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Washington, D.C. 20549


(Check One)



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



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


For fiscal year ended:
Commission File Number:

  December 31, 2014
No. 1-12384

(Exact name of registrant as specified in its charter)

(Province or other
jurisdiction of incorporation
or organization)

(Primary standard industrial
classification code number,
if applicable)
(I.R.S. employer
identification number, if

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

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

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

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


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


Title of each class:

  Name of each exchange on which

Common shares


New York Stock Exchange

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


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


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



  Annual Information Form   ý   Annual Audited Financial Statements

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


Common Shares

  As of December 31, 2014 there were
1,444,119,940 Common Shares issued and

Preferred Shares



        Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 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.


  ý   No   o

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


  o   No   o


        The Registrant's Annual Information Form dated February 26, 2015, included in this annual report on Form 40-F, and Audited Consolidated Financial Statements and Management's Discussion and Analysis for the year ended December 31, 2014, included as Exhibit 99-1 and Exhibit 99-2, respectively, to this annual report on Form 40-F, are incorporated by reference into and as an exhibit to, as applicable, each of the Registrant's Registration Statements under the Securities Act of 1933: Form S-8 (File No. 333-87604), Form S-8 (File No. 333-112234), Form S-8 (File No. 333-118648), Form S-8 (File No. 333-124415), Form S-8 (File No. 333-149532), Form S-8 (File No. 333-161021), Form S-8 (File No. 333-161029) and Form F-10 (File No. 333-196501).





1   Advisories

2   Glossary of Terms and Abbreviations
2   Common Industry Terms
4   Common Abbreviations
4   Conversion Table

5   Corporate Structure
5   Name and Incorporation
5   Intercorporate Relationships

6   General Development of the Business
6   Overview
8   Three-Year History

10   Narrative Description of Suncor's Businesses
10   Oil Sands
15   Exploration and Production
19   Refining and Marketing
22   Other Suncor Businesses

24   Suncor Employees

25   Social and Environmental Policies

26   Statement of Reserves Data and Other Oil and Gas Information
28   Oil and Gas Reserves Tables and Notes
33   Future Net Revenues Tables and Notes
41   Additional Information Relating to Reserves Data
48   Contingent Resources

54   Industry Conditions

60   Risk Factors

68   Dividends

69   Description of Capital Structure

71   Market for Securities

72   Directors and Executive Officers

78   Audit Committee Information

80   Legal Proceedings and Regulatory Actions

80   Interest of Management and Others in Material Transactions

80   Transfer Agent and Registrar

80   Material Contracts

80   Interests of Experts

81   Disclosure Pursuant to the Requirements of the New York Stock Exchange

81   Additional Information

82   Advisory – Forward-Looking Information and Non-GAAP Financial Measures

A-1   Schedule "A" – Audit Committee Mandate
B-1   Schedule "B" – Suncor Energy Inc. Policy and Procedures for Pre-Approval of Audit and Non-Audit Services
C-1   Schedule "C" – Form 51-101F2 Report on Reserves Data by Independent Qualified Reserves Evaluator or Auditor
D-1   Schedule "D" – Form 51-101F2 Report on Reserves Data by Independent Qualified Reserves Evaluator or Auditor
E-1   Schedule "E" – Form 51-101F3 Report of Management and Directors on Reserves Data and Other Information


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

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

References to our 2014 audited Consolidated Financial Statements mean Suncor's audited Consolidated Financial Statements prepared in accordance with Canadian generally accepted accounting principles (GAAP), which is within the framework of International Financial Reporting Standards (IFRS), the notes and the auditors' report, as at and for each year in the two-year period ended December 31, 2014. References to our MD&A mean Suncor's Management's Discussion and Analysis, dated February 26, 2015.

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

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



Common Industry Terms


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

Natural gas is naturally occurring mixtures of hydrocarbon gases and other gases.

Conventional natural gas is natural gas that has been generated elsewhere and has migrated as a result of hydrodynamic forces and is trapped in discrete accumulations by seals that may be formed by localized structural, depositional or erosional geological features.

Natural gas liquids (NGLs) are hydrocarbon components that can be recovered from natural gas as a liquid, including, but not limited to, ethane, propane, butanes, pentanes, and condensates. Liquefied petroleum gas (LPG) consists predominantly of propane and/or butane and, in Canada, frequently includes ethane.

Oil and gas exploration and development processes

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

Exploration costs are costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects that may contain oil and gas reserves, including costs of drilling exploratory wells and exploratory type stratigraphic test wells.

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

Reservoir is a subsurface rock unit that contains an accumulation of petroleum.



Production processes

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

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

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

Midstream refers to transportation, storage and wholesale marketing of crude or refined petroleum products.

Overburden is the material overlying oil sands that must be removed before mining. Overburden is removed on an ongoing basis to continually expose the ore.

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

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

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

Upgrading is the two-stage process by which bitumen is converted into SCO.

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

Reserves and resources

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


Common Abbreviations

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

bbl(s)   barrel(s)
bbls/d   barrels per day
mbbls   thousands of barrels
mbbls/d   thousands of barrels per day
mmbbls   millions of barrels
mmbbls/d   millions of barrels per day
boe   barrels of oil equivalent
boe/d   barrels of oil equivalent per day
mboe   thousands of barrels of oil equivalent
mboe/d   thousands of barrels of oil equivalent per day
mmboe   millions of barrels of oil equivalent
mmboe/d   millions of barrels of oil equivalent per day
mcf   thousands of cubic feet of natural gas
mcf/d   thousands of cubic feet of natural gas per day
mcfe   thousands of cubic feet of natural gas equivalent
mmcf   millions of cubic feet of natural gas
mmcf/d   millions of cubic feet of natural gas per day
mmcfe   millions of cubic feet of natural gas equivalent
mmcfe/d   millions of cubic feet of natural gas equivalent per day
bcf   billions of cubic feet of natural gas
bcfe   billions of cubic feet off natural gas equivalent
GJ   gigajoules
mmbtu   millions of British thermal units
m3   cubic metres
m3/d   cubic metres per day
km   kilometres
MW   megawatts

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

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

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

Conversion Table(1)(2)

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

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



Name and Incorporation

Suncor Energy Inc. (formerly Suncor Inc.) was originally formed by the amalgamation under the Canada Business Corporations Act (the CBCA) 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, the company further amalgamated with a wholly owned subsidiary under the CBCA. We amended our articles in 1995 to move our registered office from Toronto, Ontario, to Calgary, Alberta, and again in April 1997 to adopt the name, "Suncor Energy Inc.". In April 1997, May 2000, May 2002, and May 2008, the company amended its articles to divide its issued and outstanding shares on a two-for-one basis.

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

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

Intercorporate Relationships

Material subsidiaries, each of which was owned 100%, directly or indirectly, by the company as at December 31, 2014, are as follows:

Name   Jurisdiction Where Organized   Description  

Canadian operations          

Suncor Energy Oil Sands Limited Partnership   Canada   This partnership holds most of the company's oil sands assets.  

Suncor Energy Products Inc.   Canada   A subsidiary that holds interests in the company's energy marketing and renewable energy businesses, and which is a partner of Suncor Energy Products Partnership.  

Suncor Energy Products Partnership   Canada   This partnership holds substantially all of the company's Canadian refining and marketing assets.  

Suncor Energy Marketing Inc.   Canada   A subsidiary of Suncor Energy Products Inc. through which production from our upstream North American businesses is marketed. Through this subsidiary, we also administer Suncor's energy trading and power activities, market certain third-party products, procure crude oil feedstock and natural gas for our downstream business, and procure and market NGLs and LPG for our downstream business.  

U.S. operations          

Suncor Energy (U.S.A.) Marketing Inc.   U.S.   A subsidiary that procures and markets third-party crude oil, in addition to procuring crude oil feedstock for the company's refining operations.  

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

International operations          

Suncor Energy UK Limited   U.K.   A subsidiary through which certain of our operations are conducted in the U.K.  

Suncor Energy Oil (North Africa) GmbH   Germany   A subsidiary through which the majority of our Libya operations are conducted.  

The company's remaining subsidiaries each accounted for (i) less than 10% of the company's consolidated assets as at December 31, 2014, and (ii) less than 10% of the company's consolidated operating revenues for the fiscal year ended December 31, 2014. In aggregate, the remaining subsidiaries accounted for less than 20% of each of (i) and (ii) described above.




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

Suncor has classified its operations into the following segments:


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

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

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

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

Oil Sands ventures operations include Suncor's 40.8% interest in the Fort Hills mining project, where Suncor is the operator, and its 36.75% interest in the Joslyn North mining project, where Total E&P Canada Ltd. (Total) is the operator. The company also holds a 12.0% interest in the Syncrude oil sands mining and upgrading operation.


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

E&P Canada operations include Suncor's 37.675% working interest in Terra Nova, which Suncor operates. Suncor also holds a 20.0% interest in the Hibernia base project and a 19.5% interest in the Hibernia Southern Extension Unit (HSEU), a 27.5% interest in the White Rose base project and a 26.125% interest in the White Rose Extensions, and a 22.729% interest in Hebron, all of which are operated by other companies. Suncor also holds interests in several exploration licences offshore Newfoundland and Labrador and Nova Scotia. E&P Canada also includes Suncor's working interests in unconventional natural gas properties in northeast B.C.

E&P International operations include Suncor's 29.89% working interest in Buzzard and its 26.69% interest in Golden Eagle. Both projects are located in the U.K. sector of the North Sea and are operated by another company. Suncor also holds interests in several exploration licences offshore the U.K. and Norway. Suncor owns, pursuant to EPSAs, working interests in the exploration and development of oilfields in the Sirte Basin in Libya. Suncor also owns, pursuant to a PSC, an interest in the Ebla gas development in the Ash Shaer and Cherrife areas in Syria. Suncor's operations in Syria were suspended indefinitely in 2011, due to political unrest in the country.



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

Refining and Supply operations refine crude oil and intermediate feedstock into a broad range of petroleum and petrochemical products. Refining and Supply consists of:

Eastern North America operations which include a refinery located in Montreal, Quebec, a refinery located in Sarnia, Ontario, and a lubricants business located in Mississauga, Ontario that manufactures and blends products which are marketed worldwide.

