40-F 1 a2190827z40-f.htm FORM 40-F

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## SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549



## Form 40-F

For fiscal year ended: December 31, 2008 Commission File Number: No. 1-12384



## SUNCOR ENERGY INC.

(Exact name of registrant as specified in its charter)

112 - 4 th Avenue S.W.

Box 38

Calgary, Alberta, Canada T2P 2V5

(403) 269-8100

(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 Unit ed States)

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

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 (Check One)

 REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES

EXCHANGE ACT OF 1934

OR

ANNUAL REPORT PURSUANT TO SECTION 13(a) OR 15(d) OF THE SECURITIES

EXCHANGE ACT OF 1934

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)

Title of each class: Name of each exchange on which registered:

Common shares New York Stock Exchange

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

Annual Information Form Annual Audited Financial Statements Page 1 of 100

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- f.mhtIndicate the number of outstanding shares of each of the issuer's c lasses of capital or common stock as of the close of the

period covered by the annual report:

Indicate by check mark whether the registrant by filing the informa tion contained in this form is also thereby furnishing the

information to the Commission pursuant to Rule 12g3-2(b) under the Securiti es Exchange Act of 1934 (the "Exchange Act").

If "Yes" is marked, indicate the file number assigned to the regi strant in connection with such rule. Yes  No Indicate by check mark whether the registrant: (1) has filed al l 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 No 

Common Shares As of December 31, 2008 there were 935,524,213 Common Shares issue d

and outstanding

Preferred Shares, Series A None Page 2 of 100

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- f.mhtSUNCOR ENERGY INC.

ANNUAL INFORMATION FORM

March 2, 2009 Page 3 of 100

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- f.mhtANNUAL INFORMATION FORM

TABLE OF CONTENTS

TABLE OF CONTENTS i

GLOSSARY OF TERMS 1

CONVERSION TABLE 5

CURRENCY 5

FORWARD

- LOOKING STATEMENTS 5

NON

- GAAP FINANCIAL MEASURES 6

CORPORATE STRUCTURE 7

Name and Incorporation 7

Intercorporate Relationships 7

GENERAL DEVELOPMENT OF THE BUSINESS 9

Overview 9

Three

- Year History 10

NARRATIVE DESCRIPTION OF THE BUSINESS 14

Oil Sands 14

Natural Gas 18

Refining and Marketing 19

STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS IN FORMATION 26

Date of Statement 26

Disclosure of Reserves Data 26

Reserves Data (Forecast Prices and Costs) 27

Reconciliation Of Changes In Reserves 34

Additional Information Relating to Reserves Data 35

Other Oil and Gas Information 36

INDUSTRY CONDITIONS 41

RISK FACTORS 48

DIVIDENDS 60

DESCRIPTION OF CAPITAL STRUCTURE 60

General Description of Capital Structure 60

Ratings 60

MARKET FOR OUR SECURITIES 62

Price Range and Trading Volume of Common Shares 62

Prior Sales 62

DIRECTORS AND EXECUTIVE OFFICERS 63

Directors 63

Corporate Officers 65

Cease Trade Orders, Bankruptcies, Penalties or Sanctions 66

Conflicts of Interest 67

SUNCOR EMPLOYEES 67

AUDIT COMMITTEE INFORMATION 68

Audit Committee Charter 68

Composition of the Audit Committee 68

Financial Literacy 68

Audit Committee Financial Expert 69

Audit Committee Pre

- Approval Policies for Non Audit Services 70

Fees Paid to Auditors 70

LEGAL PROCEEDINGS AND REGULATORY ACTIONS 71 Page 4 of 100

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INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANS ACTIONS 71

TRANSFER AGENT AND REGISTRAR 71

MATERIAL CONTRACTS 72

INTERESTS OF EXPERTS 72 Page 5 of 100

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DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NEW YORK STOCK EXCHANGE 72

ADDITIONAL INFORMATION 72

SCHEDULE “ A ”

- SUNCOR ENERGY INC. POLICY AND PROCEDURES FOR PRE

- APPROVAL OF AUDIT

AND NON

- AUDIT SERVICES A

- 1

SCHEDULE “ B ”

- AUDIT COMMITTEE CHARTER B

- 1

SCHEDULE “ C ”

- FORM 51

- 101F3 REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS

DISCLOSURE C

- 1

SCHEDULE “ D ”

- FORM 51

- 101F2 REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESE RVES

EVALUATOR D

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- f.mhtGLOSSARY 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 unl ess the context otherwise requires.

Barrel of Oil Equivalent (BOE)

Suncor converts natural gas to barrels of oil equivalent (BOE) at a 6 thousand cubic feet:1 barrel ratio. BOEs may be

misleading, particularly if used in isolation. The BOE conversi on ratio of 6:1 is based on an energy equivalency conversion

method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

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 ot her petroleum products.

Capacity

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

design specifications.

Coal Bed Methane

Natural gas produced from wells drilled into a coal formation.

Conventional Crude Oil

Crude oil produced through wells by standard industry recovery methods.

Conventional Natural Gas

Natural gas produced from all geological strata, excluding coal bed methane.

Crude Oil

Unrefined liquid hydrocarbons, excluding natural gas liquids.

Development Costs

Includes all costs associated with moving reserves from other c lasses such as “proved undeveloped” and “probable” to the

“proved developed” class.

Downstream

This business segment manufactures, distributes and markets refi ned products from crude oil.

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- f.mhtDry Hole

An exploration or development well determined, on an economic basis, to be incapable of producing hydrocarbons, and that

will be plugged, abandoned and reclaimed.

Feedstock

In the oil sands business, feedstock generally refers to raw bitum en required in the production of synthetic crude oil. In the

downstream business segment, feedstock refers to purchases of components required in the production of refined product other

than crude oil.

Finding Costs

Includes the cost of and investment in undeveloped land, geological and geophys ical activities, exploratory drilling and direct

administrative costs necessary to discover crude oil and natural gas reserves.

Gross Wells/Land Holdings

Total number of wells or acres, as the case may be, in whic h Suncor has an interest.

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 a t 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.

Lifting Costs

Includes all expenses related to the operation and maintenance of producing or producible wells and related facilities, natural

gas plants and gathering systems.

MD&A

Suncor’s Management’ s Discussion and Analysis dated February 25, 2009, accompanying its audited consolidated financial

statements, notes and auditors’ report, as at and for the th ree years in the period ended December 31, 2008.

Natural Gas

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

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- f.mhtNatural Gas Liquids

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.

Net Wells/Land Holdings

Suncor’ s undivided percentage interest in the gross number of wells or gross number of acres, as the case may be, after

deducting interests of third parties.

Overburden

Material overlying oil sands that must be removed before minin g. Consists of muskeg, glacial deposits and sand.

Oil Sands

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

Reservoir

A porous and permeable subsurface rock formation that contains a s eparate accumulation of petroleum that is confined by

impermeable rock or water barriers and is characterized by a single pressure system.

Synthetic Crude Oil (SCO)

A mixture of hydrocarbons derived by upgrading crude bitumen from oil sands; may contain sulphur or other non- hydrocarbon

compounds and has many similarities to crude oil. Sour synthetic cr ude oil is produced from oil sands that requires only partial

upgrading and contains a higher sulphur content than sweet synthetic crude oil. Sweet synthetic crude oil is produced from oil

sands consisting of a blend of hydrocarbons resulting from thermal crac king and purification of bitumen.

Upstream

These business segments include acquisition, exploration, development, production and marketing of crude oil, natural gas and

natural gas liquids; and for greater clarity include the production of synthetic crude oil, bitumen and other oil products from oil

sands as well as production using conventional methods.

Utilization

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

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- f.mhtWells

Development Well

A well drilled inside the established limits of an oil or gas r eservoir, 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. ga s well, shut- in well, producing oil well, producing gas well,

suspended well or dry and abandoned well).

Exploratory Well

A well drilled in a territory without existing proved reserves, wi th the intention to discover commercial reservoirs or deposits

of crude oil and/or natural gas.

Certain other terms used in this AIF but not defined herein are defined in National Instrument 51-101 – Standards of

Disclosure for Oil and Gas Activities (“NI 51-101”) and, unless the context otherwise requires, shall have the same meanings

herein as in NI 51-101.

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- f.mhtCONVERSION TABLE

Notes:

(1) Conversion using the above factors on rounded numbers appearing in this A IF may produce small differences from

reported amounts.

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

CURRENCY

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

FORWARD-LOOKING STATEMENTS

This AIF contains certain forward- looking statements that are based on our current expectations, estimat es, projections and

assumptions that were made by the company in light of its experienc e, and its perception of historical trends.

All statements that address expectations or projections about the future, including statements about our strategy for growth,

expected future expenditures, commodity prices, costs, schedules, pr oduction volumes, operating and financial results and

expected impact of future commitments, are forward-looking statemen ts. Some of the forward- looking statements may be

identified by words like “expects,” “anticipates,” “estimate s,” “plans,” “scheduled,” “intends,” “may,” “believes,” “project s,”

“indicates,” “could,” “focus,” “vision,” “goal,” “proposed,” “targe t,” “objective,” “continue” and similar expressions. These

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 our experienc e. Our actual results may differ materially from those

expressed or implied by our forward-looking statements and you are caut ioned 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 debt capital markets at acceptable r ates;

availability of third party bitumen; success of our hedging strategie s; maintaining a desirable debt to cash flow ratio; changes

in the general economic, market and business conditions; fluctuat ions in supply and demand for our products; commodity

prices, interest rates and currency exchange rates; our ability t o respond to changing markets, and to receive timely regulatory

approvals; the successful and timely implementation of capital pr ojects including growth projects and regulatory projects (for

example, the emissions reduction modifications at our Firebag in- situ development); the accuracy of cost estimates, some of

which are provided at the conceptual or other preliminary stage of pr ojects and prior to commencement of conception of the

detailed engineering needed to reduce the margin of error or level of accuracy; the integrity and reliability of our capital ass ets;

the cumulative impact of other resource development; the cost o f compliance with existing and future environmental laws; the

accuracy of Suncor’ s reserve, resource and future production estimates and our succ ess at exploration and development

drilling and related activities; the maintenance of satisfact ory relationships with unions, employee associations and joint

venture partners; competitive actions of other companies, including i ncreased competition

5 1 cubic metre m = 6.29 barrels 1 tonne = 0.984 tons (long)

1 cubic metre m (natural gas) = 35.49 cubic feet 1 tonne = 1.102 tons (short)

1 cubic metre m (overburden) = 1.31 cubic yards 1 kilometre = 0.62 miles

1 hectare = 2.5 acres 3

3

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- f.mhtfrom other oil and gas companies and 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, the Government of A lberta’ s review of the unintended consequences of the

proposed New Crown Royalty Regime, and the Government of Canada’ s current review of greenhouse gas emission

regulations); the ability and willingness of parties with whom w e have material relationships to perform their obligations to us;

and the occurrence of unexpected events such as fires, blowouts, f reeze- ups, equipment failures and other similar events

affecting us or other parties whose operations or assets directl y or indirectly affect us. These important factors are not

exhaustive.

Many of these risk factors and other specific risks and uncertai nties 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 o f these documents are available without charge from Suncor at 112

– 4 Avenue S.W., Calgary, Alberta, T2P 2V5, 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 a t www.sec.gov. Information contained in or otherwise

accessible through our website does not form a part of this AIF, a nd is not incorporated into the AIF by reference.

References to our 2008 Consolidated Financial Statements mean Suncor ’ s audited consolidated financial statements prepared

in accordance with Canadian generally accepted accounting principl es (“GAAP”), the notes and the auditors’ report, as at and

for the three years in the period ended December 31, 2008.

NON-GAAP FINANCIAL MEASURES

Certain financial measures referred to in this AIF that are not prescribed by GAAP, namely, cash flow from operations, cash

and total operating costs per barrel and return on capital employed ( “ROCE”). These non- GAAP financial measures do not

have any standardized meaning and therefore are unlikely to be comparable to similar measures presented by other companies.

We include cash flow from operations (dollars and per share amount s), cash and total operating costs per barrel data and

ROCE because investors may use this information to analyze operati ng performance, leverage and liquidity. The additional

information should not be considered in isolation or as a substitute for measures of performance prepared in accordance with

Canadian GAAP.

6

CORPORATE STRUCTURE

Name and Incorporation

Suncor Energy Inc. (formerly Suncor Inc.) was originally formed by the a malgamation 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 fr om Toronto, Ontario, to Calgary,

Alberta, and again in April 1997, to adopt our current name, “Suncor E nergy 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.

Our registered and principal office is located at 112 - 4th Avenue , S.W. Calgary, Alberta, T2P 2V5.

Intercorporate Relationships

We have four principal subsidiaries and partnerships.

Suncor Energy Oil Sands Limited Partnership is an Alberta lim ited partnership that is indirectly wholly owned by Suncor

Energy Inc. Effective February 1, 2005, Suncor Energy Inc., as gener al partner, and one of its wholly- owned subsidiaries, as a

limited partner, formed the Suncor Energy Oil Sands Limited Par tnership. At this time the partnership held certain net profits

interests related to our oil sands business and natural gas busines s. Effective January 1, 2006, Suncor Energy Inc. contributed,

subject to certain exceptions, its oil sands assets to the par tnership. This internal reorganization had no effect on operations or th Page 12 of 100

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- f.mhton our consolidated net earnings.

Suncor Energy Products Inc. (formerly Sunoco Inc.) is an Ontario corp oration that is wholly- owned by Suncor Energy Inc.

This company refines petroleum products at our refinery in Sarnia, Ontario. Refined products and petrochemicals are marketed

directly and indirectly through subsidiaries and joint ventures. We oper ate a retail business in Canada under the Sunoco brand

through this subsidiary. We are unrelated to Sunoco, Inc. (formerly known as Sun Company, Inc.), headquartered in

Philadelphia, Pennsylvania.

Suncor Energy Marketing Inc., wholly- owned by Suncor Energy Products Inc., is incorporated under the laws of Alberta. This

company markets, mainly to customers in Canada and the United Stat es, the crude oil, diesel fuel, bitumen and byproducts

such as petroleum coke, sulphur and gypsum, produced by our oil sands busines s. 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. This subsidiary markets certain natural gas, natural gas li quids, sulphur, and crude volumes produced

by, and purchased from, our natural gas business unit. Suncor Energy Mar keting Inc. holds a 50% interest in Sun

Petrochemicals Company, a petrochemical products joint venture.

Suncor Energy (U.S.A.) Inc., indirectly wholly- owned by Suncor Energy Inc., is incorporated under the laws of Delawar e. Through this U.S. subsidiary, headquartered in Denver, Colorado, we refine crude oil at our refinery in Commerce City,

Colorado, near Denver, into a broad range of petroleum products, and m arket our refined products to industrial, wholesale and

commercial customers principally in Colorado and to retail cust omers in Colorado through Phillips 66 ® -

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- f.mhtbranded sites. We also transport crude oil on our wholly owned pipelines i n Wyoming and Colorado.

We also have a number of other subsidiary companies. However, the total assets of such subsidiaries and partnerships

combined, and their total sales and operating revenues, do not constit ute more than 20 per cent of the consolidated assets, or

consolidated sales and operating revenues, respectively, of Suncor.

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- f.mhtGENERAL DEVELOPMENT OF THE BUSINESS

Overview

Suncor is an integrated energy company, with corporate headquarters in Calgary, Al berta, 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 natura l gas, transport and refine crude oil and market

petroleum and petrochemical products. Periodically, we also marke t third- party petroleum products. We also carry on energy

trading activities focused principally on buying and selling futures contr acts and other derivative instruments based on the

commodities we produce.

We have three principal operating businesses:

Our oil sands business, located near Fort McMurray, Alberta, produc es bitumen recovered from oil sands through mining and

in-situ technology and upgrades it into refinery feedstock, diesel fuel and by- products. Bitumen feedstock is also occasionally

supplemented by third-party suppliers.

Our natural gas business, based in Calgary, Alberta, explores for , acquires, develops and produces natural gas, natural gas

liquids, oil and by- products from reserves primarily in western Alberta and northeast ern British Columbia. The sale of natural

gas production offsets natural gas purchased for internal consumption at our oil sands operations.

Our refining and marketing business, refines crude oil at Suncor’ s refineries in Sarnia, Ontario, and Commerce City, Colorado,

into a broad range of petroleum and petrochemical products and produces ethanol at our plant in St. Clair, Ontario for blending

into fuels. These products are then marketed to industrial, comm ercial and retail customers principally in Ontario and

Colorado. In Ontario, our retail businesses are managed through Sunoco

- branded and joint venture operated retail networks,

and in Colorado our retail businesses are managed through Phillips 66 ®

- branded sites. We also transport crude oil on our

wholly-owned pipelines in Wyoming and Colorado, and engage in third- party energy marketing and trading activities through

this business. The refining and marketing business also encompasses third- party energy marketing and trading activities, and

provides marketing services for the sale of crude oil, natural gas, refined products and by- products from the oils sands and

natural gas segments.

For financial reporting purposes, we also report financial data f or activities not directly attributable to an operating business

under the results of Suncor’s “Corporate and Eliminations” segment. This includes the activity of our self- insurance entity, as

well as investments in wind energy.

In 2008, we produced approximately 264,700 boe per day, comprised of 228,000 bar rels per day (bpd) of crude oil from our

oil sands operations, and 220 million cubic feet equivalent per day ( mmcfe/d) of natural gas and liquids from our natural gas

business. In 2007, the most recent period with published results, we w ere the largest crude oil and natural gas liquids producer

in the country (approximately 9% of Canada’s crude oil production in 2007) a nd were also Canada’ s 16th largest natural gas

producer.

2008 Canadian Crude Oil Forecast and Market Outlook – Appendix B.1

Oilweek – July 2008, Top 100 Oil and Gas Producers

9 1

2

1

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- f.mhtIn 2008, our refining and marketing business sold approximately 198,100 bpd or 31,500 m per day of refined products,

mainly in Ontario and Colorado, but also in other parts of the United States and in Europe.

Three-Year History

Oil Sands

Over the past three years we have continued to advance our multi- phased growth strategy to increase production capacity. Key

milestones and significant events that have affected our oil sands business during this time period include the following:

• Firebag Stage 2 – Firebag Stage 2 commenced commercial operations in the first quart er of 2006, furthering our plans to

increase bitumen supply.

• Royalties – In November 2006, we exercised our option, under our royalty agreement with the Government of Alberta, to

transition our base oil sands mining operations and associated upgradi ng from a royalty assessed on upgraded product

values to a bitumen- based royalty starting on January 1, 2009. In January 2008, we entered into t he Suncor Royalty

Amending Agreement (the “Amending Agreement”) with the government of Alberta, which modifies the rates under the

Government of Alberta’s recently enacted New Royalty Framework (the “New Royalty Framework”) which would

otherwise apply to our base mining operations. Under the Amending Agreeme nt, prior to January 1, 2010, we would pay a

royalty in respect of our base operations at 25% of the difference bet ween a project’ s annual gross revenues net of related

allowable transportation costs (R), less allowable costs (C ) including allowable capital expenditures (the R- C Royalty),

subject to a minimum royalty of 1% of R. In addition, the Amending Agre ement provides Suncor with certainty for

various matters, including the bitumen valuation methodology, allowed cost , royalty in- kind, and certain taxes. Under the

New Royalty Framework enacted in December 2008, royalty rates will move to a sliding scale royalty of 25% - 40% of RC, subject to minimum royalty of 1% - 9%, depending on oil price. In both cases, the sliding scale royalty w ould move

with an increase in WTI prices from Cdn$55/bbl to the maximum rat e at Cdn$120/bbl. From 2010 through 2015 royalty

rates on our base mining operations are those in the New Royalty Framework, with a cap of 30% of R- C and a minimum

royalty of 1.0% to 1.2% of R. In 2016 and subsequent years, the royalty rate s for all of our oil sand operations (our base

mining project and our Firebag in- situ project) will be the rates prescribed under the New Royalt y Framework, unless it is

amended or superseded prior to that time.

• Voyageur South Extension of Mine – In July 2007, Suncor filed a regulatory application for the Voyageur South

extension of mine. Bitumen produced at the proposed project is expecte d to provide additional feedstock flexibility once

operational.

• Operating Permit – We were issued a new 10- year operating approval in connection with our oil sands business in

August 2007.

• Firebag Cogeneration – A capital project expanding Firebag Stages 1 and 2 in conjunction with the addition of a

cogeneration facility was completed in 2007.

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- f.mht• Coker Unit – A $2.3 billion expansion to one of two oil sands upgraders was comple ted in 2008. This new set of cokers is

intended to increase design capacity by 90,000 bpd to a total of 350,000 bpd. Production in 2009 is targeted at 300,000

bpd (+ 5%/-10%).

• Regulatory Requirements

• In September 2007, high emissions at our Firebag in- situ operations resulted in orders being issued by both

Alberta Environment and the Alberta Energy and Utilities Board th at capped production. The production cap was

lifted on July 22, 2008 after Suncor demonstrated the ability to mee t emissions restrictions.

• In December 2007, high emissions at our base plant resulted in an orde r being issued by Alberta Environment.

Emissions at the oil sands plant exceeded air quality standards, a nd accordingly we are upgrading our emission

control equipment and reducing discharges to the tailings ponds. In ad dition, we have introduced processing

changes and are undertaking a more comprehensive monitoring program.

• Progress on Growth Projects – At December 31, 2008, Suncor had spent approximately $7.0 billion on our planned $20.6

billion Voyageur growth strategy (comprised of $11.6 billion targeted for cons truction of a third upgrader and $9.0 billion

for expanding bitumen supply at our Firebag in-situ operation), which involves the expansion of our Firebag in- situ

operations and the construction of a third upgrader. Other current w ork includes construction of a naphtha unit intended to

enhance product mix (60% complete at December 31, 2008), the Firebag Sulphur Plant intended to support our emissions

abatement plan (55% complete as at December 31, 2008) and the Ste epbank Extraction Plant which is expected to

improve operational performance (70% complete at December 31, 2008) . On January 20, 2009, Suncor’ s Board of

Directors approved a revised capital budget which deferred the company ’ s growth projects in light of recent market

conditions. Suncor plans to complete the Steepbank Extraction Plant and Firebag Sulphur Plant, while placing all other

growth projects in “safe mode” until market conditions improve. For further discussion of our signif icant capital projects,

see page 14 of our MD&A.

The following changes to our oil sands business have occurred, or are expe cted to occur in 2009:

• Petro-Canada Agreement – Incremental bitumen to feed the expanded oil sands upgrader commenced January 1, 2009

under a processing agreement between Suncor and Petro- Canada. Under the terms of the agreement, we will process

an average of 27,000 bpd of Petro-Canada bitumen on a fee-for-service basi s. Petro- Canada retains ownership of the

bitumen which is processed into sour crude oil product of about 22,000 bpd. In addition, Suncor has agreed to sell an

additional 26,000 bpd of our proprietary sour crude oil production to Petro- Canada. Both the processing and sales

components of the agreement are for a minimum 10-year term.

• Steepbank Extraction Plant and Firebag Sulphur Plant – We are targeting completion of the Steepbank Extraction

Plant and the Firebag Sulphur Plant during 2009

.

The material factors used to develop target completion dates and c ost estimates are: current capital spending plans, the curre nt

status of procurement, design and engineering phases of the projects, updates from third parties on delivery of services and

goods associated with the project, and estimates from major proje ct teams on completion of future phases of the project.

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- f.mhtWe have assumed that commitments from third parties will be honore d and that material delays and increased costs related to

the risk factors referred above will not be encountered. For a dditional information on risks, uncertainties and other factors that

could cause actual results to differ, please see “Risk Factor s – Major Projects” in this AIF.

Natural Gas

Key milestones and significant events that have affected our nat ural gas business during the past three years include the

following:

• South Rosevear Gas Plant – In January 2006, we disposed of 15% of the total interest in the Sout h Rosevear gas plant

for proceeds of $12 million. We currently retain a 60.4% interest and continue to operate the gas plant.

• Acquisition – In March 2007, we acquired developed and undeveloped lands in British Columbia f or approximately

$160 million.

• Divestment of non-core assets – In May 2008, we disposed of Arctic p roperties for proceeds of $24 million.

