SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 40-F
(Check One)
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Registration statement pursuant to Section 12 of the Securities Exchange Act of 1934 | ||
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or | ||
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Annual report pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 |
For fiscal year ended: |
December 31, 2014 No. 1-12384 |
SUNCOR ENERGY INC.
(Exact name of registrant as specified in its charter)
Canada |
1311,1321,2911, 4613,5171,5172 (Primary standard industrial classification code number, if applicable) |
98-0343201 (I.R.S. employer identification number, if applicable) |
150 - 6th Avenue S.W.
Box 2844
Calgary, Alberta, Canada T2P 3E3
(403) 296-8000
(Address and telephone number of registrant's principal executive office)
CT Corporation System
111 Eighth Avenue
New York, New York, U.S.A. 10011
(212) 894-8940
(Name, address and telephone number of agent for service in the United States)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class: |
Name of each exchange on which registered: |
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Common shares |
New York Stock Exchange |
Securities registered or to be registered pursuant to Section 12(g) of the Act:
None
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:
None
For annual reports, indicate by check mark the information filed with this form:
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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 outstanding |
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Preferred Shares |
None |
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the 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.
Yes |
ý | No | o |
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes |
o | No | o |
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).
ANNUAL INFORMATION FORM DATED FEBRUARY 26, 2015
TABLE OF CONTENTS
1 | Advisories | |
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2 | Glossary of Terms and Abbreviations | |
2 | Common Industry Terms | |
4 | Common Abbreviations | |
4 | Conversion Table | |
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5 | Corporate Structure | |
5 | Name and Incorporation | |
5 | Intercorporate Relationships | |
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6 | General Development of the Business | |
6 | Overview | |
8 | Three-Year History | |
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10 | Narrative Description of Suncor's Businesses | |
10 | Oil Sands | |
15 | Exploration and Production | |
19 | Refining and Marketing | |
22 | Other Suncor Businesses | |
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24 | Suncor Employees | |
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25 | Social and Environmental Policies | |
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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 | |
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54 | Industry Conditions | |
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60 | Risk Factors | |
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68 | Dividends | |
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69 | Description of Capital Structure | |
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71 | Market for Securities | |
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72 | Directors and Executive Officers | |
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78 | Audit Committee Information | |
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80 | Legal Proceedings and Regulatory Actions | |
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80 | Interest of Management and Others in Material Transactions | |
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80 | Transfer Agent and Registrar | |
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80 | Material Contracts | |
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80 | Interests of Experts | |
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81 | Disclosure Pursuant to the Requirements of the New York Stock Exchange | |
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81 | Additional Information | |
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82 | Advisory Forward-Looking Information and Non-GAAP Financial Measures | |
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Schedules | ||
A-1 | Schedule "A" Audit Committee Mandate | |
B-1 | Schedule "B" Suncor Energy Inc. Policy and Procedures for Pre-Approval of Audit and Non-Audit Services | |
C-1 | Schedule "C" Form 51-101F2 Report on Reserves Data by Independent Qualified Reserves Evaluator or Auditor | |
D-1 | Schedule "D" Form 51-101F2 Report on Reserves Data by Independent Qualified Reserves Evaluator or Auditor | |
E-1 | Schedule "E" Form 51-101F3 Report of Management and Directors on Reserves Data and Other Information |
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.
SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014 1
GLOSSARY OF TERMS AND ABBREVIATIONS
Common Industry Terms
Products
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.
Bitumen is a naturally occurring solid or semi-solid hydrocarbon, consisting mainly of heavier hydrocarbons that are too heavy or thick to flow or be pumped without being diluted or heated and that is not primarily recoverable at economic rates through a well without the implementation of enhanced recovery methods. After it is extracted, bitumen may be upgraded into crude oil and other petroleum products.
Light and Medium Oil is crude oil with a relative density greater than 22.3 degrees API gravity.
Oil sands are naturally occurring stratified deposits of unconsolidated sand/sandstone and other sedimentary rocks saturated with varying amounts of water and bitumen.
Synthetic crude oil (SCO) is a mixture of liquid hydrocarbons derived by upgrading bitumen, kerogen or other substances such as coal, or derived from gas to liquid conversion and may contain sulphur or other compounds. Yields of SCO from Suncor's upgrading processes are approximately 80% of bitumen feedstock input, and may vary depending on the source of bitumen. SCO may contain sulphur or other non-hydrocarbon compounds and has many similarities to crude oil. SCO with lower sulphur content is referred to as sweet synthetic crude oil, while SCO with higher sulphur content is referred to as sour synthetic crude oil.
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.
Wells:
Delineation wells are drilled for the purpose of assessing the stratigraphy, structure and bitumen saturation of an oil sands lease. The wells are also used to define known accumulations for the assignment of reserves.
Development wells are drilled inside the established limits of an oil or gas reservoir, or in close proximity to the edge of the reservoir, to the depth of a stratigraphic horizon known to be productive.
Disposal wells are drilled in which waste fluids can be injected for safe disposal. These wells are subject to regulatory requirement to avoid the contamination of freshwater aquifers.
Dry holes are exploratory or development wells found to be incapable of producing either oil or gas in sufficient quantities to justify the completion as an oil or gas well.
Exploratory wells are drilled in a territory without existing proved reserves, with the intention of discovering commercial reservoirs or deposits of crude oil and/or natural gas.
Infill wells are drilled between existing development wells to target regions of the reservoir containing bypassed hydrocarbon or to accelerate production.
Observation wells are used to monitor changes in a producing field. Parameters being monitored include fluid saturations and reservoir pressure.
2 SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014
Service wells are development wells drilled or completed for the purpose of supporting production in an existing field, such as wells drilled for the injection of gas or water.
Sidetrack wells are secondary wellbores drilled away from an original wellbore. These enable the bypass of an unusable section of the original wellbore or allow for exploration of a nearby geological feature.
Stratigraphic wells are usually drilled without the intention of being completed for production and are geologically directed to obtain information pertaining to a specific geologic condition, such as core hole drilling or delineation wells on oil sands leases, or to measure the commercial potential (i.e. size and quality) of a discovery, such as appraisal wells for offshore discoveries.
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.
Primary upgrading, also referred to as coking or thermal cracking, heats the bitumen in coke drums to remove excess carbon. The superheated hydrocarbon vapours are sent to fractionators where they condense into naphtha, kerosene and gas oil. Carbon residue, or coke, is removed from the coke drums periodically and later sold as a byproduct.
Secondary upgrading, a purification process also referred to as hydrotreating, adds hydrogen to, and reduces the sulphur and nitrogen of, primary upgrading output to create sweet SCO and diesel.
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.
SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014 3
Common Abbreviations
The following is a list of abbreviations that may be used in this AIF:
Measurement | ||
bbl(s) | barrel(s) | |
bbls/d | barrels per day | |
mbbls | 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 |
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U.S. | United States | |
U.K. | United Kingdom | |
B.C. | British Columbia | |
$ or Cdn$ | Canadian dollars | |
US$ | United States dollars | |
£ | Pounds sterling | |
€ | Euros | |
Products, Markets and Processes |
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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 |
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CORPORATE STRUCTURE
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 | |||
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Canadian operations | |||||
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Suncor Energy Oil Sands Limited Partnership | Canada | This partnership holds most of the company's oil sands assets. | |||
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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. | |||
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Suncor Energy Products Partnership | Canada | This partnership holds substantially all of the company's Canadian refining and marketing assets. | |||
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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. | |||
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U.S. operations | |||||
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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. | |||
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Suncor Energy (U.S.A.) Inc. | U.S. | A subsidiary through which our U.S. refining and marketing operations are conducted. | |||
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International operations | |||||
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Suncor Energy UK Limited | U.K. | A subsidiary through which certain of our operations are conducted in the U.K. | |||
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Suncor Energy Oil (North Africa) GmbH | Germany | A subsidiary through which the majority of our Libya operations are conducted. | |||
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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 ENERGY INC. ANNUAL INFORMATION FORM 2014 5
GENERAL DEVELOPMENT OF THE BUSINESS
Overview
Suncor is an integrated energy company headquartered in Calgary, Alberta, Canada. We are strategically focused on developing one of the world's largest petroleum resource basins Canada's Athabasca oil sands. In addition, we explore for, acquire, develop, produce and market crude oil and natural gas in Canada and internationally; we transport and refine crude oil, and we market petroleum and petrochemical products primarily in Canada. Periodically, we market third-party petroleum products. We also conduct energy trading activities focused principally on the marketing and trading of crude oil, natural gas and byproducts.
Suncor has classified its operations into the following segments:
OIL SANDS
Suncor's Oil Sands segment, with assets located in the 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:
EXPLORATION AND PRODUCTION
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.
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REFINING AND MARKETING
Suncor's Refining and Marketing segment consists of two primary operations:
CORPORATE, ENERGY TRADING AND ELIMINATIONS
The grouping Corporate, Energy Trading and Eliminations includes the company's investments in renewable energy projects, results related to energy marketing, supply and trading activities, and other activities not directly attributable to any other operating segment.
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Three-Year History
Over the last three years, several events have influenced the general development of Suncor's business.
2012
2013
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production levels as the ramp-up of Stage 4 was completed. The complex ended 2013 achieving daily production rates of approximately 95% of nameplate capacity of 180 mbbls/d.
2014
SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014 9
NARRATIVE DESCRIPTION OF SUNCOR'S BUSINESSES
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:
After overburden is removed, open-pit mining operations use shovels to excavate oil sands bitumen ore, which is trucked to sizers and breaker units that reduce the size of the ore. Next, a slurry of hot water, sand and bitumen is created and delivered via a pipeline to extraction plants. The raw bitumen is separated from the slurry using a hot water process that creates a bitumen froth. Naphtha is added to the bitumen froth to form a diluted bitumen, which is subsequently sent to a centrifuge plant that removes most of the remaining impurities and minerals. Coarse tailings produced in this process are placed directly into sand placement areas.