Western North America operations which include refineries located in Edmonton, Alberta and Commerce City, Colorado.

Other Refining and Supply assets include interests in a petrochemical plant, pipelines and product terminals in Canada and the U.S.

Downstream Marketing operations sell refined petroleum products to retail, commercial and industrial customers through a combination of company-owned, Petro-Canada branded-dealer and other retail stations in Canada and Colorado, a nationwide commercial road transport network in Canada, and a bulk sales channel in Canada. Lubricant products are marketed worldwide through company-operated locations and distributor networks.


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

Renewable Energy interests include seven wind facilities across Canada, including Adelaide which is the most recent addition to the portfolio, and the St. Clair ethanol plant in Ontario. An eighth wind farm, Cedar Point, is planned to commence commercial operations later in 2015.

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

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

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


Three-Year History

Over the last three years, several events have influenced the general development of Suncor's business.


Steve Williams appointed as Chief Executive Officer. In December 2011, Steve Williams, formerly Suncor's Chief Operating Officer (COO), was appointed president and a member of the company's Board of Directors, and assumed the role of Chief Executive Officer (CEO) in May 2012. Prior to becoming COO, Mr. Williams served as Executive Vice President, Oil Sands for four years where he was responsible for leading Suncor's Oil Sands operations through a significant period of growth.

TROTM commissioned. Suncor completed installation of its tailings management assets. Infrastructure included pipes, pumphouses and fluid transfer barges that (a) pump tailings water from extraction plants to a sand placement area, (b) pump mature fine tailings from the sand placement area to a tailings pond for TROTM treatment, and (c) pump treated water from tailings ponds back to extraction plants for use in production processes. Through the TROTM process, mature fine tailings are converted more rapidly into a solid material suitable for reclamation.

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

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

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

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

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


Voyageur oil sands upgrader project deferred. In March, Suncor announced that it was not proceeding with the Voyageur upgrader project in response to changed market conditions that challenged the project economics. Suncor acquired Total's interest in Voyageur Upgrader Limited Partnership (VULP) for $515 million to gain full control of VULP's assets, including a hot bitumen blending facility and tankage used to support the company's growing Oil Sands operations.

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

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

Firebag ramp-up completed. Firebag production in 2013 increased by approximately 40% over 2012


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

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

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

Rail offloading facility complete. Construction of a rail offloading facility to enable receipt of inland crudes at the Montreal refinery was completed in the fourth quarter of 2013. The Montreal refinery received its first shipment in early December.

Successful completion of Upgrader 1 turnaround. Suncor successfully executed planned maintenance across its operations, including a seven-week turnaround at Upgrader 1, which was the largest turnaround in the company's history. The next scheduled turnaround at Oil Sands operations is in 2016.


Market access initiatives. Crude by rail shipments to the company's Montreal refinery averaged approximately 33 mbbls/d in 2014. In addition, the rail offloading facilities at Tracy, Quebec were used to move crude to new and existing markets. Suncor also started transporting heavy crude on TransCanada's Gulf Coast Pipeline which provided increased access to global-based pricing.

Exploration interests in E&P Canada. In May 2014, Suncor signed a farm-in agreement with Shell Canada to acquire a 20% interest in a deepwater exploration opportunity in the Shelburne Basin, offshore Nova Scotia. In December 2014, Suncor acquired a 30% interest in an exploration licence in the Flemish Pass off the coast of Newfoundland and Labrador and a 50% interest in another exploration licence in the Carson Basin near the Flemish Pass.

Joslyn North mining project scaled back. Although regulatory permits for the Joslyn North mining project have been obtained, in May 2014, Suncor decided, along with the other co-owners, to reduce spending on the Joslyn North mining project and continue engineering work and optimization studies to support the development plan for the project.

Investment in water management strategy. Suncor commissioned a waste water treatment plant, which is expected to increase the reuse and recycling of waste water from Suncor's upgrading operations and reduce freshwater withdrawal. In addition, Suncor, along with its project partners, approved the development of the Water Technology Development Centre (WTDC), which is expected to connect to Suncor's Firebag operations and provide an environment to test water treatment and recycling technologies. The WTDC is scheduled to become operational in early 2017.

Reinforced Suncor's focus on core assets. Consistent with our long-term corporate strategy to focus on core assets, Suncor sold its Wilson Creek assets in E&P Canada, announced the sale of its interest in Pioneer Energy's retail business, and acquired a sulphur recovery facility adjacent to the Montreal refinery.

MacKay River debottleneck and process optimization. Suncor achieved first oil from the MacKay River facility debottleneck project in the third quarter of 2014.

First oil from Golden Eagle Area Development (GEAD). During the fourth quarter, first oil was achieved at the Golden Eagle project, which is anticipated to ramp up to its peak production rate of approximately 18,000 boe/d (net) during 2015.

Libya operations shut in. Production in Libya temporarily resumed in the latter half of 2014. However, political unrest in December of 2014 resulted in the Libya National Oil Company (NOC) declaring force majeure on oil exports from two terminals resulting in the shut in of substantially all of the company's production by the end of the fourth quarter. Consequently, Suncor also declared force majeure for all exploration commitments in Libya on December 14, 2014.

Firebag production exceeds nameplate capacity. Firebag production in 2014 averaged approximately 95% of nameplate capacity of 180 mbbls/d, and greater than 180 mbbls/d in the fourth quarter. Continued infill and new SAGD well pair development allowed Suncor to optimize steam placement into the reservoir.



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

Oil Sands

Oil Sands Operations – Assets and Operations

Oil Sands Base Operations

Our integrated Oil Sands Base operations, located in the Athabasca oil sands of northeast Alberta, involve numerous activities:

Mining and Extraction
Power and Steam Generation and Process Water Use

Oil Sands Base Assets

Millennium and North Steepbank

Suncor pioneered the commercial development of the Athabasca oil sands beginning in 1962, achieving first production in 1967. Bitumen is currently mined from the Millennium area, which began production in 2001, and the North Steepbank area, which began production in 2011. During 2014, the company mined approximately 149 million tonnes of bitumen ore (2013 – 151 million tonnes). During 2014, Suncor processed an average of 274 mbbls/d of mined bitumen in its extraction facilities (2013 – 270 mbbls/d).

Upgrading facilities

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

During 2014, Suncor averaged 289 mbbls/d of upgraded (SCO and diesel) production, sourced from bitumen provided by both Oil Sands Base and In Situ operations (2013 – 283 mbbls/d).


Other Mining Leases

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

In Situ Operations

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

The SAGD Process
Central Processing Facilities
Power and Steam Generation
Maintenance and Bitumen Supply

In Situ Assets


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

As at December 31, 2014, Firebag had ten well pads in operation, with 125 SAGD well pairs and 31 infill wells either producing or on initial steam injection. Central processing facilities have been designed to be flexible as to which well pads supply bitumen. Steam generated at the various facilities can be used at multiple well pads. In addition, Firebag includes five cogeneration units that generate steam, which are capable of producing approximately 420 MW of electricity. The Firebag site power load requirements are 110 MW and Suncor exports approximately 310 MW of electricity. There are also 13 OTSGs at the site for additional steam generation.

During 2014, Firebag production averaged 172 mbbls/d (2013 – 143 mbbls/d). During 2014, the SOR at Firebag was 2.8 (2013 – 3.3).

MacKay River

Production from Suncor's MacKay River operations commenced in 2002. As at December 31, 2014, MacKay River included six well pads with 95 well pairs either producing or on initial steam injection. The MacKay River central processing facilities have bitumen processing capacity of approximately 38 mbbls/d. A third party owns the on-site cogeneration unit, which Suncor operates under a commercial agreement that is used to generate steam and electricity. There are also four OTSGs at the site for additional steam generation. The company is in the process of completing further well pad development associated with the MacKay River facility debottleneck project.

During 2014, Mackay River production averaged 27 mbbls/d (2013 – 29 mbbls/d). During 2014, the SOR at MacKay River was 2.9 (2013 – 2.6).

Suncor has regulatory approval to increase bitumen processing capacity by approximately 20,000 mbbls/d with an additional central processing facility at MacKay River


(MacKay River Expansion). However, in January 2015, Suncor deferred the timing of a sanction decision for this project as a result of the current lower crude price environment.

Other In Situ Leases

Suncor owns several other oil sands leases, including those known as Meadow Creek, Lewis, Chard and Kirby, on which it may undertake exploratory drilling. In 2014, Suncor drilled 55 core holes at Lewis and 37 gross core holes at Meadow Creek. Plans for winter 2015 drilling include an additional 100 core holes at Lewis and 68 core holes at Meadow Creek. Suncor holds a 100% working interest in Lewis, 10% working interest in Kirby, 25% to 50% working interest in Chard, and a 75% working interest in Meadow Creek.

Starting with Meadow Creek, Suncor is commencing a greenfield growth plan with a concept to further develop new in situ reservoirs using a replication strategy to build standardized surface facilities, well pads and infrastructure. This will reduce facility capital expenditures. The winter exploratory drilling programs are designed to identify sufficient resources to fill facilities associated with the replication strategy. A development application is anticipated to be filed with the Alberta Energy Regulator (AER) in 2015.

Oil Sands Ventures


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

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

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

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

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

In 2014, Suncor's share of Syncrude production averaged 31 mbbls/d (2013 – 32 mbbls/d).

Fort Hills

Fort Hills is an oil sands mining area comprising leases on the east side of the Athabasca River, north of Oil Sands Base operations. Designs for the Fort Hills mining project plan for 180 mbbls/d of bitumen production capacity (gross). Fort Hills will use a paraffinic froth treatment process to provide marketable bitumen product. Suncor originally acquired a 60% working interest in Fort Hills through the merger, but subsequently disposed of 19.2% as part of transactions with Total. Suncor now holds a 40.8% working interest in the Fort Hills project and is the contract operator for the project. The company's share of the post-sanction project costs are estimated to be $5.5 billion. Approximately $1.6 billion of the company's 2015 capital budget has been allocated to this project. Project activities in 2015 are expected to focus on completing detailed engineering on the secondary extraction and utilities areas, the continued ramp up of field construction activities, and procurement spending across all areas. As at December 31, 2014, Suncor had incurred $1.3 billion post-sanction project costs.