• Offshore Permit - In September 2008, Suncor, together with a partner, successfully b id for a large offshore parcel in

the Newfoundland and Labrador Offshore Area. This land is adjacent and complementary to an existing holding in

the Bjarni area and provides Suncor with a long- term option for future potential natural gas growth. In order to retain

the lands, the exploration license requires Suncor to commit to spend net $30 million in exploration work on the lands

within six years.

Refining and Marketing

Key milestones and significant events that have affected our ref ining and marketing business during the past three years

include the following:

• Reduced Refinery Air Emissions – In connection with the acquisition of a refinery from ConocoPhillips on August 1,

2003, we assumed obligations at the refinery pursuant to a Consent Decree with the United States Environmental

Protection Agency to reduce air emissions. These obligations we re met during a planned maintenance shutdown in

2006 for a total cost of approximately $60 million (approximately U S$50 million).

• Diesel Desulphurization and Oil Sands Integration – In July 2006, the Commerce City refinery completed its diesel

desulphurization and oil sands integration project at a total cost of approximately $530 million (US$435 million). The

completion of the project allows the refinery to produce ultra low s ulphur diesel to meet requirements of fuels

desulphurization legislation, and enables the refinery to process up to 15,000 bpd of oil sands sour crude oil. In

addition, the modifications increased the refinery’s ability to proce ss a broader slate of synthetic crude oil.

• Ethanol Plant – In July 2006, we completed construction of our St. Clair ethanol facil ity at a cost of $112 million and

with a production capacity of 200 million litres per year. The e thanol produced is primarily blended into our Sunocobranded fuels and fuels sold through our joint venture operated networks. N atural Resources Canada contributed $22

million towards this project through their Ethanol Expansion Program. T his contribution

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- f.mhtof $22 million includes a repayment obligation, of which $2 million has bee n repaid to date.

• Diesel Desulphurization and Oil Sands Integration – In November 2007, Suncor completed a multiphase three- year $950 million project at the Sarnia refinery with a 120-day shutdown to c omplete the tie- ins. The project increased the

amount of oil sands crude oil the refinery can upgrade, improved the fa cility’ s environmental performance, and

commencing in 2006 enabled the production of ultra low sulphur diesel fuel. During 2008, additional equipment

improvements were identified that will be required before the r efinery can achieve full benefit from these

modifications. We are currently evaluating our options relating to these capital expenditures.

• The observed performance of our Sarnia refinery in 2008, after complet ion of our diesel desulphurization and oil

sands integration project in 2007, has enabled us to upwardly revise our nameplate capacity to 85,000 bpd from the

previously disclosed 70,000 bpd. Starting January 1, 2009, refinery util ization will be calculated using the 85,000 bpd

capacity. The Commerce City refining capacity has also been i ncreased from 90,000 bpd to 93,000 bpd effective

January 1, 2009.

Other

Renewable Energy

In addition to renewable energy investments in ethanol production through our Refining and Marketing segment, Suncor also

invests in renewable wind power. Suncor is a partner in four wind power projects, including two projects commissioned in the

past three years.

In November 2006, we, along with our joint venture partners, Enbridge Incom e Fund and Acciona Wind Energy Canada Inc.,

officially opened a 30- megawatt wind power project near Taber, Alberta called the C hin Chute Wind Power Project. The

project includes 20 wind turbines with the capacity to produce enough zero- emission electricity to offset the equivalent of

approximately 102,000 tonnes of carbon dioxide per year.

In September 2007, we, along with our joint venture partner Acciona Wind Energy Canada Inc., officially opened a 76-

megawatt wind power plant near Ripley, Ontario. The $176 million Ripley Wind Power Project consists of 38 wind turbines, a

27- km transmission line and two electrical substations. The project is expected to displace at least 66,000 tonnes of carbon

dioxide per year.

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- f.mhtNARRATIVE DESCRIPTION OF THE BUSINESS

Oil Sands

Suncor produces a variety of refinery feedstock, diesel fuel and by- products by developing our resource leases in the

Athabasca oil sands in northeastern Alberta and upgrading the bitumen extracted at our plant near Fort McMurray, Alberta.

Our oil sands operations, accounting for virtually all of our conventiona l and synthetic crude oil production in 2008, represent

a significant portion of our 2008 cash flow from operations (86%), net earnings (95%) and capital employed excluding major

projects in progress (68%). These percentages have been determined excluding the corporate and eliminations segment

information.

Operations

Our integrated oil sands business involves four operations located nea r Fort McMurray, Alberta.

1) Bitumen is supplied from a combination of open mining operations, in-sit u operations and third-party supply.

2) Primary extraction facilities recover the bitumen from the mi ned oil sands ore. In in- situ operations, primary extraction

occurs in the ground. Both mined and in- situ bitumen also undergoes secondary extraction processes in prepara tion for

upgrading.

3) Heavy oil upgrading converts bitumen into crude oil products. Since lat e 2005, we have upgraded bitumen from Firebag,

with only a small portion of non-upgraded production being strategically so ld directly into the market.

4) Required utilities (water, steam and electricity) are gene rated through facilities on site, some owned and operated by

Suncor, and others owned and operated by third parties.

Mining/Extraction - The first step of the open pit mining operation is to remove the overburden with trucks and shovels to

access the oil sands - a mixture of sand, clay and bitumen. Oil sands ore is then excava ted and either transported to fixed sizing

and extraction plants or fed directly to a mobile sizing and extra ction operation at the mine face . In the primary extraction

process, bitumen is separated from the oil sands ore using a hot wate r process. After the final removal of impurities and

minerals during secondary extraction, naphtha is added to dilute the bitumen to facilitate transportation to upgrading.

In-Situ - Our in-situ operation (Firebag) uses an extraction technology called Steam Assisted Gravity Drainage (“SAGD”) to

separate bitumen from oil sands deposits that are too deep to be mi ned 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 c ondensed steam drain into the bottom well and flow up

the well to the surface. The bitumen is pumped to our oil/water separation facilities where the water is removed from the

bitumen, treated and recycled back to the steam generation faciliti es. For current stages of in

- situ development, naphtha is

added to dilute the bitumen to facilitate transportation to upgrading. F uture stages propose to use a heated pipeline instead of

naphtha dilution for transport.

Refer to “Non-GAAP Financial Measures” on page 6 of this AIF.

14

3 3

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- f.mhtUpgrading - 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 synthetic crude oil, is eit her sold directly to customers as sour synthetic crude oil or

is further upgraded into sweet synthetic crude oil by removing the sulph ur and nitrogen using a hydrogen treating process.

Four separate streams of refined crude oil are produced: diesel , naphtha, kerosene and gas oil.

We continue to explore and develop improved and alternative technologies to fa cilitate increased efficiency and processing

within our operations. For example, based on the results of test ing performed during the past two years, we may utilize new

mining technology and processes in our future mine development plans.

While there is virtually no finding costs associated with oil sands resources, delineation of the resources, costs associated with

production including mine development and drilling wells for SAGD operat ions, and costs associated with upgrading bitumen

into synthetic crude oil, can entail significant capital outlays. The costs associated with production at oil sands are largely f ixed

in the short term and, as a result, operating costs per unit a re largely dependent on levels of production. Natural gas is used in

the production of synthetic crude oil, particularly in SAGD production at our Firebag operations, and accordingly natural gas

prices are a key variable component of synthetic crude oil production cos ts.

In the normal course of our operations, we regularly complete plann ed maintenance shutdowns of our oil sands facilities.

These shutdowns are scheduled, and provide both preventative maintenance and capital replacement, which are expected to

improve our operational efficiency. In July 2007, a scheduled maintenance shutdown of Upgrader 2 occurred to facilitate the

tie- in of new coker units, an important milestone in the capital expans ion project to increase oil sands production capacity to

350,000 bpd in the second half of 2008. In May 2008, a planned shutdown of Upgrader 1 was undertaken to provide both

preventative maintenance and capital replacement to improve opera tional efficiency.

Principal Products

Sales of light sweet synthetic crude oil and diesel represented 45% of oil sands consolidated operating revenues in 2008,

compared to 60% in 2007. The other significant component of our revenues were light sour synthetic crude oil and bitumen

sales of 46% (2007 – 39%). Set forth below is information on daily sales volumes and t he corresponding percentage of oil

sands operating revenues by product for each of the last two years.

We anticipate that approximately 50% of oil sands sales volumes in 2009 will be light sweet synthetic crude and diesel

products.

15 Product: 2008 2007

(thousands

of barrels

per day) (% of

operating

revenues) (thousands

of barrels

per day) (% of

operating

revenues)

Light sweet crude oil / diesel 96.8 45 126.7 60

Light sour crude oil / bitumen 130.2 46 108.0 39

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- f.mhtPrincipal Markets

We market our crude oil product blends principally to customers in Canada and the United States, and periodically to offshore

markets.

Transportation

We own and operate a pipeline that transports synthetic crude oil from Fort McMurray, Alberta to Edmonton, Alberta. The

pipeline has a capacity of approximately 110,000 bpd.

We have a transportation service agreement on the Enbridge Athaba sca Pipeline for a term that commenced in 1999 and

extends to 2028. Total line capacity is 600,000 bpd. Under this agreement, our current pipeline commitment is 182,000 bpd for

the transportation of synthetic crude oil and diluted bitumen from Fort McMurray, Alberta to Hardisty, Alberta.

We are a founding member of the Waupisoo pipeline that went into se rvice on June 1, 2008. Under this agreement, our

founding member status is for a minimum term of 25 years with opti ons to extend. Total line capacity is 350,000 bpd with

potential expansion to 535,000 bpd. Under this agreement our current pipeline commitment is 30,000 bpd for the

transportation of synthetic crude oil and diluted bitumen from Cheec ham to Edmonton, Alberta.

Suncor has entered into long-term service agreements with affiliat es of TransCanada Corporation to transport crude oil on the

Keystone pipeline. The agreements will provide for pipeline transpo rtation of our crude oil from Hardisty, Alberta to both

Patoka, Illinois and Cushing, Oklahoma. Linefill on the Keystone pipeli ne is targeted to occur in 2009, with transportation of

crude oil expected to commence in early 2010. Our capacity on this pipe line in 2010 will be 25,000 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 million barrels of storage and for f ixed five-year terms. On January 1, 2009, Suncor contracted

storage facilities for an additional one million barrels at Ned erland, Texas, for a fixed five-year term.

In 2008, we entered into new commitments for the transportation of c rude oil on the Express New pipeline (30,000 bpd

starting in 2008) and the Wamsutter pipeline (10,000 bpd expected to star t in 2010). We continue to evaluate additional

pipeline agreements to support planned increases in production capacity.

Periodically, we also enter into strategic short- term cargo transport agreements to ship synthetic crude oil inte rnationally.

These agreements have a term of less than one year, and are spe cific to individual shipments.

We have a 20- year agreement with TransCanada Pipeline Ventures Limited Par tnership 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. It extends approximately 300 kilometres south of the plant and connects with TransCanada Pipeline’s Alberta intraprovincial pipeline system. The Albersun pipeline has the capacity to move in excess of 100 mmcf/day of natural gas. We

arrange for natural gas supply and purchase most of the natural gas on the system under delivery- based contracts. The pipeline

moves natural gas both north and south for us and other shippers.

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- f.mhtOur oil sands mining facilities are readily accessible by public road. Our Firebag in- situ facilities are currently accessible by

air and private road. We anticipate termination of current road access in 2010, and continue to evaluate alternative means of

access.

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.

Sales of Synthetic Crude Oil and Diesel

Aside from on-site fuel use, all of oil sands’ production is sold to, and subsequently marketed by Suncor Energy Market ing

Inc. Primary markets for our crude oil products include refining oper ations in Alberta, Ontario, the U.S. Midwest and the U.S.

Rocky Mountain region. Diesel products are sold primarily in western Canada.

In 1997, we entered into a long-term agreement with Flint Hills R esources LLC (“Flint Hills”) to supply Flint Hills with up to

30,000 bpd (approximately 13% of our average 2008 total production (2007 — 13%)) of sour crude from our oil sands

operation. We began shipping the crude to Flint Hills at Hardisty , Alberta on January 1, 1999. The initial term of the

agreement extends to January 1, 2009, with month to month evergreen terms thereafter, subject to termination on twenty- four

months notice by either party. Neither party has provided notice of t ermination at this time.

Under a long-term sales agreement with Consumers Co-operative Re fineries Limited (“CCRL”) we supply CCRL with 20,000

bpd of sour crude oil production. In 2005, we signed another contract wit h CCRL for an additional 12,000 bpd of sour crude

oil. Both CCRL agreements extend through to 2011, with renewal options t hat could extend out to 2018 and beyond. Both

agreements continue until terminated by either party with twenty- four months notice. Neither party has provided notice of

termination at this time.

Effective January 1, 2009 the agreements with Petro- Canada for bitumen processing and sour crude oil supply commenced. As

a result and effective January 1, 2009 our agreement to supply up to 30,000 bpd of diluent to Petro- Canada for bitumen

blending expired. Under the bitumen processing agreement, we will proce ss an average of 27,000 bpd of Petro

- Canada

bitumen on a fee for service basis. Petro

- Canada will retain ownership of the bitumen and resulting sour cru de oil production

of approximately 22,000 bpd. In addition, under the sour crude oil supply agree ment, we will supply up to 26,000 bpd of our

proprietary sour crude oil production to Petro-Canada. Both the proces sing and supply agreements are for a minimum 10- year

term.

A portion of our oil sands production is used in our Sarnia and Commerc e City refining operations. During 2008, the Sarnia

refinery processed approximately 18% (2007 - 7%) of our oil sands crude oil production and the Commerce City r efinery

processed approximately 4% (2007 – 6%).

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- f.mhtThere were no customers that represented 10% or more of our cons olidated revenues in 2008 or 2007.

Environmental Compliance

For a discussion of environmental risks at our oil sands operations, r efer to the “Legal and Regulatory Risks” in the Risk

Factors section of this AIF.

Natural Gas

Our natural gas business, based in Calgary, Alberta, explores for, develops and produces conventional natural gas, natural gas

liquids, oil and by- products primarily in western Canada, supplying markets throughout North Am erica. The sale of this

production provides a natural price hedge for natural gas purchased for internal consumption at our oil sands operations.

Our exploration program is primarily focused on multiple geological zones in three core asset areas: Northern (northeast

British Columbia and northwest Alberta), Foothills (western Al berta and portions of northeast British Columbia) and Central

(northwest Alberta).

Marketing, Pipeline and Other Operations

We operate natural gas processing plants at South Rosevear, Pine Cr eek, Progress and Simonette with a total design capacity

of approximately 265 mmcf/d. Our capacity interest in these gas pro cessing plants is approximately 115 mmcf/d. We also have

varying undivided percentage ownership interests in natural gas processi ng plants operated by other companies and processing

agreements in facilities where we do not hold an ownership interes t.

Approximately 93% of our natural gas production in 2008 was sold to Suncor Ene rgy Marketing Inc. and then marketed under

direct sales arrangements to customers in Alberta, British C olumbia, eastern Canada, and the United States. Contracts for these

direct sales arrangements are of varied terms, with a majori ty having terms of one year or less, and incorporate pricing which

is either fixed over the term of the contract or determined on a monthly basis in relation to a specified market reference pric e. Under these contracts, we are responsible for transportation arra ngements to the point of sale.

Approximately 7% of our natural gas production in 2008 was sold under exis ting contracts to aggregators (“system sales” ).

Proceeds received by producers under these system sales arrange ments are determined on a netback basis, whereby each

producer receives revenue equal to its proportionate share of sale s less regulated transportation charges and a marketing fee.

Most of our system sales volumes are contracted to Cargill Gas Marketing Ltd. and Pan-Alberta Gas.

To provide exposure to the Pacific Northwest and California markets, we have a long- term gas pipeline transportation contract

on the TCPL Gas Transmission Northwest Pipeline. Our contract, which started in 1995, is for 40,000 MMBtu/day and expires

in 2023.

We do not typically enter long- term supply arrangements for our conventional crude oil production. Instead, our conventional

crude oil production is generally sold under spot contracts or under contra cts that can be terminated on relatively short notice.

Our conventional crude oil production is shipped on pipelines operated by i ndependent pipeline companies. We currently have

no pipeline commitments related to the shipment of conventional crude oil.

18

Principal Products

Sales of natural gas represented 81% (2007 – 89%) of the business unit’ s consolidated operating revenues in 2008, with 11%

(2007 – 10%) comprised of sales of natural gas liquids and crude oil. The remaining 8% (2007 – 1%) related mainly to sales

of sulphur by-product. Set forth below is information on daily sales volu mes and the corresponding percentage of natural gas’ s operating revenues by product for the last two years.

Product: 2008 2007

(mmcf (% of (mmcf (% of Page 24 of 100

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- f.mhtNote:

(1) The remaining 8% relates mainly to our sales of sulphur by- product.

Competitive Conditions

For a discussion of the competitive conditions affecting the natural gas business unit, refer to “Competition” in the Risk

Factors section of this AIF.

Seasonal Impacts

Risks and uncertainties associated with weather conditions an d wildlife restrictions can shorten the winter drilling season a nd

can impact the spring and summer drilling programs, potentially res ulting in increased costs or reduced production.

Environmental Compliance

For a discussion of environmental risks at our natural gas operati ons, refer to the “Legal and Regulatory Risks” outlined in the

Risk Factors section of this AIF.

Refining and Marketing

Our refining and marketing business consists of downstream operation s in Canada and the United States and an energy

marketing and trading business.

Our Canadian- based refining and marketing business operates in central Canada. Our refinery in Sarnia, Ontario, has a current

crude oil capacity of 85,000 bpd, up from previous capacity of 70,000 bpd as the result of improvements made with the

completion of our diesel desulphurization and oil sands integration projec t in 2007. The plant refines petroleum feedstock from

oil sands and other sources into gasoline, distillates, and petroc hemicals with the majority of these refined products distributed

in Ontario. We also distribute product purchased from third parties . Our ethanol plant in St. Clair, Ontario produces ethanol

from corn, which is used for blending into our fuels and is also sold to third parties and has a capacity of 200 million litres per

year.

As a marketing channel for Canadian refined products, our Ontario re tail networks sold approximately 52% of refining and

marketing’s total Canadian sales volume in 2008 (2007 –

19 equivalent

per day) operating

revenues) equivalent

per day) operating

revenues)

Natural gas 202 81 196 89

Crude oil and natural gas liquids 18 11 19 10

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- f.mht51%). The retail networks include the Sunoco- branded retail network, joint venture retail and bulk distribution f acilities and

cardlock operations. Approximately 42% of our Canadian refined product sales in 2008 were wholesale and industrial sales

(2007 – 44%). Sun Petrochemicals Company, a joint venture between a Suncor subsidiary and a Toledo, Ohio- based refinery,

generated the remaining refined product sales.

Our U.S.- based refining and marketing business includes a refining facility, a retail network, and a pipeline transportation

business primarily in Colorado and Wyoming. The Commerce City, Colora do refining facility has a current combined crude

distillation capacity of 93,000 bpd, increased from 90,000 bpd previously reported. The majority of the refined products from

the Commerce City refinery are distributed in Colorado.

In 2008, approximately 78% (2007 – 74%) of our U.S.- based petroleum product sales volumes were to industrial,

commercial, wholesale and refining customers in Colorado, repres enting primarily jet fuels, diesel and gasoline.

Approximately 15% of our U.S. petroleum products sales in 2008 (2007 – 18%) were sold through a distribution network in

Colorado that sells gasoline and diesel fuel to retail customer s. Asphalt sales comprised the remaining 7% of U.S. refined

product sales volumes for 2008 (2007 – 8%).

The energy marketing and trading business activities encompasses third- party energy marketing and trading activities, as well

as providing marketing services for the sale of crude oil, natur al gas, refined products and by- products and the use of financial

derivatives.

Procurement of Feedstocks

Canada

The Sarnia refinery processes both synthetic and conventional crude oil . In 2008, 75% (2007 – 43%) of the crude oil refined

at the Sarnia Refinery was synthetic crude oil, of which 71% was supplied from our oil sands operations (2007 – 50%). The

balance of the refinery ’ s synthetic crude oil, as well as its conventional and condensate feedstocks, were purchased from others

under month-to- month contracts. In the event of a significant disruption in the supply of synthetic crude oil, the refinery has

the flexibility to substitute other sources of sweet or sour conven tional crude oil.

We procure conventional crude oil feedstock for our Sarnia refiner y primarily from western Canada, supplemented from time

to time with crude oil from the United States and other count ries. Foreign crude oil is delivered to Sarnia via pipeline fr om the

United States Gulf Coast or via the Enbridge Pipeline from Mont real. We have not made any firm capacity commitments on

these pipeline systems. Crude oil is procured from the market on a spot basis or under contracts which can be terminated on

short notice.

We continue to enter into reciprocal buy/sell or exchange arrangement s with other refining companies from time to time as a

means of minimizing transportation costs, balancing product availabi lity and enhancing refinery utilization. We also purchase

refined products in order to meet customer requirements.

Diesel desulphurization and oil sands integration work at our Sa rnia refinery was completed in 2007. During 2008, additional

equipment improvements were identified that will be required before the refinery can achieve full benefit from these

modifications. We are currently evaluating our options relating to these capital expenditures.

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- f.mhtUnited States

The Commerce City refining operation processes both conventional and s ynthetic crude oil. Approximately 10% of the

refinery’s crude oil is purchased from Canadian sources (2007 – 23%), with the remainder supplied from sources in the

United States, primarily from the Rocky Mountain region.

The refinery’s crude oil purchase contracts have terms ranging fr om month-to-month to multi- year. 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 on a spot purchase basis.

With the completion of our diesel desulphurization and oil sands inte gration projects, we are now capable of processing of up

to 15,000 bpd of oil sands sour crude oil at our U.S. refining operation.

Refining Operations

Canada

The Sarnia refinery produces a wide range of products, including transport ation fuels, heating fuels, liquefied petroleum gases,

residual fuel oil, asphalt feedstock and petrochemicals.

The Sarnia refinery has capacity to refine 85,000 bpd of crude oil. Refi ning units include a 29,000 bpd hydrocracker and a

5,300 bpd alkylation unit. The petrochemical facilities have a ca pacity of 18,500 bpd and our gasoline desulphurization unit

has the capacity to process 10,000 bpd. The distillate hydrotreater tha t became operational in July 2006 has a processing

capacity of 43,600 bpd.

In 2008, the refinery had cracking capacity of 45,600 bpd from a Houdry cat alytic cracker (“catcracker”). In 2004, a study to

assess the catcracker concluded that, with planned improvements and upgrades, it can continue to be operated economically

and safely for at least 10 years. A range of replacement options for the catcracker will continue to be analyzed.

The refinery’s external steam and electricity needs are primar ily met through the Sarnia Regional Co-generation Project.

In July 2006, with the completion of our St. Clair ethanol facility, we began producing ethanol for use in our blended gasoline

products, and for sale to third parties. Production capacity for this facility is 200 million litres per year.

United States

Refining units include two fluidized catalytic crackers with a 27,000 bpd combined capacity, a 19,000 bpd distillate

hydrotreater and a 26,000 bpd gas oil hydrotreater. The refined gasoline products from the Commerce City refinery primarily

supply our marketing operations in Colorado.

The Commerce City refining operation is a high conversion operat ion that produces a full range of products, including

gasoline, jet fuels, diesel and asphalt. The refinery utiliz es a crude slate containing approximately one- third heavy, high

sulphur crude oil.

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- f.mhtThe following chart sets out refining and marketing’ s combined total daily crude input and average refinery utilization r ates

for both its Canadian and U.S. refinery operations in 2008 and 2007.

Combined U.S. and Canadian Capacity

(1) Based on crude unit capacity of 70,000 bpd for Sarnia and 90,000 bpd for Comme rce City and input to crude units.

In the normal course of our operations we regularly complete planned ma intenance shutdowns of our refinery facilities. These

shutdowns are scheduled, and provide both preventative maintenance and capi tal replacement which is expected to maintain

our operational efficiency. During 2008, a significant maintenance shut down was successfully completed at our Sarnia

refinery, and in 2007 significant maintenance shutdowns were succes sfully completed at both our Sarnia and Commerce City

refining facilities.

Principal Products

Set forth below is information on daily sales volumes and the corre sponding percentage of refining and marketing’ s operating

revenues by product category for the last two years.

