarities to crude oil. SCO with lower sulphur content is referred to as "sweet" while SCO with higher sulphur content is referred to as "sour".

Utilization

The average use of capacity, taking into consideration planned and unplanned facility outages and maintenance.

Wells

Appraisal well

A well drilled to measure the commercial potential (i.e. size and quality) of a hydrocarbon discovery. Before development, a discovery is likely to need several such wells.

Development or developmental well

A well drilled inside the established limits of an oil or gas reservoir, or in close proximity to the edge of the reservoir, to the depth of a stratigraphic horizon known to be productive.

Drilled well

A well that has been drilled and has a defined status (e.g. gas well, shut-in well, producing oil well, producing gas well, suspended well or dry and abandoned well).

Exploratory or exploration well

A well drilled in a territory without existing proved reserves, with the intention to discover commercial reservoirs or deposits of crude oil and/or natural gas.

West Texas Intermediate (WTI)

A type of crude oil used as a benchmark in oil pricing, WTI is the underlying commodity of futures contracts on the New York Mercantile Exchange (NYMEX).

SUNCOR ENERGY INC. 2011 ANNUAL INFORMATION FORM 3



CONVERSION TABLE (1)(2)

1 cubic metre m3 = 6.29 barrels   1 tonne = 0.984 tons (long)

1 cubic metre m3 (natural gas) = 35.49 cubic feet

 

1 tonne = 1.102 tons (short)

1 cubic metre 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.

PRESENTATION OF INFORMATION

All references in this AIF to dollar amounts are in Canadian (Cdn) dollars unless otherwise indicated.

FORWARD-LOOKING STATEMENTS

Certain statements contained in this AIF constitute "forward-looking statements" within the meaning of the United States Private Securities Litigation Reform Act of 1995 and "forward-looking information" within the meaning of applicable Canadian securities legislation (collectively, "forward-looking statements"). All forward-looking statements are based on the company's current expectations, estimates, projections, beliefs and assumptions based on information available at the time the statement was made and in light of the company's experience and its perception of historical trends, including expectations and assumptions concerning the accuracy of reserve and resource 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.

Some of the forward-looking statements may be identified by words like "expects", "anticipates", "estimates", "plans", "scheduled", "intends", "may", "believes", "projects", "indicates", "could", "focus", "vision", "goal", "proposed", "target", "objective", "continue" and similar expressions. Forward-looking statements in this AIF include references to:

business strategies and goals;

future investment decisions;

future capital, exploration and other expenditures;

future cash flows;

future resource purchases and sales;

anticipated construction and repair activities;

anticipated turnarounds at upgraders, refineries and other facilities;

anticipated refining margins;

future oil and natural gas production levels, including anticipated field lives, and the sources of their growth;

project development and expansion schedules and results;

future exploration activities and results, and dates by which certain areas may be developed or come on-stream;

anticipated retail throughputs;

anticipated pre-production and operating costs;

reserves and resources estimates;

future royalties and taxes payable;

anticipated cost savings, and other synergies, realized from the merger with Petro-Canada;

production life-of-field estimates;

natural gas export capacity;

future financing and capital activities;

4 SUNCOR ENERGY INC. 2011 ANNUAL INFORMATION FORM


contingent liabilities;

the impact and cost of compliance with existing and potential environmental regulations;

future regulatory approvals;

expected rates of return.

In addition, all other statements that address expectations or projections about the future, including statements about our strategy for growth, commodity prices, costs, schedules, production volumes, operating and financial results, and expected impact of future commitments, are forward-looking statements.

Forward-looking statements 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. Our actual results may differ materially from those expressed or implied by our forward-looking statements, and readers are cautioned not to place undue reliance on them.

The risks, uncertainties and other factors, many of which are beyond our control, that could influence actual results include, but are not limited to, market instability affecting Suncor's ability to borrow in the capital debt markets at acceptable rates; consistently and competitively finding and developing reserves that can be brought on-stream economically; success of hedging strategies; maintaining a desirable debt to cash flow ratio; changes in the general economic, market and business conditions; our ability to finance capital investment to replace reserves or increase processing capacity in a volatile commodity pricing and credit environment; fluctuations in supply and demand for Suncor's products; commodity prices, interest rates and currency exchange; volatility in natural gas and liquids prices; Suncor's ability to respond to changing markets and to receive timely regulatory approvals; the successful and timely implementation of capital projects including growth projects and regulatory projects; risks and uncertainties associated with consulting with stakeholders and obtaining regulatory approval for exploration and development activities in Suncor's operating areas (these risks could increase costs and/or cause delays to or cancellation of projects); effective execution of planned turnarounds; 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 needed to reduce the margin of error and increase the level of accuracy; the integrity and reliability of Suncor's capital assets; the cumulative impact of other resource development; the cost of compliance with current and future environmental laws; the accuracy of Suncor's reserve, resource and future production estimates and its success at exploration and development drilling and related activities; the maintenance of satisfactory relationships with unions, employee associations and joint venture partners; 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; uncertainties resulting from potential delays or changes in plans with respect to projects or capital expenditures; actions by governmental authorities including the imposition of taxes or changes to fees and royalties, changes in environmental and other regulations (for example, our negotiations with the Alberta Department of Energy in respect of the Bitumen Valuation Methodology Regulation; the Government of Canada's current review of greenhouse gas emission regulations); the ability and willingness of parties with whom we have material relationships to perform their obligations to us (including in respect of any planned divestitures); risks and uncertainties associated with the ability to meet closing conditions with respect to the sale of any of Suncor's assets, the timing of closing and the consideration to be received with respect to the planned sale of any of Suncor's assets, including 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; the occurrence of unexpected events such as fires, blowouts, freeze-ups, equipment failures and other similar events affecting Suncor or other parties whose operations or assets directly or indirectly affect Suncor; failure to realize anticipated synergies or cost savings; risks regarding the integration of the Suncor and Petro-Canada after the merger; and incorrect assessments of the values of Petro-Canada. The foregoing important factors are not exhaustive.

Many of these risk factors and other specific risks and uncertainties are discussed in further detail in "Risk Factors", and throughout this AIF and in our MD&A. Readers are also referred to the risk factors described in other documents we file from time to time with securities regulatory authorities. Copies of these documents are available without charge from Suncor at 150-6th Avenue S.W., Calgary, Alberta, T2P 3E3, by calling 1-800-558-9071, or by email request to info@suncor.com or by referring to SEDAR at www.sedar.com or by referring to EDGAR at www.sec.gov. Information contained in or otherwise accessible through our website does not form a part of this AIF, and is not incorporated into this AIF by reference.

ACCOUNTING MATTERS

References to our "2010 Consolidated Financial Statements" mean Suncor's audited consolidated financial statements prepared in accordance with Generally Accepted Accounting Principles (GAAP), the notes and the auditors' report, as at and for the three-year period ended December 31, 2010. References to our MD&A mean Suncor's Management's Discussion and Analysis, dated February 24, 2011, accompanying the 2010 Consolidated Financial Statements.

On August 1, 2009, Suncor completed its merger with Petro-Canada. As such, the 2009 results reflect those of the post-merger Suncor from August 1, 2009 together with results of legacy Suncor only from January 1, 2009 through July 31,

SUNCOR ENERGY INC. 2011 ANNUAL INFORMATION FORM 5



2009. The comparative figures from 2008 reflect solely the results of legacy Suncor. Additional information about Suncor and legacy Petro-Canada filed with Canadian securities commissions and the United States (U.S.) Securities and Exchange Commission (SEC), including periodic quarterly and annual reports, are available online at www.sedar.gov and our website www.suncor.com.

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

The Canadian Institute of Chartered Accountants Accounting Standards Board confirmed in February 2008 that Canadian publicly accountable enterprises must adopt International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board, effective January 1, 2011. For more information with respect to the company's adoption of IFRS, see the "Changes in Accounting Policies" section of our MD&A.

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 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 articles to divide our issued and outstanding shares on a two-for-one basis.

Pursuant to an arrangement (the Arrangement), which was completed effective August 1, 2009, legacy Suncor and legacy Petro-Canada amalgamated to form a single corporation continuing under the name "Suncor Energy Inc.". The Arrangement was effected pursuant to section 192 of the Canada Business Corporations Act through an arrangement agreement dated March 22, 2009 and accompanying plan of arrangement, as amended. Under the terms of the Arrangement, Petro-Canada shareholders received 1.28 Suncor common shares for each Petro-Canada common share held.

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

6 SUNCOR ENERGY INC. 2011 ANNUAL INFORMATION FORM


Inter-Corporate Relationships

Material subsidiaries, each of which was owned 100%, directly or indirectly, by the company as at December 31, 2010 are as follows:

Name
Jurisdiction
  Purpose

Suncor Energy Oil Sands Limited Partnership Canada   A partnership in which Suncor Energy Inc. and certain of its wholly-owned subsidiares are partners. The partnership holds certain oil sands assets.

Suncor Energy Products Inc. (1)

Canada

 

An Ontario corporation that is wholly-owned by Suncor Energy Inc. through which some of Suncor's Canadian refining and marketing operations are conducted.

Suncor Energy Marketing Inc.

Canada

 

A subsidiary of Suncor Energy Products Inc. through which the products produced by our North American businesses are marketed. Through this subsidiary, we also administer Suncor's energy trading activities, market certain third-party products, and procure crude oil feedstocks and natural gas for our downstream business.

Suncor Energy (U.S.A.) Inc.

U.S.

 

A subsidiary of Suncor Energy Inc. through which our U.S. refining and marketing operations are conducted.

Suncor Energy Oil & Gas Partnership

Canada

 

A partnership in which Suncor Energy Inc. and one of its wholly-owned subsidiaries are partners. The partnership holds certain of our upstream Canadian oil and gas operations and our 12% interest in the Syncrude joint venture.

3908968 Canada Inc.

Canada

 

A subsidiary of Suncor Energy Inc. that holds certain of our international interests.

Petro-Canada Cooperative Holding UA

Netherlands

 

A subsidiary of 3908968 Canada Inc. that holds certain of our international interests.

Petro-Canada (International) Holdings BV

Netherlands

 

A subsidiary of Petro-Canada Cooperative Holding UA that holds certain of our international interests.

Petro-Canada Germany GmbH

Germany

 

A subsidiary of Petro-Canada (International) Holdings BV that holds the majority of our Libya interests.

Petro-Canada Oil (North Africa) GmbH

Germany

 

A subsidiary of Petro-Canada Germany GmbH through which the majority of our Libya operations are conducted.

Petro-Canada U.K. Holdings Ltd.

United Kingdom (U.K.)

 

A subsidiary of 3908968 Canada Inc. that holds certain of our U.K. interests.

Petro-Canada U.K. Ltd.

U.K.

 

A subsidiary of Petro-Canada U.K. Holdings Ltd. through which certain of our operations are conducted in the U.K.

(1)
Effective January 1, 2011, Suncor Energy Products Inc. transferred substantially all of its assets and liabilities relating to Suncor's Canadian refining and marketing operations to Suncor Energy Products Partnership. Suncor Energy Products Inc. is a general partner of Suncor Energy Products Partnership.

Individually, the company's remaining subsidiaries accounted for (i) less than 10% of the company's consolidated assets as at December 31, 2010, and (ii) less than 10% of the company's consolidated sales and operating revenues for the fiscal year ended December 31, 2010. In aggregate, the remaining subsidiaries accounted for less than 20% of each of (i) and (ii) described above.

SUNCOR ENERGY INC. 2011 ANNUAL INFORMATION FORM 7


GENERAL DEVELOPMENT OF THE BUSINESS

Overview

Suncor is an integrated energy company, with corporate headquarters 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, and we transport and refine crude oil, and market petroleum and petrochemical products primarily in Canada. Periodically, we also market third-party petroleum products. We also carry on energy trading activities focused principally on marketing and trading of crude oil, natural gas, refined products and byproducts, and the use of financial derivatives.

Our operating segments are composed of Oil Sands, Natural Gas, International and Offshore, and Refining and Marketing. For financial reporting purposes, we also report financial data for activities not directly attributable to an operating business under "Corporate, Energy Trading and Eliminations". This includes our energy trading activities and our investments in renewable energy opportunities.