Other Assets

Joslyn is an oil sands mining area comprising leases southwest of Fort Hills and on the west side of the Athabasca River. Preliminary designs for the Joslyn North mining project plan for 157 mbbls/d of bitumen production (gross). Suncor acquired a 36.75% working interest in this asset as a result of transactions with Total. Although regulatory permits for the Joslyn North mining project have been obtained, in May 2014, Suncor, together with the other co-owners, agreed to scale back certain development activities in order to focus on engineering studies to further optimize the project development plan.


New Technology

Technology is a fundamental component to Suncor's business. Suncor has pioneered commercial oil sands development and continues to advance technology through innovation and collaboration to improve efficiencies, lower costs and increase environmental performance. Development of new technology can take extended periods of time, first to demonstrate technical viability and then to demonstrate economic viability. The necessary validation typically occurs through a series of progressive tests which allow results to be reliably scaled and assessed for implementation.

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

Oxy-Fuel Combustion – Suncor is involved in a collaborative research and development project that could improve the prospects for implementing carbon capture and storage.

Zero Liquid Discharge – Suncor uses a zero liquid discharge process at our MacKay River in situ facility to achieve maximum water reuse by recovering waste water from produced bitumen.

Enhanced Solvent Extraction Incorporating Electromagnetic Heating (ESEIEH) – This new method of in situ bitumen recovery uses radio frequency heating and solvents to reduce energy, greenhouse gas and water footprints. The second phase of pilot testing is expected to begin in the first quarter of 2015.

N-SOLVTM – Suncor is currently undertaking field tests on using this condensing solvent to extract bitumen, which could significantly reduce energy use and greenhouse gas emissions. The pilot test is ongoing.

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

Suncor is a founding member of Canada's Oil Sands Innovation Alliance (COSIA), a group of oil sands producers focused on accelerating the pace of environmental performance improvement through collaborative action and innovation.

Sales of Principal Products

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

For bitumen production from In Situ operations, Suncor's marketing strategy allows it to take advantage of changes in market conditions by either: a) upgrading the bitumen directly at our Oil Sands Base facilities; b) upgrading diluted bitumen at Suncor's Edmonton refinery; or c) selling diluted bitumen directly to third parties. Increased bitumen sales may also be required during upgrading facilities outages. During 2013, Suncor increased the flexibility of marketing In Situ production by completing the construction of the hot bitumen insulated pipeline and the blending facilities at the East Tank Farm, and securing diluent blending stock. In Situ bitumen production processed by Oil Sands Base upgrading facilities in 2014 decreased to 49% or 98 mbbls/d (2013 – 55% or 94 mbbls/d) as more In Situ bitumen was sold directly to market following the commissioning of the hot bitumen infrastructure.

    2014   2013  
Sales Volumes and Operating Revenues – Principal Products   mbbls/d   % operating
  mbbls/d   % operating

Sweet – Light sweet SCO and diesel (including Syncrude)   161.4   44   147.9   43  

Sour – Light sour SCO and bitumen   260.3   52   241.9   51  

Non-proprietary, byproducts and other operating revenues(1)   n/a   4   n/a   6  

    421.7       389.8      

Operating revenues include sales of non-proprietary volumes, primarily third-party diluent purchased to support sales of bitumen that is required when the company is unable to meet diluent demands internally, as well as revenues associated with excess power from cogeneration units.


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

Distribution of Products

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

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

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

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

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

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

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

To most major refining hubs via the Enbridge mainline, Express/Platte and Keystone pipeline systems.


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

Effective January 1, 2009, under the New Royalty Framework, royalties are based on a sliding-scale rate of 25% to 40% of net revenue, subject to a minimum royalty within a range of 1% to 9% of gross revenue. Revenues used in royalty formulas are driven primarily by benchmark prices for WCS, while sliding-scale percentages in royalty formulas depend on prices for WTI from Cdn$55/bbl to the maximum rate at a WTI price of Cdn$120/bbl. A project remains subject to the minimum royalty (the pre-payout phase) until the project's cumulative gross revenues exceed its cumulative costs, including an annual investment allowance (the post-payout phase).

Oil Sands Base and Syncrude

As part of the New Royalty Framework, both Suncor and the co-owners of Syncrude reached separate agreements with the Government of Alberta for the implementation of the New Royalty Framework:

For the period from January 1, 2010 to December 31, 2015, royalty rates for Oil Sands Base are based on a sliding scale, depending on the Canadian dollar equivalent for WTI, from 25% to 30% of net revenue. Oil Sands Base royalties are also subject to the minimum royalty rate range of 1.0% to 1.2% of gross revenue. In 2014, Suncor incurred royalties at Oil Sands Base mining operations at a rate of 30% of net revenue (2013 – 30% of net revenue).

Syncrude will continue paying the bitumen-based royalty based on the greater of 1% gross revenue, or 25% of net revenue, until December 31, 2015. For 2014, the royalty rate at Syncrude was 25% of net revenue (2013 – 25% of net revenue). In addition, the co-owners of Syncrude agreed to pay an additional royalty of $975 million over a six-year period starting in 2010, which is contingent on achieving certain production levels.

In 2014, Oil Sands Base royalties were approximately 7% of Oil Sands Base operating revenues (2013 – 6%). In 2014, Suncor incurred royalties on Syncrude operations averaging approximately 7% of Syncrude operating revenues (2013 – 6%).

Beginning on January 1, 2016, Suncor's Oil Sands Base and Syncrude operations are expected to be subject to the generic royalty regime as set out in the New Royalty Framework.

In Situ

Royalty rates for Suncor's MacKay River and Firebag are based on the New Royalty Framework.

In 2014, Suncor incurred royalties at an average rate of 7% of gross revenue for MacKay River (2013 – 6% of gross revenue) and royalties at an average rate of 7% of gross revenue for Firebag (2013 – 7% of gross revenue), which continues in the pre-payout phase.


Exploration and Production

E&P Canada – Assets and Operations

East Coast Canada

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

Terra Nova

The Terra Nova oilfield is approximately 350 km southeast of St. John's. Terra Nova was discovered in 1984, and was the second oilfield to be developed offshore Newfoundland and Labrador. Operated by Suncor, the production system uses a FPSO vessel that is moored on location, and has gross production capacity of 180 mbbls/d (68 mbbls/d net to Suncor) and oil storage capacity of 960 mbbls. Terra Nova was the first harsh environment development in North America to use a FPSO vessel. Actual annual production levels are lower than production capacity, reflecting current reservoir capability, including natural declines, gas and water injection and production limits, and asset and facility reliability. The Terra Nova oilfield is divided into three distinct areas, known as the Graben, the East Flank and the Far East. Production from Terra Nova began in January 2002. As at December 31, 2014, there were 30 wells: 17 oil production wells, ten water injection wells and three gas injection wells. In 2014, Suncor's share of Terra Nova production averaged 17 mbbls/d compared to 14 mbbls/d in 2013. Annual turnaround maintenance was completed at the Terra Nova facility in August 2014 which lasted four weeks.

Hibernia and the Hibernia Southern Extension Unit (HSEU)

The Hibernia oilfield, encompassing the Hibernia and Ben Nevis Avalon reservoirs, is approximately 315 km southeast of St. John's and was the first field to be developed in the Jeanne d'Arc Basin. Operated by Hibernia Management and Development Company Ltd., an ExxonMobil-managed company, the production system is a fixed GBS that sits on the ocean floor, and has gross production capacity of 230 mbbls/d (46 mbbls/d net to Suncor) and oil storage capacity of 1,300 mbbls. Actual production levels are lower, reflecting current reservoir capability, including natural declines, gas and water injection and production limits, and asset and facility reliability. Hibernia commenced production in November 1997. As at December 31, 2014, there were 63 wells: 37 oil production wells, 14 single-zone water injection wells, seven dual-zone water injection wells and five gas injection wells. In 2014, Suncor's share of Hibernia production averaged 23 mbbls/d (2013 – 27 mbbls/d).

In 2010, final agreements were signed between the Hibernia co-venturers and the Government of Newfoundland and Labrador that established the fiscal, equity and operational principles for the development of the HSEU. Three development wells have been completed from the GBS platform and are producing oil. Subsea infrastructure was installed in late 2013 and drilling activities continued through 2014. Current development plans include drilling two additional development wells from the GBS platform and five additional water injection wells in the excavated subsea drill centre. The number of development and injection wells required may be revised as the development proceeds and uncertainties regarding reservoir capability are resolved. Production from the HSEU is expected to reach higher rates in 2015 when several planned water injection wells are completed.

White Rose and the White Rose Extensions

White Rose is approximately 350 km southeast of St. John's. Operated by Husky Oil Operations Limited, White Rose uses a FPSO vessel and has gross production capacity of 140 mbbls/d (39 mbbls/d net to Suncor) and oil storage capacity of 940 mbbls. Actual annual production levels are lower than production capacity, reflecting current reservoir capability, including natural declines, gas and water injection and production limits, and asset and facility reliability. Production from White Rose began in November 2005. As at December 31, 2014, there were 34 wells: 15 oil production wells, 15 water injection wells, one gas injection well and three gas storage wells. In 2014, Suncor's share of White Rose production averaged 15 mbbls/d (2013 – 15 mbbls/d).

In 2007, the White Rose co-venturers signed an agreement with the Government of Newfoundland and Labrador for the development of the White Rose Extensions, which include the North Amethyst, South White Rose Extension, and West White Rose satellite fields. In May 2010, first oil was achieved in North Amethyst, and development drilling is ongoing. Development of the South White Rose Extension began in 2013 with the installation of subsea gas injection infrastructure. Oil production and water injection infrastructure were installed in 2014; drilling began in 2014 and is expected to continue in 2015 with first oil anticipated in the second quarter of 2015.

Development of the West White Rose field has been divided into two stages. The first stage was approved in 2010 and first oil was achieved in 2011. In late 2014, sanction of the second stage was deferred by the co-owners of the project in light of the current lower crude price environment.