After the diluted bitumen is transferred to upgrading facilities, the naphtha is removed and recycled to be used again as diluent in extraction processes. Bitumen is upgraded through a coking and distillation process. The upgraded product, referred to as sour SCO, is either sold or upgraded further into sweet SCO by removing sulphur and nitrogen using a hydrotreating process. In addition to sweet and sour SCO, upgrading processes also produce diesel and other byproducts.
To generate steam for the mining and extraction process, the company uses either a cogeneration unit or coke-fired boilers. Electricity is generated by turbine generators, some of which are part of the Oil Sands Base cogeneration unit, or provided by cogeneration units at Firebag. Process water is used in extraction processes and then recycled.
In the normal course of operations, Suncor regularly conducts planned maintenance events at its facilities. Large planned maintenance events which require units to be taken offline to be completed are often referred to as turnarounds. Turnaround maintenance provides opportunities for both preventive maintenance and capital replacement, which are expected to improve reliability and operational efficiency. Production may be impacted during the turnaround cycle. Planned maintenance events generally occur on routine cycles, determined by historical operating performance, recommended usage factors or regulatory requirements. A turnaround typically involves shutting down the unit, inspecting it for wear or other damage, repairing or replacing components, and then restarting the unit.
Mining processes disturb areas of land that must be reclaimed. Land reclamation activities involve soil salvage and replacement, wetlands research, the protection of fish, waterfowl and other wildlife, and re-vegetation.
The extraction process produces tailings that are a mixture of water, clay, sand and residual bitumen. Suncor has developed a tailings management approach, known as TROTM. TROTM is expected to accelerate and improve the company's tailings management processes, eliminate the need for new tailings ponds at existing mining operations, and, in the years ahead, reduce the number of tailings ponds presently in operation.
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).
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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.
SAGD is an enhanced oil recovery technology for producing bitumen. It requires drilling pairs of horizontal wells with one located above the other. To help reduce land disturbance and improve cost efficiency, well pairs are drilled from multi-well pads. Low pressure steam is injected into the upper wellbore to create a high-temperature steam chamber underground. This process reduces the viscosity of the bitumen, allowing heated bitumen and condensed steam to drain into the lower wellbore and flow up to the surface aided by subsurface pumps or circulating gas.
The bitumen and water mixture is pumped to separation units at central processing facilities, where the water is removed from the bitumen, treated and recycled for use in steam generation. To facilitate shipment, In Situ operations blend diluent with the bitumen, or transport it on an insulated pipeline as hot bitumen.
To generate steam for operations, the company uses Once Through Steam Generators (OTSGs) or cogeneration units. OTSGs are powered by both purchased natural gas and produced natural gas recovered at central processing facilities. Cogeneration units are energy-efficient systems, which use natural gas combustion to power turbines that generate electricity and steam used in SAGD operations. Excess electricity generation from cogeneration units is used at Oil Sands Base facilities or sold to the power grid.
Central processing facilities, steam generation units and well pads are all subject to routine inspection and maintenance cycles.
SAGD production volumes are impacted by reservoir quality and the capacity of central processing facilities and steam generation units to process liquids and generate steam. As with conventional oil and gas properties, SAGD wells experience natural production declines after several years. In an effort to maintain bitumen supply, Suncor drills new wells from existing well pads or constructs new well pads.
In Situ Assets
Firebag
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
SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014 11
(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
Syncrude
Suncor holds a 12% interest in the Syncrude joint arrangement, located near Fort McMurray, which includes mining operations at Mildred Lake North and Aurora North. Syncrude also has regulatory approval to develop the Aurora South oil sands mining leases. In 2012, the Syncrude co-owners announced a plan to develop two mining areas adjacent to the current mine, subject to final sanctioning and regulatory approvals, which would consequently extend the life of Mildred Lake by approximately ten years. The plan proposes to use existing mining and extraction facilities 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.
12 SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014
New Technology
Technology is a fundamental component to Suncor's business. Suncor has pioneered commercial oil sands development and continues to advance technology through innovation and collaboration to improve efficiencies, lower costs and increase environmental performance. 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:
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 revenues |
mbbls/d |
% operating revenues |
|||||
|
|||||||||
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 | ||||||||
|
SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014 13
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:
From Hardisty, where Suncor owns storage capacity with additional capacity under contract, the company has various options for delivering product to customers:
Royalties
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:
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.
14 SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014
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.
Hebron
Discovered in 1980, the Hebron oilfield is located 340 km southeast of St. John's. The project is operated by
SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014 15
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
Buzzard
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.
16 SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014
Other Assets
Other Suncor exploration and appraisal initiatives in the North Sea include:
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
Libya
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).
Syria
In December 2011, amid continuing unrest in Syria, sanctions were introduced and Suncor declared force majeure under its contractual obligations and suspended its operations in the country. 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.
SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014 17
Exploration and Production Sales Summary:
2014 | 2013 | |||||||||
|
|
|||||||||
Sales Volumes | mboe/d |
% operating revenues |
mboe/d |
% operating revenues |
||||||
|
||||||||||
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
Royalties
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
18 SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014
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.
SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014 19
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 | |||||||||
|
20 SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014
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.
SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014 21
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 | ||||
|
2014 |
2013 |
|||||||||
Sales Volumes | mbbls/d |
% operating revenues |
mbbls/d |
% operating revenues |
||||||
|
||||||||||
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
22 SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014
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 | |||||||
|
||||||||||||
Non-operated | ||||||||||||
|
||||||||||||
Ripley | Ripley, Ontario | 50.0 | 76 | 38 | 2007 | |||||||
|
||||||||||||
Chin Chute | Taber, Alberta | 33.3 | 30 | 20 | 2006 | |||||||
|
||||||||||||
Magrath | Magrath, Alberta | 33.3 | 30 | 20 | 2004 | |||||||
|
||||||||||||
SunBridge | Gull Lake, Saskatchewan | 50.0 | 11 | 17 | 2002 | |||||||
|
SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014 23
SUNCOR EMPLOYEES
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.
24 SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014
SOCIAL AND ENVIRONMENTAL POLICIES
Suncor has a Standards of Business Conduct Code (the Code), which applies to Suncor's directors, officers, employees and contract workers. The Code requires strict compliance with legal requirements and sets Suncor's standards for the ethical conduct of our business. Topics addressed in the Code include competition, conflict of interest, the protection and proper use of corporate assets and opportunities, confidentiality, disclosure of material information, trading in shares and securities, communications to the public, improper payments, harassment, fair dealing in trade relations, and accounting, reporting and business controls. The Code is supported by detailed policy guidance and standards and a Code compliance program, under which every Suncor director, officer, employee and contract worker is required to annually read a summary of the Code and affirm that he or she has reviewed the summary, affirm that he or she understands the requirements of the Code, and provide confirmation of his or her compliance with the Code during the preceding year 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.
SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014 25
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION
Date of Statement
The Statement of Reserves Data and Other Oil and Gas Information outlined below is dated February 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
26 SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014
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.
SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014 27
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 | ||||||||||||||||||
(mmbbls) |
(mmbbls) |
(mmbbls) |
(bcfe) |
(mmboe) |
||||||||||||||||||
Gross |
Net |
Gross |
Net |
Gross |
Net |
Gross |
Net |
Gross |
Net |
|||||||||||||
|
||||||||||||||||||||||
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 | ||||||||||||||||||||||
Mining | | | | | | | | | | | ||||||||||||
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 | ||||||||||||
|
||||||||||||||||||||||
Proved | ||||||||||||||||||||||
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 | ||||||||||||
|
||||||||||||||||||||||
Probable | ||||||||||||||||||||||
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.
28 SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014
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 Plus Probable |
Proved | Probable |
Proved Plus Probable |
Proved | Probable |
Proved Plus Probable |
Proved | Probable |
Proved Plus Probable |
Proved | Probable |
Proved Plus Probable |
|||||||||||||||||||
|
|||||||||||||||||||||||||||||||||
mmbbls | mmbbls | mmbbls | mmbbls | mmbbls | mmbbls | mmbbls | mmbbls | mmbbls | bcfe | bcfe | bcfe | mmboe | mmboe | mmboe | |||||||||||||||||||
|
|||||||||||||||||||||||||||||||||
Mining | |||||||||||||||||||||||||||||||||
|
|||||||||||||||||||||||||||||||||
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 | |||||||||||||||
|
|||||||||||||||||||||||||||||||||
Discoveries(8) | | | | | | | | | | | | | | | | ||||||||||||||||||
|
|||||||||||||||||||||||||||||||||
Acquisitions | | | | | | | | | | | | | | | | ||||||||||||||||||
|
|||||||||||||||||||||||||||||||||
Dispositions | | | | | | | | | | | | | | | | ||||||||||||||||||
|
|||||||||||||||||||||||||||||||||
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 | ) | |||||||||||||
|
|||||||||||||||||||||||||||||||||
Discoveries(8) | | | | | | | | | | | | | | | | ||||||||||||||||||
|
|||||||||||||||||||||||||||||||||
Acquisitions | | | | | | | | | | | | | | | | ||||||||||||||||||
|
|||||||||||||||||||||||||||||||||
Dispositions | | | | | | | | | | | | | | | | ||||||||||||||||||
|
|||||||||||||||||||||||||||||||||
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 | ||||||||||||||
|
|||||||||||||||||||||||||||||||||
Discoveries(8) | | | | | | | | | | | | | | | | ||||||||||||||||||
|
|||||||||||||||||||||||||||||||||
Acquisitions | | | | | | | | | | | | | | | | ||||||||||||||||||
|
|||||||||||||||||||||||||||||||||
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 | ) | ||||||||||
|
|||||||||||||||||||||||||||||||||
Discoveries(8) | | | | | | | | | | | | | | | | ||||||||||||||||||
|
|||||||||||||||||||||||||||||||||
Acquisitions | | | | | | | | | | | | | | | | ||||||||||||||||||
|
|||||||||||||||||||||||||||||||||
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.
SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014 29
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 Plus Probable |
Proved | Probable |
Proved Plus Probable |
Proved | Probable |
Proved Plus Probable |
Proved | Probable |
Proved Plus Probable |
Proved | Probable |
Proved Plus Probable |
|||||||||||||||||||
|
|||||||||||||||||||||||||||||||||
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 | |||||||||||||||
|
|||||||||||||||||||||||||||||||||
Discoveries(8) | | | | | | | | | | | | | | | | ||||||||||||||||||
|
|||||||||||||||||||||||||||||||||
Acquisitions | | | | | | | | | | | | | | | | ||||||||||||||||||
|
|||||||||||||||||||||||||||||||||
Dispositions | | | | | | | | | | | | | | | | ||||||||||||||||||
|
|||||||||||||||||||||||||||||||||
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 | ) | ||||||||||||
|
|||||||||||||||||||||||||||||||||
Discoveries(8) | | | | | | | | | | | | | | | | ||||||||||||||||||
|
|||||||||||||||||||||||||||||||||
Acquisitions | | | | | | | | | | | | | | | | ||||||||||||||||||
|
|||||||||||||||||||||||||||||||||
Dispositions | | | | | | | | | | | | | | | | ||||||||||||||||||
|
|||||||||||||||||||||||||||||||||
Economic Factors(9) | | | | | | | (1 | ) | | | | | | (1 | ) | | | ||||||||||||||||
|
|||||||||||||||||||||||||||||||||
Production | | | | | | | (2 | ) | | (2 | ) | | | | (2 | ) | | (2 | ) | ||||||||||||||
|
|||||||||||||||||||||||||||||||||
December 31, 2014 | | | | | | | 142 | 111 | 253 | | | | 142 | 111 | 253 | ||||||||||||||||||
|
|||||||||||||||||||||||||||||||||
Total | |||||||||||||||||||||||||||||||||
|
|||||||||||||||||||||||||||||||||
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 | ) | |||||||||
|
|||||||||||||||||||||||||||||||||
Discoveries(8) | | | | | | | | | | | | | | | | ||||||||||||||||||
|
|||||||||||||||||||||||||||||||||
Acquisitions | | | | | | | | | | | | | | | | ||||||||||||||||||
|
|||||||||||||||||||||||||||||||||
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.
30 SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014
Notes to Reserves Data Tables
as at December 31, 2014
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:
Net means:
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
SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014 31
estimate, if the extraction is by means not involving a well. The developed category may be subdivided into producing and non-producing.
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.
32 SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014
Future Net Revenues Tables and Notes(1)
Net Present Value of Future Net Revenues Before Income Taxes
as at December 31, 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 | ||||||||||||||
|
||||||||||||||
Mining | | | | | | | ||||||||
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 | ||||||||
|
||||||||||||||
Proved | ||||||||||||||
|
||||||||||||||
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 | ||||||||
|
||||||||||||||
Probable | ||||||||||||||
|
||||||||||||||
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.
SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014 33
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 | |||||||||||||
|
|||||||||||||
Mining | | | | | | ||||||||
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 | ) | |||||||
|
|||||||||||||
Proved | |||||||||||||
|
|||||||||||||
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 | ||||||||
|
|||||||||||||
Probable | |||||||||||||
|
|||||||||||||
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 | ||||||||
|
34 SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014
Total Future Net Revenues
as at December 31, 2014
(forecast prices and costs)
(in $ millions, undiscounted) | Revenue | Royalties |
Operating Costs |
Development Costs |
Abandonment Expenses |
Future Net Revenues Before Deducting Future Income Tax Expenses |
Future Income Tax Expenses |
Future Net Revenues After Deducting Future Income Tax Expenses |
||||||||||
|
||||||||||||||||||
Proved Developed Producing | ||||||||||||||||||
|
||||||||||||||||||
Mining | 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 | ||||||||||||||||||
|
||||||||||||||||||
Mining | | | | | | | | | ||||||||||
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 | ||||||||||
|
||||||||||||||||||
Proved | ||||||||||||||||||
|
||||||||||||||||||
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 | ||||||||||
|
||||||||||||||||||
Probable | ||||||||||||||||||
|
||||||||||||||||||
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 | ||||||||||
|
SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014 35
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 | ||||
|
||||||
Proved | ||||||
|
||||||
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 | ||||
|
36 SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014
Notes to Future Net Revenues Tables
In Situ Future Net Revenues
Future net revenues for In Situ properties reflect the flexibility of Suncor's operations, which allows production from these properties to be either upgraded to SCO or sold as non-upgraded bitumen. The proportion of upgraded production is based on estimated available upgrading capacity and can vary depending on unplanned maintenance, fluctuations in production from mining and extraction operations, or changes in the company's overall Oil Sands development strategy, including with respect to planned upgrading capacity.
Future net revenues disclosed above include the estimated uplift to the future sales price and the associated upgrader operating and sustaining capital costs of upgrading approximately 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.
SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014 37
Prices Impacting Reserves Tables(1)
Forecast |
Brent North Sea(2) |
WTI Cushing Oklahoma |
WCS Hardisty Alberta(3) |
Light Sweet Edmonton Alberta(4) |
Pentanes Plus Edmonton Alberta(5) |
AECO Gas(6) |
B.C. Gas Westcoast Station 2(7) |
National Balancing Point North Sea(8) |
|||||||||
|
|||||||||||||||||
Year | US$/bbl | US$/bbl | Cdn$/bbl | Cdn$/bbl | Cdn$/bbl | Cdn$/mmbtu | Cdn$/mmbtu | Cdn$/mmbtu | |||||||||
|
|||||||||||||||||
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 | |||||||||
|
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 Statements and the MD&A should be consulted for information on income taxes at the corporate entity level.
38 SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014
Future Development Costs(1)
as at December 31, 2014
(forecast prices and costs)
($ millions) | 2015 | 2016 | 2017 | 2018 | 2019 | Remainder | Total |
Discounted At 10% |
||||||||||
|
||||||||||||||||||
Proved | ||||||||||||||||||
|
||||||||||||||||||
Mining | 3 602 | 4 016 | 3 004 | 1 667 | 1 857 | 37 091 | 51 236 | 23 602 | ||||||||||
|
||||||||||||||||||
In Situ | 1 285 | 1 071 | 1 101 | 1 273 | 1 110 | 25 422 | 31 262 | 11 771 | ||||||||||
|
||||||||||||||||||
E&P Canada | 797 | 471 | 167 | 91 | 87 | 398 | 2 011 | 1 614 | ||||||||||
|
||||||||||||||||||
Total Canada | 5 684 | 5 558 | 4 272 | 3 031 | 3 053 | 62 911 | 84 509 | 36 986 | ||||||||||
|
||||||||||||||||||
North Sea | 155 | 70 | 95 | 11 | 13 | 160 | 504 | 355 | ||||||||||
|
||||||||||||||||||
Other International | 40 | 74 | 31 | 32 | 33 | 498 | 708 | 335 | ||||||||||
|
||||||||||||||||||
Total Proved | 5 879 | 5 702 | 4 398 | 3 074 | 3 099 | 63 570 | 85 721 | 37 677 | ||||||||||
|
||||||||||||||||||
Proved Plus Probable | ||||||||||||||||||
|
||||||||||||||||||
Mining | 3 590 | 4 019 | 3 003 | 1 714 | 1 925 | 51 064 | 65 314 | 25 338 | ||||||||||
|
||||||||||||||||||
In Situ | 1 354 | 1 372 | 811 | 1 114 | 1 124 | 64 690 | 70 465 | 13 806 | ||||||||||
|
||||||||||||||||||
E&P Canada | 960 | 682 | 468 | 279 | 201 | 723 | 3 313 | 2 537 | ||||||||||
|
||||||||||||||||||
Total Canada | 5 904 | 6 073 | 4 282 | 3 107 | 3 250 | 116 477 | 139 092 | 41 681 | ||||||||||
|
||||||||||||||||||
North Sea | 181 | 88 | 95 | 11 | 13 | 211 | 598 | 404 | ||||||||||
|
||||||||||||||||||
Other International | 51 | 75 | 36 | 35 | 33 | 688 | 917 | 386 | ||||||||||
|
||||||||||||||||||
Total Proved Plus Probable | 6 136 | 6 236 | 4 412 | 3 153 | 3 296 | 117 376 | 140 608 | 42 471 | ||||||||||
|
Development costs include costs associated with both developed and undeveloped reserves. Significant development activities and costs for 2015 are expected to include:
Management currently believes that internally generated cash flows, existing and future credit facilities, and access to debt capital markets are sufficient to fund future development costs. There can be no guarantee that funds will be available or that Suncor will allocate funding to develop all of the reserves attributed in the GLJ Reports and the Sproule Reports. Failure to develop those reserves would have a negative impact on future cash flow from operating activities.
The interest or other costs of external funding are not included in the reserves and future net revenue estimates and could reduce reserves and future net revenue to some degree depending upon the funding sources utilized. Suncor does not anticipate that interest or other funding
SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014 39
costs would make development of any property uneconomic.