Note:

(1) Includes ancillary revenues

22

Total Canadian and U.S. Refinery Capacity 2008 2007

Average daily crude input (barrels per day) 155,600 157,600

Average crude utilization rate (%) 97 98

Product: 2008 2007

(thousands

of

cubic

meters

per day) (% of

operating

revenues) (thousands

of

cubic

meters

per day) (% of

operating

revenues)

Transportation Fuels

Gasoline

Retail 4.6 7 5.2 13

Joint Ventures 3.0 3 3.1 5

Other 8.3 13 8.5 24

Jet Fuel 2.0 3 2.3 4

Diesel 8.8 14 8.3 18

Sub

- total

– Transportation 26.7 40 27.4 64

Fuels

Petrochemicals 0.8 1 0.9 2

Asphalt 1.8 1 1.7 2

Other 2.2 2 3.5 5

Total Refined Products 31.5 44 33.5 73

Other Non-Refined Products 1 2

Energy Marketing & Trading 55 25

Total % 100 100 (1)

(1) Page 28 of 100

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- f.mhtPrincipal Markets

Canada

Approximately 52% (2007 – 51%) of our total Canadian sales volumes are marketed through reta il networks. In 2008, this

network was comprised of:

• 276 Sunoco-branded retail service stations (2007 – 272)

• 159 Pioneer-operated retail service stations (2007 – 151)

• 52 UPI-operated retail service stations (2007 – 55)

• 11 UPI-operated bulk distribution facilities for rural and farm f uels (2007 – 13)

• 47 Sunoco branded Fleet Fuel Cardlock sites (2007 – 48)

Refined petroleum products (excluding petrochemicals) are markete d under several brands, including the Company’ s Canadian “Sunoco” trademark. Our other principal trademarks include “Ecowash” and “Gold Diesel”, our premium lowsulphur diesel product.

Approximately 42% (2007 – 44%) of refining and marketing’ s Canadian sales volumes are sold to industrial, commercial,

wholesale and refining customers, primarily in Ontario. Refining a nd marketing also supplies industrial and commercial

customers in Quebec through long-term arrangements with other regiona l refiners.

Refining and marketing has a 50% interest in Sun Petrochemicals Com pany, a petrochemical marketing joint venture that

markets products from our Sarnia, Ontario refinery and from a Tole do, Ohio, refinery owned by the joint venture partner. Sun

Petrochemicals Company markets petrochemicals used to manufactu re plastics, rubber, synthetic fibres, industrial solvents and

agricultural products, and gasoline octane enhancers. We sell our be nzene production directly to other petrochemical

manufacturers in Sarnia, Ontario.

Refining and marketing’ s share of total refined product sales in its primary Canadian m arket of Ontario was approximately

18% in 2008 (2007 – 20%).

Transportation fuels accounted for 83% of our Canadian sales volumes in 2008 (2007 – 78%); and petrochemicals accounted

for 6% (2007 – 5%). The remaining volumes included other refined products such as heating fuels, heavy oils and liquefied

petroleum gases, and were sold to industrial users and resellers

.

Refined petroleum products are also supplied to the Pioneer and UPI joint ventures. We have a separate supply agreement with

both UPI and Pioneer. These supply agreements are evergreen and ar e subject to termination only in accordance with the terms

of the various agreements between the parties.

Pioneer is a 50% joint venture partnership with Th e Pioneer Group.

UPI Inc. is a joint venture company owned 50% with GROWMARK Inc., a U.S. Midwest agricultural supply and grain marketing cooperative.

23 4

5

5

4

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- f.mhtUnited States

Approximately 78% (2007 – 74%) of refining and marketing’ s U.S. sales volumes are sold to industrial, commercial,

wholesale and refining customers, primarily in Colorado, of which approx imately 10% was sold to ConocoPhillips (2007 –

10%) and 18% was sold to Valero (2007 – 23%).

Approximately 15% (2007 – 18%) of our total U.S. sales volumes are m arketed through Phillips 66 ® - branded retail outlets.

In 2008, this network was comprised of:

• 44 owned Phillips 66 ® - branded retail sites, which account for appr oximately 5% of refining and marketing’ s

U.S. sales volumes (2007 – 44 sites; 5% of sales volumes)

• Supply agreements with 200 additional Phillips 66 ® branded retail sites throughout Colorado, which account for

approximately 10% of our U.S. sales volumes (2007 – 173 outlets; 13% of sales volumes). These agreements are

typically for three-year terms with provision for automatic thre e-year renewal periods on an evergreen basis.

We have an exclusive license from ConocoPhillips to use the Phillips 66 ® and related trademarks and brand names in

Colorado until December 31, 2012.

The U.S. refining operation supplied all of its asphalt production t o SemMaterials, L.P. until SemMaterials’ bankruptcy

protection filing in the summer of 2008. Subsequently, we now directly manage the sales of asphalt, which made up 7% of

refining and marketing’s U.S. 2008 sales volumes (2007 – 8%).

We estimate our U.S. sales of total light fuels refined produc t in 2008 represented a 36% market share, in its primary market of

Colorado (2007 – 40%). Within this market, our Phillips 66 ® - branded sites hold a 7% market share (2007 – 7%).

Transportation and Distribution

Canada

For our Canadian operations, refining and marketing owns and operates pet roleum transportation, terminal and dock facilities,

including storage facilities and bulk distribution plants in Ontario. The major mode of transporting gasoline, diesel, jet fuel and

heating fuels from the Sarnia refinery to core markets in Onta rio is the Sun- Canadian Pipe Line, which is 55% owned by

Suncor and 45% owned by another refiner. The pipeline operates as a pri vate facility for its owners, serving terminal facilities

in Toronto, Hamilton and London.

We also have pipeline access, subject to availability, to p etroleum markets in the Great Lakes region of the United States by

way of a pipeline system in Sarnia operated by a U.S. based r efiner. This link to the U.S. allows refining and marketing’ s Canadian operations to move products to market or obtain feedstocks/prod ucts when market conditions are favourable in the

Michigan and Ohio markets.

United States

For our U.S. operations, approximately 60% of crude oil processed at the Denver refining operation is transported via pipeline,

with the remainder supplied via truck. We own and operate the Rocky M ountain Crude pipeline system, which runs from

Guernsey, Wyoming to Denver,

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- f.mhtColorado. This is a common carrier pipeline that transports crude for the Denver refinery as well as for other shippers. We

also own and operate the Centennial pipeline, which transports crude from Guernsey, Wyoming to Cheyenne, Wyoming.

The Rocky Mountain Crude system had a capacity of 38,000 bpd in 2008 for the Guer nsey to Cheyenne leg of the pipeline and

73,500 bpd for the Cheyenne to Denver leg of the pipeline. In 2008, it utili zed approximately 43% (2007 – 73%) of its

capacity with average throughput of 16,500 bpd (2007 – 27,600 bpd) in the Guernsey to Cheyenne leg of the pipeline, and

utilized approximately 85% (2007 - 92%) with average throughput of 62,200 bpd (2007

– 67,700 bpd) in the higher capacity

Cheyenne to Denver leg. During the same period, the Centennial pipeli ne utilized approximately 46% (2007 – 80%) of

capacity, with an average throughput of approximately 29,400 bpd (2007 – 50,800 bpd)

.

Our U.S. operations have both truck and rail loading racks at the Com merce City refining facility with product loading

capacity in excess of 30,000 bpd, a one- mile long 7,000 bpd jet fuel pipeline that connects to a common carrier pipeline

system for deliveries to the Denver International Airport, and a four

- mile long 14,000 bpd diesel pipeline that delivers diesel

product directly to the Union Pacific railroad yard in Denver, Color ado.

In both our Canadian and U.S. operations, we believe our own storage faci lities, and those under long- term contractual

arrangements with other parties, are sufficient to meet our c urrent and foreseeable storage needs.

Competitive Conditions

For a discussion of the competitive conditions affecting our refini ng 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 marketi ng operations, refer to the “Legal and Regulatory Risks” in

the Risk Factors section of this AIF.

25

STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS IN FORMATION

Date of Statement

The statement of reserves data and other oil and gas information out lined below is dated February 6, 2009, with an effective

date of December 31, 2008. The preparation date of the information i s February 2, 2009.

Disclosure of Reserves Data

As a Canadian issuer, we are subject to the reporting requireme nts of Canadian securities regulatory authorities, including the

reporting of our reserves in accordance with National Instrument 51-1 01 Standards of Disclosure for Oil and Gas Activities

(“NI 51-101”). Prior to 2008, we had presented our disclosures in accordance with U.S. disclosure requirements under an

exemption from Canadian securities requirements which was not rene wed by us following our December 31, 2007 annual

disclosures. As a result, reserves information presented for com parative years has been restated to comply with NI 51- 101,

consistent with the presentation format for December 31, 2008 reser ve disclosures.

The reserves and contingent resources data set forth below is bas ed upon an evaluation by GLJ with an effective date of

December 31, 2008 contained in the GLJ Report dated February 6, 2009. The reserves data summarizes our oil, liquids and

natural gas reserves and the net present values of future net reven ue for these reserves using forecast prices and costs prior to

provision for interest, general and administrative expenses, cost associated with environmental regulations, the impact of any

hedging activities or the liability associated with certain a bandonment and all well, pipeline, facilities and mine reclamat ion

costs. Future net revenues have been presented on a before and a fter tax basis. The reserves data conforms with the

requirements of NI 51- 101. We engaged GLJ to provide an evaluation of proved and proved plus probable reserves and

contingent resources. See also “ Definitions and Notes to Reserves Data Tables ” below. Page 31 of 100

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- f.mhtThe company’s reserves are located primarily in Alberta and Bri tish Columbia, Canada.

It should not be assumed that the estimates of future ne t 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 attain ed and

variances could be material. The recovery and reserves esti mates of crude 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 crude oil, natural gas and natural gas liquid reser ves may be greater than or less than the estimates provided

herein. Readers should review the definitions and inform ation contained in “ Definitions and Notes to Reserves Data

Tables” in conjunction with the following tables and notes. For more

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- f.mhtinformation as to the risks involved, see “Risk Factors — Uncertainty of Reserve and Resource Estimates” in this AIF

.

Reserves Data (Forecast Prices and Costs)

Summary of Oil and Gas Reserves as at December 31, 2008

(1) Represents light and medium oil for our conventional reserves, andsynthetic crude oil (“SCO”) for our mining and insitu reserves.

27 Oil Natural Gas Natural Gas Liquids

Working Interest

MMbbl Net

MMbbl Working

Interests

Bcf Net

Bcf Working Interest

MMbbl Net

MMbbl

Proved Producing

Conventional

2 2 459 352 5 4

SCO – Mining 1,571 1,335

- - - - SCO – In-Situ

94 91

- - - - Total Proved Producing 1,667 1,428 459 352 5 4

Proved Developed Non

- Producing

Conventional

- - 50 38

- - SCO – In-Situ

45 43

- - - - Total Proved Developed Non

- Producing

45 43 50 38

- -

Proved Undeveloped

Conventional

- - 30 24

- - SCO –In-Situ

766 658

- - - - Total Proved Undeveloped

766 658 30 24

- -

Total Proved

Conventional

2 2 539 414 5 4

SCO – Mining 1,571 1,335

- - - - SCO – In-Situ

905 792

- - - -

Total Proved 2,478 2,129 539 414 5 4

Total Probable

Conventional

1

- 216 153 2 1

SCO – Mining

745 626

- - - - SCO – In-Situ

1,808 1,506

- - - - Total Probable 2,554 2,132 216 153 2 1

Total Proved Plus Probable

Conventional

3 2 755 567 7 5

SCO – Mining 2,316 1,961

- - - -

SCO – In-Situ 2,713 2,298

- - - - Total Proved Plus Probable 5,032 4,261 755 567 7 5 (1) Page 33 of 100

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- f.mhtNet Present Value of Future Net Revenues as at Decembe r 31, 2008

Total Future Net Revenues as at December 31, 2008 – Undiscoun ted

28 Net Present Values of Future Net Revenue BEFORE

Income Taxes – Discounted at %/year ($ millions) Unit Value Before Income Tax

Discounted at 10%/tear ($ millions)

0%

5% 10% 15% 20% $/Boe $/Mcfe

PROVED

Producing 71,961 47,160 33,186 24,744 19,325 22.28 3.71

Developed Non-Producing 2,356 1,775 1,380 1,103 902 28.05 4.68

Undeveloped 26,833 11,304 4,967 2,085 651 7.50 1.25

Total Proved

101,150 60,239 39,533 27,932 20,878 17.96 2.99

Total Probable

126,456 39,370 14,052 5,140 1,486 6.51 1.08

TOTAL PROVED PLUS

PROBABLE 227,606 99,609 53,585 33,072 22,364 12.29 2.05

Net Present Values of Future Net Revenue AFTER

Income Taxes

– Discounted at %/year

0%

5% 10% 15% 20%

PROVED

Producing 55,850 37,013 26,360 19,895 15,724

Developed Non-Producing 2,005 1,533 1,209 979 809

Undeveloped 20,009 8,238 3,443 1,264 178

Total Proved

77,864 46,784 31,012 22,138 16,711

Total Probable

94,627 29,052 10,008 3,294 538

TOTAL PROVED PLUS

PROBABLE 172,491 75,836 41,020 25,432 17,249

($ millions) Revenue Royalties Operating

Costs Capital

Development

Costs Abandonment

Costs Future

Net Revenue

Before Income

Taxes Income

Tax Future

Net Revenue

After Income

Taxes

PROVED

Producing 167,832 25,474 54,614 15,744 39 71,961 16,111 55,850

Developed Non-producing 4,614 319 1,675 258 6 2,356 351 2,005

Undeveloped

87,029 12,803 33,304 13,743 346 26,833 6,824 20,009

Total Proved

259,475 38,596 89,593 29,745 391 101,150 23,286 77,864

Total Probable

344,459 58,628 119,854 38,872 649 126,456 31,829 94,627

TOTAL PROVED PLUS

PROBABLE 603,934 97,224 209,447 68,617 1,040 227,606 55,115 172,491 Page 34 of 100

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- f.mhtFuture Net Revenue by Production Group as at December 31, 20 08

(1) The estimated future net revenue presented i n the tables above do not reflect the fair market v alue of the reserves. The forecast prices and cost

assumptions applied are estimates only, and actual reserve realizations may differ materially.

Definitions and Notes to Reserves Data Tables:

In the tables set forth above in “Disclosure of Reserves Dat a” and elsewhere in this AIF the following definitions and other

notes are applicable:

1. “ Gross ” means:

(a) in relation to our interest in production and reserves, our intere st (operating and non-operating) before

deduction of royalties and without including any royalty interest of us ;

(b) in relation to wells, the total number of wells in which we have an interest; and

(c) in relation to properties, the total area of properties in which w e have an interest.

29 Future Net Revenue BEFORE Income Taxes -

Discounted at 10%/year

$(millions) $/Boe $/Mcfe

Proved Producing

Light and Medium Oil 75 32.47 5.41

Natural Gas 1,365 22.19 3.70

Non

- conventional activities (Oil Sands)

SCO-Mining 2,699 29.74 4.96

SCO-In-Situ 29,047 21.76 3.63

Total Proved Producing 33,186 22.28 3.71

Total Proved

Light and Medium Oil 76 32.33 5.39

Natural Gas 1,489 20.64 3.44

Non

- conventional activities (Oil Sands )

SCO-Mining 8,920 11.27 1.88

SCO-In-Situ 29,048 21.76 3.63

Total Proved 39,533 17.96 2.99

Total Proved Plus Probable

Light and Medium Oil 85 29.58 4.93

Natural Gas 1,838 18.61 3.10

Non

- conventional activities (Oil Sands)

SCO-Mining 15,522 6.76 1.13

SCO-In-Situ 36,140 18.43 3.07

Total Proved Plus Probable 53,585 12.29 2.05 (1) Page 35 of 100

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- f.mht2. “ Net ” means:

(a) in relation to our interest in production and reserves, our interes t (operating and non- operating) after

deduction of royalties obligations, plus our royalty interest in pro duction or reserves;

(b) in relation to wells, the number of wells obtained by aggregating our working interest in each of our gross

wells; and

(c) in relation to our interest in a property, the total area in which we have an interest multiplied by the working

interest we owned.

3. Columns may not add due to rounding.

4. The oil, natural gas liquids and natural gas reserves estimates presented in the GLJ Report are based on the

definitions and guidelines contained in the Canadian Oil and Gas Evalua tion Handbook (“COGE Handbook”). A

summary of those definitions are set forth below. The synthetic cr ude oil reserves include our diesel sales volumes, as

well as relatively immaterial volumes of bitumen sales.

Reserves Categories

Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable

from known accumulations, from a given date forward, based on anal ysis of drilling, geological, geophysical and

engineering data; the use of established technology; and specified economic conditions.

Reserves are classified according to the degree of certainty a ssociated with the estimates.

(a) Proved reserves are those reserves that can be estimated with a high degree of c ertainty to be recoverable. It

is likely that the actual remaining quantities recovered will exce ed the estimated proved reserves.

(b) Probable reserves are those additional reserves that are less certain to be re covered than proved reserves. It

is equally likely that the actual remaining quantities recovered wi ll 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 divide d into developed and undeveloped categories:

(c) Developed reserves are those reserves that are expected to be recovered from ex isting wells and installed

facilities or, if facilities have not been installed, that w ould 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.

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- f.mht(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 resumpt ion 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.

(d) Undeveloped reserves are those reserves expected to be recovered from known accumulati ons where a

significant expenditure (for example, when compared to the cost of dril ling a well) is required to render them

capable of production. They must fully meet the requirements of the reserves classification (proved,

probable) to which they are assigned.

In multi- well pools it may be appropriate to allocate total pool reserves be tween the developed and undeveloped

categories or to subdivide the developed reserves for the pool between de veloped producing and developed nonproducing. 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.

Levels of Certainty for Reported Reserves

The qualitative certainty levels referred to in the definitions a bove 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 reserv es are presented). Reported reserves should target the

following levels of certainty under a specific set of economic condi tions:

(a) at least a 90 per cent probability that the quantities actually r ecovered will equal or exceed the estimated

proved reserves; and

(b) at least a 50 per cent probability that the quantities actually r ecovered will equal or exceed the sum of the

estimated proved plus probable reserves.

A qualitative measure of the certainty levels pertaining to esti mates prepared for the various reserves categories is

desirable to provide a clearer understanding of the associated ris ks and uncertainties. However, the majority of

reserves estimates will be 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.

5. Forecast prices and costs

These are prices and costs that are generally acceptable as being a reasonable outlook of the future as of December

31,2008. To the extent that there are fixed or presently determinable future prices or costs to which we are legally

bound by a contractual or other obligation to supply a

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- f.mhtphysical product, including those for an extension period of a contra ct that is likely to be extended, those prices or

costs shall be incorporated into the forecast prices.

The forecast cost and price assumptions include increases in wellhe ad selling prices and take into account inflation

with respect to future operating and capital costs. Crude oil and natural gas benchmark reference pricing, as at

December 31, 2008, inflation and exchange rates utilized in the GLJ R eport were as follows:

The company’ s weighted average historical prices realized for the year ended D ecember 31, 2008 were $95.96/bbl for

synthetic crude oil, $8.23/mcf for natural gas, and $70.89/bbl for natural gas liquids.

6. Future Development Costs

The following table sets forth development costs deducted in the e stimation of our future net revenue attributable to

the reserves categories noted below as at December 31, 2008.

Management currently believes internally generated cash flows, exi sting credit facilities and access to capital debt

markets are sufficient to fund growth plans. There can be no guarantee that funds will be available or that we will

32 Year Inflation % Bank of Canada

Average Noon

Exchange Rate

$US/$Cdn NYMEX WTI Crude oil at

Cushing Oklahoma

$US/bbl Light, Sweet Crude

Oil at Edmonton (40

API, 0.3%S) $Cdn/bbl NYMEX Natural Gas

at Henry Hub

$US/mmbtu Natural Gas

at AECO

$Cdn/mmbtu

2009 2.0 0.825 57.50 68.61 7.00 7.58

2010 2.0 0.850 68.00 78.94 7.50 7.94

2011 2.0 0.875 74.00 83.54 8.00 8.34

2012 2.0 0.925 85.00 90.92 8.75 8.70

2013 2.0 0.950 92.01 95.91 9.20 8.95

2014 2.0 0.950 93.85 97.84 9.38 9.14

2015 2.0 0.950 95.73 99.82 9.57 9.34

2016 2.0 0.950 97.64 101.83 9.76 9.54

2017 2.0 0.950 99.59 103.89 9.96 9.75

2018 2.0 0.950 101.59 105.99 10.16 9.95

2019+ 2.0 0.950 +2%/yr +2%/yr +2%/yr +2%/yr

($ millions)

2009 2010 2011 2012 2013 Subtotal Remainder Total 10%

Discounted

Total Proved 2,138 3,107 1,206 1,247 1,351 9,049 20,695 29,744 13,980

Total Proved Plus Probable 2,866 5,091 3,848 3,358 2,552 17,715 50,902 68,617 24,638 Page 38 of 100

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- f.mhtallocate funding to develop all of the reserves attributed in the G LJ Report. Failure to develop those reserves would

have a negative impact on future cash flow from operating activiti es.

The interest or other costs of external funding are not included in the reserves and future net revenue estimates and

would reduce reserves and future net revenue to some degree depending upon the funding sources utilized. We do not

anticipate that interest or other funding costs would make developme nt of any property uneconomic.

Costs associated with the Voyageur upgrader designed to process approxi mately 245,000 bbl/d of in- situ bitumen,

were included only to the extent that the development plan for the Fi rebag reserves required additional upgrading, as

the remaining costs are believed to be related to development of conti ngent resources. The proved undeveloped and

proved plus probable undeveloped Firebag reserves utilize only 40,000 and 175,000 bbl /d, respectively, of the

additional design capacity; for approximately 17 and 30 years, respecti vely.

7. Estimated future well abandonment costs related to reserves w ells have been taken into account by GLJ in

determining the aggregate future net revenue therefrom.

8. The forecast price and cost assumptions assumed the continuance of current laws and regulations.

9. All factual data supplied to GLJ was accepted as represented. No field inspection was conducted.

10. The estimates of future net revenue presented in the tables above do not represent fair market value.

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- f.mhtReconciliation of Changes in Reserves

Reconciliation of Gross Reserves as at December 31, 2008

(1) Represents light and medium oil for our conventional reserves, and SCO for our mining and in-situ reserves.

Note: The presentation of infill drilling under SEC disclosures historically had been classified as a “Technical Revision”.

Under current NI 51-101 disclosures infill drilling balances are reported as “Extensions and Improved Recovery”.

34 Oil Natural Gas Natural Gas Liquids

Proved Plus Proved Plus Proved

Plus

Proved Probable Probable Proved Probable Probable Proved Probable Probable

(MMbbl) (MMbbl) (MMbbl) (Bcf) (Bcf) (Bcf) (MMbbl) (MMbbl) (MMbbl)

December 31, 2007

Conventional 2

- 2 573 232 805 6 2 8

SCO - Mining 1,634 740 2,374

SCO - In-Situ 854 1,837 2,691

- - - - - -

2,490 2,577 5,067 573 232 805 6 2 8

Extensions and Improved

Recovery

Conventional

- - - 40

- 40

- - - SCO - In-Situ 51 (51)

- - - - - - - 51 (51 )

- 40

- 40

- - - Technical Revisions

Conventional

- 1 1 (4 ) (19 ) (23)

- - - SCO - Mining 9 5 14

- - - - - - SCO - In-Situ 11 22 33

- - - - - -

20 28 48 (4 ) (19 ) (23)

- - - Discoveries

Conventional

- - - 2 2 4

- - -

-

- - 2 2 4

- - - Economic Factors

Conventional

- - - 1 1 2

- - -

-

- - 1 1 2

- - - Production

Conventional

- - - (73)

- (73 ) (1 )

- (1 )

SCO - Mining (72 )

- (72)

- - - - - - SCO - In-Situ (11 )

- (11 )

- - - - - - (83 )

- (83 ) (73 )

- (73 ) (1 )

- (1 )

December 31, 2008

Conventional 2 1 3 539 216 755 5 2 7

SCO - Mining 1,571 745 2,316

- - - - - - SCO - In-Situ 905 1,808 2,713

- - - - - -

2,478 2,554 5,032 539 216 755 5 2 7 (1) Page 40 of 100

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- f.mhtAdditional Information Relating to Reserves Data

Undeveloped Reserves

The table below outlines the proved and probable undeveloped reserves, by produ ct type, attributed to the company over the

three most recent years specifically, and in aggregate for those beyond three years.