Discovered in 1980, the Hebron oilfield is located 340 km southeast of St. John's. The project is operated by


ExxonMobil Canada Properties. On December 31, 2012, the Hebron co-owners announced project sanction. Development of the Hebron project includes the construction of a concrete GBS that supports an integrated topsides deck to be used for production, drilling and accommodations. Development plans include 1,200 mbbls of oil storage capacity and 52 well slots with a gross oil production capacity of 150 mbbls/d (34 mbbls/d net to Suncor). Construction of the GBS and topside progressed according to plan during 2014. The GBS was successfully moved from dry dock into its deepwater construction site in the third quarter of 2014. First oil is expected in 2017. Suncor's share of the post-sanction project cost estimate provided by the project operator is approximately $2.8 billion.

Other Assets

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

During 2014, Suncor entered into an agreement with Shell Canada Limited and ConocoPhillips Canada East Coast Partnership to pursue a deepwater exploration opportunity in the Shelburne Basin, located approximately 250 km offshore Nova Scotia. Through the agreement, Suncor acquired a 20% non-operating interest. Current plans are to proceed with two exploration wells commencing in 2015.

Suncor continues to pursue opportunities offshore Newfoundland and Labrador. During the fourth quarter of 2014, Suncor was a successful joint bidder with ExxonMobil Canada for exploration licences in the Flemish Pass and Carson Basin, located approximately 500 km off the east coast of Newfoundland. The work commitment on these licences in the Flemish Pass and Carson Basin is over the next six to nine years, with no significant spend planned in 2015. The company also holds interests in 50 other significant discovery licences and 12 other exploration licences offshore in this area.

North America Onshore

The North America Onshore business explores for, develops and produces natural gas, NGLs, crude oil and byproducts in Western Canada. Suncor sold the majority of its natural gas business in 2013 followed by the sale in 2014 of its interests in its Wilson Creek assets in central Alberta for $168.5 million before closing adjustments and other closing costs. Following these disposals, the retained assets produce approximately 4 mboe/d, primarily natural gas, from the Kobes/Montney assets in northeast B.C., in which Suncor has a 100% working interest.

Suncor also holds undeveloped assets that allow the company to explore long-term opportunities.

E&P International – Assets and Operations

North Sea


The Buzzard oilfield is located in the Outer Moray Firth, 95 km northeast of Aberdeen, Scotland. Operated by Nexen Petroleum U.K. Limited (Nexen U.K.), a subsidiary of China National Offshore Oil Corporation Limited, the Buzzard facilities have gross installed production capacity of approximately 220 mbbls/d (66 mbbls/d net to Suncor) of oil and 80 mmcf/d (24 mmcf/d net to Suncor) of natural gas. Actual annual production levels are lower than production capacity, reflecting current reservoir capability, including natural declines, water injection limits, gas and water production limits, and asset and infrastructure reliability. Buzzard commenced production in January 2007. Buzzard consists of four bridge-linked platforms supporting wellhead facilities, production facilities, living quarters and utilities, and sulphur handling. As at December 31, 2014, there were 48 wells: 35 oil and gas production wells and 13 water injection wells. In 2014, Suncor's share of Buzzard production averaged 47 mboe/d (2013 – 56 mboe/d).

In 2014, Buzzard completed two oil development wells.

Golden Eagle

The Golden Eagle development operated by Nexen U.K. is approximately 20 km north of the Buzzard oilfield and consists of the unitization of the Peregrine, Hobby, Golden Eagle and Solitaire areas. During 2011, the Golden Eagle project was sanctioned. The development incorporates a production, utilities and accommodation platform, linked to a separate wellhead platform, with a peak production rate of 70 mbbls/d (18 mbbls/d net to Suncor) from 21 development wells. The estimated gross development cost will be £2 billion (Cdn$3.3 billion) or £0.6 billion (Cdn$1.0 billion) net to Suncor, based on sanction date cost estimates and exchange rates. In 2014, activities included the transportation and installation of the processing utilities and quarters deck. Drilling of development wells commenced in March 2014 and will continue through 2015 as the project ramps up to planned capacity. First oil was achieved on October 30, 2014. In 2014, Suncor's share of GEAD production averaged 0.6 mbbls/d. The Golden Eagle co-owners also hold adjacent exploration licences and continue to explore the region.


Other Assets

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

Beta discovery (Norway) – Suncor is the operator for the PL375, PL375b and PL375c licences, in which it has an 80% interest. The company drilled the first exploration well in early 2010, encountering hydrocarbons. An appraisal well was drilled and tested later in 2010 with positive results. However, a third well drilled into a separate fault block did not encounter hydrocarbons. The company will continue to evaluate the Beta discovery by interpreting 3D seismic data acquired in 2013, with further drilling starting in 2015. The Beta licences also contain other exploration opportunities.

Butch discovery (Norway) – In 2011, Centrica plc, the operator for the PL405 licence in which Suncor has a 30% interest, drilled an exploration well resulting in a discovery, followed by a sidetrack well to assess the lateral extent of the hydrocarbons. Early in 2012, a second sidetrack well was attempted but abandoned, due to well instability, before reaching its intended depth. In 2014, two additional wells were drilled to explore for oil in separate fault blocks from the discovery, but did not encounter hydrocarbons.

Lily prospect (U.K.) – In 2013, the operator for the P928 20/1S licence, in which Suncor has a 29.89% interest, drilled an exploration well, which was completed in the first quarter of 2014, but did not encounter hydrocarbons.

Blackjack prospect (U.K.) – During the first half of 2014, the operator of the P300 14/26a licence, in which Suncor has a 26.69% interest, drilled an exploration well. The well did encounter hydrocarbons, but following evaluation, it was determined to be non-commercial.

Suncor continues to pursue other opportunities in the North Sea, the Norwegian Sea and the Barents Sea. The company holds interests in 27 exploration licences in the U.K. and Norwegian sectors of these areas.

Other International


In Libya, Suncor is signatory to seven EPSAs with the NOC. Five of the seven EPSAs contain producing fields and exploration prospects; the remaining two are exploration EPSAs that do not contain producing fields, one of which is being relinquished because the exploration program was not successful. Under the EPSAs, Suncor pays 100% of the exploration costs, 50% of the development costs and 12% of the operating costs. The development, operating and eligible exploration costs are recovered through a 12% share of production (Cost Recovery oil). Any Cost Recovery oil remaining after Suncor's costs have been recovered is referred to as excess petroleum, and is shared between Suncor and the NOC based on several factors. The EPSAs expire on December 31, 2032, but include an initial five-year extension through the end of 2037. Libya is a member of the Organization of Petroleum Exporting Countries (OPEC) and is subject to quotas that can affect the company's production in Libya.

From March to September 2011, the operator for the joint operation, Harouge Oil Operations BV, shut in production as a result of political unrest. By early 2012, production had restarted in all major producing fields. In July 2013, production was shut in again as political unrest resulted in the closure of seaport terminals. Production remained shut in until July 2014, when the last two affected terminals were reopened and production slowly began to resume. However, in December 2014, operations in Libya were again disrupted as political unrest continued, resulting in the closure of two of the main seaport terminals and, as a result, substantially all of Suncor's production was again shut in. The region remains volatile and Suncor's ability to return to continued and normal production levels remains uncertain. The estimated cost of Suncor's remaining exploration work program commitment at December 31, 2014, is US$359 million.

In 2014, Suncor's share of production in Libya averaged 7 mbbls/d (2013 – 21 mbbls/d).


In December 2011, amid continuing unrest in Syria, sanctions were introduced and Suncor declared force majeure under its contractual obligations and suspended its operations in the country. Consequently, the company has ceased recording all production and revenue associated with its Syrian assets. Since 2011, Suncor has not been able to monitor the status of any of its assets in the country, including whether certain facilities have suffered damage. As a result of continued uncertainty about Suncor's future in the country, the remaining value of the Suncor assets was impaired in 2013.

Suncor conducts its Syrian operations pursuant to a PSC, where the company pays 100% of the development costs and recovers these costs from a 40% share of production after deduction of royalties of 12.5%. This petroleum revenue is referred to as Cost Recovery petroleum. The amount by which Cost Recovery petroleum exceeds recoverable cost is referred to as Excess Cost Recovery petroleum, 50% of this amount is due to the General Petroleum Corporation (GPC) and the remaining 50% is shared between Suncor and the GPC according to a profit-sharing schedule.

Sales of Principal Products

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

In Libya, crude oil is marketed by the NOC on behalf of Suncor.


Exploration and Production Sales Summary:

    2014   2013
Sales Volumes   mboe/d   % operating
  mboe/d   % operating

E&P Canada                  

  Crude oil and NGLs   55.2   53   61.2   43  

  Natural gas   2.8   1   32.0   4  

E&P International                  

  Crude oil and NGLs   47.2   46   75.2   53  

  Natural gas   0.9   0   1.2   0  

Total Exploration and Production                  

  Crude oil and NGLs   102.4   99   136.4   96  

  Natural gas   3.7   1   33.2   4  

Distribution of Products

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

North America Onshore – gas production from B.C. is typically sold at Station 2, part of the Spectra B.C. transmission system. Suncor also holds firm capacity on the TransCanada PipeLines Gas Transmission Northwest Pipeline, which enables Suncor to deliver natural gas to the Pacific Northwest and California markets.

Buzzard – crude oil is transported via the third-party operated Forties Pipeline System to the Hound Point terminal in Scotland and sold as part of the Forties Blend crude stream. Natural gas is transported via the third-party operated Frigg Pipeline System to the St. Fergus Gas Terminal in Scotland.

Golden Eagle – crude oil is transported to the third-party operated Flotta Terminal in the Orkney Islands in Scotland where it is shipped to market as part of the Flotta Gold blend.


East Coast Canada

The Terra Nova royalty consists of a sliding-scale basic royalty payable, with two tiers of incremental royalties. The basic royalty is now capped at 10% of gross field revenue. The tier one royalty is the greater of the basic royalty or 30% of net revenue, and became payable in 2005. Net revenue is gross revenue adjusted for eligible operating and capital costs. The tier two royalty, equal to an additional 12.5% of net revenue, became payable in 2008. During 2014, Terra Nova royalties averaged 21% of gross revenue (2013 – 12% of gross revenue).