Abandonment and Reclamation Costs
The company completes an annual review of its consolidated abandonment and reclamation costs. This review considers the nature of Suncor's forecasted production and development plans, consistent with that assumed in our long-range planning, where determinable, for liabilities associated with its upstream operations as at December 31, 2014. Where no legal liability or constructive obligation for reclamation exists, potential costs have been excluded from the company's abandonment and reclamation cost estimates. Estimates are based on the anticipated method and extent of restoration, consistent with legal requirements, technological advances and the possible future use of the site.
As at December 31, 2014, Suncor estimated its undiscounted, uninflated abandonment and reclamation liability for surface leases, wells, facilities and pipelines pertaining to its upstream assets, to be approximately $8.7 billion (discounted at 10%, approximately $2.4 billion). This cost estimate does not include the company's estimated abandonment and reclamation costs for its Refining and Marketing assets ($0.2 billion, undiscounted and uninflated). Suncor estimates that it will incur $1.1 billion of its identified abandonment and reclamation costs during the next three years (undiscounted: 2015 $0.4 billion, 2016 $0.4 billion, 2017 $0.3 billion), over 80% of which is associated with Oil Sands mining operations. The $8.7 billion abandonment and reclamation costs are associated with Suncor's current disturbances and wells drilled as at December 31, 2014. This estimate does not include costs for future planned disturbances or future wells that have yet to be drilled.
Approximately $2.5 billion (undiscounted) has been deducted as abandonment costs in estimating the future net revenues from proved plus probable reserves. This $2.5 billion represents the abandonment obligation for approximately 2,100 net production wells and approximately 1,800 net service and other wells, including a forecasted number of future wells for undeveloped reserves related to in situ and conventional activities that are not included in Suncor's $8.7 billion total.
Abandonment and reclamation costs included in Suncor's $8.7 billion total that are excluded from the determination of future net revenues from reserves include, but are not limited to, costs related to the reclamation of disturbed land from oil sands mining activities, the treatment of oil sands tailings, the decommissioning of oil sands and natural gas processing facilities and well pads, lease sites, and the abandonment of wells for which no reserves have been assigned.
40 SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014
Additional Information Relating to Reserves Data
Gross Proved and Probable Undeveloped Reserves
The tables below outline the gross proved and probable undeveloped reserves and represent undeveloped reserves additions resulting from acquisitions, discoveries, infill drilling, improved recovery and/or extensions pertaining to the year in which the events first occurred.
Gross Proved Undeveloped Reserves(1)
(forecast prices and costs)
Prior | 2012 | 2013 | 2014 | |||||||||||||||
|
|
|
|
|||||||||||||||
First Attributed |
Total at December 31 2011 |
First Attributed |
Total at December 31 2012 |
First Attributed |
Total at December 31 2013 |
First Attributed |
Total at December 31 2014 |
|||||||||||
|
||||||||||||||||||
SCO (mmbbls) | ||||||||||||||||||
|
||||||||||||||||||
Mining | | | | | | | | | ||||||||||
|
||||||||||||||||||
In Situ | 502 | 502 | 46 | 493 | 75 | 564 | | 532 | ||||||||||
|
||||||||||||||||||
Total SCO | 502 | 502 | 46 | 493 | 75 | 564 | | 532 | ||||||||||
|
||||||||||||||||||
Bitumen (mmbbls) | ||||||||||||||||||
|
||||||||||||||||||
Mining | | | | | 845 | 845 | | 845 | ||||||||||
|
||||||||||||||||||
In Situ | 661 | 661 | 64 | 785 | 74 | 875 | | 830 | ||||||||||
|
||||||||||||||||||
Total Bitumen | 661 | 661 | 64 | 785 | 918 | 1 720 | | 1 674 | ||||||||||
|
||||||||||||||||||
Light & Medium Oil (mmbbls) | ||||||||||||||||||
|
||||||||||||||||||
E&P Canada(2) | 27 | 27 | 4 | 32 | 2 | 27 | 38 | 52 | ||||||||||
|
||||||||||||||||||
North Sea | 43 | 43 | | 32 | | 25 | | 16 | ||||||||||
|
||||||||||||||||||
Other International(3) | 6 | 6 | 4 | 4 | | 5 | | 2 | ||||||||||
|
||||||||||||||||||
Total Light & Medium Oil | 76 | 76 | 7 | 67 | 2 | 57 | 38 | 70 | ||||||||||
|
||||||||||||||||||
Natural Gas (bcfe)(4) | ||||||||||||||||||
|
||||||||||||||||||
E&P Canada(2) | 79 | 79 | | 80 | 4 | 5 | | | ||||||||||
|
||||||||||||||||||
North Sea | 3 | 3 | | 2 | | 1 | | 1 | ||||||||||
|
||||||||||||||||||
Other International(3) | | | | | | | | | ||||||||||
|
||||||||||||||||||
Total Natural Gas | 82 | 82 | | 82 | 4 | 6 | | 1 | ||||||||||
|
||||||||||||||||||
Total (mmboe) | 1 253 | 1 253 | 117 | 1 359 | 996 | 2 342 | 38 | 2 277 | ||||||||||
|
SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014 41
Gross Probable Undeveloped Reserves(1)
(forecast prices and costs)
Prior | 2012 | 2013 | 2014 | |||||||||||||||
|
|
|
|
|||||||||||||||
First Attributed |
Total at December 31 2011 |
First Attributed |
Total at December 31 2012 |
First Attributed |
Total at December 31 2013 |
First Attributed |
Total at December 31 2014 |
|||||||||||
|
||||||||||||||||||
SCO (mmbbls) | ||||||||||||||||||
|
||||||||||||||||||
Mining | 263 | 263 | | 260 | | 265 | | 265 | ||||||||||
|
||||||||||||||||||
In Situ | 1 212 | 1 212 | | 1 043 | | 1 074 | | 1 112 | ||||||||||
|
||||||||||||||||||
Total SCO | 1 475 | 1 475 | | 1 303 | | 1 339 | | 1 378 | ||||||||||
|
||||||||||||||||||
Bitumen (mmbbls) | ||||||||||||||||||
|
||||||||||||||||||
Mining | | | | | 397 | 397 | | 408 | ||||||||||
|
||||||||||||||||||
In Situ | 669 | 669 | | 594 | | 369 | | 268 | ||||||||||
|
||||||||||||||||||
Total Bitumen | 669 | 669 | | 594 | 397 | 766 | | 677 | ||||||||||
|
||||||||||||||||||
Light & Medium Oil (mmbbls) | ||||||||||||||||||
|
||||||||||||||||||
E&P Canada(2) | 219 | 219 | 5 | 222 | 22 | 236 | 10 | 189 | ||||||||||
|
||||||||||||||||||
North Sea | 17 | 17 | 2 | 33 | | 23 | | 13 | ||||||||||
|
||||||||||||||||||
Other International(3) | 14 | 14 | 8 | 8 | | 9 | 1 | 3 | ||||||||||
|
||||||||||||||||||
Total Light & Medium Oil | 251 | 251 | 14 | 262 | 22 | 267 | 11 | 205 | ||||||||||
|
||||||||||||||||||
Natural Gas (bcfe)(4) | ||||||||||||||||||
|
||||||||||||||||||
E&P Canada(2) | 92 | 92 | 1 | 54 | 17 | 21 | | 3 | ||||||||||
|
||||||||||||||||||
North Sea | 2 | 2 | | 4 | | 2 | | 1 | ||||||||||
|
||||||||||||||||||
Other International(3) | 416 | 416 | | | | | | | ||||||||||
|
||||||||||||||||||
Total Natural Gas | 510 | 510 | 1 | 57 | 17 | 23 | | 4 | ||||||||||
|
||||||||||||||||||
Total (mmboe) | 2 480 | 2 480 | 14 | 2 170 | 422 | 2 376 | 11 | 2 260 | ||||||||||
|
42 SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014
Undeveloped In Situ reserves, which constitute approximately 60% of Suncor's gross proved undeveloped reserves and 61% of Suncor's gross probable undeveloped reserves, will take several years to develop. Undeveloped In Situ reserves have been assigned to reserves areas which are not classified as developed producing. Where supported by core hole wells, proved undeveloped reserves have been attributed to regions within 1.2 km from currently drilled or near-term planned production wells where AER approval is pending and, in the case of Firebag, also within 2.4 km from producing wells. Management uses integrated plans to forecast future development. These detailed plans align current production, processing and pipeline capacities, capital spending commitments and future development for the next ten years, and are reviewed and updated annually for internal and external factors affecting planned activity. The timing associated with developing undeveloped reserves is a function of the forecasts of the declining production from existing In Situ wells. Suncor has delineated In Situ reserves to a high degree of certainty through seismic data and core hole drilling, consistent with COGE Handbook guidelines. In most cases, proved reserves have been drilled to a density of 16 wells per section, which is in excess of the eight wells per section required for regulatory approval. In order to determine the economic cutoffs of undeveloped reserves, geological information is tested against existing production analogues that use established technology.
Undeveloped Mining reserves constitute approximately 37% of Suncor's gross proved undeveloped reserves and 30% of Suncor's gross probable undeveloped reserves, and relate to the Fort Hills mining area and Syncrude Aurora South mining area, which have regulatory approvals substantially in place and are well-delineated by core hole drilling. First oil for the Fort Hills mining area is expected by the fourth quarter of 2017. The co-owners of Syncrude do not expect that the Aurora South mining area will come on-stream before 2024, when production from the Mildred Lake mining area is expected to be complete.
Undeveloped conventional (light and medium oil, natural gas and NGLs) reserves constitute approximately 3% of Suncor's gross proved undeveloped reserves and approximately 9% of Suncor's gross probable undeveloped reserves. Undeveloped conventional reserves primarily relate to the company's offshore assets at E&P Canada, mainly associated with Hebron which is currently under development (first oil expected in 2017), and underdrilled or undrilled fault blocks related to extension areas in Hibernia, White Rose and Terra Nova. In developing these reserves, Suncor considers existing facility capacity, capital allocation plans and remaining recoverable resources availability. Accordingly, in some cases, it will take longer than two years to develop all of the currently assigned undeveloped conventional reserves. Suncor plans to develop the majority of the conventional proved undeveloped reserves over the next five years and the majority of the conventional probable undeveloped reserves over the next seven years.