The table below outlines various Suncor investments as at December 31, 2010:


Oil Sands   International and Offshore
•  Mining   •  East Coast Canada
  •  Millennium and Steepbank Mining Operations       •  Terra Nova (2) (37.675% Interest)
  •  Syncrude (12% Interest)       •  Hibernia (20% Interest)
  •  Fort Hills (60% Interest) (1)       •  Hibernia South Extension (3) (19.5% Interest)
  •  Other Mining Developments       •  White Rose (27.5% Interest)
•  In Situ       •  White Rose Extensions (4) (26.125% Interest)
  •  Firebag       •  Hebron (22.7% Interest)
  •  MacKay River   •  North Sea
  •  Other In Situ Developments       •  Buzzard (29.9% Interest)
•  Upgrading Facilities       •  Golden Eagle Area Development (26.7% Interest)
        •  Other Exploration Acreage
Natural Gas   •  Syria PSCs
•  Western Canada   •  Libya EPSAs
  •  Shale (northeast British Columbia (B.C.))    
  •  Shallow (southeast Alberta)   Corporate, Energy Trading and Eliminations
  •  Foothills (western Alberta, northeast B.C.)   •  Energy Trading activities
  •  Plains (western Alberta)   •  St. Clair Ethanol Plant
•  Northwest Territories (NWT)/Nunavut   •  Wind Farms
•  Alaska/Arctic Islands       •  Ripley (50% Interest)
        •  Chin Chute (33.3% Interest)
Refining and Marketing       •  Magrath (33.3% Interest)
•  Refineries       •  SunBridge (50% Interest)
  •  Edmonton Refinery       •  Wintering Hills (70% Interest)
  •  Montreal Refinery       •  Kent Breeze
  •  Sarnia Refinery    
  •  Commerce City (Colorado) Refinery    
  •  ParaChem Chemicals Joint Venture (51% Interest)    
•  Sales and Marketing    
  •  Retail Operations    
  •  Wholesale Operations    
•  Mississauga Lubricants Plant    

(1)
On December 17, 2010, Suncor announced that it had entered into a strategic partnership with Total E&P Canada Ltd. (Total). Assuming the transaction closes, Total will acquire a portion of Suncor's interest in Fort Hills, resulting in Suncor holding a 40.8% interest. See the "Three-Year History by Segment" section for further details about this transaction.

(2)
In the fourth quarter of 2010, the joint owners of the Terra Nova oilfield finalized the redetermination of working interests required under the Terra Nova Development and Operating Agreement following field payout on February 1, 2005. Suncor's working interest increased to 37.675% from 33.990%.

(3)
Suncor's working interest in the Hibernia South Extension agreement is 19.5% after Nalcor Energy Oil and Gas Inc. (NALCOR) acquired its 10% unit interest effective with the signing of the related agreement on February 16, 2010.

(4)
The White Rose Extensions are the White Rose North Amethyst, West White Rose and South White Rose Extensions. Suncor's working interest in the White Rose Extensions is 26.125% after NALCOR acquired its 5% working interest effective with the signing of the final project agreements in February 2009.

8 SUNCOR ENERGY INC. 2011 ANNUAL INFORMATION FORM


Three-Year History by Segment

Pursuant to a statutory plan of arrangement completed effective August 1, 2009, Suncor and Petro-Canada, and certain of their respective subsidiaries, amalgamated to form a single corporation continuing under the name "Suncor Energy Inc.". The Arrangement was effected pursuant to section 192 of the Canada Business Corporations Act through an arrangement agreement dated March 22, 2009 (Arrangement Agreement) and accompanying plan of arrangement, as amended (the Plan of Arrangement). Under the Arrangement Agreement and Plan of Arrangement, each holder of common shares of legacy Suncor received one common share of Suncor and each holder of common shares of legacy Petro-Canada received 1.28 common shares of Suncor for each share of Petro-Canada held. Upon completion of the Arrangement, approximately 60% of the outstanding common shares of Suncor were held by legacy Suncor shareholders and approximately 40% of the outstanding common shares of Suncor were held by legacy Petro-Canada shareholders.

Oil Sands

Our Oil Sands business, located near Fort McMurray, Alberta, produces bitumen recovered from oil sands through mining and in situ technology and upgrades it into refinery feedstock, diesel fuel and byproducts. Bitumen feedstock is also occasionally supplemented by third-party suppliers. The company also has a 12% ownership interest in the Syncrude oil sands mining and upgrading joint venture, also located near Fort McMurray, Alberta.

Key milestones and significant events that have affected our Oil Sands business during this time period include the following:

        2010

SUNCOR ENERGY INC. 2011 ANNUAL INFORMATION FORM 9


        2009

        2008

The following changes to our Oil Sands business have occurred, or are expected to occur, in 2011:

10 SUNCOR ENERGY INC. 2011 ANNUAL INFORMATION FORM


Natural Gas

Our Natural Gas business explores for, acquires, develops and produces natural gas, NGLs, oil and byproducts from reserves in Western Canada. This business also has assets in NWT, Alaska, and the Arctic Islands.

Key milestones and significant events that have affected our Natural Gas business during the past three years include the following:

        2010

        2009

The following changes to our Natural Gas business have occurred, or are expected to occur, in 2011:

International and Offshore

International and Offshore consists of conventional oil and gas exploration, development and production offshore Newfoundland and Labrador, in the North Sea, and in Libya and Syria. Suncor acquired the International and Offshore assets in the merger with Petro-Canada in 2009.

Our East Coast Canada business comprises production and exploration activity offshore Newfoundland and Labrador. The company has a position in every major producing oil development in the region and is the operator of the Terra Nova oilfield. The company also holds a number of exploration licences and significant discovery licences in the region.

SUNCOR ENERGY INC. 2011 ANNUAL INFORMATION FORM 11


Our International business focuses on countries and regions where material positions of long-life assets may be built. This includes the exploration for, and production of, crude oil and natural gas primarily in the North Sea (offshore U.K. and Norway), Libya and Syria.

Key milestones and significant events that have affected our International and Offshore business during the past three years include the following:

East Coast Canada

        2010

        2009

North Sea

        2010

        2009

12 SUNCOR ENERGY INC. 2011 ANNUAL INFORMATION FORM


        2008

Libya

        2010

        2008

Syria

        2010

Trinidad and Tobago

        2010

The following changes to our International and Offshore business have occurred, or are expected to occur, in 2011:

Refining and Marketing

Our Refining and Marketing business refines crude oil at Suncor's refineries in Edmonton, Alberta, Montreal, Quebec and Sarnia, Ontario in Canada, and in Commerce City, Colorado, U.S., into a broad range of petroleum and petrochemical products for sale to retail, commercial and industrial customers. In 2010, our Refining and Marketing business averaged sales of 87,800 cubic metres per day (m3/d) of refined products nationwide in Canada and in Colorado, as well as into other parts of the

SUNCOR ENERGY INC. 2011 ANNUAL INFORMATION FORM 13



United States and Europe. Refining and Marketing transports crude oil through pipelines in Eastern and Western Canada, and through wholly-owned pipelines in Wyoming and Colorado.

Our Refining and Marketing business also includes a lubricants plant in Mississauga, Ontario that produces specialty lubricants and waxes.

In Canada, our retail business is managed primarily through Petro-CanadaTM-branded retail sites. In Colorado, our retail business is primarily managed through Phillips 66® and Shell®-branded sites.

Key milestones and significant events that have affected our Refining and Marketing business during the past three years include the following:

        2010

        2009

        2008

The following changes to our Refining and Marketing business have occurred, or are expected to occur, in 2011:

14 SUNCOR ENERGY INC. 2011 ANNUAL INFORMATION FORM


Other Suncor Businesses

Renewable Energy

Key milestones and significant events that have affected our renewable energy interests during the past three years include the following:

        2010

The following changes to our Renewable Energy business have occurred, or are expected to occur, in 2011:

Forward-Looking Information

The preceding paragraphs describing the general development of our business contain forward-looking statements, including those related to: cost estimates; the Total transaction (and the anticipated terms of same); our TROTM process, and the expectation that we will spend $670 million during 2011 to continue development of the initiative; the planned expansion of Firebag Stages 3 and 4, NSE and MNU assets (and expected production and capacity relating to the foregoing assets); expected turnarounds; planned divestitures of our natural gas assets and U.K. assets; anticipated first oil from some of Suncor's International and Offshore assets; and project completion dates. The material factors and assumptions used to develop the foregoing forward-looking statements include those related to the following: current capital spending plans; the current status of procurement, design and engineering phases of projects; updates from third-parties on delivery of services and goods associated with the projects; and estimates from major project teams on completion of future phases of the project. We have assumed that commitments from third parties will be honoured and that material delays and increased costs related to projects will not be encountered. Assumptions for production outlook include implementing reliability and operational efficiency initiatives, which we expect to minimize further unplanned maintenance. We have also provided forward-looking statements concerning the timing of the proposed transaction with Total and the development of the Fort Hills mine and Voyageur upgrader. Suncor has provided these anticipated times in reliance on certain assumptions that Suncor believes are reasonable at this time, including assumptions as to the timing of receipt of the necessary regulatory, court and other third party approvals; and the time necessary to satisfy the conditions to the closing of the transaction. These dates may change for a number of reasons, including unforeseen delays in the inability to secure necessary regulatory or other third-party approvals in the time assumed or the need for additional time to satisfy the conditions to the completion of the transaction. There is no assurance that the transaction will close as scheduled or at all, or if it does close, that any of the key terms of the agreement will come to fruition. For additional information on risks, uncertainties and other factors that could cause actual results to differ, please see the "Forward-Looking Statements" section above and the our Risk Factors section of this AIF.

SUNCOR ENERGY INC. 2011 ANNUAL INFORMATION FORM 15


NARRATIVE DESCRIPTION OF SUNCOR'S BUSINESSES

Oil Sands

Operations

Our integrated Oil Sands business involves five operations located near Fort McMurray, Alberta:

Oil sands ore is supplied from open pit mining operations.

Open pit mining operations extract the overburden with trucks and shovels to provide access to the oil sands, which are excavated and delivered via hydrotransport pipeline to ore preparation plants, where crushers and sizers prepare the ore for primary extraction.

Primary extraction facilities recover the bitumen from the mined oil sands ore.

In the primary extraction process, raw bitumen is separated from sand using a hot water process in giant separation cells. After the final removal of impurities and minerals during secondary extraction, naphtha is added to dilute the bitumen to facilitate transportation to upgrading facilities.

In situ operations provide additional bitumen to upgrading facilities.

Our in situ operations, Firebag and MacKay River, use SAGD to separate bitumen from oil sands deposits that are too deep to be mined economically. The first step of the SAGD process is to drill a pair of horizontal wells with one located above the other. Steam produced by on-site steam generation facilities is injected through the top well into the oil sands. Heated bitumen and condensed steam drain into the bottom well and flow up the well to the surface. The bitumen and water mixture is pumped to our oil/water separation facilities where the water is removed from the bitumen, treated and recycled back to the steam generation facilities. At our Firebag operation, naphtha is added to dilute the bitumen to facilitate transportation to our upgraders. At our MacKay River operation, a heated pipeline is used instead of naphtha dilution for transport. The bitumen is transported to our upgrading facilities or sold directly to market.

Upgrading facilities convert bitumen into crude oil products.

After the diluted bitumen is transferred to the upgrading plant, the naphtha is removed and recycled to be used again as diluent. The bitumen recovered from both in situ and mining is upgraded through a coking and distillation process. The upgraded product, referred to as sour SCO, is either sold directly to customers or upgraded further into sweet SCO by removing the sulphur and nitrogen using a hydrogen treating process. In addition to sweet and sour SCO, our upgrading also produces diesel, naphtha, kerosene and gas oil.

Utilities – water, steam and electricity – are generated through facilities on site, some owned and operated by Suncor and others owned and operated by third parties. Process water is used in extraction processes. Steam generation is critical to SAGD processes and also assists in the production of energy in Suncor's plants. Excess energy produced is sold back to the power grid.

There are virtually no finding costs associated with oil sands resources; however, the delineation and development (mining and in situ drilling) of the resources, and the upgrading of bitumen into SCO involve significant capital outlays. As a result, our production costs are largely fixed in the short term such that operating costs per unit are largely dependent on levels of production. Natural gas is used in the production of SCO, particularly in our SAGD operations, and, accordingly, natural gas prices are a key variable component of SCO production costs.

We continue to explore and develop improved and alternative technologies to facilitate increased efficiency within our operations. In the normal course of our operations, we regularly conduct planned maintenance shutdowns of our facilities. These shutdowns provide opportunities for both preventive maintenance and capital replacement, which are expected to improve operational efficiency.

Suncor also holds a 12% interest in Syncrude, which operates the North and Aurora oil sands mines, a utilities plant, bitumen extraction plant and upgrading facility that processes bitumen and produces SCO. Mine operations use truck, shovel and hydrotransport systems. Suncor's share of SCO production is processed primarily at our refinery in Edmonton, Alberta, with the balance periodically processed in Eastern Canada and in the United States.

In 2010, production at Suncor's Oil Sands facilities averaged 283,000 bpd, and Suncor's share of production from Syncrude averaged 35,200 bpd.

Transportation

Suncor owns a pipeline that transports SCO from our facilities in Fort McMurray, Alberta to Edmonton, Alberta. The pipeline has a capacity of approximately 110,000 bpd and is operated by Suncor's Refining and Marketing business.

16 SUNCOR ENERGY INC. 2011 ANNUAL INFORMATION FORM


We have a transportation service agreement on the Enbridge Athabasca Pipeline for a term that commenced in 1999 and extends to 2028. Total line design capacity is 600,000 bpd, and the current configuration capacity is 350,000 bpd. Under this agreement, our current pipeline commitment is 182,000 bpd for the transportation of SCO and diluted bitumen from Fort McMurray, Alberta to Hardisty, Alberta.