The Hibernia royalty agreement for production from the original oilfields and the AA Block consists of a sliding-scale basic royalty, two tiers of incremental royalties, and an additional net profits interest (NPI). The basic royalty is now capped at 5% of gross revenue. The tier one royalty, which became payable in 2009, is the greater of the basic royalty or 30% of net revenue. The tier two royalty is an additional 12.5% of net revenue, but has not yet been triggered. Production from the AA Block, which commenced in late 2009, attracts an additional tier three of 12.5% of net revenue. The NPI, which also became payable in 2009, is an additional 10% of net revenue. Limited production from the HSEU began in 2011. The HSEU has a similar royalty structure (gross, tier one and tier two) to that described above for Hibernia. Currently, Suncor is only subject to a 5% gross royalty. HSEU production will be subject to an additional tier three royalty that ranges between 2.5% and 7.5% of net revenue, depending on the price for WTI. The HSEU tier three royalty will coincide with the triggering of the tier one royalty. For that portion of the HSEU that is contained within the original Hibernia licence area, but will be developed with the new subsea facilities, production will be subject to an additional tier three royalty that ranges between 7.5% and 12.5% of net revenue, depending on the price for WTI. During 2014, Hibernia (including the HSEU) royalties and NPI combined to average 33% of gross revenue (2013 – 36% of gross revenue).

The White Rose royalty for the base project consists of a sliding-scale basic royalty, with two tiers of incremental


royalties. The basic royalty is now capped at 7.5% of gross field revenue. The tier one royalty is the greater of the basic royalty or 20% of net revenue and became payable in 2007. The tier two royalty, equal to an additional 10% of net revenue, became payable in 2008. The royalty for production from the White Rose Extensions is similar to the base project, except that there is an additional tier three royalty, equal to 6.5% of net revenue, which is payable if WTI is greater than US$50/bbl. Tier one and tier three royalties for White Rose Extensions became payable in 2014. During 2014, total White Rose royalties averaged 14% of gross revenue (2013 – 16%).

E&P International

There are no royalties on oil and gas production from the North Sea; however, in the U.K., oil and gas profits are subject to a 62% income tax rate. The U.K. Government has announced that this will be reduced to 60% effective January 1, 2015. The reduction is expected to be substantively enacted in the first half of 2015. For operations in Libya, all government interests, except for income taxes, are presented as royalties.

Refining and Marketing

Refining and Supply – Assets and Operations

Eastern North America

Montreal Refinery

The Montreal refinery has a crude oil capacity of 137 mbbls/d, processing primarily conventional crude oil, with a flexible configuration that allows processing of light, sour and heavy grades of crude oil, as well as intermediate feedstock. Crude oil is procured from the market on a spot basis or under contracts that can be terminated on short notice. Crude oil for the refinery is supplied via the Portland-Montreal Pipeline, by marine transportation and by rail for inland crudes. The Montreal refinery received inland crude volumes averaging 33 mbbls/d through 2014.

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

In 2014, Suncor completed the acquisition of a sulphur recovery plant that is now integrated with the Montreal refinery's operations and is expected to secure the refinery's long-term sulphur recovery needs.

Sarnia Refinery

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

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

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

Other Facilities

Suncor holds a 51% interest in ParaChem Chemicals L.P. (ParaChem), which owns and operates a petrochemicals plant located adjacent to the Montreal refinery. Feedstock for the plant includes xylene and toluene produced by the Montreal and Sarnia refineries. The plant primarily produces paraxylene, which is used by customers to manufacture polyester textiles and plastic bottles. Paraxylene production was approximately 366,000 metric tonnes in 2014 (2013 – 355,000 metric tonnes). ParaChem also produces benzene, hydrogen and heavy aromatics. Benzene production is delivered back to the Montreal refinery to be marketed with production from that facility.

Suncor's lubricants plant produces specialty lubricants and waxes that are marketed in Canada and internationally. The facility, located in Mississauga, Ontario, is the largest producer of lubricant base stocks in Canada. In 2014, the plant produced approximately 844 million litres of lubricant base stocks. Feedstock for the lubricants facility comes from Suncor's Montreal refinery and other purchase contracts.


Western North America

Edmonton Refinery

The Edmonton refinery has a crude oil capacity of 142 mbbls/d and has the potential to run entirely on feedstock sourced from oil sands. Crude oil is supplied to the refinery via company-owned and third-party pipelines.

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

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

Commerce City Refinery

The Commerce City refinery has a crude oil capacity of 98 mbbls/d. The refinery processes primarily conventional crude oil, but also has the capability of processing up to 16 mbbls/d of sour SCO and diluted bitumen from Suncor's Oil Sands Base operations. A majority of crude feedstock is supplied from sources in the U.S., primarily the Rocky Mountain region, while the remainder is purchased from Canadian sources. Crude oil purchase contracts have terms ranging from month-to-month to multi-year. Approximately 61% of crude oil supplied to the refinery is transported via pipeline, with the remainder transported via truck.

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

Other Facilities

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

Refinery Throughputs, Utilizations and Yields

The following tables summarize the crude feedstock, utilizations and production yield mix for Suncor's refineries for the years ended December 31, 2014 and 2013. Refinery utilizations include the impacts of planned and unplanned maintenance events.

Average Daily Crude Throughput           Montreal           Sarnia           Edmonton           Commerce City  
(mbbls/d, except as noted)   2014   2013   2014   2013   2014   2013   2014   2013  

Oil Sands Base sweet synthetic       11.5   28.0   41.3   45.5   0.6    

Oil Sands Base sour synthetic       24.1   11.3   63.2   59.3   10.8   8.0  

Other synthetic       15.4   11.6   26.8   23.6   8.7   8.9  

East Coast Canada light conventional(1)   23.2   14.6              

Other light conventional   79.4   94.2   5.0   24.8     0.5   65.8   72.1  

Sour conventional   4.9   0.2   19.8         11.0   11.3  

Heavy conventional   15.6   16.7              

Total   123.1   125.7   75.8   75.7   131.3   128.9   96.9   100.3  

Utilization(2) (%)   90   92   89   89   92   92   99   102  

Includes purchases of Suncor and third-party shares of production from East Coast Canada oilfields.

Refinery utilizations based on crude 2014 processing capacities (in mbbls/d): Montreal – 137; Sarnia – 85; Edmonton – 142; and Commerce City – 98. Edmonton processing capacity was 140 mbbl/d in 2013; the utilization rate has not been restated.


Refined petroleum production yield mix           Montreal           Sarnia           Edmonton           Commerce City  
(%)   2014   2013   2014   2013   2014   2013   2014   2013  

Gasoline   42   41   47   39   41   43   47   49  

Distillates   35   37   34   46   54   52   35   35  

Other   23   22   19   15   5   5   18   16  

Distribution Terminals and Pipelines

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

Suncor has ownership interests in certain pipelines, including the following:

Pipeline   Ownership   Type   Origin   Destinations  

Portland-Montreal Pipeline   23.8%   Crude oil   Portland, Maine   Montreal, Quebec  

Trans-Northern Pipeline   33.3%   Refined product   Montreal, Quebec   Ontario – Ottawa, Toronto & Oakville  

Sun-Canadian Pipeline   55.0%   Refined product   Sarnia, Ontario   Ontario – Toronto, London & Hamilton  

Alberta Products Pipeline   35.0%   Refined product   Edmonton, Alberta   Calgary, Alberta  

Rocky Mountain Crude Pipeline   100.0%   Crude oil   Guernsey, Wyoming   Denver, Colorado  

Centennial Pipeline   100.0%   Crude oil   Guernsey, Wyoming   Cheyenne, Wyoming  

Marketing – Assets and Operations

Suncor's retail service station network operates nationally in Canada primarily under the Petro-CanadaTM brand. As at December 31, 2014, this network consisted of 1,465 outlets across Canada, excluding Pioneer retail locations. In addition, refined products are marketed through independent dealers and joint arrangements. Suncor's Canadian retail network had annual sales of gasoline motor fuels averaging approximately 4.8 million litres per site in 2014 (2013 – 4.8 million litres) and attracted an estimated 17.3% share (2013 – 17.7%) of the national retail urban market.

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

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

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


Retail Summary:

    As at December 31  
Locations   2014   2013  

Retail Service Stations – Canada          

  Petro-CanadaTM-branded   1 465   1 454  

  SunocoTM-branded   1   7  

    1 466   1 461  

Retail Service Stations – Colorado          

  Shell®-branded retail service stations   38   38  

  Phillips 66®-branded retail service stations   6   6  

    44   44  

Wholesale Cardlock Sites – Canada          

  Petro-CanadaTM-branded cardlock sites (PETRO-PASS)   266   259  

Sales Volumes   mbbls/d   % operating
  mbbls/d   % operating

Gasoline (includes motor and aviation gasoline)                  

  Eastern North America   117.0       116.0      

  Western North America   118.6       131.4      

    235.6   44   247.4   47  

Distillates (includes diesel and heating oils, and aviation jet fuels)                  

  Eastern North America   107.2       89.1      

  Western North America   100.3       120.7      

    207.5   39   209.8   39  

Other (includes heavy fuel oil, asphalts, lubricants, petrochemicals, other)                  

  Eastern North America   58.2       57.0      

  Western North America   30.4       28.6      

    88.6   17   85.6   14  

    531.7       542.8      

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

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

Other Suncor Businesses

Energy Trading

Suncor's Energy Trading business is organized around five main commodity groups – crude oil, natural gas, sulphur, petroleum coke and electricity – and has trading offices in


Canada, the U.K. and the U.S. Energy Trading provides commodity supply, transportation, storage and pricing solutions. Our customers include mid- to large-sized commercial and industrial consumers, utility companies and energy producers.

The Energy Trading business supports the company's Oil Sands and E&P production by optimizing price realizations, managing inventory levels during unplanned outages at Suncor's facilities and managing the impacts of external market factors, such as pipeline disruptions or outages at refining customers. The Energy Trading business has entered into arrangements for other midstream infrastructure, such as pipeline, storage capacity and rail access, to optimize delivery of existing and future growth production, while generating trading earnings on select strategies and opportunities.

The Energy Trading business commenced rail shipments through two rail offload facilities in 2014. The Montreal, Quebec facility was operational throughout 2014 and is used to provide non-proprietary inland crude to the Montreal refinery. The company also secured a new offloading agreement at a rail terminal in Tracy, Quebec, which became operational in the third quarter of 2014 and allowed access to eastern tidewaters for non-proprietary products.