Properties with no Attributed Reserves
The following table is a summary of properties to which no reserves are attributed as at December 31, 2014. For lands in which Suncor holds interests in different formations under the same surface area pursuant to separate leases, the area has been counted for each lease.
Country |
Gross Hectares |
Net Hectares |
|||
|
|||||
Canada | 6 715 533 | 3 831 801 | |||
|
|||||
Libya | 2 950 978 | 1 339 489 | |||
|
|||||
U.S. Alaska | 798 040 | 265 987 | |||
|
|||||
Norway | 545 065 | 172 571 | |||
|
|||||
Syria(1) | 345 194 | 345 194 | |||
|
|||||
U.K. | 117 201 | 41 515 | |||
|
|||||
Australia (overriding royalty interest only) | 113 027 | | |||
|
|||||
Total | 11 585 038 | 5 996 557 | |||
|
Suncor's undeveloped petroleum assets include exploration properties in a very preliminary phase of evaluation, to discovery areas where tenure to the property is held indefinitely on the basis of hydrocarbon test results, but
SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014 43
where economic development is not currently possible or has not yet been sanctioned. Certain Mining and In Situ properties may be in a relatively mature phase of evaluation, where a significant amount of development has occurred; however, reserves cannot be attributed due to one or more contingencies, such as project sanction. In many cases where reserves are not attributed to lands containing one or more discovery wells, the key limiting factor is the lack of available production infrastructure. Each year, as part of the company's process to review the economic viability of its properties, some properties are selected for further development activities, while others are temporarily deferred, sold, swapped or relinquished back to the mineral rights' owner.
In 2015, Suncor's rights to 33,217 net hectares in Canada and 37,325 net hectares in Norway are scheduled to expire. Substantial portions of expiring lands may have their tenure continued beyond 2015 through the conduct of work programs and/or the payment of prescribed fees to the rights' owner. No land tenure expiries are scheduled to occur for either Mining or In Situ properties for 2015.
Oil and Gas Properties and Wells
The following table is a summary of oil and gas wells associated with the company's operations as at December 31, 2014.
Oil Wells | Natural Gas Wells | ||||||||||||||||
|
|
||||||||||||||||
Producing | Non-Producing(1)(2) | Producing | Non-Producing(1)(2) | ||||||||||||||
|
|
|
|
||||||||||||||
Gross | Net | Gross | Net | Gross | Net | Gross | Net | ||||||||||
|
|||||||||||||||||
Alberta In Situ(3) | 249.0 | 249.0 | 126.0 | 126.0 | | | | | |||||||||
|
|||||||||||||||||
British Columbia | | | | | 36.0 | 31.0 | 9.0 | 8.4 | |||||||||
|
|||||||||||||||||
Newfoundland | 68.0 | 17.6 | 1.0 | 0.3 | | | | | |||||||||
|
|||||||||||||||||
North Sea | 33.0 | 9.8 | 4.0 | 1.2 | | | | | |||||||||
|
|||||||||||||||||
Other International(4) | | | 419.0 | 211.1 | | | 6.0 | 6.0 | |||||||||
|
|||||||||||||||||
Total | 350.0 | 276.4 | 550.0 | 338.6 | 36.0 | 31.0 | 15.0 | 14.4 | |||||||||
|
There are no producing wells associated with Mining properties. Suncor has no proved developed non-producing reserves or probable developed non-producing reserves in its Mining reserves.
For In Situ properties, proved non-producing reserves and probable non-producing reserves are associated with wells that have been drilled within the last three years, which require further capital for completion and tie-in to facilities to bring the wells on-stream. Because this capital is small relative to the cost to drill, complete and tie-in a well pair, the associated reserves are considered developed.
Proved plus probable developed non-producing reserves for North Sea are primarily associated with recently drilled development wells to be brought on production in 2015.
For Other International, non-producing reserves are associated with wells in Libya that were suspended due to political unrest in the country, which resulted in the closure of export terminal operations at eastern Libyan seaports. Production in Libya was temporarily resumed in the last half of 2014 but was again shut in by year end and, as such, all associated reserves were classified as non-producing.
44 SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014
The table below summarizes the company's costs incurred related to its oil and gas activities for the year ended December 31, 2014.
($ millions) |
Exploration Costs |
Proved Property Acquisition Costs |
Unproved Property Acquisition Costs |
Development Costs |
Other Costs(1) |
Total | |||||||
|
|||||||||||||
Canada Mining and In Situ | 161 | | | 3 427 | 50 | 3 638 | |||||||
|
|||||||||||||
Canada E&P Canada | 62 | | 1 | 1 191 | | 1 254 | |||||||
|
|||||||||||||
Total Canada | 223 | | 1 | 4 618 | 50 | 4 892 | |||||||
|
|||||||||||||
North Sea | 176 | | | 342 | | 518 | |||||||
|
|||||||||||||
Other International | 58 | | | 19 | | 77 | |||||||
|
|||||||||||||
Total | 457 | | 1 | 4 979 | 50 | 5 487 | |||||||
|
Exploration and Development Activities
The table below outlines the gross and net exploratory and development wells the company completed during the year ended December 31, 2014.
Exploratory Wells(1) | Development Wells | |||||||||
|
|
|||||||||
Total number of wells completed | Gross | Net | Gross | Net | ||||||
|
||||||||||
Canada Oil Sands | ||||||||||
|
||||||||||
Oil | 1.0 | 1.0 | 33.0 | 33.0 | ||||||
|
||||||||||
Service(2) | 4.0 | 3.8 | 55.0 | 55.0 | ||||||
|
||||||||||
Stratigraphic Test(3) | 358.0 | 215.2 | 603.0 | 295.9 | ||||||
|
||||||||||
Total | 363.0 | 220.0 | 691.0 | 383.9 | ||||||
|
||||||||||
Canada E&P Canada | ||||||||||
|
||||||||||
Oil | | | 2.0 | 0.6 | ||||||
|
||||||||||
Dry Hole | | | 1.0 | 0.3 | ||||||
|
||||||||||
Natural Gas | | | 2.0 | 2.0 | ||||||
|
||||||||||
Service(2) | | | 3.0 | 0.8 | ||||||
|
||||||||||
Stratigraphic Test(3) | 1.0 | 0.3 | | | ||||||
|
||||||||||
Total | 1.0 | 0.3 | 8.0 | 3.7 | ||||||
|
||||||||||
North Sea | ||||||||||
|
||||||||||
Oil | | | 4.0 | 1.1 | ||||||
|
||||||||||
Service(2) | | | 1.0 | 0.3 | ||||||
|
||||||||||
Dry Hole | 2.0 | 0.6 | 2.0 | 0.6 | ||||||
|
||||||||||
Stratigraphic Test(3) | 3.0 | 0.9 | | | ||||||
|
||||||||||
Total | 5.0 | 1.5 | 7.0 | 2.0 | ||||||
|
||||||||||
Other International | ||||||||||
|
||||||||||
Dry Hole | 2.0 | 1.0 | | | ||||||
|
||||||||||
Total | 2.0 | 1.0 | | | ||||||
|
SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014 45
Significant exploration and development activities in 2014 included:
Production History(1)
The table below outlines the company's historical production information, by product type. Average price realized is net of transportation costs, but before royalties.
2014 | Q1 | Q2 | Q3 | Q4 | Year Ended | ||||||||
|
|||||||||||||
Canada Oil Sands(2) | |||||||||||||
|
|||||||||||||
Total production (mbbls/d) | 424.4 | 403.1 | 441.1 | 419.3 | 422.1 | ||||||||
|
|||||||||||||
Total In Situ bitumen production (mbbls/d) | 187.1 | 199.8 | 199.1 | 210.9 | 199.0 | ||||||||
|
|||||||||||||
|
|||||||||||||
($/bbl) | |||||||||||||
|
|||||||||||||
Average price realized | 96.49 | 99.33 | 91.87 | 73.20 | 90.27 | ||||||||
|
|||||||||||||
Royalties | (5.04 | ) | (6.88 | ) | (10.62 | ) | (2.79 | ) | (6.38 | ) | |||
|
|||||||||||||
Total cash operating costs(3) | (36.61 | ) | (35.89 | ) | (31.99 | ) | (35.32 | ) | (34.90 | ) | |||
|
|||||||||||||
In Situ cash operating costs(3) | (19.90 | ) | (17.80 | ) | (15.25 | ) | (14.05 | ) | (16.64 | ) | |||
|
|||||||||||||
Canada Light & Medium Oil(4) | |||||||||||||
|
|||||||||||||
Total production (mbbls/d) | 59.9 | 55.5 | 46.8 | 58.1 | 55.0 | ||||||||
|
|||||||||||||
|
|||||||||||||
($/bbl) | |||||||||||||
|
|||||||||||||
Average price realized | 119.62 | 120.44 | 110.41 | 78.51 | 106.24 | ||||||||
|
|||||||||||||
Royalties | (34.41 | ) | (34.78 | ) | (31.71 | ) | (14.52 | ) | (25.97 | ) | |||
|
|||||||||||||
Production costs | (10.14 | ) | (12.28 | ) | (13.74 | ) | (14.66 | ) | (13.11 | ) | |||
|
|||||||||||||
Netback(6) | 75.07 | 73.38 | 64.96 | 49.33 | 67.16 | ||||||||
|
|||||||||||||
North Sea Light & Medium Oil(5) | |||||||||||||
|
|||||||||||||
Total production (mboe/d) | 56.5 | 54.3 | 24.2 | 56.2 | 47.7 | ||||||||
|
|||||||||||||
|
|||||||||||||
($/boe) | |||||||||||||
|
|||||||||||||
Average price realized | 111.55 | 113.63 | 106.49 | 82.27 | 104.12 | ||||||||
|
|||||||||||||
Royalties | | | | | | ||||||||
|
|||||||||||||
Production costs | (5.77 | ) | (5.73 | ) | (14.74 | ) | (4.47 | ) | (6.42 | ) | |||
|
|||||||||||||
Netback(6) | 105.78 | 107.90 | 91.75 | 77.80 | 97.70 | ||||||||
|
46 SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014
The following table provides the production volumes on a working interest basis, before royalties for each of Suncor's significant fields for the year ended December 31, 2014.