We are a founding member of the Waupisoo Pipeline, owned and operated by Enbridge Inc. (Enbridge) that went into service on June 1, 2008. Under the agreement, our founding member status is for a minimum term of 25 years with options to extend. Total line capacity is 350,000 bpd with potential expansion to 535,000 bpd. Our pipeline commitment under this agreement is 75,000 bpd for the transportation of SCO and diluted bitumen from Cheecham, Alberta to Edmonton, Alberta.

Following the Petro-Canada merger, we additionally assumed i) a short-haul commitment from Fort McMurray to Cheecham for 58,000 bpd on the Enbridge Athabasca Pipeline; ii) a lateral transportation agreement for 40,000 bpd from MacKay River to the Athabasca Tank Terminal that also includes contracted storage facilities of 250,000 bbls, which expires June 30, 2017; and iii) contracted storage facilities at Edmonton for 500,000 bbls, which expires March 31, 2028.

In 2009, Suncor entered into long-term service agreements with affiliates of TransCanada Corporation to transport crude oil on the Keystone Pipeline. The agreements will provide for pipeline transportation of our crude oil from Hardisty, Alberta to both Patoka, Illinois and Cushing, Oklahoma. Our capacity from Hardisty, Alberta to Patoka, Illinois is 25,000 bpd. In 2011, our contracted capacity from Patoka, Illinois to Cushing, Oklahoma is 50,000 bpd. In 2008, Suncor contracted additional storage facilities at both Patoka and Cushing, in order to provide further flexibility for trading strategies. Both contracts are for 1.1 MMbbls of storage and for fixed five-year terms. On January 1, 2009, Suncor contracted storage facilities for an additional 1.2 MMbbls at Nederland, Texas for a fixed five-year term. Until the company completes its Oil Sands growth projects, Suncor's Energy Trading business expects to optimize the capacities associated with these arrangements.

In 2008, we entered into commitments for the transportation of crude oil on the Express New Pipeline (30,000 bpd starting in 2008) and the Wamsutter Pipeline (10,000 bpd starting in 2009). The Express New Pipeline runs from Hardisty, Alberta to Wood River, Illinois, and helps enable delivery of sour SCO production to our Commerce City refinery or to the Gulf Coast. The Wamsutter Pipeline in Wyoming runs from Wamsutter to Fort Laramie and also primarily helps deliver crude oil feedstock to the Commerce City refinery. We continue to evaluate additional pipeline agreements to support planned increases in production capacity.

Periodically, we also enter into strategic short-term cargo transportation agreements to ship SCO internationally. These agreements have a term of less than one year and are specific to individual shipments.

We have a 20-year agreement with TransCanada Pipeline Ventures Limited Partnership to provide us with firm capacity on a natural gas pipeline that came into service in 1999. The natural gas pipeline ships natural gas to our Oil Sands facility.

We also transport natural gas to our Oil Sands operations on the company-owned and operated Albersun Pipeline, constructed in 1968. This pipeline extends approximately 300 kilometres south of the Oil Sands plant and is connected to TransCanada PipeLine Limited's (TCPL) Alberta intra-provincial pipeline system. The Albersun Pipeline had the capacity to move in excess of 100 MMcf/d of natural gas in both north and south directions until we closed our Atmore receipt terminal in November 2009. Following this closure, our capacity became 46 MMcf/d in the north direction only. We arrange for natural gas supply and purchase most of the natural gas on the system under delivery-based contracts.

Our Oil Sands mining facilities are readily accessible by public road. Our Firebag in situ facilities are currently accessible by air and private road, while our MacKay River in situ facilities are accessible by a combination of public and private roads. We anticipate termination of the current road access to Firebag in 2011. The East Athabasca Highway was completed in the fourth quarter of 2010 to provide access to the Firebag site. This highway is owned by Suncor, Husky Energy Inc. and Imperial Oil Ltd. to provide each company with access to its oil sands operations in the area.

Principal Products

Sales of light sweet SCO and diesel represented 45% (2009 – 48%) and sales of light sour SCO and bitumen represented 49% (2009 – 49%) of Oil Sands consolidated operating revenues in 2010. Information on daily sales volumes and the corresponding percentage of Oil Sands operating revenues by product for each of the last two years are as follows:


Product:   2010
  2009
 
    Mbbls/d   % of operating
revenues
  Mbbls/d   % of operating
revenues
 


 

 

 

 

 

 

 

 

 

 
Sweet synthetic crude oil (1) / diesel   137.9   45   144.9   48  
Sour synthetic crude oil / bitumen   176.6   49   147.5   49  

Total   314.5       292.4      

(1)
Includes sales of Syncrude production, effective August 1, 2009.

SUNCOR ENERGY INC. 2011 ANNUAL INFORMATION FORM 17


Sales of Synthetic Crude Oil, Bitumen and Diesel

SCO and bitumen production from our Oil Sands operations is sold to and subsequently marketed by Suncor's Energy Trading business. Primary markets for our synthetic crude oil and bitumen products include refining operations in Alberta, Ontario, the U.S. Midwest and the U.S. Rocky Mountain regions. Diesel products are sold primarily in Western Canada, marketed by Suncor's Refining and Marketing business.

For production of bitumen from our in situ assets, Oil Sands operating strategy allows Suncor to take advantage of changes in market and operating conditions by either: a) upgrading the bitumen directly at our Oil Sands facilities; b) upgrading the bitumen at Suncor's refineries, by transporting diluted bitumen to those facilities; or c) selling diluted bitumen directly to third parties.

In 1997, we entered into a long-term agreement with Flint Hills Resources LLC (Flint Hills) to supply Flint Hills with up to 30,000 bpd of sour crude from our Oil Sands operations. We began shipping the crude to Flint Hills at Hardisty, Alberta on January 1, 1999. The term of the initial agreement expires on June 30, 2011. A new agreement was negotiated to supply Flint Hills with 20,000 bpd beginning July 1, 2011. The initial term of that agreement extends to June 30, 2014 and will continue thereafter until termination upon a minimum of 24 months notice by either party.

Under a long-term sales agreement from August 2001 with Consumers Co-operative Refineries Limited (CCRL), we supply CCRL with 20,000 bpd of sour crude oil production. In 2005, we signed another contract with CCRL for an additional 12,000 bpd of sour crude oil. The initial term of both CCRL agreements is 15 years with five-year evergreen terms thereafter subject to termination by either party on 24 months notice. Neither party has provided notice of termination at this time.

A portion of our Oil Sands production is used in our refining operations. Our refineries processed the following portion of our total Oil Sands crude sales in the past two years:


Refinery   Year Ended
December 31, 2010

  Year Ended
December 31, 2009

 
    Mbbls/d   % total
Oil Sands sales (1)
  Mbbls/d   % total
Oil Sands sales (1)
 


 

 

 

 

 

 

 

 

 

 
Edmonton (2)   55   24   58   25  
Sarnia   60   27   44   18  
Commerce City   9   4   9   4  

Total   124       111      

(1)
Calculated based on Oil Sands sales, excluding diesel and bitumen sales.

(2)
For 2009, reflects operations subsequent to the Petro-Canada merger on August 1, 2009.

There were no customers that represented 10% or more of our consolidated revenues in 2010 or 2009.

Competitive Conditions

For a discussion of the competitive conditions affecting our Oil Sands operations, refer to "Competition" in the Risk Factors section of this AIF.

Seasonal Impacts

Severe winter climatic conditions at our Oil Sands operations can cause reduced production and, in some situations, can result in higher costs.

Environmental Compliance

For a discussion of environmental risks at our Oil Sands operations, refer to "Government Regulation" in the Risk Factors section of this AIF.

As part of Suncor's strong focus on operational excellence, Suncor has set four key environmental performance goals it intends to reach by 2015 (the base year for planned improvements is 2007): reduce total water intake by 12%, increase land area reclaimed by 100%, improve energy efficiency by 10% and reduce air emissions by 10%. In addition, Suncor has advanced strategies focused on operational excellence aimed at further improving process safety and reliability, which in turn will impact our environmental impact. Suncor has adopted a clear set of process safety management standards and has implemented the same at all of our facilities.

In 2010, Suncor reclaimed the industry's first tailings pond to a trafficable surface. As well, Suncor received approval and started implementation of a new tailings technology, TROTM, which Suncor expects will significantly reduce tailings reclamation time. The technology has already enabled Suncor to cancel plans to build five additional tailings ponds at its existing operations. Suncor will continue to pursue the implementation of TROTM across its existing operations and continue to take a

18 SUNCOR ENERGY INC. 2011 ANNUAL INFORMATION FORM



leadership position in collaborative efforts with industry counterparts on the development of environmental technologies. Suncor expects to spend significant amounts of capital over 2010 and 2011 to implement TROTM. This represents a significant step forward in addressing one of the biggest environmental challenges facing the oil sands industry.

Suncor will also work closely with the Oil Sands Leadership Initiative (OSLI). Comprised of Suncor, Total and three other like-minded oil sands companies, this organization is squarely focused on innovations that lead to continuous improvement in environmental, social and economic performance.

Suncor has implemented a regulatory compliance assurance process applicable to its ongoing operations and proposed future projects. A major component of the regulatory assurance work is carried out through the implementation of a software system that sets out applicable legal requirements and generates tasks to meet these requirements. To date, the scope of the regulatory compliance assurance process has included environmental regulatory compliance, mainly associated with Suncor's Oil Sands and In Situ operations

Suncor has also implemented a comprehensive roles and responsibilities matrix as part of our greenhouse gas (GHG) management program. For details refer to "Suncor's Governance Process" in the Risk Factors section of this AIF.

Natural Gas

Our Natural Gas business explores for, develops and produces natural gas, NGLs, crude oil and byproducts in Western Canada, supplying markets throughout North America. After the merger with Petro-Canada, we implemented a new strategy with greater emphasis on unconventional gas. To focus on this goal, and to help reduce the company's debt, we decided to sell a number of non-core natural gas assets.

Our exploration program is primarily focused on multiple geological zones throughout Western Canada. The business is structured with the following core asset areas:

Shale (northeast B.C.);

Shallow (southeast Alberta);

Foothills (western Alberta and portions of northeast B.C.); and

Plains (western Alberta).

Marketing, Pipeline and Other Operations

In Western Canada, Suncor operates 10 natural gas processing plants, with total licensed capacity of 793 MMcf/d, of which the company's share is 481 MMcf/d. The following table shows Suncor's working interest ownership and the licensed capacity of operated processing plants as at December 31, 2010.


Suncor Operated Plants   Working Interest
Ownership
%
  Gross Licensed
Capacity
MMcf/d
  Net Licensed
Capacity
MMcf/d
 


 

 

 

 

 

 

 

 
Hanlan Sweet   40.73   44.2   18.0  
Hanlan Sour   49.86   382.0   190.5  
Wilson Creek   52.17   34.6   18.1  
Boundary Lake Sweet   100.00   20.0   20.0  
Boundary Lake Sour   50.00   66.0   33.0  
Parkland 1   43.98   18.1   8.0  
Parkland 2   34.75   11.7   4.1  
Ferrier   99.99   120.0   120.0  
Gilby East   100.00   52.4   52.4  
Progress   38.46   44.0   16.9  

Total       793.0   481.0  

Suncor also has varying working interests in other natural gas processing plants and field gathering facilities operated by other oil and natural gas companies. The company's aggregate share from such interests is 91.5 MMcf/d of licensed capacity.

In 2010, Suncor's share of production from its Natural Gas properties was 575 MMcfe/d, with 432 MMcfe/d produced from continuing operations.

Substantially all of our natural gas production is sold to our Energy Trading business, which then markets the product to our customers under direct sales arrangements. 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 either fixed over the term of the contract or determined on a monthly basis in relation to a specified market reference price. Under these contracts, we are responsible for transportation arrangements to the point of sale.

SUNCOR ENERGY INC. 2011 ANNUAL INFORMATION FORM 19


To provide price diversity for natural gas marketing Suncor holds 85,000 MMcf/d of firm capacity on the Alliance Pipeline system and 68,000 MMbtu per day on the TCPL Gas Transmission Northwest Pipeline (GTN). The Alliance pipeline capacity, which expires in December 2015, enables Suncor to transport high-energy, rich natural gas from northeast B.C. and northwest Alberta to the Alliance pipeline terminus in Illinois. The GTN capacity, which expires in 2023, enables Suncor to deliver natural gas to the Pacific Northwest and California markets.

Suncor does not typically enter into long-term supply arrangements to sell its conventional crude oil and NGL production. Instead, our conventional crude oil and NGL production is generally sold under spot contracts or under contracts that can be terminated on relatively short notice. Our conventional crude oil production is shipped on pipelines operated by independent pipeline companies. We currently have no pipeline commitments related to the shipment of conventional crude oil.