The Energy Trading business supports the company's Refining and Marketing business by optimizing the supply of crude and NGLs feedstock to the four refineries, managing crude inventory levels during refinery turnarounds and periods of unplanned maintenance as well as managing external impacts from pipeline disruptions.

Renewable Energy

Since 2006, Suncor has invested in Canada's biofuels industry. Suncor operates Canada's largest ethanol facility, the St. Clair Ethanol plant in the Sarnia-Lambton region of Ontario. The ethanol plant has a nameplate capacity of 400 million litres per year. In 2014, the plant produced 412.0 million litres of ethanol (2013 – 415.0 million litres). In 2014, Suncor also invested in biodiesel technology to capture a production cost advantage, through interests in both a technology company and the retrofit of a biodiesel plant, which is scheduled to be completed by the end of 2015.

In addition, Suncor's renewable energy interests include six wind power projects in operation, as well as the Adelaide wind farm that was completed in 2014. Including Adelaide, Suncor's wind farms have a gross generating capacity of 295 MW. Suncor continues to evaluate new opportunities to build its renewable energy portfolio with potential wind power project sites that are in various stages of the evaluation process.

An eighth wind farm, the Cedar Point project, has received regulatory approval. An appeal of this permit is currently in progress. Suncor expects a final decision on that appeal to be made in March 2015. Detailed engineering is concluding and construction is expected to be completed in 2015. The project is expected to add 100 MW of gross generating capacity.

Suncor's wind power projects:

Wind Power Projects       Ownership
Interest (%)
  Size (MW)   Turbines   Completed  

Operated by Suncor                      

  Wintering Hills   Drumheller, Alberta   70.0   88   55   2011  

  Kent Breeze   Thamesville, Ontario   100.0   20   8   2011  

  Adelaide   Strathroy, Ontario   75.0   40   18   2014  


  Ripley   Ripley, Ontario   50.0   76   38   2007  

  Chin Chute   Taber, Alberta   33.3   30   20   2006  

  Magrath   Magrath, Alberta   33.3   30   20   2004  

  SunBridge   Gull Lake, Saskatchewan   50.0   11   17   2002  



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

As of December 31   2014   2013  

Oil Sands   6 098   6 310  

Exploration and Production   505   479  

Refining and Marketing   3 528   3 265  

Corporate, Energy Trading and Renewable Energy   3 849   3 892  

Total   13 980   13 946  

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

Approximately 34% of the company's employees were covered by collective agreements at the end of 2014. The majority of collective agreements, covering approximately 4,225 employees, were renewed in 2013 for a 3-year term. The collective agreement with Unifor covering approximately 70 employees on Terra Nova was successfully renewed in January 2015. Collective agreements with the United Steel Workers Union, representing approximately 265 employees at the Commerce City refinery, and with the Sunoco Employees' Bargaining Association, representing approximately 200 employees at the Sarnia refinery, will expire January 31, 2015 and February 28, 2015, respectively. Suncor is currently in negotiations to renew the collective agreements at Commerce City refinery and Sarnia refinery.



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

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

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

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

Suncor has an Environment, Health and Safety (EH&S) policy, which affirms Suncor's aspirations to be a sustainable energy company by meeting or exceeding the environmental, social and economic expectations of our current and future stakeholders. The policy reflects Suncor's belief that our EH&S efforts are complementary and interdependent with our economic and social performance. The policy makes it clear that Suncor management is responsible for ensuring that employees under their direction are competent to manage their EH&S responsibilities and are knowledgeable of the hazards and risks associated with their jobs, and that all Suncor employees and contractors are accountable for compliance with relevant acts, codes, regulations, standards and procedures, and for their own personal safety and the safety of their co-workers.

The Environment, Health, Safety and Sustainable Development Committee of the Board of Directors meets quarterly to review Suncor's effectiveness in meeting its obligations pertaining to EH&S. The committee also reviews the effectiveness with which Suncor establishes appropriate EH&S policies, including environmental performance, given legal, industry and community standards. Management systems are maintained by this committee to implement such policies and ensure compliance.

To support and highlight the goals of the EH&S policy, Suncor holds an Annual President's Operational Excellence Awards, which honours employees and contractors who demonstrate an exceptional commitment to environment, health and safety performance. The awards ceremony highlights progress on safety initiatives and provides educational opportunities for all employees.

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



Date of Statement

The Statement of Reserves Data and Other Oil and Gas Information outlined below is dated February 26, 2015, with an effective date of December 31, 2014. The preparation date of the information is as of February 20, 2015.

Disclosure of Reserves Data

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

The reserves data set forth in this section of the AIF for Suncor's Mining and In Situ operations is based upon evaluations conducted by GLJ Petroleum Consultants Ltd. (GLJ), contained in their reports (the GLJ Reports). The reserves data set forth below for all other reserves, which includes Suncor's interests in its conventional assets offshore Newfoundland and Labrador and its natural gas assets located in Western Canada (collectively, E&P Canada), and conventional assets offshore the U.K. (North Sea) and in Libya (Other International), is based upon evaluations conducted by Sproule Associates Limited or Sproule International Limited (collectively, Sproule), contained in their reports (the Sproule Reports). Each of GLJ and Sproule (collectively, the Evaluators) are independent qualified reserves evaluators as defined in NI 51-101.

The reserves data summarizes Suncor's SCO, bitumen, light and medium oil, natural gas and NGLs reserves and the net present values of future net revenues for these reserves using forecast prices and costs prior to provision for interest, general and administrative expense, and certain abandonment and reclamation costs.

Advisories – Future Net Revenues

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

Significant Risk Factors and Uncertainties Affecting Reserves and Resources Data

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

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

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


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

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

The reserves evaluations are based in part on the assumed success of activities we intend to undertake in future years. The reserves and estimated cash flow to be derived from the reserves contained in the reserves evaluations will be reduced to the extent that such activities do not achieve the level of success assumed in the reserves evaluations.

The reserves evaluations are effective as of a specific effective date and have not been updated, and thus do not reflect changes in our reserves, since that date.


Oil and Gas Reserves Tables and Notes

Summary of Oil and Gas Reserves(1)(2)(3)
as at December 31, 2014
(forecast prices and costs)

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



































Proved Developed Producing                                          
  Mining   1 792   1 589               1 792   1 589  
  In Situ   159   151   138   127           297   278  
  E&P Canada           58   43   38   30   65   48  
Total Canada   1 951   1 740   138   127   58   43   38   30   2 154   1 916  
North Sea           71   71   2   2   72   72  
Other International                      

Total Proved Developed Producing   1 951   1 740   138   127   130   115   40   32   2 226   1 988  

Proved Developed Non-Producing                                          
  In Situ   7   5   26   25           33   29  
  E&P Canada               12   9   2   1  
Total Canada   7   5   26   25       12   9   35   31  
North Sea           3   3       3   3  
Other International           140   49       140   49  

Total Proved Developed Non-Producing   7   5   26   25   143   52   12   9   178   83  

Proved Undeveloped                                          
  Mining       845   734           845   734  
  In Situ   532   447   830   704           1 362   1 150  
  E&P Canada           52   48       52   48  
Total Canada   532   447   1 674   1 437   52   48       2 258   1 932  
North Sea           16   16   1   1   16   16  
Other International           2   1       2   1  

Total Proved Undeveloped   532   447   1 674   1 437   70   65   1   1   2 277   1 949  

  Mining   1 792   1 589   845   734           2 637   2 323  
  In Situ   698   603   994   855           1 692   1 458  
  E&P Canada           110   91   50   39   119   98  
Total Canada   2 491   2 192   1 838   1 589   110   91   50   39   4 447   3 879  
North Sea           91   91   3   3   91   91  
Other International           142   49       142   49  

Total Proved   2 491   2 192   1 838   1 589   343   231   53   42   4 681   4 019  

  Mining   498   429   408   333           907   762  
  In Situ   1 156   940   329   241           1 485   1 182  
  E&P Canada           230   167   18   14   233   169  
Total Canada   1 655   1 369   737   574   230   167   18   14   2 624   2 113  
North Sea           37   37   2   2   38   38  
Other International           111   42       111   42  

Total Probable   1 655   1 369   737   574   378   246   20   16   2 773   2 192  

Proved Plus Probable                                          
  Mining   2 291   2 018   1 253   1 066           3 543   3 085  
  In Situ   1 854   1 543   1 322   1 097           3 177   2 639  
  E&P Canada           340   258   68   52   351   267  
Total Canada   4 145   3 561   2 575   2 163   340   258   68   52   7 071   5 991  
North Sea           128   128   5   5   129   129  
Other International           253   91       253   91  

Total Proved Plus Probable   4 145   3 561   2 575   2 163   721   477   73   58   7 454   6 211  

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


Reconciliation of Gross Oil Reserves(1)(2)(3)
as at December 31, 2014
(forecast prices and costs)

    SCO(4)   Bitumen   Light & Medium Oil   Natural Gas(5)   Total    
    Proved   Probable   Proved
  Proved   Probable   Proved
  Proved   Probable   Proved
  Proved   Probable   Proved
  Proved   Probable   Proved
    mmbbls   mmbbls   mmbbls   mmbbls   mmbbls   mmbbls   mmbbls   mmbbls   mmbbls   bcfe   bcfe   bcfe   mmboe   mmboe   mmboe    


December 31, 2013   1 863   520   2 382   845   397   1 241               2 707   916   3 624    

  Extensions & Improved Recovery(6)                                  

  Technical Revisions(7)   18   (21 ) (3 )   12   12               18   (10 ) 9    




  Economic Factors(9)                                  

  Production   (89 )   (89 )                   (89 )   (89 )  

December 31, 2014   1 792   498   2 291   845   408   1 253               2 637   907   3 543    

In Situ                                                                

December 31, 2013   715   1 092   1 807   1 043   457   1 500               1 758   1 550   3 307    

  Extensions & Improved Recovery(6)                                  

  Technical Revisions(7)   8   64   72   (7 ) (129 ) (136 )             2   (65 ) (63 )  




  Economic Factors(9)                                  

  Production   (25 )   (25 ) (42 )   (42 )             (67 )   (67 )  

December 31, 2014   698   1 156   1 854   994   329   1 322               1 692   1 485   3 177    