SCO | Bitumen |
Light & Medium Oil |
|||||
|
|||||||
mbbls/d | mbbls/d | mbbls/d | |||||
|
|||||||
Mining Suncor | 213.0 | | | ||||
|
|||||||
Mining Syncrude | 31.0 | | | ||||
|
|||||||
Firebag | 75.6 | 75.4 | | ||||
|
|||||||
MacKay River | 0.3 | 26.4 | | ||||
|
|||||||
Buzzard | | | 47.1 | ||||
|
|||||||
GEAD | | | 0.6 | ||||
|
|||||||
Hibernia | | | 23.1 | ||||
|
|||||||
White Rose | | | 14.6 | ||||
|
|||||||
Terra Nova | | | 17.3 | ||||
|
|||||||
Total | 319.9 | 101.8 | 102.7 | ||||
|
Production Estimates
The table below outlines the production estimates for 2015 that are included in the estimates of gross proved reserves and gross probable reserves as at December 31, 2014. Production estimates for 2015 for proved plus probable reserves, evaluated as at December 31, 2014, from Suncor's mining operations (excluding Syncrude) are 226.2 mbbls/d of SCO, approximately 39% of total estimated production for 2015, and from Firebag are 159.2 mbbls/d of SCO and bitumen, approximately 28% of total estimated production for 2015.
SCO | Bitumen |
Light & Medium Oil |
Natural Gas | Total | ||||||||||||||||||
(mbbls/d) |
(mbbls/d) |
(mbbls/d) |
(mmcfe/d)(1) |
(mmboe/d) |
||||||||||||||||||
Gross |
Net |
Gross |
Net |
Gross |
Net |
Gross |
Net |
Gross |
Net |
|||||||||||||
|
||||||||||||||||||||||
Canada | ||||||||||||||||||||||
|
||||||||||||||||||||||
Proved | 316.2 | 308.4 | 113.3 | 109.6 | 51.9 | 39.3 | 19.3 | 15.9 | 484.6 | 460.0 | ||||||||||||
|
||||||||||||||||||||||
Probable | 19.1 | 18.9 | 3.2 | 3.1 | 7.1 | 6.2 | 1.8 | 1.6 | 29.7 | 28.5 | ||||||||||||
|
||||||||||||||||||||||
Proved Plus Probable | 335.3 | 327.3 | 116.6 | 112.7 | 59.0 | 45.5 | 21.2 | 17.5 | 514.3 | 488.5 | ||||||||||||
|
||||||||||||||||||||||
North Sea | ||||||||||||||||||||||
|
||||||||||||||||||||||
Proved | | | | | 48.0 | 48.0 | 5.0 | 5.0 | 48.8 | 48.8 | ||||||||||||
|
||||||||||||||||||||||
Probable | | | | | 2.4 | 2.4 | 0.8 | 0.8 | 2.6 | 2.6 | ||||||||||||
|
||||||||||||||||||||||
Proved Plus Probable | | | | | 50.5 | 50.5 | 5.8 | 5.8 | 51.4 | 51.4 | ||||||||||||
|
||||||||||||||||||||||
Other International | ||||||||||||||||||||||
|
||||||||||||||||||||||
Proved | | | | | 8.1 | 1.9 | | | 8.1 | 1.9 | ||||||||||||
|
||||||||||||||||||||||
Probable | | | | | | | | | | | ||||||||||||
|
||||||||||||||||||||||
Proved Plus Probable | | | | | 8.1 | 1.9 | | | 8.1 | 1.9 | ||||||||||||
|
||||||||||||||||||||||
Total | ||||||||||||||||||||||
|
||||||||||||||||||||||
Proved | 316.2 | 308.4 | 113.3 | 109.6 | 108.0 | 89.3 | 24.4 | 20.9 | 541.5 | 510.8 | ||||||||||||
|
||||||||||||||||||||||
Probable | 19.1 | 18.9 | 3.2 | 3.1 | 9.5 | 8.6 | 2.6 | 2.4 | 32.3 | 31.0 | ||||||||||||
|
||||||||||||||||||||||
Proved Plus Probable | 335.3 | 327.3 | 116.6 | 112.7 | 117.5 | 97.9 | 27.0 | 23.3 | 573.8 | 541.8 | ||||||||||||
|
SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014 47
Work Commitments
The practice of governments requiring companies to pledge to carry out work commitments in exchange for the right to carry out exploration for and development of hydrocarbons is common, particularly in unexplored or lightly explored regions of the world. The following table shows the estimated values of work commitments Suncor has made in regard to the lands it holds as at December 31, 2014. These commitments run through 2020 and beyond, and are primarily for conducting seismic programs and drilling exploration wells.
Country/Area ($ millions) |
2015 | Total | |||
|
|||||
Canada | 3 | 103 | |||
|
|||||
North Sea | 133 | 155 | |||
|
|||||
Other International | 10 | 416 | |||
|
Forward Contracts
Suncor may use financial derivatives to manage its exposure to fluctuations in commodity prices; however, Suncor did not consider any financial derivative transactions to be material in 2014. A description of Suncor's use of such instruments is provided in the 2014 audited Consolidated Financial Statements and related MD&A for the year ended December 31, 2014.
Tax Horizon
In 2014, Suncor was subject to cash tax in the majority of the local jurisdictions in which it generates earnings, including earnings related to its Canadian, North Sea and Other International production.
Contingent Resources
Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters, or lack of infrastructure or markets. The contingent resources estimates provided herein are best estimates of the quantities that are potentially recoverable. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. The best estimate of potentially recoverable volumes is generally prepared independent of the risks associated with achieving commercial production. Contingent resources can be further classified into the following subclasses:
Development Pending is where resolution of the final conditions for development is being actively pursued (high chance of development).
Development On Hold is where there is a reasonable chance of development, but there are major non-technical contingencies to be resolved that are usually beyond the control of the operator.
Development Unclarified is when the evaluation is incomplete and there is ongoing activity to resolve any risks or uncertainties.
Development Not Viable is where no further data acquisition or evaluation is currently planned and, hence, there is a low chance of development.
The discussion below also makes reference to evaluation scenario status and recovery technology status which are described in the COGE Handbook(1).
Evaluation scenario status, in relation to particular resources, is defined as follows:
Conceptual Study the initial stage of the development of a project scenario, with limited detail and typically based on limited information. Major parameters will be mostly assumed. While the results may be sufficient for initial delineation of the resources and for identifying the need for additional technical data, they will be insufficient for making economic decisions regarding development.
Pre-Development Study is an intermediate step in the development of a project evaluation scenario. The amount of information that is available for the reservoir of interest is greater than for a conceptual study. In particular, the petroleum initially in place has been reasonably well defined and the remaining uncertainty lies largely in the recovery factor and the economic viability. The level of economic analysis is sufficient to assess development options and overall project viability, but is insufficient for a final investment decision or for seeking outside major financing.
Development Study is the most detailed step in the development of a project evaluation scenario. It is based on a detailed geological and engineering study and economic analysis of information on the specific project, and provides
(1) These descriptions are abbreviated. For more complete descriptions, please see the description in the COGE Handbook.
48 SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014
sufficient information for the creation of a development plan, from which a development decision can be made.
Recovery technology status, in relation to particular resources, is defined as follows:
Established Technology methods that have been proven to be successful in commercial applications.
Technology Under Development a recovery process or process improvement project that has been determined to be technically viable via field test and is being field tested further to determine its economic viability in the subject reservoir.
Experimental Technology is a technology that is being field tested to determine the technical viability of applying a recovery process or process improvement project to unrecoverable discovered petroleum initially in place in a subject reservoir. Experimental technology differs from established technology and technology under development in that it is being tested for technical, not commercial, viability and is usually at a smaller scale.
GLJ conducted independent assessments of best estimate contingent resources volumes for all of Suncor's Mining and In Situ properties. Sproule Unconventional Limited conducted an independent assessment of Suncor's best estimate contingent resources contained in the Kobes/Montney shale formation of northeast B.C. (approximately 33% of Suncor's E&P contingent resources). Best estimate contingent resources for remaining conventional properties were prepared by Suncor's internal qualified reserves evaluators without independent audit or review. All contingent resources estimates were conducted in accordance with the COGE Handbook. The effective date of Suncor's best estimate of contingent resources is as of December 31, 2014, except in the case of Syria, which is as at December 31, 2011.
In 2011, the company's assets in Syria were impacted by political unrest and international sanctions. As a result, volumes previously reported as reserves based on an evaluation conducted by Sproule with an effective date of December 31, 2011 were reclassified to contingent resources in 2012 and have remained classified as contingent resources since that time. As political unrest in Syria has persisted throughout 2014, the company has not been able to update any information used by Sproule since the 2011 evaluation. The contingent resources estimate for Syria assumes that there has been no production subsequent to Sproule's 2011 evaluation and that infrastructure, including wells and pipelines, existing at December 31, 2011, exist at December 31, 2014. Therefore, these contingent resources are subject to uncertainty arising from any new information or change in circumstances, such as production, changes in asset performance or condition, or development activities, about which Suncor and Sproule are unaware.