Principal Products

Sales of natural gas represented 77% of the Natural Gas business segment's consolidated operating revenues in 2010, with 22% comprised of sales of NGLs and crude oil. The remaining 1% is related mainly to sales of sulphur byproduct. Average daily sales volumes and the corresponding percentage of Natural Gas's operating revenues by product for the last two years are as follows:


Product:   2010
  2009
 
    MMcfe/d   % of operating
revenues
  MMcfe/d   % of operating
revenues
 

Natural gas   522   77   397   76  
Crude oil and NGLs   53   22   49   23  

Total   575       446      

Competitive Conditions

For a discussion of the competitive conditions affecting the Natural Gas business, refer to "Competition" in the Risk Factors section of this AIF.

Seasonal Impacts

Risks and uncertainties associated with weather conditions and wildlife restrictions can shorten the winter drilling season and can impact the spring and summer drilling programs, potentially resulting in increased costs or reduced production.

Environmental Compliance

For a discussion of environmental risks at our Natural Gas operations, refer to "Government Regulation" in the Risk Factors section of this AIF.

International and Offshore

The International and Offshore business explores for, develops and produces crude oil and natural gas offshore Newfoundland and Labrador and in the North Sea, primarily in the U.K. and Norway, and conventionally in Libya and Syria. International and Offshore's business interests include:

20 SUNCOR ENERGY INC. 2011 ANNUAL INFORMATION FORM


As part of its strategic business alignment, during 2010, Suncor divested all of its Trinidad and Tobago assets and certain non-core North Sea assets, including all assets in The Netherlands.

Exploration and Production

East Coast Canada

Terra Nova

The Terra Nova oilfield, which is approximately 350 kilometres southeast of St. John's, Newfoundland, was discovered by Petro-Canada in 1984. Terra Nova is the second oilfield to be developed offshore Newfoundland and Labrador. This Suncor-operated production system uses a Floating Production, Storage and Offloading (FPSO) vessel that is moored on location, with a gross production capacity of 180,000 bpd and storage capacity of 960,000 bbls. Terra Nova was the first harsh environment development in North America to use a FPSO vessel. Actual production levels are lower than production capacity, reflecting current reservoir capability. Production from the Terra Nova oilfield began in January 2002. The field is estimated to have a remaining production life of approximately 13 to 20 years at current rates.

On December 1, 2010, the joint owners of the Terra Nova oilfield finalized the redetermination of working interests required under the Terra Nova Development and Operating Agreement following field payout on February 1, 2005. As a result, Suncor's working interest increased to 37.675% from 33.990% effective January 1, 2011.

At December 31, 2010, there were 15 producing oil wells, nine water injection wells and three gas injection wells in operation. Field production is transported by shuttle tanker from the FPSO to either a transshipment terminal on Placentia Bay or, if tanker schedules permit, directly to market. Crude oil delivered to the transshipment facility is transferred to storage tanks and loaded onto tankers for transport to markets in Eastern Canada and the U.S. Suncor has a 14% ownership interest in the transshipment facility.

In 2010, Suncor's share of Terra Nova production averaged 23,200 bpd. H2S was detected in several production wells in the fourth quarter of 2010. The affected wells and facilities have been safely shut-in while the company develops a mitigation plan to safely address the situation.

Hibernia and Hibernia South

The Hibernia oilfield, encompassing the Hibernia and Ben Nevis Avalon reservoirs, is approximately 315 kilometres 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., the production system is a fixed Gravity Base Structure (GBS), which sits on the ocean floor. The GBS has gross production capacity of 230,000 bpd and storage capacity of 1.3 MMbbls. Actual production levels are lower reflecting current reservoir capability and natural decline. Hibernia commenced production in November 1997. The Hibernia oilfield is estimated to have a remaining production life of 25 to 30 years at current rates.

Final fiscal agreements were signed between co-venturers and the Government of Newfoundland and Labrador in February 2010 that established the key fiscal, equity and operational principles for the development of the Hibernia South Extension. The Hibernia South Unit Development Plan Amendment (DPA) was approved by the Canada Newfoundland and Labrador Offshore Petroleum Board (CNLOPB) on September 3, 2010. The federal and provincial governments approved the CNLOPB decision on October 8, 2010. Subject to completion of certain agreements with the federal government, production from Hibernia South is expected in mid-2011, with the completion of the first oil producer/water injector well pair.

At December 31, 2010, there were 34 producing oil wells, 24 water injection wells and six gas injection wells in operation. Hibernia uses the same transshipment terminal and the same system of shuttle tankers that are used for Terra Nova, and also transports its crude oil to markets in Eastern Canada and the U.S.

In 2010, Suncor's share of Hibernia production averaged 30,900 bpd.

White Rose and the White Rose Extensions

White Rose, the third oilfield development offshore Newfoundland, is about 350 kilometres southeast of St. John's. Operated by Husky Oil Operations Limited, White Rose uses a FPSO vessel (similar to Terra Nova) that has a gross production capacity of

SUNCOR ENERGY INC. 2011 ANNUAL INFORMATION FORM 21



140,000 bpd and a storage capacity of 940,000 bbls. Production from the White Rose oilfield began in November 2005. The field is estimated to have a remaining production life of approximately 15 to 18 years at current rates.

In December 2007, the White Rose joint venture participants signed a formal agreement with the Province of Newfoundland and Labrador for the development of the White Rose Extensions, incorporating the South White Rose Extension, North Amethyst and West White Rose satellite fields. In May 2010, first oil was achieved in the North Amethyst portion of the White Rose Extensions and development drilling is ongoing. Development of the West White Rose Extension will be divided into two stages. Stage 1 was approved in the second quarter of 2009. First oil from the West White Rose Extension is expected by mid-2011 following completion of the first production well. Results of Stage 1, combined with other ongoing evaluation, will help define the scope of Stage 2.

At December 31, 2010, there were 10 producing oil wells and 12 water injection wells in operation. White Rose uses the same transshipment terminal and the same system of shuttle tankers that are used for Hibernia and Terra Nova, and also transports its crude oil directly to markets in Eastern Canada and the U.S.

In 2010, Suncor's share of White Rose production averaged 14,500 bpd.

Hebron

Hebron is an oilfield discovery located 340 kilometres southeast of St. John's. In August 2008, the Hebron joint venture participants reached an agreement with the Government of Newfoundland and Labrador on commercial terms that will allow development activities to proceed for Hebron. The project will be operated by ExxonMobil Canada Ltd. The contract for front end engineering and design for topsides, procurement and construction was awarded in September 2010. The development plan application is expected to be submitted for approval in the second quarter of 2011, with first oil expected in 2017.

Other Exploration Offshore Newfoundland

In addition to existing East Coast Canada developments, Suncor also holds interests in a number of other discoveries and continues to pursue opportunities offshore Newfoundland and Labrador.

North Sea

The Buzzard oilfield is located in the Outer Moray Firth, 95 kilometres northeast of Aberdeen, Scotland. Operated by Nexen Petroleum U.K. Limited, the Buzzard system has production capacity of 200,000 bpd of oil and 60 mmcf/d of natural gas. Buzzard achieved first oil in January 2007 and reached peak production in the middle of 2007. Buzzard is supported by four bridge-linked platforms supporting wellhead facilities, production facilities, sulphur handling, and living quarters and utilities. Crude oil is transported via the Forties pipeline system to the Kinneil terminal in Scotland, and natural gas is transported via the Frigg pipeline to the St. Fergus gas terminal in Scotland. Commissioning of the fourth platform, installed to remove H2S in the oil production from some segments of the field, was initiated in 2010 and will continue into the first quarter of 2011. The field is expected to have a remaining production life of approximately 20 years at current rates.

An agreement has been reached to unitize the discoveries in Pink, Hobby and Golden Eagle into a pre-development project called the Golden Eagle Area Development. A development project is ongoing with first oil projected in 2014-2015.

In 2010, Suncor reached agreements to sell non-core offshore U.K. assets (Scott/Telford and Triton) and completed the sale of a portion of these assets. Suncor also sold its non-core offshore Netherlands assets.

In 2010, Suncor's share of North Sea production averaged 79,000 boe/d, including 55,500 boe/d from Buzzard.

In Norway, the company completed its first operated exploration well in January 2010 and encountered hydrocarbons. An appraisal well was drilled and tested in the fourth quarter of 2010 with positive results. Further evaluation is required to determine the potential size of this discovery.

Libya

Suncor conducts its Libya operations pursuant to EPSAs, under which the company pays 50% of the costs and recovers these costs from 12% of production. Excess production is then shared between Suncor and the Libyan government. The EPSAs, which expire in 2033, enable Suncor and the NOC to design and implement jointly the redevelopment of the existing fields in the Sirte Basin.

As a result of the merger, the company assumed the remaining US$500 million obligation for a signature bonus relating to Petro-Canada's ratification of the EPSAs in 2008. As at December 31, 2010, the undiscounted value of Suncor's remaining obligation is US$290 million, payable in several installments through 2013. Under the EPSAs, Suncor is the exploration operator and has committed to fully fund an exploration program, at an estimated remaining cost of US$335 million. Failure by Suncor to conduct its exploration commitment or make the signature bonus payments could result in the NOC terminating the EPSAs, which would result in Suncor losing all of its rights to production in Libya.

In 2010, Suncor's share of production in Libya averaged 35,200 boe/d.

22 SUNCOR ENERGY INC. 2011 ANNUAL INFORMATION FORM


Syria

The Ebla gas project is operated pursuant to a PSC, under which the company pays 100% of the costs and recovers these costs from a 40% share of production after deduction for royalties of 12.5%. The remaining profit is shared between Suncor and the Syria government. The Ebla PSC will expire in April 2035.

First commercial gas production from Ebla was achieved on April 10, 2010. First oil was achieved on December 10, 2010. The transfer of ownership of hydrocarbons to the Syria government is governed under the terms and conditions of the PSC and related sales agreements.

Located in the Central Syrian Gas Basin, Ebla includes the Ash Shaer and Cherrife development areas, which cover more than 300,000 acres (approximately 1,251 square kilometres) combined. The Ebla development comprises the gas producing wells, a gas gathering and compression station, approximately 80 kilometres of pipeline and a gas treatment plant. The facility is designed to produce 80 MMcf/d of natural gas, along with related liquefied petroleum gas (LPG) and condensate volumes. Natural gas is delivered into the Syrian national gas grid for domestic consumption. LPG volumes are delivered via truck to major Syrian cities. Condensate and oil are transported to the Banias refinery in Syria.

In 2010, Suncor's share of production in Syria averaged 11,600 boe/d.

Trinidad and Tobago

On August 5, 2010, the company completed the sale of its Trinidad and Tobago assets. Prior to the sale, Suncor's share of Trinidad and Tobago production averaged 11,300 boe/d.

Principal Products

Sales of crude oil and NGLs represented 92% and sales of natural gas represented 8% of International and Offshore's consolidated operating revenues. Information on daily sales volumes and the corresponding percentage of International and Offshore's operating revenues by product for 2010, 2009 and the final five months of 2009 are as follows:


Product:   Year ended
December 31, 2010

  Year ended
December 31, 2009

 
    Mboe/d   % of operating
revenues
  Mboe/d   % of operating
revenues
 

Crude oil and NGLs   179.6   92   66.8   95  
Natural gas   21.5   8   8.1   5  

Total   201.1       74.9      

 

Product:   Five months ended
December 31, 2009 (1)

 
    Mboe/d   % of operating
revenues
 

Crude oil and NGLs   159.5   95  
Natural gas   19.3   5  

Total   178.8      

(1)
Reflects operations subsequent to the Petro-Canada merger on August 1, 2009.

Sales of Conventional Crude Oil and Natural Gas

We do not typically enter into long-term supply arrangements for our East Coast Canada or North Sea production. Instead, this production is generally sold under spot contracts or under contracts that can be terminated on relatively short notice.

Approximately 20,000 bpd of Suncor's share of Hibernia production was sold to our Montreal refinery.

Hydrocarbons produced in Libya are marketed by the Libya government on behalf of Suncor.

The transfer of ownership of hydrocarbons to the Syria government is governed under the terms and conditions of the PSC and related sales agreements.

Competitive Conditions

For a discussion of the competitive conditions affecting the International and Offshore business unit, refer to "Competition" in the Risk Factors section of this AIF.

SUNCOR ENERGY INC. 2011 ANNUAL INFORMATION FORM 23



Seasonal Impacts

The primary seasonal International and Offshore impacts are caused by winter storms, pack ice, icebergs and fog offshore Newfoundland and Labrador. During the winter storm season (October to March), we may have to reduce production rates at our offshore facilities as a result of limited storage capacity and the inability to offload to shuttle tankers due to wave height restrictions. We also experience seasonal impacts in the spring period, due to pack ice and icebergs drifting in the area of our offshore facilities. We have had precautionary shut-in of FPSO production and drilling delays due to pack ice and icebergs. In late spring and early summer, fog also impacts our ability to transfer personnel to the offshore facilities by helicopter.