E&P Canada                                                                

December 31, 2013               70   281   351   57   41   97   79   288   367    

  Extensions & Improved Recovery(6)               1   10   11   10   2   12   2   10   13    

  Technical Revisions(7)               61   (59 ) 2   11   (15 ) (3 ) 63   (62 ) 2    



  Dispositions               (3 ) (2 ) (5 ) (19 ) (10 ) (29 ) (6 ) (4 ) (10 )  

  Economic Factors(9)                     (2 ) (1 ) (2 )        

  Production               (19 )   (19 ) (7 )   (7 ) (20 )   (20 )  

December 31, 2014               110   230   340   50   18   68   118   233   351    

Total Canada                                                                

December 31, 2013   2 577   1 612   4 189   1 887   854   2 741   70   281   351   57   41   97   4 544   2 754   7 298    

  Extensions & Improved Recovery(6)               1   10   11   10   2   12   2   10   13    

  Technical Revisions(7)   27   43   70   (7 ) (117 ) (124 ) 61   (59 ) 2   11   (15 ) (3 ) 83   (136 ) (53 )  



  Dispositions               (3 ) (2 ) (5 ) (19 ) (10 ) (29 ) (6 ) (4 ) (10 )  

  Economic Factors(9)                     (2 ) (1 ) (2 )        

  Production   (114 )   (114 ) (42 )   (42 ) (19 )   (19 ) (7 )   (7 ) (176 )   (176 )  

December 31, 2014   2 491   1 655   4 145   1 838   737   2 575   110   230   340   50   18   68   4 447   2 624   7 071    

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


Reconciliation of Gross Oil Reserves(1)(2)(3) (continued)
as at December 31, 2014
(forecast prices and costs)

    SCO(4)   Bitumen   Light & Medium Oil   Natural Gas(5)   Total    
    Proved   Probable   Proved
  Proved   Probable   Proved
  Proved   Probable   Proved
  Proved   Probable   Proved
  Proved   Probable   Proved
    mmbbls   mmbbls   mmbbls   mmbbls   mmbbls   mmbbls   mmbbls   mmbbls   mmbbls   bcfe   bcfe   bcfe   mmboe   mmboe   mmboe    

North Sea                                                                

December 31, 2013               107   36   144   5   3   8   108   37   145    

  Extensions & Improved Recovery(6)                                  

  Technical Revisions(7)               3   (1 ) 2   1   (1 )   3   (1 ) 2    




  Economic Factors(9)               (2 ) 2           (2 ) 2      

  Production               (17 )   (17 ) (3 )   (3 ) (17 )   (17 )  

December 31, 2014               91   37   128   3   2   5   91   38   129    

Other International                                                                

December 31, 2013               151   112   263         151   112   263    

  Extensions & Improved Recovery(6)                 1   1           1   1    

  Technical Revisions(7)               (6 ) (2 ) (8 )       (6 ) (2 ) (8 )  




  Economic Factors(9)               (1 )           (1 )      

  Production               (2 )   (2 )       (2 )   (2 )  

December 31, 2014               142   111   253         142   111   253    


December 31, 2013   2 577   1 612   4 189   1 887   854   2 741   329   429   758   62   44   105   4 804   2 902   7 706    

  Extensions & Improved Recovery(6)               1   11   12   10   2   12   2   12   14    

  Technical Revisions(7)   27   43   70   (7 ) (117 ) (124 ) 58   (63 ) (4 ) 12   (15 ) (3 ) 80   (140 ) (59 )  



  Dispositions               (3 ) (2 ) (5 ) (19 ) (10 ) (29 ) (6 ) (4 ) (10 )  

  Economic Factors(9)               (3 ) 3     (2 ) (1 ) (2 ) (3 ) 3   (1 )  

  Production   (114 )   (114 ) (42 )   (42 ) (38 )   (38 ) (10 )   (10 ) (196 )   (196 )  

December 31, 2014   2 491   1 655   4 145   1 838   737   2 575   343   378   721   53   20   73   4 681   2 773   7 454    

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


Notes to Reserves Data Tables
as at December 31, 2014

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

Reserves data tables may not add due to rounding.

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

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

Includes associated and non-associated gas (combined) as well as NGLs (1 mmbbls of proved and 1 mmbbls of proved plus probable NGLs reserves (gross) as at December 31, 2014).

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

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

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

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

Definitions for Reserves Data Tables and Best Estimate Contingent Resources

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

Gross means:

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

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

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

Net means:

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

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

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

Reserves Categories

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

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

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

Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. Proved reserves estimates should target at least a 90% probability that the quantities actually recovered will equal or exceed the estimate.

Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. That is, proved plus probable reserves estimates should target at least a 50% probability that the quantities actually recovered will equal or exceed the estimate.

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

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

Developed reserves are those reserves that are expected to be recovered (i) from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (for example, when compared to the cost of drilling a well) to put the reserves on production, or (ii) through installed extraction equipment and infrastructure that is operational at the time of the reserves


estimate, if the extraction is by means not involving a well. The developed category may be subdivided into producing and non-producing.

Developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.

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

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

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

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


Future Net Revenues Tables and Notes(1)

Net Present Value of Future Net Revenues Before Income Taxes
as at December 31, 2014
(forecast prices and costs)

    (in $ millions, discounted at % per year)   Unit Value(2)  
    0%   5%   10%   15%   20%   ($/boe)  

Proved Developed Producing                          

  Mining   34 387   20 097   12 770   8 698   6 267   8.03  
  In Situ   6 629   5 762   5 071   4 514   4 059   18.24  
  E&P Canada   2 180   1 995   1 833   1 694   1 576   37.93  

Total Canada   43 195   27 853   19 674   14 907   11 902   10.27  

North Sea   4 774   3 993   3 438   3 030   2 721   47.93  
Other International              

Total Proved Developed Producing   47 969   31 846   23 111   17 937   14 622   11.63  

Proved Developed Non-Producing                          

  In Situ   1 112   951   824   722   639   27.98  
  E&P Canada   32   24   19   15   13   12.68  

Total Canada   1 144   975   843   737   651   27.25  

North Sea   218   179   152   132   116   45.40  
Other International   4 024   2 971   2 307   1 858   1 539   47.55  

Total Proved Developed Non-Producing   5 387   4 126   3 301   2 727   2 307   39.88  

Proved Undeveloped                          

  Mining   18 143   4 819   526   (1 148 ) (1 895 ) 0.72  
  In Situ   33 432   16 677   8 973   5 085   2 960   7.80  
  E&P Canada   1 678   821   302   (22 ) (227 ) 6.32  

Total Canada   53 253   22 318   9 800   3 915   838   5.07  

North Sea   779   676   593   525   469   36.52  
Other International   50   33   21   12   6   29.91  

Total Proved Undeveloped   54 082   23 027   10 414   4 452   1 313   5.34  


  Mining   52 529   24 916   13 296   7 550   4 371   5.72  
  In Situ   41 173   23 390   14 867   10 321   7 658   10.20  
  E&P Canada   3 890   2 840   2 153   1 688   1 362   22.07  

Total Canada   97 592   51 146   30 316   19 559   13 391   7.82  

North Sea   5 771   4 849   4 183   3 687   3 306   45.81  
Other International   4 075   3 004   2 327   1 870   1 545   47.30  

Total Proved   107 438   58 999   36 827   25 116   18 242   9.16  


  Mining   39 290   11 687   5 464   3 330   2 347   7.17  
  In Situ   70 813   19 482   7 344   3 637   2 200   6.22  
  E&P Canada   14 898   8 988   6 020   4 319   3 248   35.57  

Total Canada   125 002   40 156   18 829   11 287   7 796   8.91  

North Sea   3 102   2 249   1 712   1 355   1 104   45.24  
Other International   4 872   2 723   1 670   1 106   777   40.03  

Total Probable   132 976   45 128   22 212   13 747   9 677   10.13  

Proved Plus Probable                          

  Mining   91 820   36 603   18 760   10 880   6 718   6.08  
  In Situ   111 987   42 871   22 212   13 958   9 858   8.42  
  E&P Canada   18 788   11 828   8 173   6 007   4 610   30.63  

Total Canada   222 595   91 303   49 145   30 845   21 187   8.20  

North Sea   8 873   7 098   5 895   5 042   4 410   45.64  
Other International   8 947   5 727   3 998   2 976   2 322   43.96  

Total Proved Plus Probable   240 415   104 127   59 038   38 863   27 919   9.50  

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


Net Present Value of Future Net Revenues After Income Taxes
as at December 31, 2014
(forecast prices and costs)

    (in $ millions, discounted at % per year)    
    0%   5%   10%   15%   20%    

Proved Developed Producing                        

  Mining   26 389   15 303   9 669   6 562   4 716    
  In Situ   5 485   4 767   4 195   3 734   3 358    
  E&P Canada   1 847   1 691   1 551   1 432   1 331    

Total Canada   33 722   21 761   15 416   11 728   9 405    

North Sea   1 528   1 286   1 111   982   884    
Other International              

Total Proved Developed Producing   35 250   23 047   16 527   12 710   10 289    

Proved Developed Non-Producing                        

  In Situ   822   701   607   531   469    
  E&P Canada   32   24   19   15   13    

Total Canada   854   725   625   546   482    

North Sea   93   79   69   61   55    
Other International   1 435   1 064   830   671   558    

Total Proved Developed Non-Producing   2 383   1 869   1 524   1 278   1 095    

Proved Undeveloped                        

  Mining   14 658   3 747   206   (1 182 ) (1 806 )  
  In Situ   24 557   11 903   6 176   3 327   1 790    
  E&P Canada   1 268   581   161   (101 ) (269 )  

Total Canada   40 482   16 231   6 543   2 044   (285 )  

North Sea   292   260   233   210   191    
Other International   17   11   6   3      

Total Proved Undeveloped   40 791   16 501   6 782   2 256   (94 )  


  Mining   41 047   19 050   9 875   5 380   2 910    
  In Situ   30 864   17 371   10 978   7 592   5 617    
  E&P Canada   3 147   2 296   1 731   1 346   1 075    

Total Canada   75 058   38 717   22 584   14 318   9 602    

North Sea   1 913   1 625   1 413   1 253   1 130    
Other International   1 453   1 075   836   674   558    