(1) Represents light and medium oil for our conventional rese rves, and SCO for our mining and in-situ reserves.

Undeveloped reserves are attributed by GLJ in accordance with standar ds and procedures contained in the COGE Handbook.

Proved undeveloped reserves are those reserves that can be estima ted with a high degree of certainty and are expected to be

recovered from known accumulations where a significant expenditure is r equired to render them capable of production.

Probable undeveloped reserves are those reserves that are less ce rtain to be recovered than proved reserves and are expected to

be recovered from known accumulations where a significant expenditur e is required to render them capable of production.

In respect to mining and in- situ reserves, management uses integrated plans to forecast fut ure development of reserves. The

detailed plan aligns current production capacity, capital spending commi tments and future development for the next 10 years,

and is reviewed and updated continuously for internal and external fact ors affecting planned activity.

In developing our reserves we consider existing facility and gathering syst em capacity, capital allocation plans and remaining

recoverable resources availability. Accordingly, in some cases it will take us longer than two years to develop all of the

currently assigned reserves. We plan to develop the majority of the proved undeveloped reserves over the next five years and

the majority of the probable undeveloped reserves over the next s even years.

35

Significant Factors or Uncertainties

The evaluation of reserves is a continuous process, one that can be significantly impacted by a variety of internal and external

influences. Revisions are often required resulting from changes in pricing, economic conditions, regulatory changes, and

historical performance. Units Prior 2006 2007 2008

Proved Undeveloped

Oil MMbbl 450.2 192.0 61.6 62.5

Conventional 0.1

- 0.1

- SCO - Mining

- - - -

SCO – In-Situ 450.1 192.0 61.5 62.5

Natural Gas Bcf 63.8 13.8 43.4 7.5

Natural Gas Liquids MMbbl 0.6

- 0.1

- Total: Oil Equivalent MMboe 461.4 194.3 68.9 63.7

Probable Undeveloped

Oil MMbbl 2,587.5

- - -

Conventional 0.1

- - - SCO

- Mining 488.0

- - -

SCO - In-Situ 2,099.4

- - -

Natural Gas Bcf 35.3 20.8 70.8 21.4

Natural Gas Liquids MMbbl 0.2 0.2 0.1 0.1

Total: Oil Equivalent MMboe 2,593.6 3.6 11.9 3.6 (1)

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- f.mhtWhile the above factors, and many others, can be considered, certa in judgments and assumptions are always required. As new

information becomes available these areas are reviewed and revis ed accordingly.

For a summary of risks and uncertainties affecting Suncor please refer to ”Industry Conditions” and “Risk Factors” in this

AIF.

Other Oil and Gas Information

Oil and Gas Properties and Wells

Suncor’s oil sands business recovers bitumen through oil sands mining and i n- situ development in northern Alberta.

Conventional activities are focused on the development and production of na tural gas, and natural gas liquids from reserves in

western Alberta.

Suncor has no proved non-producing reserves from either of its mining or in- situ reserves. Within conventional reserves,

specific properties are capable of producing (primarily gas) but a re limited due to pending pipeline connections, or current

pipeline capacity and processing restrictions. The majority of thes e properties have been in their current non- producing state

for less than 3 years, and it is anticipated that pipeline const raints will be satisfactorily addressed in the next 2 – 3 years.

A summary of “oil” and “gas” wells for the company’s reserves are outlined below:

Properties with No Attributed Reserves

The company has a total of approximately 3,184,000 acres (net 1,994,000 acres) for current and future development related to

its mining, in- situ and conventional properties. The company has rights to explore, deve lop, and exploit approximately

137,000 net acres that could potentially expire by December 31, 2009. These net acres are entirely attributed to our

conventional properties, no land tenure expiries are scheduled to occur for either mining or in-situ properties for 2009.

Forward Contracts

The company has hedged a portion of its forecasted US dollare denomina ted sales subject to US dollar West Texas

Intermediate (WTI) price risk. As of February 10, 2009, we have crude oil hedges for approximately 125,000 bpd of

production from February 1 through December 31,

36 Oil Wells Natural Gas Wells

Producing Non

- Producing Producing Non

- Producing

Gross Net Gross Net Gross Net Gross Net

Alberta 74 56 68 64 394 232 33 16

British

Columbia 17 7 5 2 145 68 12 6

Total Canada 91 63 73 66 539 300 45 22 Page 42 of 100

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- f.mht2009. These volumes are in addition to previously reported options to sell 55,000 bpd at an equivalent WTI floor price of US

$60.00 per barrel from January 1 to December 31, 2009. The combinati on of the previous options and new fixed- price hedges

provides Suncor with an equivalent WTI floor price of about US $53.50 for approximately 180,000 bpd of production in 2009.

For the full year 2010, we have crude oil hedges for approximately 50, 000 bpd at an equivalent WTI floor price of US $50.00

per barrel and a ceiling price of approximately US $68.00 per barre l. This program replaces previously reported 2010 options

to sell 55,000 bpd at an equivalent WTI floor price of US $60.00, which w as effectively exited by selling similar contracts for

gross proceeds to Suncor of approximately $250 million before tax.

Additional Information Concerning Abandonment and Reclamation Costs

The company completes an annual review of its forecast abandonment and reclamation costs as they relate to our overall

corporate operations. The specific estimates established for f orecasted abandonment and reclamation costs are based on

available information, consistent with that assumed in our long range planning. These estimates consider the nature of all our

forecasted abandonment and reclamation costs, where determinable, for our mining, in- situ and conventional operations.

Assets with indeterminate lives have been excluded from the company ’s abandonment and reclamation cost estimates.

At December 31, 2008 Suncor estimated its abandonment and reclamation costs for surface leases, wells and facilities to be

approximately $4.1 billion (discounted at 10% approximately $1.3 billion). Of this $4.1 billion total, $1 billion (approximately

24%) has been deducted as abandonment costs in estimating the f uture net revenue from reserves. This $1 billion represents

our abandonment obligations for reserve wells (in-situ and conventional ac tivities).

The company anticipates approximately $630 million of its identified a sset retirement obligations to be incurred during the

next 3 years.

Tax Horizon

We expect to pay taxes in 2009.

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- f.mhtCosts Incurred

The table below summarized the company’ s capital expenditures related to its reserve activities for the year ended

December 31, 2008.

Exploration and Development Activities

The table below outlines the gross and net exploratory and development wel ls the company participated in during the year

ended December 31, 2008. These represent wells from both our in-si tu and conventional activities.

Production Estimates

The table below outlines the volume of the company’ s production estimated for the year ended December 31, 2009, as is

reflected in the estimate of future net revenues disclosed previously under “Reserves Data”.

(1) Represents light and medium oil for our conventional reserves and S CO for our mining and in-situ reserves.

38 (Reported in millions)

Property Acquisitions

- Exploration 133

Land

Proved

- Unproved 19

Total 19

Development 2,398

Total Capital 22,550

Exploratory Wells Development Wells

Gross Net Gross Net

CANADA

Oil

- - 24 24

NaturalGas 7 5 24 17

Dry 7 4 7 5

Other

- - 1

-

Total 14 9 56 46

Oil Natural Gas Natural Gas Liquids

Working Interest Net Working Interest Net Working Interest Net

Mbbl/day Mbbl/day MMcf/day MMcf/day Mbbl/day Mbbl/day

Total Proved 269 263 199 146 2 2

Total Proved Plus Probable 288 281 209 153 3 2 (1) Page 44 of 100

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- f.mhtProduction History

The table below outlines the company’ s historical production information, by product type, for each of the four financial

quarters, and in aggregate as an average daily measure.

Average daily production for oilsands (mining and in- situ) was 22.8 Mbbl/day in 2008 and the average daily production

volumes by product type for the year ended December 31, 2008 for conventional was:

39 Q1 Q2 Q3 Q4

Synthetic Crude Oil

Average Production (mbbl/d) 248.00 174.60 245.60 243.80

Average Price Received ($/bbl) 96.16 121.12 116.32 61.53

Royalties ($/bbl) 12.50 8.18 11.02 2.41

Production Costs ($/bbl) 31.55 50.85 34.00 41.30

Netback 52.11 62.09 71.30 17.82

Natural Gas

Average Production (mmcf/d) 209.00 205.00 197.00 195.00

Average Price Received ($/mcf) 7.30 9.62 9.10 6.90

Royalties ($/mcf) 1.53 2.23 2.35 1.64

Production Costs ($/mcf) 1.27 1.45 1.60 1.21

Netback 4.50 5.94 5.15 4.05

Natural Gas Liquids

Average Production (mbbl/d) 3.30 3.40 2.60 3.10

Average Price Received ($/bbl) 64.14 86.14 96.88 39.31

Royalties ($/bbl) 24.64 20.73 24.91 5.32

Production Costs ($/bbl) 7.61 8.69 9.63 7.26

Netback 31.89 56.72 62.34 26.73

Year Ended December 31, 2008

Conventional Nat Gas (mmcf/d) Liquids (mmcfe/d) Total (mmcfe/d)

Foothillls 99 1 100

Northern 65 11 76

Central Alberta 35 6 41

Other 3 0 3

Total 202 18 220 Page 45 of 100

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- f.mhtRemaining Recoverable Resources

Suncor holds a 100% interest in its oil sands leases, all located near Fort McMurray in the Athabasca region of Alberta. Based

on independent evaluations conducted by GLJ effective December 31, 2008, our estimate of remaining recoverable synthetic

crude oil resources is as follows:

Remaining recoverable resources were 15,500 millions of barrels of SCO at December 31, 2007. The decrease in 2008 was

primarily due to additional drilling and modeling for the Audet leases

.

The contingent resources are not classified as reserves due to t he absence of a commercial development plan that includes a

firm intent to develop within a reasonable timeframe, and in som e cases due to higher uncertainty as a result of lower corehole drilling density. Our Voyageur South development area, for which we submitted a regulatory application in 2007, is part

of our mining contingent resources. Significant mining contingent resources are also associated with our Audet leases, located

north of our Firebag in- situ leases and immediately adjacent to leases proposes for mi ning development by other operators. All

of our in- situ leases are associated with our Firebag leases. While we consider the contingent resources to be potentially

recoverable under reasonable economic operating conditions, there is no certainty that it will be commercially viable to

produce any portion of the resources.

The company has not finalized the development basis for these conti ngent resources. The volumes assume that Suncor

continues to treat and upgrade substantially all of its bitumen using curr ent technologies. Future strategic decisions regarding

marketability of bitumen versus synthetic crude oil and implementa tion of new upgrading technologies could impact actual

recoveries and product type of the contingent resources.

40 Remaining Recoverable Resources

As at December 31, 2008

(millions of barrels of SCO) Mining In

- Situ Total

Total Proved 1,600 900 2,500

Total Probable 700 1,800 2,500

Total Proved Plus Probable Reserves 2,300 2,700 5,000

Contingent Resources – Best Estimate 3,500 6,500 10,000

Remaining Recoverable Resources (unrisked) 5,800 9,200 15,000

1) Numbers in the above table are rounded to the nearest 100 million.

2) Contingent resources are those quantities of petroleum estimat ed, as of a given date, to be potentially recoverable from

known accumulations using established technology or technology under development, bu t which are not currently

considered to be commercially recoverable due to one or more continge ncies. There is no certainty that it will be

commercially viable to produce the contingent resources.

3) Best Estimate is considered to be the best estimate of the qu antity that will actually be recovered. It is equally likely that

the actual remaining quantities recovered will be greater or les s than the best estimate. The best estimate of potentially

recoverable volumes is generally prepared independent of the risks a ssociated with achieving commercial production.

4) Remaining recoverable resources (unrisked) are the arithmetic sum of proved and probable reserves and best estimate

contingent resources. Suncor has not quantified potentially recoverabl e volumes from either undiscovered accumulations

or its carbonate leases. The contingent resources have not bee n adjusted for risk based on the chance of development. It is

not an estimate of volumes that may be recovered. Actual recove ry may be less. (1)

(2)(3)

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- f.mhtINDUSTRY CONDITIONS

The oil and natural gas industry is subject to extensive controls and regulations governing its operations (including land tenure,

exploration, development, production, refining, transportation, and market ing) imposed by legislation enacted by various

levels of government and with respect to export and taxation of oil a nd natural gas by agreements among the governments of

Canada and Alberta, among others, all of which should be carefull y considered by investors in the oil and gas industry. It is

not expected that any of these controls or regulations will affe ct the company’ s operations in a manner materially different

than they would affect other oil and gas companies of similar siz e. All current legislation is a matter of public record and the

company is currently unable to predict what additional legislation or amendments may be enacted. Outlined below are some

of the principal aspects of legislation, regulations and agreement s governing the oil and gas industry.

Pricing and Marketing - Oil and Natural Gas

The producers of oil are entitled to negotiate sales contracts directly with oil purchasers, with the result that the market

determines the price of oil. Oil prices are primarily based on worldwide supply and demand. The specific price depends in part

on oil quality, prices of competing fuels, distance to the markets, the value of refined products, the supply/demand balance,

and other contractual terms. Oil exporters are also entitled to enter into export contracts with terms not exceeding one year in

the case of light crude oil and two years in the case of hea vy crude oil, provided that an order approving such export has been

obtained from the National Energy Board of Canada (the “NEB”). Any oil export to be made pursuant to a contract of longer

duration (to a maximum of 25 years) requires an exporter to obtain an export licence from the NEB and the issuance of such

licence requires a public hearing and the approval of the Governor in Council.

The price of natural gas is also determined by negotiation between buy ers and sellers. Natural gas exported from Canada is

subject to regulation by the NEB and the Government of Canada. Exporter s are free to negotiate prices and other terms with

purchasers, provided that the export contracts must continue to meet certain other criteria prescribed by the NEB and the

Government of Canada. Natural gas (other than propane, butane and ethan e) exports for a term of less than two years or for a

term of two to 20 years (in quantities of not more than 30,000 m /day), must be made pursuant to an NEB order. Any natural

gas export to be made pursuant to a contract of longer duration (to a maximum of 25 years) or a larger quantity requires an

exporter to obtain an export licence from the NEB and the issuance of such licence requires a public hearing and the approval

of the Governor in Council.

The government of Alberta also regulates the volume of natural gas t hat may be removed from the province for consumption

elsewhere based on such factors as reserve availability, trans portation arrangements, and market considerations.

Pipeline Capacity

Although pipeline expansions are ongoing, the pro-rationing of capacity on the i nter- provincial pipeline systems can occur

from time to time due to pipeline and downstream operating problems that can affect the ability to market western Canadian

crude oil and natural gas.

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- f.mhtThe North American Free Trade Agreement

The North American Free Trade Agreement (“NAFTA”) among the governments of Canada, the United States of America,

and Mexico became effective on January 1, 1994. NAFTA carries f orward most of the material energy terms that were

contained in the Canada/United States Free Trade Agreement, whi ch has been in place since October 1988. In the context of

energy resources, Canada continues to remain free to determine whether exports of energy resources to the United States or

Mexico will be allowed, provided that any export restrictions do not: (i) reduce the proportion of energy resources exported

relative to domestic use (based upon the proportion prevailing in the m ost recent 36 month period); (ii) impose an export price

higher than the domestic price subject to an exception with respect to certain voluntary measures which only restrict the

volume of exports; and (iii) disrupt normal channels of supply. Under NAFTA all three countries are prohibited from

imposing minimum or maximum export or import price requirements, provide d, in the case of export price requirements, any

circumstances in which any other form of quantitative restrictions could be imposed is also prohibited, and in the case of

import-price requirements, such requirements do not apply with res pect to enforcement of countervailing and anti- dumping

orders and undertakings.

NAFTA contemplates the reduction of Mexican restrictive trade practices in the energy sector by 2010 and prohibits

discriminatory border restrictions and export taxes. NAFTA also contemplates clearer disciplines on regulators to ensure fair

implementation of any regulatory changes and to minimize disruption of contr actual arrangements and avoid undue

interference with pricing, marketing and distribution arrangements , which is important for Canadian natural gas exports.

NAFTA may become subject to renegotiation and in such event, there c an be no guarantees that the company will not face

material trade restrictions, including in respect of pricing by NA FTA participants on its oil and gas products..

Royalties and Incentives

General

In addition to federal regulation, each province has legislation and re gulations which govern land tenure, royalties, production

rates, environmental protection, and other matters. The royalty r egime is a significant factor in the profitability of crude oi l,

natural gas liquids, sulphur, and natural gas production. Royalties payable on production from lands other than Crown lands

are determined by negotiations between the mineral freehold owner and the lessee, although production from such lands may

be subject to certain provincial taxes. Crown royalties are det ermined by governmental regulation and are generally calculated

as a percentage of the value of the gross production. The rate of r oyalties payable generally depends in part on prescribed

reference prices, well productivity, geographical location, fiel d discovery date, method of recovery, depth of well, and the type

or quality of the petroleum product produced. Other royalties and royalty

- like interests are, from time to time, carved out of the

working interest owner’s interest through non- public transactions. These are often referred to as overriding royalties, gross

overriding royalties, net profits interests, or net carried int erests.

Occasionally the governments of the western Canadian provinces crea te incentive programs for exploration and development.

Such programs provide for royalty rate reductions, royalty holidays, and tax credits, and are generally introduced when

commodity prices are low. The programs are designed to encourage expl oration and development activity by improving

earnings and cash flow within the industry. Royalty holidays and reducti ons would reduce the amount of Crown royalties paid

by oil and gas producers to the provincial governments and would increase the net income and funds from operations of such

producers. However, the

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- f.mhttrend in recent years has been for provincial governments to revise e xisting incentive programs and royalty structures, which

have generally resulted in increases to the amounts of royalties ultimately payable..

The Canadian federal corporate income tax rate levied on taxable inc ome is 22.1% effective January 1, 2007 for active

business income including resource income. With the elimination of the corporate surtax effective January 1, 2008 and other

rate reductions introduced in the October 2007 Economic Statement , the federal corporate income tax rate will decrease to

15% in five steps: 19.5% on January 1, 2008, 19% on January 1, 2009, 18% on Januar y 1, 2010, 16.5% on January 1, 2011

and 15% on January 2012.

Alberta

In Alberta, companies are granted the right to explore, produce and de velop petroleum and natural gas resources in exchange

for royalties, bonus bid payments and rents. On October 25, 2007, the Alber ta government released a report entitled “ The New

Royalty Framework” containing the government’s proposals for Albert a’s new royalty regime, and was followed by the Mines

and Minerals (New Royalty Framework) Amendment Act, 2008 , which was given Royal Assent on December 2, 2008. The

New Royalty Framework and the applicable new legislation becam e effective on January 1, 2009. Prior to the New Royalty

Framework, the amount of conventional oil royalties that were payable was influenced by the oil production, density of the oil,

and the vintage of the oil (the “Generic Regime”). Originally, t he vintage classified oil was “new oil” and “old oil” depending

on when the oil pools were discovered. If the pool was discovered pri or to March 31, 1974 it was considered “old oil”, and if

it was discovered after March 31, 1974 and before September 1, 1992, it was considered “new oil”. The Alberta government

introduced in 1992 a Third Tier Royalty with a base rate of 10% and a rate cap of 25% for oil pools discovered after

September 1, 1992. The new oil royalty reserved to the Crown ha d a base rate of 10% and a rate cap of 30%. The old oil

royalty reserved to the Crown had a base rate of 10% and a rate c ap of 35%. The New Royalty Framework eliminates this

classification and establishes new royalty rates for conventional oil, natural gas and oil sands. At that time, the new royalty

rates for conventional oil are set by a single sliding rate f ormula which is applied monthly and increases the old royalty from

30%- 35% applied to the old and new tiers, to up to 50% and with rate caps once the price of conventional oil reaches

Cdn.$120 per barrel. The sliding rate formula includes in its calc ulation the price of oil and well production.

With respect to natural gas, and similar to the conventional oil f ramework, the royalties outlined in the New Royalty

Framework are set by a single sliding rate formula ranging from 5% to 50% with a rate cap once the price of natural gas

reaches Cdn$16.59/Gigajoule. The New Royalty Framework determined ra te is based on well depth, production rate, gas price

and gas quality. Prior to the New Royalty Framework, the royalty r eserved to the Crown in respect of natural gas production,

subject to various incentives, was up to 30%, in the case of new na tural gas, and up to 35%, in the case of old natural gas,

depending upon a prescribed or corporate average reference price. In r esponse to the drop in commodity prices experienced

during the second half of 2008, the Government of Alberta announced on Novembe r 19, 2008, the introduction of a five year

program of transitional royalty rates with the intent of promoting new drilling, which program became effective January 1,

2009. Under this new program companies drilling new natural gas or conve ntional oil deep wells (between 1,000 and 3,500

metres) will be given a one- time option, on a well by well basis, to adopt either the new trans itional royalty rates or those

outlined in the New Royalty Framework. In order to qualify for thi s program wells must be drilled during the period starting

on January 1, 2009 and ending in December 31, 2013. Following this period a ll new wells drilled will automatically be

subject to the New Royalty Framework.

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- f.mhtOil sands projects are now subject to the New Royalty Framework, and regulated by, among others, the Oil Sands Royalty

Regulation, 2009 approved by the Government of Alberta on December 10, 2008. Royalties on our curr ent Firebag In- Situ

project were under the 1997 Generic Regime until the end of 2008, and asse ssed based on bitumen value. In December 2008,

the Government of Alberta enacted the New Royalty Framework, whic h increased royalty rates from the 1997 Generic Regime

to a sliding-scale royalty of 25% to 40% of R – C, subject to minimum royalty of 1% to 9% of R, depending on oil price . In

both cases, a sliding

- scale royalty moves with increases in WTI prices from Cdn$55\bbl to the maximum rate at a WTI price

of Cdn$120\bbl. Royalty on our base oil sands mining and associated upgradi ng operations are modified by Crown

agreements and assessed on the R - C royalty subject to a minimum royalty as follows: (a) based on upgra ded product values

until December 31, 2008 with rates at 25% of R - C subject to the 1% minimum royalty of R; (b) commencing January 1,

2009, a bitumen-based royalty applies pursuant to Suncor’s exercise of i ts option to transition to the bitumen- based Generic

Regime. The royalty rates will remain at 25% of the R- C, subject to the 1% minimum royalty of R, but will apply to a re vised

R - C where R will be based on bitumen value and C would exclude subs tantially all upgrading costs; (c) from January 1, 2010

through December 31, 2015, pursuant to our January 2008 royalty amending agreem ent with the Government of Alberta, the

New Royalty Framework rates described above will apply to the bitume n royalty for current production levels, subject to a cap

of 30% of R- C, and a minimum royalty of 1% to 1.2% of R. In addition, the Suncor Royalty Amending Agreement provides

Suncor with a level of certainty for various matters, including the bitumen valuation methodology, allowed cost, royalty in

kind and certain taxes; and (d) in 2016 and subsequent years, the royal ty rates for all of our oil sands operations, our base

operations and our Firebag In- Situ project, will be the rates prescribed under the New Royal ty Framework, unless as amended

or superseded prior to that time.

On April 10, 2008, the Government of Alberta introduced two new royalty prog rams to encourage the development of deep oil

and gas reserves, and these are: (a) a five- year oil program for exploration wells over 2,000 metres that wil l provide royalty

adjustments to offset higher drilling costs and provide a greater i ncentive for producers to continue to pursue new, deeper oil

plays (these oil wells will qualify for up to a $1 million or 12 mont hs of royalty offsets, whichever comes first); and (b) a fiveyear natural gas deep drilling program that will replace the exi sting program in order to encourage continued deep gas

exploration for wells deeper than 2,500 metres (the program will cr eate a sliding scale of royalty credit according to depth, of

up to $3,750 per metre). These new programs are to be implemented al ong with the New Royalty Framework.