Environmental Compliance

For a discussion of environmental risks for our International and Offshore operations, refer to "Government Regulation" in the Risk Factors section of this AIF.

Refining and Marketing

The Refining and Marketing business:

Owns and operates refineries in Edmonton, Alberta, Montreal, Quebec, Sarnia, Ontario and Commerce City, Colorado, with a total crude oil capacity of 443,000 bpd.

Owns and operates a lubricants plant in Mississauga, Ontario.

Owns a joint venture interest in a petrochemical plant in Montreal, Quebec.

Owns and operates and has equity interests in pipeline systems in Canada and the U.S.

Owns and operates a network of distribution terminals across Canada and in Colorado.

Markets refined products to retail, commercial and industrial customers, primarily in Canada and Colorado, through a combination of company-owned, branded-dealer and joint venture-operated retail stations, a large Canadian national commercial road transportation network and a bulk sales channel.

Refining and Product Supply Operations

Eastern North America

Our Montreal refinery has a current crude oil capacity of 130,000 bpd and produces gasoline, distillates, asphalts, heavy fuel oil, petrochemicals and solvents, which are distributed primarily across Quebec and Ontario. The Montreal refinery also produces feedstock for our lubricants plant.

The Montreal refinery processes primarily foreign conventional crude oil and has a flexible configuration that allows processing of a variety of crude oils, including heavy grades and intermediate feedstocks. Crude oil is procured from the market on a spot basis or under contracts that can be terminated on short notice.

Suncor holds a 51% interest in ParaChem Chemicals L.P. (ParaChem), which owns and operates a petrochemicals plant located adjacent to the Montreal refinery. The plant primarily produces up to 350,000 metric tons per year of paraxylene, which is used to manufacture polyester textiles and plastic bottles. ParaChem also produces benzene, hydrogen and heavy aromatics.

Our Sarnia refinery has a current crude oil capacity of 85,000 bpd and produces gasoline, distillates, and petrochemicals, which are primarily distributed in Ontario. On December 31, 2010, the company terminated its joint venture partnership with Sun Petrochemicals Company, a Toledo, Ohio-based refinery, which managed the sale of petrochemicals from Sarnia. These petrochemical sales will now be marketed solely by Refining and Marketing.

The Sarnia refinery processes both SCO and conventional crude oil. In 2010, we refined 68,000 bpd of SCO, of which 31,300 bpd was supplied from our Oil Sands operations. In the event of a significant disruption in the supply of SCO, the Sarnia refinery has the flexibility to substitute other sources of sweet or sour conventional crude oil. The balance of the refinery's feedstocks are purchased from third parties on a spot basis or under contracts that can be terminated on short notice.

To maintain supply and demand balance, Suncor imports and exports feedstocks and finished products from the East Coast. Suncor also enters into reciprocal exchange arrangements with other refining companies in Eastern North America as a means of minimizing transportation costs, balancing product availability and leveraging our assets.

Our lubricants plant produces specialty lubricants and waxes that are marketed in Canada and internationally. Suncor's lubricants plant is the largest producer of lubricant base stocks in Canada, with annual base oil production capacity in excess of 900 million litres. Feedstock for our lubricants facility comes from our Montreal refinery and other purchase contracts.

24 SUNCOR ENERGY INC. 2011 ANNUAL INFORMATION FORM


Western North America

Our Edmonton refinery has a current crude oil capacity of 135,000 bpd and primarily produces gasoline and distillates, the majority of which are distributed in Western Canada.

The Edmonton refinery has the potential to run entirely on feedstocks sourced from Alberta's oil sands and heavy crude oil production. Feedstock is supplied from Suncor's Oil Sands operations, Syncrude operations (including volumes purchased by Suncor from other joint owners' share of production) and other producers from the Athabasca and Cold Lake regions of Alberta. The refinery can upgrade directly 35,000 bpd of blended feedstock (comprised of 25,000 bpd of bitumen and 10,000 bpd of diluent) and process 45,000 bpd of sour SCO. The refinery can also process 55,000 bpd of sweet SCO through its synthetic train.

Our Commerce City refinery has a current combined crude distillation capacity of 93,000 bpd and produces primarily gasoline, diesel and asphalt. The majority of the refined products from the refinery are distributed to industrial, commercial, wholesale, and refining customers in Colorado. The remaining production is sold through a retail distribution network in Colorado.

The Commerce City refinery processes conventional crude oil and after the completion of our diesel desulphurization and oil sands integration projects, the refinery is now capable of processing up to 15,000 bpd of sour SCO from Suncor's Oil Sands operations. In the event of a significant disruption in the supply of crude oil, the refinery has the flexibility to substitute other sources of sweet or sour crude oil. 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. The crude oil purchase contracts have terms ranging from month-to-month to multi-year.

To maintain supply and demand balance, Suncor imports and exports feedstocks and finished products from the West Coast. Suncor also enters into reciprocal exchange arrangements with other refining companies in western North America as a means of minimizing transportation costs, balancing product availability and leveraging our assets.

The following table summarizes the crude feedstock and utilizations for Suncor's refineries for the year ended December 31, 2010.


Refinery   2010 Average Daily Crude Input
 
    Average Daily
Crude Input
Mbbls/d
  Conventional
Mbbls/d
  Synthetic
Mbbls/d
  Oil Sands
Synthetic
Mbbls/d
  Utilization
%
 

Montreal   121.5   121.5       94  
Sarnia   70.5   2.3   36.9   31.3   83  
Edmonton   118.6   25.9   39.6   53.1   88  
Commerce City   99.0   89.3     9.7   106  

Transportation and Distribution

Eastern North America

Crude oil for the Montreal refinery is largely supplied by the Portland-Montreal Pipeline, in which Suncor has a 24% ownership interest. Refined products are distributed via the Trans-Northern Pipeline (33% ownership interest) and also by truck, rail and marine vessel.

Crude oil is supplied to the Sarnia refinery primarily via the Enbridge system. We procure conventional crude oil feedstock primarily from Western Canada, but periodically supplement supply with purchases from the U.S. and other countries. Foreign crude oil is delivered to Sarnia via the Enbridge Pipeline system from Montreal. We have not made any firm capacity commitments on these pipeline systems. Refined products are distributed via the Sun-Canadian Pipeline (55% ownership interest), delivering to core markets in Ontario via terminal facilities in Toronto, Hamilton and London, and also via marine vessel and rail. The Sarnia refinery also has limited access to pipelines delivering refined product into the U.S.

Western North America

Crude oil is supplied to the Edmonton refinery via third-party pipelines. Refined products are distributed via the Alberta Products Pipeline (35% ownership interest), the TransMountain Pipeline, and the Enbridge Pipeline system. Refined product also moves to distribution terminals via truck and rail.

Approximately 60% of crude oil supplied to the Commerce City refinery is transported via pipeline, with the remainder transported via truck. Refined products are distributed by truck and rail, a jet fuel pipeline to the Denver International Airport and a diesel pipeline to the Union Pacific railroad yard in Denver.

In the U.S., Suncor owns and operates the Rocky Mountain Crude Pipeline system, which runs from Guernsey, Wyoming to Denver, Colorado. This is a common carrier pipeline that transports crude for our refinery as well as for other shippers. We also own and operate the Centennial Pipeline, which transports crude from Guernsey, Wyoming to Cheyenne, Wyoming.

SUNCOR ENERGY INC. 2011 ANNUAL INFORMATION FORM 25


Refining and Marketing owns and operates 13 major refined products terminals across Canada 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 Refining and Marketing's current storage and distribution needs.

Marketing Operations

Suncor's retail service station network operates nationally under the Petro-CanadaTM brand. Most of Suncor's owned and operated SunocoTM-branded retail and cardlock sites were re-branded to the Petro-CanadaTM brand in 2010. In addition to marketing through our proprietary retail outlets, petroleum product is marketed through independent dealers and joint venture facilities. In conjunction with the merger with Petro-Canada, the Canadian Competition Bureau required Suncor to divest 104 retail sites in Ontario, which was successfully completed during 2010.

As at December 31, 2010, Suncor's branded retail service station network consisted of 1,457 outlets across Canada. Our network had annual sales of gasoline motor fuels averaging approximately 5.1 million litres per site in 2010, and attracted a 19% share of the national retail market (based on data available from Statistics Canada for the period from January to October 2010). Our Colorado retail network consisted of 44 outlets owned by Suncor.


Retail Sites:
  As at December 31,
 
Canada   2010   2009  

Petro-CanadaTM-branded retail service stations   1,447   1,318  
SunocoTM-branded retail service stations   10   280  

Total branded retail service stations   1,457   1,598  


Colorado

 

 

 

 

 

Shell®-branded retail service stations   37   37  
Phillips 66®-branded retail service stations   7   7  

Total retail service stations   44   44  

Suncor has product supply agreements with an additional 178 Shell®-branded sites and 73 Phillips 66®-branded sites in Colorado. We also generate non-petroleum revenues from convenience stores, car washes, and automotive repair and maintenance services.

Suncor's wholesale operations sell petroleum products into farm, home heating, paving, small industrial, commercial and truck markets. Through our Petro-Pass network, we are the leading national marketer to the commercial road transport segment in Canada. We also sell large volumes of petroleum products directly to large industrial and commercial customers and independent marketers.


Wholesale Sites:
  As at December 31,
 
Canada   2010   2009  

Petro-CanadaTM-branded cardlock sites (Petro-Pass)   249   235  
SunocoTM-branded cardlock sites     49  

    249   284  

26 SUNCOR ENERGY INC. 2011 ANNUAL INFORMATION FORM


Principal Products

Daily sales volumes and corresponding percentages of Refining and Marketing's operating revenues for the last two years are as follows:


Product:   2010
  2009
 
    thousands of
m3/d
  % of operating
revenues
  thousands of
m3/d
  % of operating
revenues
 

Gasoline (1)                  
  Eastern North America   22.2       14.6      
  Western North America   18.9       13.0      
   
    41.1   48   27.6   52  
Distillates (2)                  
  Eastern North America   12.4       8.8      
  Western North America   18.5       9.5      
   
    30.9   36   18.3   33  
Other (3)                  
  Eastern North America   10.7       4.3      
  Western North America   5.1       4.7      
   
    15.8   16   9.0   15  

Total   87.8       54.9      

(1)
Includes motor and aviation gasoline.

(2)
Includes diesel oils, heating oils and aviation jet fuels.

(3)
Includes heavy fuel oil, asphalts, lubricants, LPG, petrochemical feedstock and other petroleum and non-petroleum products.
 

Product:   Five months ended
December 31, 2009 (1)

 
    thousands of
3/d
  % of operating
revenues
 

Gasoline (2)          
  Eastern North America   23.0      
  Western North America   18.9      
   
    41.9   51  
Distillates (3)          
  Eastern North America   13.4      
  Western North America   15.4      
   
    28.8   34  
Other (4)          
  Eastern North America   6.9      
  Western North America   7.2      
   
    14.1   15  

Total   84.8      

(1)
Reflects operations subsequent to the Petro-Canada merger on August 1, 2009.

(2)
Includes motor and aviation gasoline.

(3)
Includes diesel oils, heating oils and aviation jet fuels.

(4)
Includes heavy fuel oil, asphalts, lubricants, LPG, petrochemical feedstock and other petroleum and non-petroleum products.

Competitive Conditions

For a discussion of the competitive conditions affecting our Refining and Marketing business, refer to "Competition" in the Risk Factors section of this AIF.

Environmental Compliance

For a discussion of environmental risks at our Refining and Marketing business operations, refer to "Government Regulation" in the Risk Factors section of this AIF.

Other Suncor Businesses

Renewable Energy

Suncor's renewable energy interests include four wind power projects, with two more projects currently under construction, and Canada's largest ethanol plant by production volume.

SUNCOR ENERGY INC. 2011 ANNUAL INFORMATION FORM 27


Wind power is one of the most economically recognized forms of green power. Suncor is a Canadian pioneer in wind power with investments in four wind farms in operation, which have a gross generating capacity of 147 MW and reduce carbon dioxide (CO2) emissions by approximately 284,000 tonnes each year. Suncor does not operate any of these wind farms. Two additional wind farm projects, Wintering Hills and Kent Breeze are under construction and will be operated by Suncor.


Wind Farm   Location   Ownership
Interest
  Size
(MW)
  Turbines   Commissioned  

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  

Biofuels

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. Our ethanol plant had an original production capacity of 200 million litres per year, which has since doubled with the completion of the plant expansion on January 22, 2011. Feedstock for the plant will consist of approximately 40 million bushels of corn annually following the expansion. In 2010, the plant produced 206 million litres of ethanol.

Energy Trading

Our Energy Trading business is organized around four main commodity groups – crude oil, natural gas, sulphur and petroleum coke. Each commodity group provides value to customers through innovative commodity supply, transportation and pricing solutions. Our customers include mid- to large-sized commercial and industrial consumers, utility companies and energy producers, all of which demand specialized solutions to meet unique energy requirements.