There is no certainty that all or any portion of the contingent resources will be commercially viable to produce, or as to the timing of any such development. The economic viability of the contingent resources is dependent upon pricing and economic conditions. Estimates of contingent resources have not been adjusted for risk based on the chance of development. Significant factors that may change contingent resources estimates include further delineation drilling, future technology improvements, and additional processing capacity.
Generally, the contingencies which currently prevent the classification of the contingent resources as reserves include:
The additional facility design work, development plans, reservoir studies and delineation drilling are often completed in the course of preparing the company's application for regulatory approvals. Once there is a high level of certainty of receiving all regulatory, corporate and co-owner approvals, as applicable, and all other contingencies are removed, the resources may then be reclassified as reserves.
Also, the company has assumed that some Mining and In Situ contingent resources will be upgraded and sold as SCO. To the extent that these volumes are not upgraded, but rather sold as bitumen, contingent resources volumes reported would be lower for SCO and higher for bitumen, and total contingent resources volumes would be higher, because of the yield factor applied to bitumen volumes when upgraded into SCO. Conversely, to the extent that more volumes are upgraded, total contingent resources volumes would be lower.
Suncor's best estimate of gross contingent resources is set out in the table below.
SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014 49
SCO | Bitumen |
Light & Medium Oil |
Natural Gas(4) | Total | ||||||||
|
||||||||||||
Best Estimate Contingent Resources(1) | mmbbls | mmbbls | mmbbls | bcfe | mmboe | |||||||
|
||||||||||||
Mining | 4 426 | 818 | | | 5 244 | |||||||
|
||||||||||||
In Situ | 7 124 | 7 087 | | | 14 210 | |||||||
|
||||||||||||
E&P Canada(2) | | | 270 | 19 992 | 3 602 | |||||||
|
||||||||||||
Total Canada | 11 550 | 7 905 | 270 | 19 992 | 23 056 | |||||||
|
||||||||||||
North America Onshore U.S.(2) | | | | 449 | 75 | |||||||
|
||||||||||||
North Sea(2) | | | 69 | 37 | 75 | |||||||
|
||||||||||||
Other International(2)(3) | | | 402 | 1 147 | 593 | |||||||
|
||||||||||||
As at December 31, 2014 | 11 550 | 7 905 | 740 | 21 624 | 23 798 | |||||||
|
||||||||||||
As at December 31, 2013 | 10 680 | 8 122 | 705 | 22 428 | 23 245 | |||||||
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Contingent resources increased to 23,798 mmboe as at December 31, 2014 from 23,245 mmboe as at December 31, 2013, due primarily to an increase in In Situ contingent resources resulting from additional drilling that added bitumen contingent resources, primarily at the company's Lewis property. Sub-classifications are as follows: Development Pending (0.5%); Development On Hold (2.5%); Development Unclarified (88.4%); and Development Not Viable (8.6%).
Generally, the timing for the economic assessments of contingent resources will be determined by Suncor's long-term resource development plan and its forecast for economic conditions. Management uses integrated plans to forecast future development of resources. These plans consider current and planned production, current and forecasted market conditions, processing and pipeline capacities, capital spending commitments and related future development plans. These plans are reviewed and updated annually for internal and external factors affecting these planned activities. In particular, as Suncor's Oil Sands reserves base depletes, the company anticipates that it will look to develop its other Mining and In Situ properties, at which time the assessment of the economic viability of specific properties with contingent resources will be made.
Details of Suncor's contingent resources and a categorization of the contingencies ascribed to these resources are provided below. Except where otherwise noted, all contingent resources are based on Established Technology.
Oil Sands
Mining Contingent Resources
Mining contingent resources comprise approximately 22% of Suncor's total contingent resources, with 73% of these contingent resources related to properties in which Suncor has a 100% working interest and the remainder forming part of joint arrangements where Suncor has working interests varying from 12% to 40.8%.
Approximately 98% of Mining contingent resources are classified as Development Unclarified due to ongoing activities, such as core hole drilling and development planning, which are being undertaken to further assess future development plans for these contingent resources. Evaluation scenario statuses are primarily Conceptual Study (approximately 83%) and Pre-Development Study (approximately 16%) stage.
Economic Contingencies
The economic status of Suncor's Mining contingent resources is currently undetermined and is dependent on the company's long-term resource development plan and its forecast for economic conditions. Prior to reserves being assigned, these contingent resources require the completion of further resource studies and delineation drilling, and the preparation of development plans and facility designs.
Non-Technical Contingencies
The reclassification of all Mining contingent resources to reserves is contingent upon an assessment that development will be sanctioned and commence within a reasonable time frame.
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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. As a result, the volumes from the Joslyn North mining project have been classified as contingent resources.
Suncor's remaining Mining contingent resources are primarily contingent upon regulatory permits which must be obtained before project sanction decisions by Suncor's Board of Directors and/or co-owners, as applicable, are considered.
In Situ Contingent Resources
In Situ contingent resources comprise approximately 60% of Suncor's total contingent resources, with approximately 83% of these contingent resources related to properties in which Suncor has a 100% working interest and the remainder forming part of joint arrangements where Suncor has working interests varying from 10% to 75%. All In Situ contingent resources are associated with clastic or sandstone formations in the Athabasca oil sands area and approximately 83% of the contingent resources are in, or adjacent to, existing Firebag or MacKay River operations.
The primary risk associated with developing In Situ contingent resources relates to actual reservoir performance versus performance estimated based on geological data. The geological data varies substantially as a result of the density of core holes used in the analyses. The density can be as low as one well per section, and as high as 16 wells per section.
Suncor also owns mineral rights in 288 sections of the Grosmont carbonate formation, all at a 100% working interest. Core hole drilling completed on these sections has identified bitumen in the Grosmont, Upper Ireton and Nisku carbonate formations. In addition, Suncor has acquired data from numerous third-party pilots currently in operation in Grosmont carbonates. However, Suncor has not recognized any contingent resources in carbonate formations, as the viability of potential recovery processes in Suncor's carbonate interests has not yet been established.
All In Situ contingent resources are classified as Development Unclarified as a result of ongoing activities, such as seismic studies, core hole drilling, well testing and facility design, to further future development plans. Currently, these resources are at the Conceptual Study (approximately 7%) or Pre-Development (approximately 93%) stage and have primarily been based on the application of established SAGD technology. A small portion (less than 4%) having an upper zone of lower bitumen saturation is being field tested for commerciality and, hence, may be considered to have a recovery technology status of Technology Under Development. No contingent resources have been assigned to those new technologies described in the Narrative Description of Suncor's Businesses section as those technologies are currently considered experimental.
Economic Contingencies
The economic status of In Situ contingent resources is currently undetermined. However, technical net pay cutoffs are consistent with, and based upon, the same economic conditions as those used in the determination of proved plus probable reserves for Firebag and MacKay River, or are analogous to existing in situ SAGD operations successfully developed by other entities in the oil sands industry.
Contingent resources have been assigned to certain sections associated with Firebag and MacKay River. These volumes have not been classified as reserves in part because drilling density is inadequate for reliable mapping of effective pay intervals. However, the company has two-dimensional and three-dimensional seismic control, minimum mapped effective pay thicknesses of 15 metres for Firebag and 14 metres for MacKay River, and drilling density greater than or equal to one vertical well per section (except when that section is bound by sections with greater than or equal to one well per section). The company expects that an assessment of the economic viability of these resources will be undertaken when drilling density has increased such that it is adequate for reliable mapping of effective pay intervals and as the company's long-term plans require additional bitumen to keep existing processing capacities associated with Firebag and MacKay River operations full.
Contingent resources for other In Situ properties (Chard, Kirby, Lewis and Meadow Creek) were assigned to sections with core holes, or lands within two legal subdivisions of a delineation well and net continuous bitumen pay greater than approximately ten to 15 metres, depending on the horizon and property. Within the Athabasca oil sands, economic production has been demonstrated at these thicknesses. Prior to reserves being assigned, these contingent resources require the completion of further reservoir studies and delineation drilling, and the preparation of development plans and facility designs. The company expects that an assessment of the economic viability of these contingent resources will be undertaken as the company's long-term plans for its upgrading facilities require additional bitumen.
Non-Technical Contingencies
The reclassification of In Situ contingent resources to reserves is also largely contingent upon an assessment that development will be sanctioned and commence within a reasonable time frame. Certain contingent resources associated with Firebag and MacKay River have regulatory approvals in place, but final investment decisions are subject to detailed assessments of economic viability and
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approval by Suncor's Board. For remaining In Situ contingent resources, the company must still obtain regulatory approvals and project sanction by Suncor's Board and/or co-owners, as applicable.
Exploration and Production
Exploration and Production's contingent resources comprise approximately 18% of Suncor's total contingent resources. These contingent resources primarily include:
E&P's contingent resources are anticipated to be recoverable using established technologies including horizontal drilling, artificial lift and improved recovery methods such as waterflood.
For E&P Canada, most (approximately 73%) of light and medium oil contingent resources are associated with Hebron, Hibernia, Terra Nova and White Rose. These, and natural gas contingent resources in Kobes/Montney, are classified as Development Unclarified due to ongoing drilling activity to further assess the resources for development. These projects are in a Pre-Development Study stage. The remaining E&P Canada contingent resources are in the Conceptual Study stage and are currently classified as Development Not Viable. These are primarily related to geographically remote areas (Mackenzie Delta and Corridor, Arctic Islands, Labrador) which lack regional infrastructure and for which there are currently no plans for further data acquisition or evaluation.