Total Proved   78 424   41 417   24 833   16 245   11 290    


  Mining   29 323   8 654   4 039   2 479   1 770    
  In Situ   52 422   14 257   5 369   2 671   1 623    
  E&P Canada   11 107   6 675   4 445   3 168   2 365    

Total Canada   92 852   29 586   13 853   8 318   5 758    

North Sea   1 198   898   701   567   472    
Other International   1 705   953   585   387   272    

Total Probable   95 756   31 437   15 139   9 272   6 501    

Proved Plus Probable                        

  Mining   70 370   27 704   13 915   7 859   4 680    
  In Situ   83 286   31 629   16 347   10 263   7 239    
  E&P Canada   14 254   8 971   6 177   4 514   3 440    

Total Canada   167 910   68 303   36 438   22 635   15 360    

North Sea   3 111   2 523   2 114   1 821   1 602    
Other International   3 158   2 028   1 420   1 061   830    

Total Proved Plus Probable   174 179   72 854   39 972   25 517   17 791    


Total Future Net Revenues
as at December 31, 2014
(forecast prices and costs)

(in $ millions, undiscounted)   Revenue   Royalties   Operating
  Future Net
Revenues Before
Income Tax
Income Tax
  Future Net
Revenues After
Income Tax

Proved Developed Producing                                  

  Mining   196 838   23 314   99 618   39 519     34 387   7 998   26 389  
  In Situ   22 104   1 352   11 323   2 650   149   6 629   1 143   5 485  
  E&P Canada   5 732   1 454   1 574   184   341   2 180   332   1 847  

Total Canada   224 674   26 120   112 516   42 353   490   43 195   9 473   33 722  

North Sea   7 418     2 275   223   146   4 774   3 246   1 528  
Other International                  

Total Proved Developed Producing   232 091   26 120   114 791   42 576   636   47 969   12 719   35 250  

Proved Developed Non-Producing                                  

  In Situ   2 059   286   515   136   11   1 112   290   822  
  E&P Canada   72   6   29   2   2   32     32  

Total Canada   2 131   292   544   138   12   1 144   290   854  

North Sea   355     118   10   9   218   125   93  
Other International   5 521     786   686   24   4 024   2 589   1 435  

Total Proved Developed Non-Producing   8 007   292   1 448   835   46   5 387   3 004   2 383  

Proved Undeveloped                                  

  Mining   77 524   10 754   36 911   11 717     18 143   3 485   14 658  
  In Situ   133 986   20 880   50 483   28 475   715   33 432   8 876   24 557  
  E&P Canada   5 472   445   1 430   1 825   95   1 678   410   1 268  

Total Canada   216 982   32 079   88 824   42 017   809   53 253   12 771   40 482  

North Sea   1 615     531   272   34   779   487   292  
Other International   76     4   22     50   33   17  

Total Proved Undeveloped   218 673   32 079   89 358   42 311   844   54 082   13 291   40 791  


  Mining   274 362   34 068   136 529   51 236     52 529   11 483   41 047  
  In Situ   158 148   22 518   62 321   31 262   874   41 173   10 309   30 864  
  E&P Canada   11 276   1 904   3 033   2 011   437   3 890   742   3 147  

Total Canada   443 786   58 490   201 883   84 509   1 311   97 592   22 535   75 058  

North Sea   9 387     2 923   504   189   5 771   3 858   1 913  
Other International   5 597     790   708   24   4 075   2 622   1 453  

Total Proved   458 771   58 490   205 597   85 721   1 525   107 438   29 015   78 424  


  Mining   131 305   21 056   56 881   14 078     39 290   9 967   29 323  
  In Situ   236 306   45 018   80 497   39 204   774   70 813   18 391   52 422  
  E&P Canada   27 137   7 261   3 481   1 303   193   14 898   3 792   11 107  

Total Canada   394 748   73 335   140 859   54 584   967   125 002   32 150   92 852  

North Sea   4 504     1 278   94   29   3 102   1 904   1 198  
Other International   5 423     338   209   4   4 872   3 167   1 705  

Total Probable   404 674   73 335   142 476   54 887   1 000   132 976   37 221   95 756  

Proved Plus Probable                                  

  Mining   405 667   55 124   193 410   65 314     91 820   21 450   70 370  
  In Situ   394 455   67 536   142 818   70 465   1 648   111 987   28 701   83 286  
  E&P Canada   38 413   9 166   6 515   3 313   630   18 788   4 534   14 254  

Total Canada   838 534   131 826   342 743   139 093   2 278   222 595   54 685   167 910  

North Sea   13 891     4 202   598   218   8 873   5 761   3 111  
Other International   11 020     1 128   917   28   8 947   5 789   3 158  

Total Proved Plus Probable   863 445   131 826   348 072   140 608   2 525   240 415   66 235   174 179  


Future Net Revenues by Production Group(1)
as at December 31, 2014
(forecast prices and costs)

(before income taxes, discounted at 10% per year)   $ millions   $/boe(2)  

Proved Developed Producing          

  Unconventional – Mining   12 770   8.03  

  Unconventional – In Situ   5 071   18.24  

Total Unconventional(3)   17 841   9.55  

Light & Medium Oil(4)   5 229   45.44  

Natural Gas(5)   41   8.24  

Total Proved Developed Producing   23 111   11.63  


  Unconventional – Mining   13 296   5.72  

  Unconventional – In Situ   14 867   10.20  

Total Unconventional(3)   28 163   7.45  

Light & Medium Oil(4)   8 604   37.14  

Natural Gas(5)   60   9.27  

Total Proved   36 827   9.16  

Proved Plus Probable          

  Unconventional – Mining   18 760   6.08  

  Unconventional – In Situ   22 212   8.42  

Total Unconventional(3)   40 972   7.16  

Light & Medium Oil(4)   17 988   37.62  

Natural Gas(5)   78   8.94  

Total Proved Plus Probable   59 038   9.50  

Figures may not add due to rounding.

Unit values are net present values of future net revenues before deducting estimated cash income taxes payable, discounted at 10%, divided by net reserves.

Total Unconventional includes SCO and bitumen.

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

Natural gas includes associated byproducts, including oil and NGLs.


Notes to Future Net Revenues Tables

In Situ Future Net Revenues

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

Future net revenues disclosed above include the estimated uplift to the future sales price and the associated upgrader operating and sustaining capital costs of upgrading approximately 40-50% of Firebag bitumen production to SCO from 2015 to 2034 and 100% thereafter. These factors translate to a $1.4 billion increase in the net present value of future net revenues (total proved plus probable reserves, before tax, discounted at 10%) from In Situ production relative to the scenario where none of the bitumen is upgraded.

Revenues and the natural gas fuel expense associated with excess power generated from cogeneration facilities at Firebag are included in future net revenues.

Prices Realized

For prices realized by Suncor during 2014, please see the Production History section contained within this Statement of Reserves Data and Other Oil and Gas Information.

Forecast Prices and Costs

Crude oil, natural gas and other important benchmark reference pricing, as well as inflation and exchange rates utilized in the GLJ Reports and the Sproule Reports, are as per GLJ's price forecast dated January 1, 2015, as set out below. To the extent that there are fixed or presently determinable future prices or costs to which Suncor is legally bound by contractual or other obligations to supply a physical product, including those for an extension period of a contract that is likely to be extended, those prices or costs have been incorporated into the forecast prices as applied to the pertinent properties. The forecast cost and price assumptions include increases in wellhead selling prices, take into account inflation with respect to future operating and capital costs, and assume the continuance of current laws and regulations.

Forecast prices included a US$/Cdn$ exchange rate of 0.85 in 2015 and 0.875 thereafter, a Cdn$/€ exchange rate of 1.45 and a Cdn$/£ exchange rate of 1.80. Forecast costs included a 2% inflation factor, except for costs for Mining, which included 4% inflation for 2016, 3% inflation for 2017 and 2% thereafter.


Prices Impacting Reserves Tables(1)

Forecast   Brent
North Sea(2)
  B.C. Gas
Station 2(7)
North Sea(8)

Year   US$/bbl   US$/bbl   Cdn$/bbl   Cdn$/bbl   Cdn$/bbl   Cdn$/mmbtu   Cdn$/mmbtu   Cdn$/mmbtu  

2015   67.50   62.50   54.35   64.71   69.24   3.31   3.16   8.82  

2016   82.50   75.00   67.20   80.00   85.60   3.77   3.62   9.43  

2017   87.50   80.00   72.00   85.71   91.71   4.02   3.87   10.00  

2018   90.00   85.00   76.80   91.43   97.83   4.27   4.12   10.29  

2019   95.00   90.00   81.60   97.14   103.94   4.53   4.38   10.86  

2020   100.00   95.00   86.40   102.86   110.06   4.78   4.63   11.43  

2021   101.35   98.54   89.19   106.18   113.62   5.03   4.88   11.58  

2022   103.38   100.51   90.98   108.31   115.89   5.28   5.13   11.81  

2023   105.45   102.52   92.79   110.47   118.20   5.53   5.38   12.05  

2024   107.56   104.57   94.65   112.67   120.56   5.71   5.56   12.29  

2025+   +2.0%/year   +2.0%/year   +2.0%/year   +2.0%/year   +2.0%/year   +2.0%/year   +2.0%/year   +2.0%/year  

Each price from the GLJ forecast was adjusted for quality differentials and transportation costs applicable to the specific product and evaluation area.

Price used when determining offshore light and medium oil reserves for E&P Canada, North Sea reserves and Other International reserves.

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

Price used when determining SCO reserves presented as In Situ and Mining reserves, and onshore light and medium oil reserves for E&P Canada.

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

Price used when determining natural gas input costs for the production of SCO and bitumen reserves.

Price used when determining natural gas reserves for E&P Canada areas.

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

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

Values presented in the table for Net Present Value of Future Net Revenues After Income Taxes reflect income tax burdens of assets at an individual asset level (for Mining, In Situ and E&P Canada) or at a business area or legal entity level (for North Sea) based on tax pools associated with that business area or legal entity. Income taxes for Other International assets are determined by their respective EPSAs. Suncor's actual corporate legal entity structure for income taxes and income tax planning has not been considered, and, therefore, the total value for income taxes presented in the table may not provide an estimate of the value at the corporate entity level, which may be significantly different. The 2014 audited Consolidated Financial S