Significant Policies

Suncor has adopted a Stakeholder Relations Policy which reflects Suncor's values and beliefs. 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 adopted 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 work 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 is in the process of finalizing specific guidelines for each of the Stakeholder Relations Policy and the Aboriginal Affairs Policy. During 2011, Suncor plans to hold training and awareness events which are expected to assist in continuing to affect the policies across the company.

28 SUNCOR ENERGY INC. 2011 ANNUAL INFORMATION FORM


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 March 3, 2011, with an effective date of December 31, 2010. The preparation date of the information is February 16, 2011.

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 in accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (NI 51-101). For the year ended December 31, 2009, Suncor applied for, and received, an exemption from Canadian securities regulatory authorities permitting Suncor to report its reserves as at December 31, 2009 in accordance with the rules and regulations of the United States Securities and Exchange Commission. Suncor did not apply for a similar exemption order for the year ended December 31, 2010. As a result, closing balances presented in 2009 have been restated (compared to those presented in our December 31, 2009 statement of reserves data and other information) to comply with NI 51-101.

The reserves data set forth below for Suncor's Canadian mining and in situ operations is based upon an evaluation conducted by GLJ Petroleum Consultants Ltd. (GLJ) with an effective date of December 31, 2010, contained in their reports (the GLJ Reports). The reserves data set forth below for all other reserves, which includes Suncor's interests in its Canadian onshore conventional (Natural Gas) and offshore conventional (East Coast Canada) assets, the North Sea of the United Kingdom (the North Sea), and Syria and Libya (collectively, Other International) is based upon evaluations or reviews conducted by Sproule Associates Limited or Sproule International Limited (collectively, Sproule) with an effective date of December 31, 2010 contained in their reports (the Sproule Reports). The reserves data reviewed by Sproule was evaluated by Suncor's internal qualified reserves evaluators. All factual data supplied to GLJ and Sproule (the Evaluators) was accepted as presented. No field inspections were conducted.

The reserves data summarizes Suncor's oil, liquids and natural gas reserves and the net present values of future net revenue for these reserves using forecast prices and costs (unless otherwise indicated) prior to provision for interest, general and administrative expenses, costs associated with environmental regulations, the impact of any hedging activities or the liabilities associated with certain abandonment and all well, pipeline, facilities and mine reclamation costs. Future net revenues have been presented on a before and after-tax basis. The reserves data conforms with the requirements of NI 51-101. See also the "Notes to Reserves Data Tables" and the "Definitions for Reserves Data Tables"

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. The recovery and reserves estimates of oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual oil, natural gas and natural gas liquid reserves may be greater than or less than the estimates provided herein. Readers should review the definitions and information contained in "Notes to Reserves Data Tables", "Definitions for Reserves Data Tables" and "Notes to Future Net Revenues Tables" in conjunction with the following tables and notes. For more information as to the risks involved, see "Risk Factors – Uncertainty of Reserves and Resources Estimates" in this AIF.

SUNCOR ENERGY INC. 2011 ANNUAL INFORMATION FORM 29


Summary of Oil and Gas Reserves (1)(2)(3)
as at December 31, 2010
(forecast prices and costs)


    SCO
  Bitumen
  Light & Medium Oil
  Natural Gas
  Natural Gas Liquids
 
    Gross   Net   Gross   Net   Gross   Net   Gross   Net   Gross   Net  

    MMbbls   MMbbls   MMbbls   MMbbls   MMbbls   MMbbls   Bcf   Bcf   MMbbls   MMbbls  


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
Proved Developed Producing                                          
  Mining   2 084   1 779                  
  In Situ   121   113   37   30              
  East Coast Canada           53   39          
  Natural Gas           10   9   953   806   8   5  
Total Canada   2 205   1 892   37   30   63   48   953   806   8   5  
North Sea (4)           86   86   10   10   1   1  
Other International (5)           102   37   251   166   8   5  

Total Proved Developed Producing   2 205   1 892   37   30   251   172   1 214   982   16   11  


Proved Developed Non-Producing

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Mining                      
  In Situ   50   47                  
  East Coast Canada                      
  Natural Gas               41   31      
Total Canada   50   47           41   31      
North Sea (4)           13   13          
Other International (5)           32   12          

Total Proved Developed Non-Producing   50   47       45   25   42   32      


Proved Undeveloped

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Mining                      
  In Situ   651   561   360   307              
  East Coast Canada           28   22          
  Natural Gas               118   109      
Total Canada   651   561   360   307   28   22   118   109      
North Sea (4)           19   19   1   1      
Other International (5)           7   3          

Total Proved Undeveloped   651   561   360   307   54   44   120   110      


Proved

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Mining   2 084   1 779                  
  In Situ   822   722   397   337              
  East Coast Canada           81   61          
  Natural Gas           10   9   1 113   946   8   5  
Total Canada   2 906   2 500   397   337   91   70   1 113   946   8   5  
North Sea (4)           118   118   12   12   1   1  
Other International (5)           141   52   251   166   8   5  

Total Proved   2 906   2 500   397   337   350   241   1 376   1 124   17   11  


Probable

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Mining   542   462   37   30              
  In Situ   462   360   1 850   1 493              
  East Coast Canada           149   96          
  Natural Gas           7   5   374   307   3   3  
Total Canada   1 003   821   1 887   1 523   155   102   374   307   3   3  
North Sea (4)           57   57   4   4      
Other International (5)           101   39   281   157   9   5  

Total Probable   1 003   821   1 887   1 523   313   198   660   468   13   8  


Proved Plus Probable

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Mining   2 626   2 240   37   30              
  In Situ   1 283   1 081   2 247   1 830              
  East Coast Canada           230   158          
  Natural Gas           17   14   1 488   1 253   11   7  
Total Canada   3 909   3 321   2 284   1 860   247   172   1 488   1 253   11   7  
North Sea (4)           175   175   16   16   1   1  
Other International (5)           241   91   532   323   17   10  

Total Proved Plus Probable   3 909   3 321   2 284   1 860   663   439   2 036   1 592   29   19  

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

30 SUNCOR ENERGY INC. 2011 ANNUAL INFORMATION FORM


Summary of Oil and Gas Reserves (1)(2)(3)
as at December 31, 2010
(constant prices and costs)


    SCO
  Bitumen
  Light & Medium Oil
  Natural Gas
  Natural Gas Liquids
 
    Gross   Net   Gross   Net   Gross   Net   Gross   Net   Gross   Net  

    MMbbls   MMbbls   MMbbls   MMbbls   MMbbls   MMbbls   Bcf   Bcf   MMbbls   MMbbls  


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
Proved Developed Producing                                          
  Mining   2 084   1 792                  
  In Situ   121   115   37   30              
  East Coast Canada           53   40          
  Natural Gas           10   10   874   756   7   5  
Total Canada   2 205   1 907   37   30   63   50   874   756   7   5  
North Sea (4)           86   87   10   10   1   1  
Other International (5)           102   37   246   166   8   5  

Total Proved Developed Producing   2 205   1 907   37   30   251   173   1 130   933   16   11  


Proved Developed Non-Producing

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Mining                      
  In Situ   50   48                  
  East Coast Canada                      
  Natural Gas               25   20      
Total Canada   50   48           25   20      
North Sea (4)           13   13          
Other International (5)           32   12          

Total Proved Developed Non-Producing   50   48       45   25   25   20      


Proved Undeveloped

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Mining                      
  In Situ   652   577   360   318              
  East Coast Canada           27   21          
  Natural Gas               79   74      
Total Canada   652   577   360   318   27   21   79   74      
North Sea (4)           19   19   1   1      
Other International (5)           7   3          

Total Proved Undeveloped   652   577   360   318   52   43   80   75      


Proved

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Mining   2 084   1 792                  
  In Situ   822   739   397   348              
  East Coast Canada           79   61          
  Natural Gas           10   10   978   850   8   5  
Total Canada   2 906   2 531   397   348   90   70   978   850   8   5  
North Sea (4)           118   118   12   12   1   1  
Other International (5)           140   52   246   166   8   5  

Total Proved   2 906   2 531   397   348   348   240   1 235   1 028   17   11  


Probable

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Mining   542   472   37   31              
  In Situ   462   384   1 850   1 580              
  East Coast Canada           150   99          
  Natural Gas           3   3   259   221   2   2  
Total Canada   1 003   856   1 887   1 612   153   102   259   221   2   2  
North Sea (4)           58   58   4   4      
Other International (5)           101   41   277   157   9   5  

Total Probable   1 003   856   1 887   1 612   312   200   540   382   12   7  


Proved Plus Probable

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Mining   2 626   2 264   37   31              
  In Situ   1 283   1 124   2 247   1 928              
  East Coast Canada           230   160          
  Natural Gas           14   12   1 237   1 071   10   7  
Total Canada   3 909   3 387   2 284   1 959   243   172   1 237   1 071   10   7  
North Sea (4)           176   176   16   16   1   1  
Other International (5)           241   92   523   323   17   10  

Total Proved Plus Probable   3 909   3 387   2 284   1 959   660   440   1 776   1 410   28   18  

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

Please see "Notes to Future Net Revenue Tables" section for important information about constant prices and costs.

SUNCOR ENERGY INC. 2011 ANNUAL INFORMATION FORM 31


Reconciliation of Gross Oil Reserves (1)(2)(3)
as at December 31, 2010
(forecast prices and costs)


    SCO
  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, 2009 (6)                                        
  Mining   2 202   591   2 794                
  In Situ   734   665   1 398   450   1 560   2 010          
  East Coast Canada               89   137   226    
  Natural Gas               15   6   21    
Total Canada   2 936   1 256   4 192   450   1 560   2 010   104   143   247    
North Sea (4)               141   70   210    
United States               23   4   28    
Other International (5)               125   133   258    

Total   2 936   1 256   4 192   450   1 560   2 010   393   350   743    


Extensions & Improved Recovery (7)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Mining                      
  In Situ   14   (8 ) 6   2   6   8          
  East Coast Canada               6   2   9    
  Natural Gas                      
Total Canada   14   (8 ) 6   2   6   8   6   3   9    
North Sea (4)                      
United States                      
Other International (5)               6   8   13    

Total   14   (8 ) 6   2   6   8   12   11   22    


Technical Revisions (8)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Mining   (29 ) (50 ) (79 )   37   37          
  In Situ   91   (195 ) (105 ) (45 ) 284   239          
  East Coast Canada               12   8   20    
  Natural Gas                 (2 ) (2 )  
Total Canada   62   (245 ) (184 ) (45 ) 321   276   12   6   18    
North Sea (4)               8   (6 ) 2    
United States                      
Other International (5)               22   (40 ) (18 )  

Total   62   (245 ) (184 ) (45 ) 321   276   42   (40 ) 2    


Discoveries (9)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Mining                      
  In Situ                      
  East Coast Canada                 2   2    
  Natural Gas                      
Total Canada                 2   2    
North Sea (4)                      
United States                      
Other International (5)                      

Total                 2   2    

Please see Notes (1) through (11) at the end of the reserves data section for important information about volumes in this table.

32 SUNCOR ENERGY INC. 2011 ANNUAL INFORMATION FORM


Reconciliation of Gross Oil Reserves (1)(2)(3) (continued)
as at December 31, 2010
(forecast prices and costs)


    SCO
  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                      
  Natural Gas                      
Total Canada                      
North Sea (4)                      
United States                      
Other International (5)                      

Total                      


Dispositions (10)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Mining                      
  In Situ                      
  East Coast Canada                      
  Natural Gas               (2 ) (1 ) (2 )  
Total Canada               (2 ) (1 ) (2 )  
North Sea (4)               (4 ) (6 ) (10 )  
United States               (23 ) (4 ) (27 )  
Other International (5)                      

Total               (29 ) (11 ) (39 )  


Economic Factors (11)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Mining                      
  In Situ                      
  East Coast Canada                      
  Natural Gas               (3 ) 3      
Total Canada               (3 ) 3      
North Sea (4)                      
United States                      
Other International (5)                      

Total                           (3 ) 3      


Production

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Mining   (89 )   (89 )              
  In Situ   (17 )   (17 ) (10 )   (10 )        
  East Coast Canada               (26 )   (26 )  
  Natural Gas               (1 )   (1 )  
Total Canada   (106 )   (106 ) (10 )   (10 ) (27 )   (27 )  
North Sea (4)               (27 )   (27 )  
United States                      
Other International (5)               (13 )   (13 )  

Total   (106 )   (106 ) (10 )   (10 ) (67 )   (67 )  


December 31, 2010

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Mining   2 084   542   2 626     37   37          
  In Situ   822   462   1 283   397   1 850   2 247          
  East Coast Canada               81   149   230    
  Natural Gas               10   7   17    
Total Canada   2 906   1 003   3 909   397   1 887   2 284   91   155   247    
North Sea (4)               118   57   175    
United States                      
Other International (5)               141   101   241    

Total   2 906   1 003   3 909   397   1 887   2 284   350   313   663    

Please see Notes (1) through (11) at the end of the reserves data section for important information about volumes in this table.