Regulations made pursuant to the Mines and Minerals Act (Alberta) provided various incentives for exploring and developing

oil reserves in Alberta. However, the Alberta Government announced in August of 2006 that four royalty programs were to be

amended, a new program was to be introduced and the Alberta Royal ty Tax Credit Program was to be eliminated, effective

January 1, 2007. The programs affected by this announcement were: (i) Deep Gas Royalty Holiday; (ii) Low Productivity

Well Royalty Reduction; (iii) Reactivated Well Royalty Exempt ion; and (iv) Horizontal Re- Entry Royalty Reduction. The

program introduced was the Innovative Energy Technologies Program (the “ IETP”) which has a stated objective of promoting

the producers’ investment in research, technology and innovation for the purposes of improving environmental performance

while creating commercial value. The IETP provides royalty r eductions which are presumed to reduce financial risk. Alberta

Energy decides which projects qualify and the level of support that wil l be provided. The deadline for the IETP’ s final round

of applications was September 20, 2008. The successful applicants for the first two rounds have been announced, and those

for the third round selection are scheduled to be announced in the

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- f.mhtfirst half of 2009. The technical information gathered from this program is to be made public once a two- year confidentiality

period expires.

The New Royalty Framework includes a policy of “shallow rights reve rsion”. The Government of Alberta stated that it will

implement this policy in order to maximize the development of currentl y undeveloped resources that is consistent with the

Government of Alberta’ s objective of maximizing recovery of known gas resources, while incr easing royalty revenues. The

policy’ s stated objective is for the mineral rights to shallow gas geologi cal formations that are not being developed to revert

back to the government and be made available for resale, and in the e vent of non

- productive shallow wells, to sever the rights

from shallow zones and encourage increased production from up- hole zones. In December 2008, the Government of Alberta

proclaimed an amendment to the Mines and Minerals Act (Alberta) with respect to shallow rights reversion. This am endment

affects leases issued after January 1, 2009, with phased-in applic ation for leases entered into prior to January 1, 2009.

Land Tenure

Crude oil and natural gas located in the western provinces is owne d predominantly by the respective provincial governments.

Provincial governments grant rights to explore for and produce oil and nat ural gas pursuant to leases, licences, and permits for

varying terms from two years, and on conditions set forth in provincial legislation including requirements to perform specific

work or make payments. Oil and natural gas located in such provinces can also be privately owned and rights to explore for

and produce such oil and natural gas are granted by lease on such terms and conditions as may be negotiated.

Environmental Regulation

The oil and natural gas industry is currently subject to environmental regulations pursuant to a variety of provincial and federal

legislation. Such legislation provides for restrictions and prohibitions on the release or emission of various substances

produced in association with certain oil and gas industry operations. In addition, such legislation requires that well and facility

sites be abandoned and reclaimed to the satisfaction of provincial authorities. Compliance with such legislation can require

significant expenditures and a breach of such requirements may result in suspension or revocation of necessary licenses and

authorizations, civil liability for pollution damage, and the impositi on of material fines and penalties.

Environmental legislation in the Province of Alberta has been consol idated into the Environmental Protection and

Enhancement Act (Alberta) (the “EPEA”), which came into force on September 1, 1993, and the Oil and Gas Conservation

Act (Alberta) (the “OGCA”). The EPEA and OGCA impose stricter environmental standards, requir e more stringent

compliance, reporting and monitoring obligations, and significantly incre ased penalties. In 2006, the Alberta Government

enacted regulations pursuant to the EPEA to specifically target su lphur oxide and nitrous oxide emissions from industrial

operations including the oil and gas industry.

In 2007, the Alberta government introduced the Climate Change and Emissions Management Amendment Act (Alberta), which

places intensity (emissions per unit of production) limits on facili ties emitting more than 100,000 tonnes of cap, carbon

dioxide equivalent per year. Suncor’ s oil sands are subject to this legislation. The act calls f or intensity reductions of 12%

commencing July 1, 2007

In compliance with this new legislation, Suncor filed application s in December 2007 to establish baseline intensities for our oil

sands facility. In March 2009, Suncor must file compliance report s

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- f.mhtthat show what actions the company took during the year to offset intensit ies. Compliance options available to Suncor include

emission reductions, utilizing offset projects or contributing to a go vernment climate change emission management fund.

For the compliance period of January 1 to December 31, 2008

, the compliance costs to Suncor are estimated at between $7

million and $8 million. Final costs determined with the company’s March 2009 compliance report filing to the province.

The United States federal and the Ontario provincial and Colorado state governments are also in various stages of developing

greenhouse gas management legislation and regulation. At this time , no such legislation has been tabled in these jurisdictions

and any potential impacts are unknown.

On April 26, 2007, the Federal Government released its Action Plan to Reduce Greenhouse Gases and Air Pollution (the

“Action Plan”) also known as ecoACTION which includes the regulatory framework for a ir emissions. This Action Plan

covers not only large industry, but regulates the fuel efficiency of ve hicles and the strengthening of energy standards for a

number of energy using products.

The Government of Canada and the Province of Alberta released on Janua ry 31, 2008 the final report of the Canada- Alberta

ecoENERGY Carbon Capture and Storage Task Force, which recommends among other things: (i) incorporating carbon

capture and storage into Canada’ s clean air regulations; (ii) allocating new funding into projects through competitive process;

and (iii) targeting research to lower the cost of technology.

On March 10, 2008, the Government of Canada released “Turning the Corner – Taking Action to Fight Climate Change” ( the

“Updated Action Plan”) which provides some additional guidance with resp ect to the Government’ s plan to reduce greenhouse

gas emissions by 20% by 2020 and by 60% to 70% by 2050.

The financial impact of these proposals will be dependent on the d etails of the final legislation. Subsequent to the introduction

of the Updated Action Plan, the Canadian federal government committe d to implement a North American cap and trade system

with the United States, and therefore it is currently not cert ain that Updated Action Plan will be implemented as proposed or at

all.

The Updated Action Plan is primarily directed towards industrial emissions from certain specified industries including the oil

sands, oil and gas and refining. The Updated Action Plan is i ntended to create a carbon emissions trading market, including an

offset system, to provide incentive to reduce greenhouse gas emis sion and establish a market price for carbon. For the oil

sands, its proposed application will be process- specific, oil sands plants built in 2012 and later, those which use hea vier

hydrocarbons, up-graders and in- situ production will have mandatory standards in 2018 that will be based on carbon capture

and storage.

The Updated Action Plan is proposed to apply only to facilities excee ding a minimum annual emissions threshold: (i) 50,000

tonnes of CO2 equivalent per year for natural gas pipelines; (i i) 3,000 tonnes of CO2 equivalent per upstream oil and gas

facility; and (iii) 10,000 boe/d/company. These proposed thresholds are significantly stricter than the current Alberta

regulatory threshold of 100,000 tonnes of CO2 equivalent per year per facil ity.

Under the Updated Action Plan four separate compliance mechanisms are proposed in respect of the above targets:

Technology Fund contributions, offset credits, clean development cre dits

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- f.mhtand credits for early action. The most significant of these com pliance mechanisms, at least initially, will be the Technolo gy Fund and for which regulated entities will be able to contribute i n order to comply with emissions intensity reductions. The

proposed contribution rate will increase over time, beginning at $15 per tonne for the 2010- 12 period, rising to $20 per tonne

in 2013, and thereafter increasing at the nominal rate of GDP gr owth. Contribution limits will correspondingly decline from

70% in 2010 to 0% in 2018. Monies raised through contributions to the Technology F und will be used to invest in technology

to reduce greenhouse gas emissions. Alternatively, regulated ent ities may be able to receive credits for investing in large- scale

and transformative projects at the same contribution rate and unde r similar requirements as mentioned above.

The proposed offset system is intended to encourage emissions reduct ions from activities outside of the regulated sphere,

allowing non- regulated entities to participate in and benefit from emiss ions reduction activities. In order to generate offset

credits, project proponents must propose and receive approval for emis sions reduction activities that will be verified before

offset credits will be issued to the project proponent. Those cre dits can then be sold to regulated entities for use in compliance

or non-regulated purchasers that wish to either cancel the offset c redits or bank them for future use or sale.

Under the Updated Action Plan, it is proposed that regulated entitie s will also be able to purchase credits created through the

Clean Development Mechanism of the Kyoto Protocol. The purchase of such Emissions Reduction Credits will be restricted

to 10% of each firm’ s regulatory obligation, with the added restriction that credits ge nerated through forest sink projects will

not be available for use in complying with the Canadian regulations.

There remains uncertainty around the outcome and impacts of climate change and environmental laws and regulations

(whether currently in force or proposed laws and regulations as descr ibed herein or future laws and regulations); it is not

currently possible to predict either the nature of any requirements or the impact on the company and its business, financial

condition, results of operations and cash flow at this time. We continue to actively work to mitigate our environmental impact,

including taking action to reduce greenhouse gas emissions, investing in renewable forms of energy such as wind power and

biofuels, accelerating land reclamation, installing new emission abatement equipment and pursuing other opportunities such as

carbon capture and sequestration.

47

RISK FACTORS

As a company, we identify risks in four principal categories: 1) O perational; 2) Financial; 3) Legal and Regulatory; and 4)

Strategic. These categories are defined below, and identified r isks have been classified accordingly. Please note, identified

risks could relate to multiple risk categories; we have classi fied risks based on the primary category to which they apply to

Suncor.

We are continually working to mitigate the impact of potential ri sks to our business. This process includes an entity- wide risk

review. The internal review is completed annually to help ensure t hat all significant risks are identified and appropriately

managed.

1) Operational Risks – Risks that directly affect our ability to continue normal operations within our identified

businesses.

Operating Hazards and Other Uncertainties

. Each of our three principal operating businesses, oil sands, natural gas, and

refining and marketing demand significant levels of investment and ther efore carry economic risks and opportunities.

Generally, our operations are subject to hazards and risks such a s fires, explosions, gaseous leaks, migration of harmful

substances, blowouts, power outages and oil spills, any of which can c ause personal injury, damage to property, IT systems

and related data and control systems, equipment and the environment, as well as interrupt operations. In addition, all of our

operations are subject to all of the risks connected with tran sporting, processing and storing crude oil, natural gas and other

related products. Risks associated with access to skilled l abour to support our operations in a safe and effective manner are

also discussed in “Labour and Materials Supply”, below.

At oil sands, mining oil sand and producing bitumen through in- situ methods, extracting bitumen from the oil sands, and

upgrading bitumen into synthetic crude oil and other products involve particul ar risks and uncertainties. Oil sands is

susceptible to loss of production, slowdowns, shutdowns or restrictions on our ability to produce higher value products due to

the interdependence of its component systems. Severe climatic conditions at oil sands can cause reduced production during

the winter season and in some situations can result in higher co sts. While there are virtually no finding costs associated with

oil sands resources, delineation of the resources, the costs assoc iated with production, including mine development and drilling

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- f.mhtcapital outlays. The costs associated with production at oil sand s are largely fixed in the short term and, as a result, operati ng

costs per unit are largely dependent on levels of production.

There are risks and uncertainties associated with natural gas operations, including all of the risks normally associated with

drilling for natural gas wells, the operation and development of such properties, including encountering unexpected formations

or pressures, premature declines of reservoirs, fires, blow- outs, equipment failures and other accidents, sour gas releases,

uncontrollable flows of crude oil, natural gas or well fluids, adver se weather conditions, pollution and other environmental

risks.

Our downstream business is subject to all of the risks normally inher ent in the operation of a refinery, terminals, pipelines and

other distribution facilities as well as service stations, inc luding loss of product, slowdowns due to equipment failures,

unavailability of feedstock, price and quality of feedstock or other incidents.

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- f.mhtWe are also subject to operational risks such as sabotage, terr orism, trespass, related damage to remote facilities, thef t and

malicious software or network attacks.

Losses resulting from the occurrence of any of these risks could ha ve a material adverse effect on our business, financial

condition, results of operations and cash flow.

Major Projects

. There are certain risks associated with the execution of our m ajor projects. These risks include: our ability to

obtain the necessary environmental and other regulatory approvals; risks relating to schedule, resources and costs, including

the availability and cost of materials, equipment and qualifi ed personnel; the impact of general economic, business and market

conditions; the impact of weather conditions; our ability to finance growth if commodity prices were to decline and stay at low

levels for an extended period; risks relating to restarting projects placed in “safe mode”, including increased capital costs; and

the effect of changing government regulation and public expectations in r elation to the impact of oil sands development on the

environment. The commissioning and integration of new facilities w ithin our existing asset base could cause delays in

achieving targets and objectives. Management believes the execution of major projects presents issues that require prudent

risk management. There are also risks associated with proje ct cost estimates provided by us. Some cost estimates are provi ded

at the conceptual stage of projects and prior to commencement or com pletion of the final scope design and detailed

engineering needed to reduce the margin of error. Accordingly, act ual costs can vary from estimates and these differences can

be material. Losses resulting from the occurrence of any of these risks could have a material adverse effect on our busines s, financial condition, results of operations and cash flow.

Insurance. Our involvement in the exploration for and development of oil and natura l gas properties may result in the

company becoming subject to liability for pollution, blow- outs, property damage, personal injury or other hazards. Although

we maintain a risk management program, which includes an insuranc e component, such insurance may not provide adequate

coverage in all circumstances, nor are all such risks insurable. Losses beyond the scope of insurance could have a material

adverse effect on our business, financial condition, results of oper ations and cash flow. In late 2005 we formed a selfinsurance entity to provide additional business interruption coverage for potential losses. In 2006, one of our external business

interruption service providers discontinued operations.

In December 2006, insurers impacted by the January 4, 2005 fire at oil sands filed a statement of claim against various parties

alleged to be potentially responsible, seeking to recover amounts paid to Suncor under our insurance contract. As required by

our insurance contract, we are named as Plaintiff. However, the action will not have an impact on the insurance settlements we

have already reached with our insurers or on our future revenues.

Confidentiality

. Breach of confidentiality could place us at competitive risk if conf idential operational information or

proprietary intellectual property was improperly disclosed.

2) Financial Risks – Risks that directly affect our busines s and financial condition.

Capital Markets . Recent market events and conditions, including disruptions in the int ernational credit markets and other

financial systems and the deterioration of global economic conditi ons, have caused significant volatility in commodity prices

and the rates at which we are able to borrow funds for our capital programs. These conditions worsened in 2008 and are

continuing in 2009, causing a loss of confidence in the broader Canadian, U.S. and global credit and financial markets and

resulting in the collapse of, and government intervention in, major banks, financial institutions and insurers and creating a

climate of greater volatility, less liquidity,

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- f.mhtwidening of credit spreads, a lack of price transparency, increa sed credit losses and tighter credit conditions, including higher

borrowing rates. Despite the various actions taken by governments around the world, concerns about the general condition of

the capital markets, financial instruments, banks, investment banks, insurers and other financial institutions caused the broader

credit markets to further deteriorate and stock markets to decli ne substantially. These factors have negatively impacted

company valuations and will impact the performance of the global econ omy going forward.

As a result of this weakened global economic situation, the compa ny along with all other oil and gas entities will have

restricted access to capital and increased borrowing costs. A lthough our business and asset base have not changed, the lending

capacity of all financial institutions has diminished and risk premi ums have increased. As future capital expenditures will be

financed out of cash generated from operations, borrowings and possible future equity sales, our ability to do so is dependent

on, among other factors, the overall state of the capital markets and investor appetite for investments in the energy industry

generally and our securities in particular.

To the extent that external sources of capital become limited or unavailable or available on onerous terms, our ability to make

capital investments and maintain existing properties may be impaire d, and our business, financial condition, results of

operations and cash flow may be materially adversely affected as a result. At December 31, 2008, we had approximately $3.0

billion of unused credit available under bank credit facilities. Based on current f unds available and expected cash from

operations, we believe that we have sufficient funds available t o fund our currently projected capital expenditures in 2009.

However, if cash flow from operations is lower than expected or 2009 capital expenditures exceed current estimates, or if w e incur major unanticipated expenses related to development or mainte nance of our existing properties, we may be required to

seek additional capital to maintain our capital expenditures at p lanned levels and our debt ratings may be adversely affected.

Failure to obtain the financing necessary for our capital expenditure pl ans may result in a delay in the planned development or

production from our operations. This in turn, could have a material a dverse effect on our business, financial condition, results

of operations and cash flow.

Issuance of Debt . From time to time we may finance capital expenditures in whole or in part with debt, which may increase

our debt levels above industry standards for oil and natural gas comp anies of similar size. Depending on future development

plans, we may require additional debt financing that may not be availa ble or, if available, may not be available on favourable

terms. Neither the company’s articles nor its by- laws limit the amount of indebtedness that we may incur. The leve l of our

indebtedness from time to time, could impair our ability to obta in additional financing on a timely basis to take advantage of

business opportunities that may arise and could negatively effect o ur debt ratings. This in turn, could have a material adverse

effect on our business, financial condition, results of operations and cash flow.

Debt Covenants . We currently have a $3.75 billion syndicated credit facilit y with 16 banks expiring in 2013 and a bilateral

credit facility of $480 million expiring in 2009. We are required to comply with financial and operating covenants under these

credit facilities. We routinely review the covenants based on a ctual and forecast results and have the ability to make changes to

our development plans and/or dividend policy to comply with covenants under the cr edit facilities. In the event that we do not

comply with such covenants under the credit facilities, our access to capital could be restricted or repayment could be required,

which could have a material adverse effect on our business, financia l condition, results of operations and cash flow. In

addition, our inability to refinance expiring credit facilities on favorable terms or at all or any restrictions imposed on our

borrowings under these facilities due to covenant breaches or otherwis e could

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- f.mhthave a material adverse effect on our business, financial conditi on, results of operations and cash flow.

Hedging

. From time to time we may enter into agreements to receive fi xed prices on our oil and natural gas production to

offset the risk of revenue losses if commodity prices decline; howev er, if commodity prices increase beyond the levels set in

such agreements, we will not benefit from such increases and we may be obligated to pay royalties on such higher prices, even

though not received by us, after giving effect to such agreements. Si milarly, from time to time we may enter into agreements

to fix the exchange rate of Canadian to United States dollars in or der to offset the risk of revenue losses if the Canadian dollar

increases in value compared to the United States dollar; howeve r, if the Canadian dollar declines in value compared to the

United States dollar, we will not benefit from the fluctuat ing exchange rate.

Uncertainty of Reserve and Resource Estimates

. The reserves estimates for our oil sands and natural gas business uni ts

included in this AIF represent estimates only. There are num erous uncertainties inherent in estimating quantities and quality

of these proved and probable reserves and resources, including many factor s beyond our control.

In general, estimates of economically recoverable reserves and t he future net cash flow from these assets based upon a number

of variable factors and assumptions, such as historical production from the properties, the assumed effect of regulation by

governmental agencies, pricing assumptions, the timing and amount of capital expenditures, future royalties, future operating

costs, yield rates for production of synthetic crude oil from bitum en, all of which may vary considerably from actual results.

The accuracy of any reserve estimate is a matter of engineer ing interpretation and judgment and is a function of the quality and

quantity of available data, which may have been gathered over time. In the oil sands business unit, reserve and resource

estimates are based upon a geological assessment, including dril ling and laboratory tests. These estimates also consider curr ent

production capacity and upgrading yields, current mine plans, operating lif e and regulatory constraints. The Firebag reserves

and resource estimates are based upon a geological assessment of data gathered from evaluation drilling, the testing of core

samples and seismic operations and demonstrated commercial succe ss of the in- situ process. Our actual production, revenues,

royalties, taxes and development and operating expenditures with re spect to our reserves will vary from such estimates and

such variances could be material. Production performance subsequent to the date of the estimate may justify revision, either

upward or downward, if material. For these reasons, estimates of the economically recoverable reserves attributable to any

particular group of properties, and classification of such reserve s based on risk of recovery, prepared by different engineers or

by the same engineers at different times, may vary substantially.

In accordance with applicable securities law, our independent res erves evaluator has used forecast prices and costs in

estimating the reserves and future net cash flow as summarized h erein. Actual future net cash flow will be affected by other

factors, such as actual production levels, supply and demand for oi l and natural gas, curtailments or increases in consumption

by oil and natural gas purchasers, changes in governmental regulati on or taxation and the impact of inflation and other factors

on costs.

Actual production cash flow is derived from our oil and gas reserve s and will vary from the estimates contained in the reserve

evaluation, and such variations could be material. The reserve eva luation is based in part on the assumed success of activities

we intend to undertake in future years. The reserves and estim ated cash flow to be derived from the reserves contained in the

reserve evaluation will be reduced to the extent that such activitie s do not achieve the level of success assumed in the reserve

evaluation. The reserve evaluation is effective as of a specif ic

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- f.mhteffective date and has not been updated, and thus does not reflect change s in our reserves since that date.

Volatility of Crude Oil and Natural Gas Prices

. Our future financial performance is closely linked to crude oil prices, and to a

lesser extent, natural gas prices. The prices of these commodities can be influenced by global and regional supply and demand

factors. Worldwide economic growth, political developments, compli ance or non- compliance with quotas imposed upon

members of the Organization of the Petroleum Exporting Countries a nd weather, among other things, can affect world oil

supply and demand. Our natural gas price realizations are affected primarily by North American supply and demand and by

prices of alternate sources of energy. All of these factors are beyond our control and can result in a high degree of price

volatility not only in crude oil and natural gas prices, but also fl uctuating price differentials between heavy and light grades of

crude oil, which can impact prices for sour crude oil and bitumen. Oil and natural gas prices have fluctuated widely in recent

years and have decreased substantially over the last six months. Given the current global economic downturn, we expect

continued volatility and uncertainty in crude oil and natural gas prices and prices may remain at depressed levels in the near

term and beyond. A prolonged period of low crude oil and natural gas pric es could affect the value of our crude oil and gas

properties and the level of spending on growth projects, and could result in curtailment of production on some properties.

Accordingly, low crude oil prices in particular could have a materi al adverse effect on our business, financial condition, results

of operations and cash flow. A key component of our business strate gy is to target production of sufficient natural gas to meet

or exceed internal demands for natural gas purchased for consumption in our oil sands operations, creating a natural price

hedge which reduces our exposure to gas price volatility. However, the re are no assurances that we will be able to continue to

increase production to keep pace with growing internal natural gas demands.

We conduct an assessment of the carrying value of our assets t o the extent required by Canadian generally accepted accounting

principles. If crude oil and natural gas prices decline further or remain at low levels, the carrying value of our assets could be

subject to downward revisions, and our earnings could be materially adver sely affected.

Volatility of Downstream Margins

. Our downstream business is sensitive to wholesale and retail ma rgins for its refined

products, including gasoline, diesel and asphalt. Margin volatili ty is influenced by, among other things, overall marketplace

competitiveness, weather, the cost of crude oil (see “Volatil ity of Crude Oil and Natural Gas Prices” above) and fluctuations in

supply and demand for refined products. We expect that margin and price vo latility and overall marketplace competitiveness,

including the potential for new market entrants, will continue. As a result, our operating results for our refining and marketing

business unit can be expected to fluctuate and may be materially adversely affected.

Energy Trading Activities

. The nature of energy trading activities creates exposure to si gnificant financial risks. These include

risks that: movements in prices or values could result in a fina ncial loss to the company; a lack of counterparties, due to mar ket

conditions or otherwise could leave us unable to liquidate or offset a position, or unable to do so at or near the previous market

price; we may not receive funds or instruments from our counterpa rty at the expected time; the counterparty could fail to

perform an obligation owed to us; we may suffer a loss as a resu lt of human error or deficiency in our systems or controls; or

we may suffer a loss as a result of contracts being unenforcea ble or transactions being inadequately documented. A separate

risk management function within the company develops and monitors pra ctices and policies and provides independent

verification and valuation of our trading and marketing activities. However, we may experience significant financial losses as a

result of these risks, which may have a material adverse ef fect on our business, financial condition, results of operations and

cash flow.

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- f.mhtExchange Rate Fluctuations

. Our 2008 Consolidated Financial Statements are presented in Canadian dollars. Results of

operations are affected by the exchange rates between the Canadian dollar and the U.S. dollar. These exchange rates have

varied substantially in the last five years. A substantial porti on of our revenue is received by reference to U.S. dollar

denominated prices and a significant portion of our debt is denominated in U .S. dollars. In addition, we have subsidiary

operations that are denominated in U.S. dollars, translated t o Canadian dollars using the current rate approach, whereby

revenues and expenses are recorded at the exchange rate at the time the transaction occurs, and assets and liabilities are

translated at the exchange rate at the balance sheet date. Ther efore, fluctuations in exchange rates between the U.S. and

Canadian dollar may give rise to foreign currency exposure, either fa vourable or unfavourable, creating another element of

uncertainty. To the extent such fluctuation is unfavourable, it may have a material adverse effect on our business, financial

condition, results of operations and cash flow.