SUNCOR ENERGY INC. 2011 ANNUAL INFORMATION FORM 33


Reconciliation of Gross Natural Gas and NGL Reserves (1)(2)(3)
as at December 31, 2010
(forecast prices and costs)


    Natural Gas
  Natural Gas Liquids
   
    Proved
  Probable
  Proved
Plus
Probable

  Proved
  Probable
  Proved
Plus
Probable

   
    Bcf   Bcf   Bcf   MMbbls   MMbbls   MMbbls    


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
December 31, 2009 (6)                            
Natural Gas and Total Canada   1 547   712   2 259   18   6   24    
North Sea (4)   29   74   102   2   1   3    
United States   154   26   180          
Trinidad and Tobago   172   90   263          
Other International (5)   341   613   953   9   19   28    

Total   2 243   1 515   3 757   29   26   55    


Extensions & Improved Recovery (7)

 

 

 

 

 

 

 

 

 

 

 

 

 

 
Natural Gas and Total Canada   39   78   116          
North Sea (4)                
United States                
Trinidad and Tobago                
Other International (5)                

Total   39   78   116          


Technical Revisions (8)

 

 

 

 

 

 

 

 

 

 

 

 

 

 
Natural Gas and Total Canada   161   (191 ) (29 ) (1 )   (1 )  
North Sea (4)   6   (5 ) 1   (1 ) (1 ) (1 )  
United States                
Trinidad and Tobago     1   1          
Other International (5)   (68 ) (331 ) (400 )   (9 ) (10 )  

Total   99   (526 ) (427 ) (2 ) (10 ) (12 )  


Discoveries (9)

 

 

 

 

 

 

 

 

 

 

 

 

 

 
Natural Gas and Total Canada   1     2          
North Sea (4)                
United States                
Trinidad and Tobago                
Other International (5)                

Total   1     2          

Please see Notes (1) through (11) at the end of the reserves data section for important information about volumes in this table.

34 SUNCOR ENERGY INC. 2011 ANNUAL INFORMATION FORM


Reconciliation of Gross Natural Gas and NGL Reserves (1)(2)(3) (continued)
as at December 31, 2010
(forecast prices and costs)


    Natural Gas
  Natural Gas Liquids
   
    Proved
  Probable
  Proved
Plus
Probable

  Proved
  Probable
  Proved
Plus
Probable

   
    Bcf   Bcf   Bcf   MMbbls   MMbbls   MMbbls    


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
Acquisitions                            
Natural Gas and Total Canada                
North Sea (4)                
United States                
Trinidad and Tobago                
Other International (5)                

Total                


Dispositions (10)

 

 

 

 

 

 

 

 

 

 

 

 

 

 
Natural Gas and Total Canada   (402 ) (133 ) (535 ) (7 ) (2 ) (10 )  
North Sea (4)   (11 ) (64 ) (75 )        
United States   (151 ) (26 ) (177 )        
Trinidad and Tobago   (158 ) (92 ) (249 )        
Other International (5)                

Total   (722 ) (315 ) (1 036 ) (7 ) (2 ) (10 )  

Economic Factors (11)                
Natural Gas and Total Canada   (45 ) (92 ) (137 )        
North Sea (4)                
United States                
Trinidad and Tobago                
Other International (5)   1     1          

Total   (44 ) (92 ) (136 )        


Production

 

 

 

 

 

 

 

 

 

 

 

 

 

 
Natural Gas and Total Canada   (189 )   (189 ) (2 )   (2 )  
North Sea (4)   (12 )   (12 )        
United States   (3 )   (3 )        
Trinidad and Tobago   (15 )   (15 )        
Other International (5)   (22 )   (22 ) (1 )   (1 )  

Total   (241 )   (241 ) (3 )     (3 )  


December 31, 2010

 

 

 

 

 

 

 

 

 

 

 

 

 

 
Natural Gas and Total Canada   1 113   374   1 488   8   3   11    
North Sea (4)   12   4   16   1     1    
United States                
Trinidad and Tobago                
Other International (5)   251   281   532   8   9   17    

Total   1 376   659   2 036   17   12   29    

Please see Notes (1) through (11) at the end of the reserves data section for important information about volumes in this table.

SUNCOR ENERGY INC. 2011 ANNUAL INFORMATION FORM 35


Notes to Reserves Data Tables
as at December 31, 2010

(1)
Numbers in the above tables are rounded to the nearest MMbbl or Bcf, as the case may be, and may not add due to rounding.

(2)
The reserves data are based upon evaluations by GLJ and Sproule with an effective date of December 31, 2010, except for certain North Sea reserves (approximately 15% of total North Sea reserves) which were evaluated by Suncor's internal qualified reserves evaluators and reviewed by Sproule. The reserves data does not account for any planned divestitures after the effective date.

(3)
See "Notes to Future Net Revenues Tables" for information on forecast and constant prices and costs.

(4)
No royalty is payable on reserves in the U.K. The "Reconciliation of Gross Oil Reserves" and "Reconciliation of Gross Natural Gas and NGL Reserves" tables include Suncor's Netherlands operations, which were sold effective August 13, 2010.

(5)
"Other International" reserves, which include Libya and Syria, include quantities of crude oil and natural gas, which will be produced under PSCs, which involve the company in upstream risks and rewards, but which do not transfer title of the product to the company. Under these PSCs, net proved and probable reserves have been determined using the economic interest method. See "Definitions for Reserves Data Tables" section.

(6)
For the year ended December 31, 2009, Suncor presented disclosures in accordance with U.S. disclosure requirements under an exemption from Canadian securities requirements. As a result, closing balances presented in the 2009 disclosure have been restated to comply with NI 51-101, consistent with the presentation format for December 31, 2010 reserve disclosures.

(7)
Extensions and Improved Recovery are additions to the reserves resulting from step-out drilling, infill drilling and installation of improved recovery schemes.

(8)
Technical Revisions include changes in previous estimates, upward or downward, resulting from new technical data or revised interpretations.

(9)
Discoveries are additions to reserves in reservoirs where no reserves were previously booked.

(10)
Suncor sold its U.S. natural gas assets effective March 1, 2010. Suncor sold its Trinidad and Tobago assets effective August 5, 2010. Suncor sold its Netherland operations, included in "North Sea" reserves in the "Reconciliation of Gross Oil Reserves" and "Reconciliation of Gross Natural Gas and NGL Reserves" tables, effective August 13, 2010.

(11)
Economic Factors are changes due to product pricing.

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 (operating and non-operating) 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 an 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 (operating and non-operating) 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, natural gas liquids and natural gas reserves estimates presented are based on the definitions and guidelines contained in the Canadian Oil and Gas Evaluation Handbook (COGE Handbook). A summary of those definitions are set forth below. The synthetic crude oil reserves include Suncor's diesel sales volumes.

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 analysis of drilling, geological, geophysical and engineering data; the use of established technology; and specified economic conditions which are generally accepted as being reasonable.

36 SUNCOR ENERGY INC. 2011 ANNUAL INFORMATION FORM


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.

Each of the reserves categories (proved and probable) may be divided into developed and undeveloped categories:

Developed reserves are those reserves that are expected to be recovered 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. The developed category may be subdivided into producing and non-producing.

(i)
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 previously been on production, and the date of resumption of production must be known with reasonable certainty.

(ii)
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 estimator'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, the contractor's (i.e. Suncor's) share of profit revenue plus cost recovery revenue is divided by the associated oil or gas price forecast to determine the contractor's net volume entitlement, or entitlement reserves. The entitlement reserves are then adjusted to include reserves relating to income taxes payable. 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 per cent probability that the quantities actually recovered will equal or exceed the estimated proved reserves; and

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

A qualitative measure of the certainty levels pertaining to estimates prepared for the various reserves categories is desirable to provide 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.

SUNCOR ENERGY INC. 2011 ANNUAL INFORMATION FORM 37


Net Present Value of Future Net Revenues
as at December 31, 2010
(forecast prices and costs)


   
Net Present Values of Future Net Revenue
Before Income Taxes Discounted at %/year
($ millions) (1)

 
Unit Value (2)

 
    0%   5%   10%   15%   20%   $/boe  


 

 

 

 

 

 

 

 

 

 

 

 

 

 
Proved Developed Producing                          
  Mining   66 666   39 429   25 893   18 474   14 043   14.56  
  In Situ   4 315   3 691   3 215   2 844   2 547   22.48  
  East Coast Canada   1 988   1 828   1 687   1 564   1 458   42.94  
  Natural Gas   4 071   2 791   2 146   1 755   1 492   14.45  
Total Canada   77 041   47 740   32 941   24 636   19 540   15.62  
North Sea   6 491   5 681   5 056   4 563   4 166   56.38  
Other International   4 861   3 640   2 895   2 399   2 046   41.39  

Total Proved Developed Producing   88 393   57 061   40 892   31 598   25 751   18.02  


Proved Developed Non-Producing

 

 

 

 

 

 

 

 

 

 

 

 

 
  Mining              
  In Situ   1 896   1 472   1 168   945   779   24.80  
  East Coast Canada              
  Natural Gas   80   55   40   30   23   7.45  
Total Canada   1 976   1 527   1 209   976   802   23.01  
North Sea   991   756   599   490   411   46.58  
Other International   1 109   620   374   239   158   31.33  

Total Proved Developed Non-Producing   4 076   2 903   2 182   1 705   1 371   28.22  


Proved Undeveloped

 

 

 

 

 

 

 

 

 

 

 

 

 
  Mining              
  In Situ   27 109   12 318   6 152   3 272   1 781   7.09  
  East Coast Canada   973   810   685   588   511   31.07  
  Natural Gas   308   186   113   68   38   6.19  
Total Canada   28 390   13 314   6 950   3 928   2 330   7.65  
North Sea   1 404   1 141   951   810   702   49.88  
Other International   197   137   99   72   52   31.57  

Total Proved Undeveloped   29 991   14 592   8 001   4 810   3 084   8.59  


Proved

 

 

 

 

 

 

 

 

 

 

 

 

 
  Mining   66 666   39 429   25 893   18 474   14 043   14.56  
  In Situ   33 320   17 481   10 536   7 061   5 107   9.95  
  East Coast Canada   2 961   2 638   2 371   2 151   1 968   38.67  
  Natural Gas   4 459   3 032   2 300   1 853   1 554   13.35  
Total Canada   107 406   62 580   41 100   29 540   22 672   13.38  
North Sea   8 886   7 578   6 607   5 863   5 278   54.32  
Other International   6 167   4 396   3 368   2 710   2 257   39.61  

Total Proved   122 460   74 554   51 075   38 113   30 208   15.58  


Probable

 

 

 

 

 

 

 

 

 

 

 

 

 
  Mining   24 854   8 447   3 272   1 402   653   6.65  
  In Situ   77 617   22 472   7 940   3 065   1 065   4.29  
  East Coast Canada   7 033   5 204   4 028   3 232   2 672   41.75  
  Natural Gas   1 835   836   461   280   176   7.83  
Total Canada   111 339   36 959   15 701   7 979   4 566   6.28  
North Sea   5 041   3 436   2 501   1 912   1 515   43.35  
Other International   5 775   3 415   2 221   1 554   1 149   31.73  

Total Probable   122 155   43 810   20 424   11 445   7 230   7.77  


Proved Plus Probable

 

 

 

 

 

 

 

 

 

 

 

 

 
  Mining   91 520   47 876   29 165   19 876   14 696   12.84  
  In Situ   110 937   39 954   18 477   10 126   6 172   6.35  
  East Coast Canada   9 994   7 842   6 399   5 384   4 640   40.56  
  Natural Gas   6 294   3 869   2 761   2 133   1 730   11.94  
Total Canada   218 745   99 541   56 802   37 519   27 238   10.20  
North Sea   13 927   11 014   9 108   7 775   6 794   50.79  
Other International   11 942   7 813   5 590   4 264   3 406   36.06  

Total Proved Plus Probable   244 614   118 368   71 500   49 558   37 438   12.11  

(1)
Numbers in the above table are rounded to the nearest $1MM and may not add due to rounding.

(2)
Unit values are before income taxes, discounted at 10%, using net reserves.