Dividends . Our payment of future dividends on our common shares will be de pendent on, among other things, our financial

condition, results of operations, cash flow, the need for funds to f inance ongoing operations, debt covenants and other business

considerations as the board of directors of the company considers r elevant. There can be no assurance that we will continue to

pay dividends in the future.

Interest Rate Risk . We are exposed to fluctuations in short-term Canadian intere st rates as a result of the use of floating rate

debt. We maintain a substantial portion of our debt capacity in revol ving, floating rate bank facilities and commercial paper,

with the remainder issued in fixed rate borrowings. To manage our i nterest rate exposures, we occasionally enter into interest

rate swap agreements and exchange contracts to either effect ively fix the interest rate on floating rate debt or to float the

interest rate on fixed rate debt.

3) Legal and Regulatory Risks – Risks that affect our ability to comply with regulatory and stat utory

requirements under applicable law.

Environmental Regulation and Risk

. Environmental regulation affects nearly all aspects of our operati ons. These regulatory

regimes are laws of general application that apply to us in the same manner as they apply to other companies and enterprises in

the energy industry. The regulatory regimes require us to obtain ope rating licenses and permits in order to operate and impose

certain standards and controls on activities relating to mining, o il and gas exploration, development and production, and the

refining, distribution and marketing of petroleum products and petrochemic als. Environmental assessments and regulatory

approvals are required before initiating most new major projects or undertaking significant changes to existing operations. In

addition to these specific, known requirements, we expect future c hanges to environmental legislation, including anticipated

legislation for air pollution (Criteria Air Contaminants) and gr eenhouse gases that will impose further requirements on

companies operating in the energy industry. See “Industry Conditions – En vironmental Regulation” in this AIF.

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

• the possible cumulative regional impacts of oil sands development;

• manufacture, import, storage, treatment and disposal of hazar dous or industrial waste and substances;

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- f.mht• the need to reduce or stabilize various emissions to air;

• withdrawals, use of, and discharges to, water;

• issues relating to land reclamation, restoration and wildlife habi tat protection;

• reformulated gasoline to support lower vehicle emissions; and

• U.S. implementation of regulation or policy to limit its purchases of oil to oil produced from conventional sources, or

U.S. state or federal calculation and regulation of fuel l ifecycle carbon content.

Changes in environmental regulation could have a material adverse effect on us from the standpoint of product demand,

product reformulation and quality, methods of production, distribution costs and financial results. For example, requirements

for cleaner- burning fuels could cause additional costs to be incurred, which ma y or may not be recoverable in the marketplace.

The complexity and breadth of these issues make it extremely di fficult to predict their future impact on us. Management

anticipates capital expenditures and operating expenses could inc rease in the future as a result of the implementation of new

and increasingly stringent environmental regulations. Compliance with environmental regulation can require significant

expenditures and failure to comply with environmental regulation may res ult in the imposition of fines and penalties, liability

for clean up costs and damages and the loss of important licenses and permits, which may in turn, have a material adverse

effect on our business, financial condition, results of operations and cash flow.

Canada is a signatory to the United Nations Framework Convention on Cl imate Change and has ratified the Kyoto Protocol

established to set legally binding targets to reduce nationwide emiss ions of carbon dioxide, methane, nitrous oxide and other

so called “greenhouse gases”. Our exploration and production facilities and other operations and activi ties emit greenhouse

gases and will require us to comply with the new regulatory framew ork announced on March 10, 2008 by the Federal

Government which is intended to force large industries to reduce emissions of greenhouse gases, in addition to the Federal

Government’s proposed Clean Air Act (Alberta) of 2006, Action Plan, Updated Action Plan and Alberta’ s recently enacted

Climate Change and Emissions Management Act and Specified Gas Emitters Regulation . The direct or indirect costs of these

regulations may have a material adverse effect on our business, f inancial condition, results of operations and cash flow. See

“Industry Conditions – Environmental Regulation” in this AIF.

A new reclamation liability management program is under review by the Province of Alberta. The new program would involve

increased reporting of progressive reclamation, an asset/liabili ty based risk assessment and consideration of reserve life. Partial

security could be required if reclamation targets are not met and full security may eventually be required.

Over the past few years legislation has been passed in Canada and the United States to reduce allowable levels of sulphur in

transportation fuels. For a discussion of projects completed at our refining and marketing operations, see the information

under refining and marketing in the “Three-Year History” section of this AIF. Projects to retrofit existing facilitie s to comply

with these standards are subject to all risks inherent in large capital projects, and to the additional risk that failure to m eet

legislated deadlines could have a material impact on the company’s

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- f.mhtability to market its products, or subject the company to fines and penalties potentially having a material adverse effect on our

business, financial condition, results of operations and cash flow.

Our refining and marketing unit’ s U.S. operations are subject to Consent Decrees with the Unite d States Environmental

Protection Agency, the United States Department of Justice and the State of Colorado. For a discussion of these Consent

Decrees and the related obligations, see the information under the refining and marketing section of the “Three Year History”

section in this AIF. The company is subject to the risk that fail ure to meet remaining obligations or the deadlines under these

Consent Decrees could have a material impact on our ability to market our products, potentially having a material adverse

effect on our business, financial condition, results of operations and cash flow.

In addition, our business could be materially adversely affected by the potential for lawsuits against greenhouse gas emitters,

based on links drawn between greenhouse gas emissions and climate c hange. See “Industry Conditions – Environmental

Regulation” in this AIF.

Governmental Regulation

. The oil and gas industry in Canada and the United States, including the oil sands industry and our

downstream segments, operates under federal, provincial, state a nd municipal legislation. This industry is also subject to

regulation and intervention by governments in such matters as land tenur e, royalties, taxes (including income taxes),

government fees, production rates, environmental protection controls , the reduction of greenhouse gas and other emissions, the

export of crude oil, natural gas and other products, the awarding or a cquisition of exploration and production, oil sands or

other interests, the imposition of specific drilling obligations, cont rol over the development and abandonment of fields and

mine sites (including restrictions on production) and possibly expropriation or cancellation of contract rights. Before

proceeding with most major projects, including significant changes to exi sting operations, we must obtain regulatory

approvals. The regulatory approval process can involve stakeholder consultat ion, environmental impact assessments and

public hearings, among other things. In addition, regulatory approvals ma y be subject to conditions including security deposit

obligations and other commitments. Failure to obtain regulatory approva ls, or failure to obtain them on a timely basis on

satisfactory terms, could result in delays, abandonment or restruct uring of projects and increased costs, all of which could have

a material adverse effect on our business, financial condition, r esults of operations and cash flow. Such regulations may be

changed from time to time in response to economic or political conditions. The implementation of new regulations or the

modification of existing regulations affecting the crude oil and natur al gas industry could reduce demand for crude oil and

natural gas, increase our costs and have a material adverse effe ct on our business, financial condition, results of operations and

cash flow.

U.S. Policies . The U.S. government has passed legislation that may be inter preted as limiting the purchase of oil and related

refined products by governmental agencies to oil and related refine d products produced from conventional sources, rather than

oil from the oil sands. Although we continue to focus on mitigating our business impact to air, water and land, current and

future U.S. environmental laws, regulations and policies may impact or limit our current business plans and/or reduce demand

for our products. As a result, our business, financial condition, res ults of operations and cash flow could be adversely affected.

Land Claims

. First Nations peoples have claimed aboriginal title and rights to portions of western Canada. In addition, First

Nations peoples have filed claims against industry participants relating in part to land claims, which may affect our business.

However, at the present time, we are unable to assess the ef fect, if any, that these land claims may have on our business.

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- f.mhtAlberta Crown Royalties . The following risk factors could cause royalty expenses to differ materially from current estimates

and impact the royalties payable to the Crown:

• The New Royalty Framework has not yet finalized the measurement and valuation of heat transfers between project

and non- project assets for integrated operators. The final determinat ion of the business rules for heat transfer may

have an impact on future royalties payable to the Crown; and

• Changes in crude oil and natural gas pricing, production volumes, foreign exc hange rates, and capital and operating

costs for each oil sands project; changes to the New Royalty Fra mework by the Government of Alberta; changes in

other legislation; and the occurrence of unexpected events.

See “Industry Conditions – Royalties and Incentives” in this AIF.

Contractual Obligations

. As a result of our reduced capital budget for 2009, we may be unabl e to fulfill all of our obligations

under some of our contractual arrangements which may require us in s ome cases to pay fees or penalties for cancellation of

such contractual arrangements and may result in the company becoming subject to litigation. This in turn, could adversely

affect our business, financial condition, results of operations and cash flow.

4) Strategic Risks – Risks that affect our ability to meet long -term goals and planning initiatives.

Dependence on Oil Sands Business

. Our significant capital commitment to further our growth projec ts at oil sands may

require us to forego investment opportunities in other segments of our ope rations. The completion of future projects to

increase production at oil sands will further increase our dependence on the oil sands segment of our business. For e xample, in

2008, the oil sands business accounted for approximately 86% of our ups tream production (2007 - 87%), 95% of our net

earnings (2007 - 87%) and 86% of our cash flow from operations (2007 - 79%). These percentages have been determined

excluding the corporate and eliminations segment information.

Reclamation. There are risks associated with our ability to complete rec lamation work, specifically reclaiming tailings ponds

which contain water, clay and residual bitumen produced through the ext raction process. To reclaim tailings ponds, we are

using a process referred to as consolidated tailings (“CT”) technology. At this time, no ponds have been fully reclaimed using

this technology. The success of the CT technology and time to recla im the tailings ponds could increase or decrease the current

asset retirement cost estimates. We continue to monitor and ass ess other possible technologies and/or modifications to the

consolidated tailings process now being used. Regulatory approval of our North Steepbank extension of mine is subject to

certain conditions related to the performance of CT technology. Our failure to adequately implement our reclamation plans

could have a material adverse effect on our business, financial co ndition, results of operations and cash flow.

In February 2009, the Energy Resources Conservation Board (“ERCB”) released a directive, Tailings Performance Criteria

and Requirements for Oil Sands Mining Schemes. The directive e stablishes performance criteria for CT operations, a

requirement for specific approval and monitoring of CT ponds, a requir ement for reporting tailings plans, and changes to the

ERCB annual mine plan requirements and approval process to regulate ta ilings operations. We are currently assessing the

impact of the directive.

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- f.mhtInterdependence of Oil Sands Systems

. The oil sands plant is susceptible to loss of production due to the interdependence of its

component systems. Through growth projects, we expect to further mitiga te adverse impacts of interdependent systems and to

reduce the production and cash flow impacts of complete plant- wide shutdowns. For example, we added a second upgrader,

which provides us with the flexibility to conduct periodic plant mainte nance on one operation while continuing production and

cash flow generation from the other. Our inability to sufficient ly manage these risks could have a material adverse effect on our business, financial condition, results of operations and cash flow

.

Need to Replace Conventional Natural Gas Reserves

. Future natural gas reserves and production from our natural gas

business unit are highly dependent on our successful discovery or acquisition of additional reserves and exploitation of our

current reserve base. This has the potential to impact our ability to maintain a price hedge against the growing consumpt ion of

natural gas in our operations. Without natural gas reserve additions through exploration and development or acquisitions, our

conventional natural gas reserves and production will decline over time as reserves are depleted. For example, in 2008, our

average natural gas reservoir decline rate was approximately 24% ( 2007 – 24%). Decline rates will vary with the nature of the

reservoir, life- cycle of the well and other factors. Therefore, historical de cline rates are not necessarily indicative of future

performance. Exploring for, developing and acquiring reserves is highly ca pital intensive. To the extent cash flow from

operations is unable to generate sufficient capital and external sources of capital become limited or unavailable, our ability to

make the necessary capital investments to maintain and expand our conve ntional natural gas reserves could be impaired. In

addition, the long- term performance of the natural gas business is dependent on our abil ity to consistently and competitively

find and develop low-cost, high- quality reserves that can be economically brought on stream. Market demand for land and

services can also increase or decrease finding and development c osts. There can be no assurance that we will be able to find

and develop or acquire additional reserves to replace production at acceptable costs.

Competition

. The petroleum industry is highly competitive in all aspects, includi ng the exploration for, and the development

of, new sources of supply, the acquisition of crude oil and natural ga s interests and the refining, distribution and marketing of

petroleum products and chemicals. We compete in virtually every as pect of our business with other energy companies. The

petroleum industry also competes with other industries in supplying ene rgy, fuel and related products to consumers. We

believe the primary competition for our crude oil production is other North American conventional and synthetic sweet and

sour crude oil producers.

A number of other companies have entered or have indicated their intenti on to enter the oil sands business and begin

producing bitumen and synthetic crude oil or expand their existing opera tions. While this activity has declined with the

corresponding decline in economic conditions, it is expected to resume onc e there is more market certainty. It is difficult to

assess the number, level of production and ultimate timing of all po tential new projects or when existing production levels may

increase. The Canadian Association of Petroleum Producers estim ates that Canada’ s production of bitumen and upgraded

synthetic crude oil could increase from approximately 1.2 million bpd in 20 07 to more than three million bpd by 2020

. Increasing industry consolidation, a global focus on oil sands and additi onal competitors with financial capacity has, over the

past number of years: (a) materially increased the supply of bitum en and synthetic crude oil and other competing crude oil

products in the marketplace; (b) exponentially

Refer to “Non GAAP Financial Measures” on page 6 o f this AIF.

Canadian Association of Petroleum Producers’ Crude Oil Forecast - Interim Update, 11 December 2008

57 6

7

6

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- f.mhtincreased land values and availability of new leases; and (c) pla ced stress on the availability and cost of all resources require d

to build and run new and existing oil sands operations. If we are unabl e to transport our produced crude oil products,

production levels may be adversely affected.

Historically, the industry- wide oversupply of refined petroleum products and the overabundance of retail outlets have kept

downward pressure on downstream refining and retail margins. Manageme nt expects that fluctuations in demand for refined

products, margin volatility and overall marketplace competitiveness will continue. In addition, to the extent that our

downstream business unit participates in new product markets, it could be exposed to margin risk and volatility from either

cost and/or selling price fluctuations.

Labour and Materials Supply. The expansion of the industry up to the third quarter of 2008 and the im pact of new entrants to

the business, had created the potential for risks related to the availability of, and competition for, skilled labour and material s supply. Although these risks were not exclusive to our oil sands opera tion, there were increased demands on the Fort

McMurray, Alberta infrastructure (for example, housing, roads, medical facilities, and schools). With today’ s market

conditions, these risks have not eroded; rather, with layoffs by s ome contractors and the corresponding move away from the

Fort McMurray region by transient workers, there is a risk that we may have difficulty sourcing the required labour for current

and future operations. As well, materials may be in short supply due to smaller labour forces in many manufacturing

operations. Our ability to operate safely and effectively and comp lete all our projects on time and on budget has the potential

to be significantly impacted by these risks. Risks associate d with completion of significant capital projects are discussed i n “Major Projects” above.

Oversupply. In the event that multiple major capital initiatives in the i ndustry proceed simultaneously, there are risks

associated with pipeline capacity and infrastructure which coul d negatively affect our sales mix, and ability to deliver oil sa nds

crudes to Suncor refineries and ultimately crude oil netbacks.

Constraints. Pipeline capacity constraints combined with plant capacity constra ints could negatively impact our ability to

produce at capacity levels in our crude oil and natural gas busines s. See “Industry Conditions - Pipeline Capacity”.

Technology Risk

. There are risks associated with growth and other capital projec ts that rely largely or partly on new

technologies and the incorporation of such technologies into new or ex isting operations, particularly as the results of the

technology in real- world applications may differ from test environments.. The suc cess of projects incorporating new

technologies, such as in-situ technology, cannot be assured.

In

- Situ Recovery

. Current steam-assisted gravity drainage (SAGD) technologies f or in- situ recovery of heavy oil and bitumen

are energy intensive, requiring significant consumption of natural ga s and other fuels in the production of steam which is used

in the recovery process. The amount of steam required in the produc tion process can also vary and impact costs. The

performance of the reservoir can also impact the timing and leve ls of production using this technology. While the technology

is now being used by several producers, commercial application of t his technology is still in the early stages relative to other

methods of production and accordingly, in the absence of and extended opera ting history, there can be no assurances with

respect to the sustainability of SAGD operations.

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- f.mhtReliance on Key Personnel . Our success depends in a large measure on certain key personnel. The loss of the services of such

key personnel could have a material adverse effect on the company. The contributions of the existing management team to the

immediate and near- term operations of the company are likely to continue to be of central importance for the foreseeable

future. In addition, the competition for qualified personnel in the oil and natural gas industry is intense and there can be no

assurance that we will be able to continue to attract and reta in all personnel necessary for the development and operation of our

business.

Labour Relations

. Hourly employees at our oil sands facility near Fort McMurray, A lberta, our London, Ontario terminal

operation, our Sarnia, Ontario refinery, our Commerce City, Col orado refinery and at Sun- Canadian Pipeline Company

Limited are represented by labour unions or employee associations. Any work interruptions involving our employees, and/or

contract trades utilized in our projects or operations, could have a material adverse effect on our business, financial condition,

results of operations and cash flow.

59

DIVIDENDS

Our Board of Directors has established a policy of paying dividends on a quarterly basis. We review our policy from time to

time in light of our financial position, financing requirements for growth, cash flow and other factors which our Board of

Directors considers relevant. Our Board of Directors approved an increase in the quarterly dividend to $0.05 per share* from

$0.04 per share* in the second quarter of 2007, and an increase to $0.04 per share* from $0.03 per share* during the second

quarter of 2006.

The following table sets forth the per share* amount of dividends we pa id to shareholders during the last three years.

* Per share amounts have been adjusted to reflect a two-for-one share split in May 2008.

DESCRIPTION OF CAPITAL STRUCTURE

General Description of Capital Structure

Our authorized capital consists of an unlimited number of common shar es without nominal or par value and an unlimited

number of preferred shares without nominal or par value, issuable in series. As at December 31, 2008, a total of 935,524,213

common shares were issued and outstanding and no preferred shares had be en issued.

Each common share entitles the holder to receive notice of and to att end all meetings of our shareholders, other than meetings

at which only the holders of another class or series are entit led to vote. Each common share entitles the holder to one vote.

The holders of common shares, in the discretion of the Board of Dire ctors, are entitled to receive out of any monies properly

applicable to the payment of dividends, and after the payment of any divid ends payable on preferred shares (if any), of any

series or any other series ranking prior to the common shares as to the payment of dividends, any dividends declared and

payable on the common shares. Upon any liquidation, dissolution or winding

- up of Suncor, or other distribution of our assets

among our shareholders for the purposes of winding- up our affairs, the holders of the common shares are entitled to share on a

share-for- share basis in the distribution, except for the prior rights of the holders of the preferred shares of any series, or any

other class ranking prior to the common shares. There are no pre- emptive or conversion rights, and the common shares are not

subject to redemption. All common shares currently outstanding and to be outstanding upon exercise of outstanding options

are, or will be, fully paid and non-assessable. Year Ended December 31,

2008 2007 2006

Common Shares

cash dividends $0.20 $0.19 $0.15

Dividends paid in common shares

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- f.mhtRatings

Our current long- term debt ratings are A(low) with a Negative Trend by Dominion Bond Rating Service Limited; Baa1 with a

Stable Outlook by Moody’s Investors Service, Inc; and BBB+ with a Ne gative Outlook by Standard & Poor’ s Rating Services,

a division of the McGraw-Hill Companies, Inc.

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- f.mhtDominion Bond Rating Service’s (“DBRS”) credit ratings are on a long

- term debt rating scale that ranges from AAA to D,

which represents the range from highest to lowest quality of such s ecurities rated. A rating of A (low) by DBRS is the third

highest of nine categories and is assigned to debt securities conside red to be of satisfactory credit quality. Protection of interest

and principal is still substantial, but the degree of strength is le ss than with AA rated entities. Entities in the A cate gory may be

more susceptible to adverse economic conditions and have greater cyclical tendencies than higher rated companies. The

assignment of a “(high)” or “(low)” modifier within each rating category indicates relative standing within such category. The

“high” and “low” grades are not used for the AAA category.

Moody’s credit ratings are on a long- term debt rating scale that ranges from AAA to C, which rep resents the range from

highest to lowest quality of such securities rated. A rating of Baa1 by Moody’ s is the fourth highest of nine categories and is

assigned to debt securities which are considered upper-medium grade obligations and are subject to low credit risk. Moody’ s appends numerical modifiers 1, 2 or 3 to each generic rating cl assification. The modifier 1 indicates that the issue ranks i n the

higher end of its generic rating category, the modifier 2 indicates a mid- range ranking and the modifier 3 indicates that the

issue ranks in the lower end of its generic rating category.

Standard and Poor’s (“S&P”) credit ratings are on a long- term debt rating scale that ranges from AAA to D, which repr esents

the range from highest to lowest quality of such securities rate d. A rating of BBB+ by S&P is the fourth highest of eleven

categories and indicates that the obligor is somewhat more suscepti ble to adverse effects of changes in circumstances and

economic conditions than obligors in the higher-rated categories. However , the obligor’ s capacity to meet its financial

commitment on the obligation is still strong. The addition of a plus (+ ) or minus (-) designation after a rating indicates the

relative standing within a particular rating category.

DBRS’s commercial paper credit ratings are on a short-term d ebt rating scale that ranges from R- 1(high) to D, which represent

the range from highest to lowest quality of such securities rat ed. A rating of R- 1(low) by DBRS is the third highest of ten

categories and is assigned to debt securities considered to be of satisfactory credit quality. The overall strength and outlook for

key liquidity, debt, and profitability ratios is not normally as favour able as with higher rating categories, but these

considerations are still respectable, and any qualifying negative f actors that exist are considered manageable, and the entity is

normally of sufficient size to have some influence in its industr y.

The credit ratings accorded to the notes by the rating agencies are not recommendations to purchase, hold or sell the notes

inasmuch as such ratings do not comment as to the market price or suitability for a particular investor. Any rating may not

remain in effect for any given period of time or may be revised or withdrawn entirely by a rating agency in the future if in its

judgment circumstances so warrant.

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- f.mhtMARKET FOR OUR SECURITIES

Price Range and Trading Volume of Common Shares

Our common shares are listed on the Toronto Stock Exchange in Canada, and on the New York Stock Exchange in the United

States.

Prior Sales

In May 2008, the company issued 5.80% Medium Term Notes with a principal amount of $700 million under an outstanding

$2 billion debt shelf prospectus. These notes bear interest at a ra te of 5.80% per annum, which is paid semi- annually, and

mature on May 22, 2018. The net proceeds were added to our general funds t o repay outstanding commercial paper, which

originally funded our working capital needs, sustaining capital expenditur es and growth capital expenditures.

In June 2008, the company issued 6.10% Notes with a principal amount of US $1.25 billion and 6.85% Notes with a principal

amount of US$750 million under an amended US$3.65 billion debt shelf pr ospectus. These notes bear interest at a rate of

6.10% per annum and 6.85% per annum, respectively, which is paid semi- annually, and mature on June 1, 2018, and June 1,

2039, respectively. The net proceeds were added to our general funds, which are used for our Toronto Stock Exchange

2008 Price Range ($Cdn) Trading Volume

High Low (000 ’ s)

January 56.14 40.92 91,478

February 52.10 45.13 54,787

March 54.73 46.11 72,828

April 61.10 47.78 69,135

May 73.10 53.96 77,431

June 71.25 58.75 79,826

July 62.30 51.32 87,330

August 62.37 51.28 64,491

September 57.21 39.61 114,560

October 43.78 21.85 174,816

November 29.89 18.80 121,190

December 28.14 19.90 100,674

New York Stock Exchange

2008 Price Range ($US) Trading Volume

High Low (000 ’ s)

January 56.73 39.67 146,039

February 53.54 44.65 85,771

March 55.54 44.92 111,128

April 60.65 46.31 119,550

May 74.28 52.88 142,737

June 69.94 58.01 109,016

July 61.99 50.80 146,177

August 59.65 49.12 117,861

September 53.95 38.00 194,496

October 41.12 17.83 332,029

November 25.98 14.52 211,059

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- f.mhtworking capital needs, sustaining capital expenditures, growth capit al expenditures and to repay outstanding commercial paper

borrowings.

DIRECTORS AND EXECUTIVE OFFICERS

Directors

The following individuals are directors of Suncor.

63 Name and

Jurisdiction of

Residence Period Served

and Independence Principal Occupations During Past Five Years

Mel E. Benson

Alberta, Canada Director since 2000

Independent Mel Benson is president of Mel E. Benson Management Services

Inc., an international management consulting firm based in Calgary,

Alberta. In 2000, Mr. Benson retired from a major international oil

company. Mr. Benson is a director of Tenax Energy Inc., chair of

Winalta Homes Inc., director of Tarpon Energy Services and direct or of the Fort McKay Group of companies. He is active with several

charitable organizations including Hull Family Services. He is al so a member of the board of governors for the Northern Alberta Institute

of Technology.

Brian A. Canfield

Washington, USA Director since 1995

Independent Brian Canfield is the chairman of TELUS Corporation, a

telecommunications company. Mr. Canfield is a member of the

Order of Canada, a member of the Order of British Columbia, and a fellow of the Institute of Corporate Directors.

Bryan P. Davies

Ontario, Canada Director 1991 to

1996 and since

2000

Independent Bryan Davies is chairman of the Canada Deposit Insurance

Corporation. He is also a director of the General Insurance St atistical

Agency and is past superintendent of the Financial Services

Commission of Ontario. Previously, he was senior vice president,

regulatory affairs with the Royal Bank Financial Group. Mr. Dav ies

is also active with a number of not-for- profit charitable

organizations.

Brian A. Felesky

Alberta, Canada Director since 2002

Independent Brian Felesky is counsel to the law firm of Felesky Flynn LLP i n Calgary, Alberta. Mr. Felesky also serves as a director on th e board

and is chair of the audit committee of Epcor Power LP. He is also a

member of the board of Precision Drilling Trust and Resin Systems

Inc. and various private corporations. Mr. Felesky is co- chair of

Homefront on Domestic Violence, vice chair of the Canada West

Foundation, member of the senate of Athol Murray College of Notre

Dame, board member of the Calgary Stampede Foundation and a

council member of the Alberta Order of Excellence. Mr. Felesky i s a

Queen ’ s Counsel and member of the Order of Canada. (3)(4)

(1)(2)

(3)(4)

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Name and

Jurisdiction of

Residence Period Served

and Independence Principal Occupations During Past Five Years

John T. Ferguson

Alberta, Canada Director since 1995

Independent John Ferguson is founder and chairman of the board of Princeton

Developments Ltd. and Princeton Ventures Ltd. Mr. Ferguson is also

a director of Fountain Tire Ltd., the Royal Bank of Canada and

Strategy Summit Ltd. In addition, he is a director of the C.D. Howe

Institute and the Alberta Bone and Joint Institute, an advisory

member of the Canadian Institute for Advanced Research and

chancellor emeritus and chairman emeritus of the University of

Alberta. Mr. Ferguson is also a fellow of the Alberta Instit ute of

Chartered Accountants and of the Institute of Corporate Director s.

W. Douglas Ford

Florida, USA Director since 2004

Independent W. Douglas Ford was chief executive, refining and marketing for BP

p.l.c. from 1998 to 2002 and was responsible for the refining,

marketing and transportation network of BP as well as the aviation

fuels business, the marine business and BP shipping. Mr. Ford

currently serves as a director of USG Corporation and Air Produ cts

and Chemicals, Inc. He is also a member of the board of trust ees of

the University of Notre Dame.

Richard L. George

Alberta, Canada Director since 1991

Non-independent,

management Richard George is the president and chief executive officer of Suncor

Energy Inc. Mr. George is also a director of the Swiss off shore and

onshore drilling company Transocean. He currently serves as the

Canadian chair of the North American Competitiveness Council and

he chaired the 2008 Governor General’ s Canadian Leadership

Conference. Mr. George was named a member of the Order of

Canada in 2007.

John R. Huff

Texas, USA Director since 1998

Independent John Huff is chairman of Oceaneering International Inc., an oil field

services company. He also serves as director of BJ Services

Company, KBR Inc. and Rowan Companies Inc. Mr. Huff is a

member of the National Petroleum Council, a trustee of the Houst on

Museum of Natural Science and is a director of St. Luke’ s Episcopal

Hospital System in Houston.

M. Ann McCaig

Alberta, Canada Director since 1995

Independent Mrs. McCaig is a trustee of the $400 million Killam Estate, a director

of the Gairdner Foundation, the Chair of the Calgary Health Trust

and the Chair of the Alberta Adolescent Recovery Centre, as wel l as

the Honorary Chair of the Alberta Bone and Joint Institute. She i s a director of the Calgary Stampede Foundation. She is Chancellor

Emeritus at the University of Calgary having served as Chancellor

from 1994 to 1998. Mrs. McCaig has received numerous awards

including an Honorary Doctor of Laws Degree from the University

of Calgary and the University of Alberta, the University of

Saskatchewan Alumni Humanitarian Award, the Queen Elizabeth

Award, the 125 Confederation of Canada Award and the Alberta

Order of Excellence. She is also a member of the Order of C anada. (2)(3)

(1)(2)

(2)(3)

(3)(4)

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- f.mht(1) Audit Committee

(2) Governance Committee

(3) Human Resources and Compensation Committee

(4) Environment, Health & Safety Committee

Corporate Officers

The following individuals are the executive officers of Suncor.

65 Name and

Jurisdiction of

Residence Period Served

and Independence Principal Occupations During Past Five Years

Michael W. O ’ Brien

Alberta, Canada Director since 2002

Independent Michael O ’ Brien served as executive vice president, corporate

development, and chief financial officer of Suncor Energy Inc.

before retiring in 2002. Mr. O’ Brien serves on the board of Shaw

Communications Inc. and is an advisor to CRA International. In

addition, he is past chair of the board of trustees for Nature

Conservancy Canada, past chair of the Canadian Petroleum Products

Institute and past chair of Canada’ s Voluntary Challenge for Global

Climate Change.

Eira M. Thomas

British Columbia, Canada Director since 2006

Independent Eira Thomas assumed the role of executive chairman of Stornoway

Diamond Corporation, a mineral exploration company, on January 1,

2009, after serving as chief executive officer since July 2003.

Previously, Ms. Thomas was president of Navigator Exploration

Corporation and chief executive officer of Stornoway Ventures Ltd.

She is also a director of Strongbow Exploration Inc. and Fortress

Minerals Corp. In addition, Ms. Thomas is a director of the

University of Toronto (U of T) Alumni Association, Lassonde

Advisory Board of the U of T, Prospectors and Developers

Association of Canada and the Northwest Territories and Nunavut

Chamber of Mines. She also is a member of the U of T President’ s Internal Advisory Council.

Name and Jurisdiction of Residence Office

J. KENNETH ALLEY

Alberta, Canada Senior Vice President and Chief Financial Officer

MARLOWE ALLISON

Alberta, Canada Vice President and Treasurer

KIRK BAILEY

Alberta, Canada Executive Vice President, Oil Sands

JOEL CROTEAU

Alberta, Canada Senior Vice President, Natural Gas and In Situ Resources

BART DEMOSKY

Alberta, Canada Senior Vice President, Business Services

RICHARD L. GEORGE

Alberta, Canada President and Chief Executive Officer (1)(2)

(1)(4)

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- f.mhtNotes:

(1) Offices shown are positions held by the officers in relation to bu sinesses of Suncor Energy Inc. and its subsidiaries. On a

legal entity basis, Mr. Little is president of Suncor Energy Ma rketing Inc. and Mr. Thornton is president of Suncor Energy

Products Inc., each of which are Suncor’s Canada- based downstream subsidiaries; and Mr. Nabholz, Ms. Lee and

Mr. Demosky are officers of Suncor Energy Services Inc., which provides major projects management, human resources

and communication, business services and other shared services to th e Suncor group of companies.

(2) This information reflects the positions of officers as at Decem ber 31, 2008.

The percentage of Common Shares of Suncor owned beneficially, direct ly or indirectly, or over which control or direction is

exercised by Suncor’s directors and executive officers, as a group, is less than 1%.

Cease Trade Orders, Bankruptcies, Penalties or Sanctions

To the best of our knowledge, having made due inquiry, we confirm that , as at the date hereof:

(a) in the last ten years, no director or executive officer of Suncor i s or has been a director or officer of another issuer

that, while that person was acting in that capacity:

(i) was the subject of a cease trade or similar order, or an or der that denied the relevant issuer access to any

exemption under Canadian securities legislation for a period of more than 30 consecutive days;

(ii) was subject to an event that resulted, after the director or executive officer ceased to be a director or

executive officer, in the company being the subject of a cease tra de or similar order or an order that denied

the relevant company access to any exemption under securities legis lation, for a period of more than 30

consecutive days; or

(iii) became bankrupt or made a proposal under any legislation relating to bankr uptcy or insolvency or was

subject to or instituted any proceedings, arrangement or compromise wit h creditors or had a receiver,

receiver manager or trustee

66 TERRENCE J. HOPWOOD

Alberta, Canada Senior Vice President and General Counsel

SUE LEE

Alberta, Canada Senior Vice President, Human Resources and Communications

MARK LITTLE

Alberta, Canada Senior Vice President, Strategic Growth and Energy Trading

KEVIN D. NABHOLZ

Alberta, Canada Executive Vice President, Major Projects

JANICE B. ODEGAARD

Alberta, Canada Vice President and Corporate Secretary

JAY THORNTON

Alberta, Canada Executive Vice President, Refining and Marketing

STEVEN W. WILLIAMS

Alberta, Canada Chief Operating Officer Page 73 of 100

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- f.mhtappointed to hold its assets, other than Mr. Ford, a director of S uncor who is currently a director of USG

Corporation, which was in bankruptcy protection until June, 2006, and who wa s also a director of United

Airlines (until February 2006) which was in Chapter 11 bankruptcy protecti on until February, 2006.

(b) no director or executive officer of Suncor has:

(i) been subject to any penalties or sanctions imposed by a court relating to securities legislation or by a

securities regulatory authority or has entered into a settlement agreement with a securities regulatory

authority; or

(ii) has been subject to any other penalties or sanctions imposed by a court or regulatory body that would likely

be considered important to a reasonable investor in making an investm ent decision; and

(c) no director or executive officer of Suncor nor any personal holding comp any controlled by such person has become

bankrupt, made a proposal under any legislation relating to bankruptcy or i nsolvency or become subject to or

instituted any proceedings, arrangement or compromise with credi tors, or had a receiver, receiver manager or trustee

appointed to hold the assets of the director or executive officer.

Conflicts of Interest

No director or executive officer has any direct or indirect mat erial interest in respect of any matter that has material ly affected

or will materially affect Suncor or any of its subsidiaries.

SUNCOR EMPLOYEES

The following table shows the distribution of employees among our thre e business units and corporate office for the past two

years.

Notes:

(1) Corporate employees includes employees from our Major Projects group, which supports all three of our business units.

(2) In addition to our employees, we also use independent contractors t o supply a range of services.

67 as at

December 31,

2008 2007

Oil Sands 3,903 3,575

Natural Gas 198 196

Refining and Marketing 1,112 1,151

Corporate 1,585 1,543

Total 6,798 6,465

(1)

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- f.mhtThe Communications, Energy and Paperworkers Union Local 707 represent a pproximately 2,300 oil sands employees. A new

collective agreement with the union was entered into effective M ay 1, 2007. The terms of the agreement include a wage

increase of 7% in the first year and 6% in each of the follow ing two years, as well as an initial lump sum payment.

Employee associations represent approximately 230 of refining and marke ting’s Sarnia refinery, London terminal and SunCanadian Pipe Line Company employees. In 2008, a four- year agreement that will be renegotiated in 2012 was signed with the

Sarnia employee association. In 2006, a three- year agreement was signed with the Canadian Auto Workers union at the

London terminal, and expires March 1, 2009. In January 2009, management received formal notification from the Union of its

intention to bargain. The agreement with the employee association of Sun- Canadian Pipe Line Company was signed in 1993,

and is renewed automatically each year unless terminated by writ ten notice by either party at least 60 days prior to the

anniversary date of the agreement. No notice has been received or gi ven to date, and management believes the agreement will

be automatically renewed on its anniversary.

The United Steel Workers union represents approximately 250 employees at refining and marketing’ s Denver refining

facilities. In February 2009, the union ratified a 3 year contract which will expire in January 2012.

AUDIT COMMITTEE INFORMATION

Audit Committee Charter

The Audit Committee Charter is attached as Schedule “B” to t his AIF.

Composition of the Audit Committee

The Audit Committee is comprised of Mr. Canfield (Chairman), Mr. Felesky, Mr. Ford, Mr. O’ Brien and Ms. Thomas. All

members are independent and financially literate. The education and expertise of each member is described under the heading

“Directors and Executive Officers”.

For the purpose of making appointments to the Company’ s Audit Committee, and in addition to the independence

requirements, all directors nominated to the Audit Committee mus t meet the test of financial literacy as determined in the

judgment of the board of directors. Also, at least one director so nominated must meet the test of financial expert as

determined in the judgment of the board of directors. The designated fi nancial expert on the Audit Committee is Michael W.

O’Brien.

Financial Literacy

Financial literacy can be generally defined as the ability to rea d and understand a balance sheet, an income statement and a

cash flow statement. In assessing a potential appointee’ s level of financial literacy, the board of directors must e valuate the

totality of the individual’s education and experience including:

• The level of the person’ s accounting or financial education, including whether the person has e arned an advanced

degree in finance or accounting;

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- f.mht• Whether the person is a professional accountant, or the equivalent, in good standing, and the length of time that the

person actively has practised as a professional accountant, or the equivalent;

• Whether the person is certified or otherwise identified as having accounting or financial experience by a recognized

private body that establishes and administers standards in respect of such expertise, whether that person is in good

standing with the recognized private body, and the length of time that t he person has been actively certified or

identified as having this expertise;

• Whether the person has served as a principal financial officer, c ontroller or principal accounting officer of a

corporation that, at the time the person held such position, was r equired to file reports pursuant to securities laws, and

if so, for how long;

• The person’ s specific duties while serving as a public accountant, auditor, principal financial officer, controller,

principal accounting officer or position involving the performance of si milar functions;

• The person’ s level of familiarity and experience with all applicable laws and regulations regarding the preparation of

financial statements that must be included in reports filed under s ecurities laws;

• The level and amount of the person’ s direct experience reviewing, preparing, auditing or analyzing financi al

statements that must be included in reports filed under provisions of securities laws;

• The person’ s past or current membership on one or more audit committees of compa nies that, at the time the person

held such membership, were required to file reports pursuant to provi sions of securities laws;

• The person’ s level of familiarity and experience with the use and analysi s of financial statements of public

companies; and

• Whether the person has any other relevant qualifications or expe rience that would assist him or her in understanding

and evaluating the corporation’ s financial statements and other financial information and to m ake knowledgeable and

thorough inquiries whether:

• The financial statements fairly present the financial conditio n, results of operations and cash flows of the corporation

in accordance with generally accepted accounting principles; and

• The financial statements and other financial information, take n together, fairly present the financial condition, results

of operations and cash flows of the corporation.

Audit Committee Financial Expert

An “Audit Committee Financial Expert” means a person who, in the judgment of the corporation’ s board of directors, has the

following attributes:

a. an understanding of Canadian generally accepted accounting principles and f inancial statements;

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- f.mhtb. the ability to assess the general application of such principles in connection with the accounting for estimates,

accruals, and reserves;

c. experience preparing, auditing or analyzing or evaluating financial s tatements that present a breadth and level of

complexity of accounting issues that are generally comparable to the breadth and complexity of issues that can

reasonably be expected to be raised by Suncor’ s financial statements, or experience actively supervising one or more persons engaged in such activities;

d. an understanding of internal controls and procedures for financial repor ting; and

e. an understanding of audit committee functions.

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

a. education and experience as a principal financial officer, principal accounting officer, controller, public accountant or

auditor or experience in one or more positions that involve the performa nce of similar functions;

b. experience actively supervising a principal financial officer, pr incipal accounting officer, controller, public

accountant, auditor or person performing similar functions;

c. experience overseeing or assessing the performance of companies or public accountants with respect to the

preparation, auditing or evaluation of financial statements; or

d. other relevant experience.

Audit Committee Pre-Approval Policies for Non Audit Ser vices

Our Audit Committee has considered whether the provision of service s other than audit services is compatible with

maintaining the auditors’ independence and has a policy governing the provision of these services. A c opy of our policy

relating to Audit Committee approval of fees paid to our auditors , in compliance with the Sarbanes Oxley Act of 2002, is

attached as Schedule “A” to this AIF.

Fees Paid to Auditors

Fees payable to PricewaterhouseCoopers LLP in 2008 and 2007 are deta iled below:

Prior year numbers have been restated to conform with current year presentation.

The nature of each category of fees is described below.

70

Audit Fees

Audit fees were paid for professional services rendered by the aud itors for the audit of Suncor’ s annual financial statements or

services provided in connection with statutory and regulatory filings or engagements. ($) 2008 2007

Audit Fees 1,600,000 1,158,000

Audit

- Related Fees 442,000 431,000

Tax Fees 7,000 2,000

All other Fees 13,000

-

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- f.mhtAudit-Related Fees

Audit- related fees were paid for professional services rendered by the auditors for preparation of reports on specified

procedures as they relate to joint venture audits and attest servic es not required by statute or regulation.

Tax Fees

Tax fees were paid for international tax planning, advice and compl iance.

All Other Fees

Fees disclosed under “All Other Fees” were paid for subscript ions to auditor-provided and supported tools.

None of the services described under the captions “Audit-related Fe es”, “Tax Fees” and “All Other Fees” were approved by

the Audit Committee pursuant to paragraph (c)(7)(i)(C) of Rule 2- 01 of Regulation S-X.

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

There are no legal proceedings to which we are a party or of which any of our property is the subject, nor are there any

proceedings known by us to be contemplated that involves a claim for damages exceeding 10% of our current assets. In

addition, there have not been any (a) penalties or sanctions imposed against the company by a court relating to securities

legislation or by a securities regulatory authority during your financi al year, (b) penalties or sanctions imposed by a court or

regulatory body against the company that would likely be considered import ant to a reasonable investor in making an

investment decision, or (c) settlement agreements entered into by the company before a court relating to securities legisl ation

or with a securities regulatory authority during your financial year

.

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANS ACTIONS

No director, executive officer, or holder of 10% or more of our secur ities or any associate or affiliate of these persons has, or

has had, any material interest in any transaction or any proposed tra nsaction that has materially affected or will materially

affect us or any of our affiliates, within the three most rec ently completed financial years or during the current financial ye ar.

TRANSFER AGENT AND REGISTRAR

The transfer agent and registrar for our common shares is Comput ershare Trust Company of Canada at its principal offices in

Calgary, Montreal, Toronto and Vancouver and Computershare Trust Company I nc. in Denver, Colorado.

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- f.mhtMATERIAL CONTRACTS

During the year ended December 31, 2008, we have not entered into any c ontracts, nor are there any contracts still in effect,

that are material to our business, other than contracts entered into in the ordinary course of business, the Shareholder Rights

Plan dated April 24, 2008 and the Royalty Amending Agreement dated Janua ry 29, 2008 between Suncor and Her Majesty the

Queen in Right of Alberta.

INTERESTS OF EXPERTS

There is no person or company whose profession or business gives authori ty to a statement made by such person or company

and who is named as having prepared or certified a report, valuation, s tatement or opinion described or included in a filing, or

referred to in a filing, made under National Instrument 51- 102 by Suncor during, or related to our most recently completed

financial year other than GLJ, Suncor’ s Independent Reserve Engineering Evaluators and PricewaterhouseCooper s LLP,

Suncor’ s auditors. As at the date hereof, none of the principals of GLJ as a group, directly or indirectly, owned more than 1%

of our common shares, including the securities of our associates and af filiates, and PricewaterhouseCoopers LLP has advised

Suncor’ s Audit Committee that they are independent with respect to Sunc or within the meaning of the Rules of Professional

Conduct of the Institute of Chartered Accountants of Alberta.

DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NEW YORK STOCK EXCHANGE

As a Canadian issuer listed on the New York Stock Exchange (the “N YSE”), we are not required to comply with most of the

NYSE rules and listing standards and instead may comply with domest ic requirements. As a foreign private issuer, we are only

required to comply with three of the NYSE rules (i) have an audit committee that satisfies the requirements of the United

States Securities Exchange Act of 1934 ; (ii) the Chief Executive Officer must promptly notify the N YSE in writing after an

executive officer becomes aware of any material non- compliance with the applicable NYSE Rules; and (iii) provide a brief

description of any significant differences between our corporate governan ce practices and those followed by U.S. companies

listed under the NYSE. The company has disclosed in the corporate go vernance section of its website at www.suncor.com that

it, in certain instances, it is not required to obtain share holder approval for material amendments to equity compensation plans

and that Suncor, while in compliance with the independence requirements of applicable securities laws in Canada (specifically

National Instrument 52-110 Audit Committees ) and the U.S. (specifically Rule 10A-3 of the Securities Exchange Act of 1934 ),

it has not adopted the director independence standards contained in Sec tion 303A.02 of the NYSE’ s Listed Company Manual.

Except as described, the company is in compliance with the NYSE c orporate governance standards in all other significant

respects.

ADDITIONAL INFORMATION

Additional information, including directors’ and officers’ remuneration and indebtedness, principal holders of our securities,

securities authorized for issuance under equity compensation plans and interests of insiders in material transactions, where

applicable, is contained in our most recent management proxy circular for our most recent annual meeting of our shareholders

that involved the election of directors. Additional financial infor mation is provided in our 2008 Consolidated Financial

Statements and MD&A.

Further information about Suncor, filed with Canadian securities commissions and the United States Securities and Exchange

Commission (SEC), including periodic quarterly and annual

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- f.mhtreports and the Annual Information Form (AIF/40- F) is available online at www.sedar.com and www.sec.gov. In addition, our

Standards of Business Conduct Code is available online at www.sunc or.com . Information contained in or otherwise accessible

through our website does not form part of this AIF, and is not incor porated into the AIF by reference.

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- f.mhtSCHEDULE “A”

***Approved and Accepted April 28, 2004***

SUNCOR ENERGY INC.

POLICY AND PROCEDURES FOR PRE-APPROVAL OF AUDIT

AND NON-AUDIT SERVICES

Pursuant to the Sarbanes-Oxley Act of 2002 and Multilateral Instrum ent 52- 110, the Securities and Exchange Commission and

the Ontario Securities Commission respectively has adopted fin al rules relating to audit committees and auditor independence.

These rules require the Audit Committee of Suncor Energy Inc (“S uncor”) to be responsible for the appointment,

compensation, retention and oversight of the work of its independent auditor. The Audit Committee must also pre- approve any audit and non-audit services performed by the independent auditor or suc h services must be entered into pursuant to preapproval policies and procedures established by the Audit Committee pur suant to this policy.

I. STATEMENT OF POLICY

The Audit Committee has adopted this Policy and Procedures for Pre -Approval of Audit and Non- Audit Services (the

“Policy”), which sets forth the procedures and the conditions pursuant to which servic es proposed to be performed by the

independent auditor will be pre-approved. The procedures outlined in this Policy are applicable to all Audit, Audit- Related,

Tax Services and All Other Services provided by the independent auditor

.

II. RESPONSIBILITY

Responsibility for the implementation of this Policy rests with the Audit Committee. The Audit Committee delegates its

responsibility for administration of this policy to management. The Audit Committee shall not delegate its responsibilities to

pre-approve services performed by the independent auditor to management.