38 SUNCOR ENERGY INC. 2011 ANNUAL INFORMATION FORM


Net Present Value of Future Net Revenues
as at December 31, 2010
(forecast prices and costs)


   
Net Present Values of Future Net Revenue
After Income Taxes Discounted at %/year
($ millions) (1)

 
    0%   5%   10%   15%   20%  


 

 

 

 

 

 

 

 

 

 

 

 
Proved Developed Producing                      
  Mining   50 377   29 410   19 145   13 580   10 281  
  In Situ   4 121   3 515   3 054   2 694   2 408  
  East Coast Canada   1 363   1 246   1 141   1 049   969  
  Natural Gas   3 239   2 229   1 718   1 408   1 199  
Total Canada   59 100   36 401   25 058   18 731   14 857  
North Sea   3 037   2 675   2 393   2 169   1 988  
Other International   2 458   1 915   1 567   1 326   1 150  

Total Proved Developed Producing   64 594   40 990   29 018   22 226   17 995  


Proved Developed Non-Producing

 

 

 

 

 

 

 

 

 

 

 
  Mining            
  In Situ   1 468   1 149   921   752   625  
  East Coast Canada            
  Natural Gas   59   39   28   20   15  
Total Canada   1 527   1 189   948   772   640  
North Sea   496   388   317   268   233  
Other International   399   230   144   95   65  

Total Proved Developed Non-Producing   2 421   1 807   1 409   1 135   938  


Proved Undeveloped

 

 

 

 

 

 

 

 

 

 

 
  Mining            
  In Situ   20 029   8 766   4 132   1 998   910  
  East Coast Canada   667   552   463   394   339  
  Natural Gas   228   130   73   37   14  
Total Canada   20 925   9 448   4 668   2 429   1 264  
North Sea   702   578   488   420   368  
Other International   70   49   35   25   19  

Total Proved Undeveloped   21 697   10 075   5 191   2 875   1 650  


Proved

 

 

 

 

 

 

 

 

 

 

 
  Mining   50 377   29 410   19 145   13 580   10 281  
  In Situ   25 618   13 430   8 107   5 444   3 944  
  East Coast Canada   2 031   1 799   1 604   1 443   1 308  
  Natural Gas   3 526   2 399   1 819   1 466   1 228  
Total Canada   81 552   47 037   30 675   21 932   16 761  
North Sea   4 234   3 641   3 198   2 857   2 589  
Other International   2 927   2 194   1 746   1 446   1 233  

Total Proved   88 713   52 873   35 619   26 236   20 583  


Probable

 

 

 

 

 

 

 

 

 

 

 
  Mining   19 242   6 289   2 291   884   339  
  In Situ   57 629   16 228   5 407   1 808   350  
  East Coast Canada   5 476   4 078   3 180   2 572   2 142  
  Natural Gas   1 367   616   332   193   114  
Total Canada   83 714   27 211   11 209   5 457   2 946  
North Sea   2 523   1 742   1 283   991   793  
Other International   2 693   1 632   1 078   762   568  

Total Probable   88 930   30 585   13 570   7 210   4 307  


Proved Plus Probable

 

 

 

 

 

 

 

 

 

 

 
  Mining   69 619   35 699   21 436   14 464   10 620  
  In Situ   83 247   29 658   13 513   7 252   4 294  
  East Coast Canada   7 506   5 877   4 784   4 014   3 451  
  Natural Gas   4 893   3 015   2 151   1 659   1 342  
Total Canada   165 265   74 248   41 883   27 389   19 707  
North Sea   6 758   5 383   4 481   3 848   3 381  
Other International   5 621   3 827   2 824   2 208   1 801  

Total Proved Plus Probable   177 644   83 459   49 188   33 445   24 889  

(1)
Numbers in the above table are rounded to the nearest $1MM and may not add due to rounding.

SUNCOR ENERGY INC. 2011 ANNUAL INFORMATION FORM 39


Total Future Net Revenues
as at December 31, 2010
(forecast prices and costs)


(undiscounted in $ millions) (1)   Revenue   Royalties   Operating
Costs
  Capital
Development
Costs
  Abandonment
Costs
  Future Net
Revenue Before
Deducting
Future
Income Tax
Expenses
  Future
Income Tax
Expenses
  Future Net
Revenue After
Deducting
Future
Income Tax
Expenses
 


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
Proved Developed Producing                                  
  Mining   226 272   33 812   81 027   44 767     66 666   16 290   50 377  
  In Situ   13 339   1 103   6 605   1 268   48   4 315   195   4 121  
  East Coast Canada   4 763   1 192   1 107   220   256   1 988   625   1 363  
  Natural Gas   8 186   1 105   2 856   22   131   4 071   832   3 239  
Total Canada   252 561   37 212   91 596   46 277   435   77 041   17 942   59 100  
North Sea   8 268     1 439   60   278   6 491   3 455   3 037  
Other International   6 844   493   1 302   170   15   4 861   2 403   2 458  

Total Proved Developed Producing   267 672   37 705   94 336   46 507   728   88 393   23 800   64 594  


Proved Developed Non-Producing

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Mining                  
  In Situ   4 959   290   2 272   488   13   1 896   428   1 468  
  East Coast Canada                  
  Natural Gas   267   53   113   20   1   80   21   59  
Total Canada   5 226   343   2 385   508   15   1 976   449   1 527  
North Sea   1 274     283       991   496   496  
Other International   1 341   11   142   71   9   1 109   709   399  

Total Proved Developed Non-Producing   7 840   353   2 809   579   24   4 076   1 654   2 421  


Proved Undeveloped

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Mining                  
  In Situ   105 768   15 301   38 693   24 198   466   27 109   7 079   20 029  
  East Coast Canada   2 658   609   579   466   31   973   306   667  
  Natural Gas   819   60   201   231   19   308   80   228  
Total Canada   109 245   15 970   39 473   24 895   516   28 390   7 464   20 925  
North Sea   1 803     291   86   24   1 404   702   702  
Other International   311   7   20   85   1   197   127   70  

Total Proved Undeveloped   111 359   15 976   39 783   25 066   541   29 991   8 294   21 697  


Proved

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Mining   226 272   33 812   81 027   44 767     66 666   16 290   50 377  
  In Situ   124 067   16 695   47 570   25 954   527   33 320   7 703   25 618  
  East Coast Canada   7 421   1 801   1 686   686   287   2 961   931   2 031  
  Natural Gas   9 272   1 217   3 170   274   152   4 459   933   3 526  
Total Canada   367 032   53 525   133 453   71 681   967   107 406   25 857   81 552  
North Sea   11 345     2 011   146   302   8 886   4 653   4 234  
Other International   8 494   510   1 464   326   26   6 167   3 239   2 927  

Total Proved   386 870   54 035   136 927   72 153   1 294   122 460   33 748   88 713  


Probable

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Mining   77 180   11 786   26 915   13 625   0   24 854   5 610   19 242  
  In Situ   240 597   48 189   72 795   41 259   736   77 617   19 988   57 629  
  East Coast Canada   14 773   5 172   1 166   1 307   95   7 033   1 557   5 476  
  Natural Gas   4 193   673   1 396   268   21   1 835   468   1 367  
Total Canada   336 743   65 820   102 272   56 459   852   111 339   27 623   83 714  
North Sea   6 046     796   180   29   5 041   2 518   2 523  
Other International   7 852   695   969   410   3   5 775   3 082   2 693  

Total Probable   350 641   66 515   104 037   57 049   884   122 155   33 223   88 930  


Proved Plus Probable

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Mining   303 452   45 598   107 942   58 392     91 520   21 900   69 619  
  In Situ   364 663   64 884   120 365   67 213   1 263   110 937   27 690   83 247  
  East Coast Canada   22 194   6 973   2 852   1 993   382   9 994   2 488   7 506  
  Natural Gas   13 464   1 891   4 565   542   173   6 294   1 401   4 893  
Total Canada   703 773   119 346   235 724   128 140   1 818   218 745   53 479   165 265  
North Sea   17 391     2 807   326   331   13 927   7 170   6 758  
Other International   16 347   1 205   2 433   735   29   11 942   6 321   5 621  

Total Proved Plus Probable   737 511   120 551   240 964   129 201   2 178   244 614   66 969   177 644  

(1)
Numbers in the above table are rounded to the nearest $1MM and may not add due to rounding.

40 SUNCOR ENERGY INC. 2011 ANNUAL INFORMATION FORM


Future Net Revenues by Production Group
as at December 31, 2010
(forecast prices and costs)


Future Net Revenue Before Income Taxes
Discounted at 10%/year
         

    $ millions (1)   $/boe (2)  

Proved          
  Unconventional – Mining   25 893   14.56  
  Unconventional – In Situ   10 536   9.95  
Total Unconventional (3)   36 429   12.84  
Light and Medium Oil (4)   11 398   47.16  
Natural Gas (5)   3 248   17.35  

Total Proved   51 075   15.58  


Proved Plus Probable

 

 

 

 

 
  Unconventional – Mining   29 165   12.84  
  Unconventional – In Situ   18 477   6.35  
Total Unconventional (3)   47 642   9.19  
Light and Medium Oil (4)   19 466   44.36  
Natural Gas (5)   4 393   16.56  

Total Proved Plus Probable   71 500   12.11  

(1)
Numbers in the above table are rounded to the nearest $1MM and may not add due to rounding.

(2)
Per unit values use net reserves.

(3)
Total Unconventional includes SCO and bitumen.

(4)
Light and Medium Oil includes associated byproducts including solution gas and NGLs.

(5)
Natural gas includes associated byproducts including oil and NGLs.

SUNCOR ENERGY INC. 2011 ANNUAL INFORMATION FORM 41


Notes to Future Net Revenues Tables

Prices

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, 2011, 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 also included a $Cdn/$US exchange rate of 1.02, a $Cdn/Euro exchange rate of 1.35 and a $Cdn/GBP exchange rate of 1.60. Forecast costs included a 2% inflation factor, except for costs for mining operations, which included 4% inflation for 2012-2014, 3% inflation for 2015 and 2% thereafter.

Constant Prices and costs

Benchmark prices utilized 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 unweighted arithmetic average of the first-day-of-the-month price for the product for each month of 2010.

Prices used in Reserves Tables(1)


Year   NYMEX WTI (2)
Crude Oil at
Cushing,
Oklahoma
  Light Sweet (3)
Crude Oil (40
API, 0.3%S)
at Edmonton
  WCS (4)
Stream
Quality at
Hardisty
  Edmonton (5)
Pentanes
Plus
  Brent Blend (6)
Crude Oil
FOB North
Sea
  Natural Gas (7)
at AECO
  National (8)
Balancing
Point (U.K.)
 

Forecast   US$/bbl   Cdn$/bbl   Cdn$/bbl   Cdn$/bbl   US$/bbl   Cdn$/MMbtu   Cdn$/MMbtu  

2011   88.00   86.22   74.98   90.54   88.50   4.16   9.03  
2012   89.00   89.29   74.95   91.96   88.25   4.74   9.01  
2013   90.00   90.92   74.13   92.74   88.50   5.31   9.03  
2014   92.00   92.96   75.23   94.82   90.50   5.77   9.23  
2015   95.17   96.19   77.84   98.12   93.67   6.22   9.56  
2016   97.55   98.62   79.79   100.59   96.05   6.53   9.80  
2017   100.26   101.39   82.02   103.42   98.76   6.76   10.08  
2018   102.74   103.92   84.05   106.00   101.24   6.90   10.33  
2019   105.45   106.68   86.28   108.82   103.95   7.06   10.61  
2020   107.56   108.84   88.01   111.01   106.06   7.21   10.82  
2021+   +2.0%/yr   +2.0%/yr   +2.0%/yr   +2.0%/yr   +2.0%/yr   +2.0%/yr   +2.0%/yr  


Constant

 

US$/bbl

 

Cdn$/bbl

 

Cdn$/bbl

 

Cdn$/bbl

 

US$/bbl

 

Cdn$/MMbtu

 

Cdn$/MMbtu

 

All   79.43   79.46   68.07   84.10   79.22   4.03   6.66  

(1)
Each price from the GLJ forecast was adjusted for quality differentials and transportation costs applicable to the specific product group and country or area of production.

(2)
Price used when determining SCO reserves presented as In Situ and Mining reserves.

(3)
Price used when determining light and medium oil reserves presented as Natural Gas reserves.

(4)
Price used when determining bitumen reserves presented as In Situ reserves.

(5)
Price used when determining diluent costs associated with bitumen reserves presented as In Situ reserves. A bitumen/diluent ratio of 2:1 was assumed.

(6)
Price used when determining light and medium oil reserves presented as East Coast Canada reserves, North Sea reserves and Other International reserves.

(7)
Price used when determining natural gas reserves presented as Natural Gas reserves for Canada. Price also used when determining natural gas input costs for the production of SCO and bitumen reserves.

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

Prices Realized

For prices realized by Suncor during 2010, please see the Production History section contained within this Statement of Reserves Data and Other Oil and Gas Information.

42 SUNCOR ENERGY INC. 2011 ANNUAL INFORMATION FORM


Future Development Costs
as at December 31, 2010
(forecast prices and costs)

The following table sets forth development costs deducted in the estimation of Suncor's future net revenue attributable to the reserves categories noted below as at December 31, 2010.


($ millions) (1)   2011   2012   2013   2014   2015   Remainder   Total   10%
Discounted
 

Proved                                  
  Mining   2 153   2 122   1 781   1 746   1 736   35 229   44 767   19 133  
  In Situ   1 338   667   745   711   984   21 509   25 954   9 608  
  East Coast Canada   198   140   114   53   47   136   689   538  
  Natural Gas   112   37   31   17   25