III. DEFINITIONS

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

a) “Audit services” include services that are a necessary part of the annual audit process and any activity that is a

necessary procedure used by the auditor in reaching an opinion on the financial statements as is required under

generally accepted auditing standards (“GAAS”), including technical reviews to reach audit judgment on accounting

standards;

The term “audit services” is broader than those services strictly required to perform an audi t pursuant to GAAS and

include such services as:

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- f.mhtii) the performance of domestic and foreign statutory audits;

iii) Attest services required by statute or regulation;

iv) Internal control reviews; and

v) Assistance with and review of documents filed with the Canadia n Securities administrators, the Securities

and Exchange Commission and other regulators having jurisdiction over Suncor a nd its subsidiaries, and

responding to comments from such regulators;

b) “Audit-related services” are assurance (e.g. due diligence services) and related service s traditionally performed by the

external auditors and that are reasonably related to the performance of the audit or review of financial statements and

not categorized under “audit fees” for disclosure purposes.

“Audit-related services” include:

i) employee benefit plan audits, including audits of employee pension plans;

ii) due diligence related to mergers and acquisitions;

iii) consultations and audits in connection with acquisitions, including eva luating the accounting treatment for

proposed transactions;

iv) internal control reviews;

v) attest services not required by statute or regulation; and

vi) consultations regarding financial accounting and reporting standards;

Non-financial operational audits are not “audit-related” services ;

c) “Tax services” include but are not limited to services related to the prepara tion of corporate and/or personal tax

filings, tax due diligence as it pertains to mergers, acquisiti ons and/or divestitures and tax planning;

d) “All other services” consist of any other work that is neither an Audit service, nor an Audit- Related service nor a Tax

service, the provision of which by the independent auditor is not exp ressly prohibited by Rule 2- 01(c)(7) of

Regulation S- X under the Securities and Exchange Act of 1934, as amended. (See A ppendix A for a summary of the

prohibited services.)

IV. GENERAL POLICY

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

• All services to be provided by the independent auditor will require sp ecific pre- approval by the Audit Committee.

The Audit Committee will not approve engaging the independent auditor f or services which can reasonably be

classified as “tax services” or “all other services” unless a compelling business case can be

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- f.mhtmade for retaining the independent auditor instead of another service provider.

• The Audit Committee will not provide pre- approval for services to be provided in excess of twelve months fr om the

date of the pre-approval, unless the Audit Committee specifically provides for a different period.

• The Audit Committee has delegated authority to pre- approve services with an estimated cost not exceeding $100,000

in accordance with this Policy to the Chairman of the Audit Commit tee. The delegate member of the Audit

Committee must report any pre-approval decision to the Audit Commit tee at its next meeting.

• The Chairman of the Audit Committee may delegate his authority to pre- approve services to another sitting member

of the Audit Committee provided that the recipient has also been delegated the authority to act as Chairman of the

Audit Committee in the Chairman’ s absence. A resolution of the Audit Committee is required to evidence the

Chairman’s delegation of authority to another Audit Committee membe r under this policy.

• The Audit Committee will, from time to time, but no less than annually, review and pre- approve the services that may

be provided by the independent auditor.

• The Audit Committee must establish pre- approval fee levels for services provided by the independent auditor on an

annual basis. On at least a quarterly basis, the Audit Commi ttee will be provided with a detailed summary of fees

paid to the independent auditor and the nature of the services provided and a forecast of fees and services that are

expected to be provided during the remainder of the fiscal year.

• The Audit Committee will not approve engaging the independent auditor to provide any prohibited non- audit services

as set forth in Appendix A.

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

follows:

a) In situations where the Chairman of the Audit Committee pre- approves work under his delegation of

authority, the Chairman will evidence his pre-approval by signing and dati ng the pre- approval request form,

attached as Appendix B. If it is not practicable for the Cha irman to complete the form and transmit it to the

Company prior to engagement of the independent audit, the Chairman may provide verbal or email approval

of the engagement, followed up by completion of the request form at the fi rst practical opportunity.

b) In all other situations, a resolution of the Audit Committee is r equired.

• All audit and non- audit services to be provided by the independent auditors shall be provided pur suant to an

engagement letter that shall:

a) be in writing and signed by the auditors

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- f.mhtb) specify the particular services to be provided

c) specify the period in which the services will be performed

d) specify the estimated total fees to be paid, which shall not exc eed the estimated total fees approved by the

Audit Committee pursuant to these procedures, prior to application of the 10% overrun.

e) include a confirmation by the auditors that the services are not within a category of services the provision of

which would impair their independence under applicable law and Canadi an and U.S. generally accepted

accounting standards.

• The Audit Committee pre- approval permits an overrun of fees pertaining to a particular engagem ent of no greater

than 10% of the estimate identified in the associated engagement l etter. The intent of the overrun authorization is to

ensure on an interim basis only, that services can continue pending a review of the fee estimate and if required,

further Audit Committee approval of the overrun. If an overrun is e xpected to exceed the 10% threshold, as soon as

the overrun is identified, the Audit Committee or its designat e must be notified and an additional pre- approval

obtained prior to the engagement continuing.

V. RESPONSIBILITIES OF EXTERNAL AUDITORS

To support the independence process, the independent auditors will:

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

b) Satisfy the Audit Committee that they have in place comprehensive i nternal policies and processes to ensure

adherence, world-wide, to independence requirements, including robust moni toring and communications;

c) Provide communication and confirmation to the Audit Committee regardi ng independence on at least a quarterly

basis;

d) Maintain registration by the Canadian Public Accountability Board a nd the U.S. Public Company Accounting

Oversight Board;

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

In addition, the external auditors will:

a) Provide regular, detailed fee reporting including balances in the “ Work in Progress” account;

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

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- f.mhtVI. DISCLOSURES

Suncor will, as required by applicable law, annually disclose its pre- approval policies and procedures, and will provide the

required disclosure concerning the amounts of audit fees, audit- related fees, tax fees and all other fees paid to its outside

auditors in its filings with the SEC.

* * *

A-5

Appendix A

Prohibited Non-Audit Services

An external auditor is not independent if, at any point during the audi t and professional engagement period, the auditor

provides the following non-audit services to an audit client.

Bookkeeping or other services related to the accounting records or f inancial statements of the audit client. Any service,

unless it is reasonable to conclude that the results of these s ervices will not be subject to audit procedures during an audit of

Suncor’s financial statements, including:

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

• Preparing Suncor’s financial statements that are filed with t he Securities and Exchange Commission (“SEC”) or that

form the basis of financial statements filed with the SEC; or

• Preparing or originating source data underlying Suncor’s financial stat ements.

Financial information systems design and implementation. Any service, unless it is reasonable to conclude that the res ults of

these services will not be subject to audit procedures during an audit of Suncor’s financial statements, including:

• Directly or indirectly operating, or supervising the operation of, Suncor’s information system or managing Suncor’ s

local area network; or

• Designing or implementing a hardware or software system that aggr egates source data underlying the financial

statements or generates information that is significant to Sunc or’ s financial statements or other financial information

systems taken as a whole.

Appraisal or valuation services, fairness opinions or contribution -in-kind reports. Any appraisal service, valuation service or

any service involving a fairness opinion or contribution-in- kind report for Suncor, unless it is reasonable to conclude that the

results of these services will not be subject to audit procedur es during an audit of Suncor’s financial statements.

Actuarial services. Any actuarially- oriented advisory service involving the determination of amounts recorde d in the financial

statements and related accounts for Suncor other than assisting Suncor in understanding the methods, models, assumptions,

and inputs used in computing an amount, unless it is reasonable to conc lude that the results of these services will not be

subject to audit procedures during an audit of Suncor’s financial stat ements.

Internal audit outsourcing services. Any internal audit service that has been outsourced by Suncor that relates to Suncor’ s internal accounting controls, financial systems, or financial st atements, unless it is reasonable to conclude that the result of

these services will not be subject to audit procedures during an audit of Suncor’s financial statements.

Management functions. Acting, temporarily or permanently, as a director, officer, or employee of Suncor, or performing any

decision-making, supervisory, or ongoing monitoring function for Suncor.

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- f.mhtHuman resources.

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

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

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

• Acting as a negotiator on Suncor’ s behalf, such as determining position, status or title, compensa tion, fringe benefits,

or other conditions of employment; or

• Recommending, or advising Suncor to hire a specific candidate for a s pecific job (except that an accounting firm may,

upon request by Suncor, interview candidates and advise Suncor on the c andidate’ s competence for financial

accounting, administrative, or control positions.)

Broker -dealer, investment adviser or investment banking services. Acting as a broker- dealer (registered or unregistered),

promoter, or underwriter, on behalf of Suncor, making investment decisi ons on behalf of Suncor or otherwise having

discretionary authority over Suncor’s investments, executing a tr ansaction to buy or sell Suncor’ s investment, or having

custody of Suncor’s assets, such as taking temporary possession of s ecurities purchased by Suncor.

Legal services. Providing any service to Suncor that, under circumstances in whic h the service is provided, could be provided

only by someone licensed, admitted, or otherwise qualified to pract ice law in the jurisdiction in which the service is prohibited.

Expert services unrelated to the audit. Providing an expert opinion or other expert service for Suncor, or Sunc or’ s legal

representative, for the purpose of advocating Suncor’ s interest in litigation or in a regulatory or administrative proce eding or

investigation. In any litigation or regulatory or administrative proceeding or investigation, an accountant’ s independence shall

not be deemed to be impaired if the accountant provides factual accounts, including testimony, of work performed or explains

the positions taken or conclusions reached during the performance of a ny service provided by the accountant for Suncor.

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- f.mhtAppendix B

Pre-approval Request Form

A-8 NATURE OF WORK ESTIMATED FEES

(Cdn $)

Total

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- f.mhtSCHEDULE “B”

AUDIT COMMITTEE CHARTER

The Audit Committee

The by-laws of Suncor Energy Inc. provide that the Board of Direct ors may establish Board committees to whom certain

duties may be delegated by the Board. The Board has established, among others, the Audit Committee, and has approved this

mandate, which sets out the objectives, functions and responsibilitie s of the Audit Committee.

Objectives

The Audit Committee assists the Board of Directors by:

• monitoring the effectiveness and integrity of the Corporation’ s financial reporting systems, management information

systems and internal control systems, and by monitoring financial rep orts and other financial matters.

• selecting, monitoring and reviewing the independence and effectivenes s of, and where appropriate replacing, subject to

shareholder approval as required by law, external auditors, and ensurin g that external auditors are ultimately accountable

to the Board of Directors and to the shareholders of the Corporati on.

• reviewing the effectiveness of the internal auditors, excludi ng the Operations Integrity Audit department which is

specifically within the mandate of the Environment, Health & Safe ty Committee (references throughout this mandate to

“Internal Audit” shall not include the Operations Integrity Audi t department); and

• approving on behalf of the Board of Directors certain financial matte rs as delegated by the Board, include the matters

outlined in this mandate.

The Committee does not have decision- making authority, except in the very limited circumstances describe d herein or where

and to the extent that such authority is expressly delegated by the Board of Directors. The Committee conveys its findings and

recommendations to the Board of Directors for consideration and, whe re required, decision by the Board of Directors.

Constitution

The Terms of Reference of Suncor’ s Board of Directors set out requirements for the composition of Board Committees and the

qualifications for Committee membership, and specify that the chair and membership of the Committees are determined

annually by the Board. As required by Suncor’s by- laws, unless otherwise determined by resolution of the board of di rectors,

a majority of the members of a committee constitute a quorum for m eetings of committees, and in all other respects, each

committee determines its own rules of procedure.

Functions and Responsibilities

The Committee has the following functions and responsibilities: Page 88 of 100

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1. Enquire as to the adequacy of the Corporation’ s system of internal controls, and review the evaluation of inter nal

controls by Internal Auditors, and the evaluation of financial and internal controls by external auditors.

2. Review management’s monitoring of compliance with the Corporat ion’s Code of Business Conduct.

3. Establish procedures for the confidential submission by employees of c omplaints relating to any concerns with

accounting, internal control, auditing or Standards of Business Conduct Code matters, and periodically review a

summary of complaints and their related resolution.

4. Review the findings of any significant examination by regulatory agencie s concerning the Corporation’ s financial

matters.

5. Periodically review management’ s governance processes for information technology resources, to asse ss their

effectiveness in addressing the integrity, the protection and the se curity of the Corporation’ s electronic information

systems and records.

6. Review the management practices in effect over officers’ expenses and perquisites.

External and Internal Auditors

7. Evaluate the performance of the external auditors and initiate and a pprove the engagement or termination of the

external auditors, subject to shareholder approval as required by applica ble law.

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

9. Review any relationships or services that may impact the objectivi ty and independence of the external auditor,

including annual review of the auditor’ s written statement of all relationships between the auditor ( including its

affiliates) and the Corporation; review and approve all engagem ents for non- audit services to be provided by external

auditors or their affiliates.

10. Review the external auditor’ s quality control procedures including any material issues raised by the most recent

quality control review or peer review and any issues raised by a governm ent authority or professional authority

investigation of the external auditor, providing details on actions taken by the firm to address such issues.

11. Review and approve the appointment or termination of the Director, Int ernal Audit, and annually review a summary

of the remuneration and performance of the Director, Internal A udit.

12. Review the Internal Audit Department Charter, and the plans, activities, organisational structure and qualifications of

the Internal Auditors, and monitor the department’s performance and independence.

13. Provide an open avenue of communication between management, the Inte rnal Auditors or the external auditors, and

the Board of Directors.

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- f.mhtFinancial Reporting and other Public Disclosure

14. Review external auditor’s management comment letter and managem ent’ s responses thereto, and enquire as to any

disagreements between management and external auditors or restri ctions imposed by management on external

auditors. Review any unadjusted differences brought to the attention of management by the external auditor and the

resolution of same.

15. Review with management and external auditors the financial materi als and other disclosure documents referred to in

paragraph 16, including any significant financial reporting issues, the presentation and impact of significant risks and

uncertainties, and key estimates and judgements of management that may be material to financial reporting including

alternative treatments and their impacts.

16. Review and approve the Corporation’s interim consolidated financial statements and accompanying management’ s discussion and analysis (“MD&A”). Review and make recommendations to the Board of Directors on approval of

the Corporation’s annual audited financial statements and MD&A, Annual Information Form and Form 40- F.

Review other material annual and quarterly disclosure documents or regulatory filings containing or accompanying

audited or unaudited financial information.

17. Review and approve the Corporation’ s policy on external communication and disclosure of material informa tion,

including the form and generic content of any quarterly earnings guidance and of any financial disclosure provided to

investment analysts and rating agencies.

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

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

Oil and Gas Reserves

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

(A) the disclosure in accordance with applicable law of information with respect to Suncor’ s oil and gas

activities including procedures for complying with applicable disclosur e requirements;

(B) providing information to the qualified reserves evaluators (“Evaluator s”) engaged annually by Suncor to

evaluate Suncor’ s reserves data for the purpose of public disclosure of such data in accordance with

applicable law.

21. Annually approve the appointment and terms of engagement of the company’ s Evaluator, including the qualifications

and independence of the Evaluator; Review and approve any proposed change in the appointment of the Evaluator,

and the reasons for such proposed change including whether there have been disputes between the Evaluator and the

Company’s management.

22. Annually review Suncor’ s reserves data and the report of the Evaluator thereon; Annually review and make

recommendations to the Board of Directors on the approval of (i) the content and filing by the Company of a

statement of reserves data

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- f.mht(“Statement”) and report of management and the directors thereon to be included in or fi led with the Statement, and

(ii) the filing of the report of the Evaluator to be included i n or filed with the Statement, all in accordance with

applicable law.

Risk Management

23. Periodically review the policies and practices of the Corporation r especting cash management, financial derivatives,

financing, credit, insurance, taxation, commodities trading and re lated matters. Oversee the Board’ s risk management

governance model by conducting periodic reviews with the objective of a ppropriately reflecting the principal risks of

the Corporation’s business in the mandate of the Board and its com mittees.

Pension Plan

24. Review the assets, financial performance, funding status, invest ment strategy and actuarial reports of the

Corporation’s pension plan including the terms of engagement of the pl an’s actuary and fund manager.

Security

25. Review on a summary basis any significant physical security mana gement, IT security or business recovery risks and

strategies to address such risks.

Other Matters

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

27. Review any recommended appointees to the office of Chief Financial Officer. Review and/or approve other financial

matters delegated specifically to it by the Board of Directors

.

Reporting to the Board

28. Report to the Board of Directors on the activities of the Committ ee with respect to the foregoing matters as required

at each Board meeting and at any other time deemed appropriate by the Committee or upon request of the Board of

Directors.

As adopted by resolution of the Board of Directors.

Revision Dated February 25, 2009

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FORM 51-101F3

REPORT OF MANAGEMENT AND DIRECTORS

ON OIL AND GAS DISCLOSURE

Management of Suncor Energy Inc. (the “Company”) are responsible for the preparation and disclosure of informati on with

respect to the Company’ s oil and gas activities in accordance with securities regula tory requirements. This information

includes reserves data which are estimates of proved reserves and probable reserves and related future net revenue as at

December 31, 2008, estimated using forecast prices and costs.

An independent qualified reserves evaluator has evaluated the Company’ s reserves data. The report of the independent

qualified reserves evaluator is presented below.

The Audit Committee of the board of directors of the Company has:

(a) reviewed the Company’ s procedures for providing information to the independent qualified reserv es

evaluator;

(b) met with the independent qualified reserves evaluator to determine whether any restrictions affected the

ability of the independent qualified reserves evaluator to report wi thout reservation; and

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

The Audit Committee of the board of directors has reviewed the Com pany’ s procedures for assembling and reporting other

information associated with oil and gas activities and has revie wed that information with management. The board of directors

has, on the recommendation of the Audit Committee, approved:

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

other oil and gas information;

(b) the filing of Form 51- 101F2 which is the report of the independent qualified reserves Evaluat or on the

reserves data; and

(c) the content and filing of this report.

Because the reserves data are based on judgements regarding fut ure events, actual results will vary and the variations may be

material. However, any variations should be consistent with the fa ct that reserves are categorized according to the probability

of their recovery. Page 92 of 100

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- f.mht“RICHARD L. GEORGE”

RICHARD L. GEORGE

President and Chief Executive Officer

“J. KENNETH ALLEY”

J. KENNETH ALLEY

Senior Vice President and Chief Financial Officer

“JOHN T. FERGUSON”

JOHN T. FERGUSON

Chairman of the Board of Directors

“BRIAN A. CANFIELD”

BRIAN A. CANFIELD

Chairman of the Audit Committee

March 2, 2009

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- f.mhtSCHEDULE “D”

FORM 51-101F2

REPORT ON RESERVES DATA

BY

INDEPENDENT QUALIFIED RESERVES

EVALUATOR

Report on Reserves Data

To the board of directors of Suncor Energy Inc. (the “Company”):

1. We have prepared an evaluation of the Company’ s reserves data as at December 31, 2008. The reserves data ar e estimates

of proved reserves and probable reserves and related future net revenue as at December 31, 2008, estimated using forecast

prices and costs.

2. The reserves data are the responsibility of the Company’ s management. Our responsibility is to express an opinion on the

reserves data based on our evaluation.

We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the

“COGE Handbook”) prepared jointly by the Society of Petroleum Evaluation Engineers (Calga ry Chapter) and the Canadian

Institute of Mining, Metallurgy & Petroleum (Petroleum Society).

3. Those standards require that we plan and perform an evaluation to obta in reasonable assurance as to whether the reserves

data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with

principles and definitions presented in the COGE Handbook.

4. The following table sets forth the estimated future net revenue (before deduction of income taxes) attributed to proved plus

probable reserves, estimated using forecast prices and costs a nd calculated using a discount rate of 10 percent, included in the

reserves data of the Company evaluated by us for the year ended Dece mber 31, 2008, and identifies the respective portions

thereof that we have evaluated and reported on to the Company’s manage ment and Board of Directors:

5. In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are in

accordance with the COGE Handbook.

6. We have no responsibility to update our reports referred to in parag raph 4 for events and circumstances occurring after their

respective preparation dates. Independent

Qualified Reserves

Evaluator Description and

Preparation

Date of

Evaluation

Report Location of

Reserves

(Country or

Foreign

Geographic

Area) Net Present Value of Future Net Revenue

(before income taxes, 10% discount rate, million

dollars)

Audited Evaluated Reviewed Total

GLJ Petroleum

Consultants February 6,

2009 Canada

- 53,484 101 53,585 Page 94 of 100

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- f.mht7. Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be

material. However, any variations should be consistent with the fa ct that reserves are categorized according to the probability

of their recovery.

Executed as to our report referred to above:

GLJ Petroleum Consultants Ltd., Calgary, Alberta, Canada,

ORIGINALLY SIGNED BY

James H. Willmon, P. Eng.

Vice-President

Calgary, Alberta, Canada

February 6, 2009

D-2

UNDERTAKING AND CONSENT TO SERVICE OF PROCESS

A. Undertaking

Suncor Energy Inc. (the "Registrant") undertakes to make available, in person or by telephone, representatives to respond

to inquiries made by the staff of the Securities and Exchange Comm ission ("SEC"), and to furnish promptly, when requested

to do so by the SEC staff, information relating to the securitie s in relation to which the obligation to file an annual report on

Form 40-F arises, or transactions in said securities.

B. Consent to Service of Process

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

DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CON TROL OVER

FINANCIAL REPORTING

See pages 43 and 44 of Exhibit 99-1 and page 26 of Exhibit 99-2

.

AUDIT COMMITTEE FINANCIAL EXPERT

See pages 69 and 70 of Annual Information Form.

CODE OF ETHICS

See page 72 of Annual Information Form.

FEES PAID TO PRINCIPAL ACCOUNTANT

See page 70 of Annual Information Form.

AUDIT COMMITTEE PRE-APPROVAL POLICIES Page 95 of 100

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- f.mhtSee Schedule "A" of Annual Information Form.

APPROVAL OF NON-AUDIT SERVICES

See Schedule "A" of Annual Information Form.

OFF-BALANCE SHEET ARRANGEMENTS

See page 77 of Exhibit 99-2. Page 96 of 100

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- f.mhtTABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS

See page 13 of Exhibit 99-2.

IDENTIFICATION OF THE AUDIT COMMITTEE

See page 68 of Annual Information Form. Page 97 of 100

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- f.mhtSIGNATURES

Pursuant to the requirements of the Exchange Act, the r egistrant certifies that it meets all of the requirements for filing on

Form 40-F and has duly caused this annual report to be signed on its beh alf by the undersigned, thereto duly authorized.

SUNCOR ENERGY INC.

DATE: March 2, 2009 PER: /s/ "J. Kenneth Alley"

J. KENNETH ALLEY

Senior Vice President and Chief Financial Officer Page 98 of 100

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- f.mhtEXHIBIT INDEX

Exhibit No. Description

99

- 1 Audited Consolidated Financial Statements of Suncor Energy Inc. for t he fiscal year ended December 31, 2008,

including reconciliation to U.S. GAAP (Note 20)

99

- 2 Management's Discussion and Analysis for the fiscal year ended December 31, 2008, dated February 25, 2009

99

- 3 Consent of PricewaterhouseCoopers LLP

99

- 4 Consent of GLJ Petroleum Consultants Ltd.

99

- 5 Certificate of President and Chief Executive Officer Pursuant to Exchange Act Rules 13a

- 14(a) or 15d

- 14(a)

99-6 Certificate of Senior Vice President and Chief Financial Off icer Pursuant to Exchange Act Rules 13a-14(a)

or 15d

- 14(a)

99-7 Certificate of the President and Chief Executive Officer Pu rsuant to 18 U.S.C. Section 1350, as Enacted Pursuant

to Section 906 of the Sarbanes

- Oxley Act of 2002

99-8 Certificate of the Senior Vice President and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as

Enacted Pursuant to Section 906 of the Sarbanes

- Oxley Act of 2002 Page 99 of 100

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UNDERTAKING AND CONSENT TO SERVICE OF PROCESS

DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CON TROL OVER FINANCIAL REPORTING

AUDIT COMMITTEE FINANCIAL EXPERT

CODE OF ETHICS

FEES PAID TO PRINCIPAL ACCOUNTANT

AUDIT COMMITTEE PRE

- APPROVAL POLICIES

APPROVAL OF NON

- AUDIT SERVICES

OFF

- BALANCE SHEET ARRANGEMENTS

TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS

IDENTIFICATION OF THE AUDIT COMMITTEE

SIGNATURES

EXHIBIT INDEX Page 100 of 100

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