North America Onshore U.S. properties are in the Conceptual Study stage and are currently classified as Development Not Viable. These are related to geographically remote areas in Alaska which lack regional infrastructure and for which there are currently no plans for further data acquisition or evaluation.
North Sea contingent resources are primarily in the Conceptual Study stage and are primarily classified as Development Unclarified due to ongoing drilling activity to further assess the resources for development.
Other International contingent resources are classified as Development On Hold due to ongoing political unrest in Libya and Syria which has precluded further assessment for an indefinite period of time.
Economic Contingencies
Except as noted below, the economic status of these contingent resources is undetermined. In general, further reservoir studies and delineation drilling, and preparation of development plans and facility designs are required to make a determination as to whether these contingent resources would be economic under current conditions.
For E&P Canada, contingent oil resources for Hebron, Terra Nova and White Rose and a portion of Hibernia (in total comprising approximately 4% of E&P Canada's total contingent resources) have been determined to be economic. The company anticipates that it will assess the economic viability of remaining Hibernia contingent oil resources within the next five years. Most (approximately 97%) of the contingent resources in the Kobes/Montney shale gas formation were determined to be economic (comprising approximately 39% of E&P Canada's total contingent resources). Remaining E&P Canada contingent resources are primarily in geographically remote areas and are currently sub-economic due to lack of processing and transportation infrastructure in these areas. These remote areas require commitments to identify the existence of sufficient resources for economic development, following which construction of processing facilities and/or transportation infrastructure would be required, which is not anticipated to occur within the next five years. Suncor working interests associated with these resources range from 8% to 100%. Timing for completion of economic evaluation of contingent resources in remote areas is not anticipated to occur within the next five years.
North America Onshore U.S. contingent resources are in geographically remote areas and are currently sub-economic due to lack of processing and transportation infrastructure in these areas. These remote areas require commitments to identify the existence of sufficient resources for economic development, following which construction of processing facilities and/or transportation infrastructure would be required, which is not anticipated to occur within the next five years.
North Sea contingent resources are in the appraisal stage. The economic status of these contingent resources is undetermined, but the company anticipates that it will assess their economic viability within the next five years.
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Other International contingent resources in Libya associated with developed fields are economic, while the economic viability of resources associated with fields that are not developed is undetermined, but the company anticipates that it will complete economic assessments for these fields in the next five years.
Non-Technical Contingencies
The reclassification of contingent resources associated with the Exploration and Production segment to reserves is contingent upon the receipt of appropriate regulatory approvals, and an assessment that development will be sanctioned by Suncor's Board and co-owners, as applicable, and commence within a reasonable time frame. Contingent resources for some E&P Canada onshore properties in geographically remote areas are also contingent upon the development of a suitable regulatory framework.
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The oil and natural gas industry is subject to extensive controls and regulations governing its operations (including land tenure, exploration, environmental, development, production, refining, transportation and marketing). These regulations are imposed by legislation enacted by various levels of government, and, with respect to export and taxation of oil and natural gas, by agreements among the governments of Canada, Alberta, British Columbia and Newfoundland and Labrador, among others, as well as the governments of the United States and other foreign jurisdictions in which we operate, all of which should be carefully considered by investors in the oil and gas industry. All current legislation is a matter of public record, and the company is unable to predict what additional legislation or amendments may be enacted. All governments have the ability to change legislation. Suncor may engage in the discussion on proposed changes to ensure Suncor's interests are recognized. The following discussion outlines some of the principal aspects of legislation, regulations and agreements governing Suncor's operations.
Pricing, Marketing and Exporting Crude Oil
The producers of oil are entitled to negotiate sales and purchase agreements directly with oil purchasers. Most agreements are linked to global oil prices. In Canada, oil exporters are also entitled to enter into export contracts. If the term of an export contract exceeds one year for light crude oil or exceeds two years for heavy crude oil (to a maximum of 25 years), the exporter is required to obtain an export licence from the National Energy Board (NEB). If the term of an export contract does not exceed one year for light crude oil or does not exceed two years for heavy crude oil, the exporter is required to obtain an order approving such export from the NEB. The NEB is currently drafting amending regulations to update the current regulations governing the issuance of export licences. The updating process is necessary to meet the criteria set out in the federal Jobs, Growth and Long-Term Prosperity Act, which received Royal Assent on June 29, 2012 (the Prosperity Act). In the transitory period, the NEB has issued, and is currently following an Interim Memorandum of Guidance concerning Oil and Gas Export Applications and Gas Import Applications under Part VI of the National Energy Board Act.
Under the North American Free Trade Agreement (NAFTA), Canada continues to remain free to determine whether exports of energy resources to the United States or Mexico will be allowed, provided that any export restrictions do not: (i) reduce the proportion of energy resources exported relative to the total supply of goods of the party maintaining the restriction as compared to the proportion prevailing in the most recent 36-month period; (ii) impose an export price higher than the domestic price (subject to an exception with respect to certain measures which only restrict the volume of exports); and (iii) disrupt normal channels of supply. All three countries are prohibited from imposing minimum or maximum export or import price requirements.
NAFTA requires energy regulators to ensure the orderly and equitable implementation of any regulatory changes and to ensure that the application of those changes will cause minimal disruption to contractual arrangements and avoid undue interference with pricing, marketing and distribution arrangements, all of which are important for Canadian oil and natural gas exports. Internationally, prices for crude oil and natural gas fluctuate in response to changes in the supply of and demand for crude oil and natural gas, market uncertainty and a variety of other factors beyond Suncor's control. These factors include, but are not limited to, the actions of OPEC, world economic conditions, government regulation, political developments, the foreign supply of oil, the price of foreign imports, the availability of alternate fuel sources, and weather conditions.
Royalties, Incentives and Income Taxes
Canada
The royalty regime is a significant factor in the profitability of SCO, bitumen, crude oil, NGLs and natural gas production. Royalties on production from lands other than Crown lands are determined by negotiations between the mineral freehold owner and the lessee, although production from such lands may be subject to certain provincial taxes. Crown royalties are determined by governmental regulation or by agreement with government in certain circumstances, which are subject to change as a result of numerous factors, including political considerations, and are generally calculated as a percentage of revenues received from the value of the gross production. The royalty rate generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date, method of recovery, depth of well, and the type or quality of the petroleum product produced. Other royalties and royalty-like interests are, from time-to-time, carved out of the owner's working interest through non-public transactions. These are often referred to as overriding royalties, gross overriding royalties, net profits interests or net carried interests.
For a discussion of the royalties in Alberta and Newfoundland and Labrador, refer to the Narrative Description of Suncor's Businesses section of this AIF.
The Canadian federal corporate income tax rate levied on taxable income was 15% for active business income, including resource income. The average provincial income tax rate for Suncor in 2014 was 10.66%.
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Other Jurisdictions
Operations in the U.S. are subject to the U.S. federal tax rate of 35% and various state-level taxes, primarily 4.63% in Colorado.
Suncor earns refundable tax credits related to eligible exploration spending in Norway at a rate of 78%.
Amounts presented in the 2014 audited Consolidated Financial Statements as royalties for production from our Libya operations are determined pursuant to EPSAs. The amounts calculated reflect the difference between Suncor's working interest in the particular project and the net revenue attributable to Suncor under the terms of the respective EPSAs. All government interests in these operations, except for income taxes, are presented as royalties.
Under our EPSAs in Libya, NOC remits taxes on Suncor's behalf. Until tax clearance certificates from tax authorities are received, Suncor records both an income tax payable to the taxation authority and an offsetting receivable from the NOC.
Land Tenure
In Canada, crude oil and natural gas located in the western provinces are owned predominantly by the respective provincial governments. Provincial governments grant rights to explore for and produce oil and natural gas pursuant to leases, licences and permits for varying terms, and on conditions set forth in provincial legislation, including requirements to perform specific work or make payments. Oil and natural gas located in such provinces can also be privately owned, and rights to explore for and produce such oil and natural gas are granted by lease on such terms and conditions as negotiated. In frontier areas of Canada, the mineral rights are primarily owned by the Canadian federal government, which, either directly or through shared jurisdiction agreements with the relevant provincial authorities, grants tenure in the form of exploration, significant discovery and production licences.
In many other international jurisdictions, crude oil and natural gas are most commonly owned by national governments that grant rights in the form of exploration licences and permits, production licences, PSCs and other similar forms of tenure. In all cases, Suncor's right to explore, develop and produce crude oil and natural gas is subject to ongoing compliance with the regulatory requirements established by the relevant country.
Environmental Regulation
The company is subject to environmental regulation under a variety of Canadian, U.S., U.K. and other foreign, federal, provincial, territorial, state and municipal laws and regulations. These regulatory regimes are laws of general application. Among other things, they provide for restrictions and prohibitions on the spill, release or emission of various substances produced in association with production that apply to Suncor and other companies in the energy industry. The regulatory regimes require Suncor to obtain operating licences and permits in order to operate, and impose certain standards and controls on activities relating to mining, oil and gas exploration, development and production, and the refining, distribution and marketing of petroleum products and petrochemicals. Environmental assessments and regulatory approvals are generally required before initiating most new major projects or undertaking significant changes to existing operations. In addition, this legislation requires that the company abandon and reclaim mine, well and facility sites to the satisfaction of regulatory authorities and, in some cases, this burden may remain with the company even after disposition of an asset to a third party. Compliance with such legislation can require significant expenditures, and a breach of these requirements may result in suspension or revocation of necessary licences and authorizations, civil liability for pollution damage, and the imposition of material fines and penalties. In addition to these specific, known requirements, Suncor expects future changes to environmental legislation, including anticipated legislation for air pollution (Criteria Air Contaminants) and greenhouse gas (GHG) emissions that will impose further requirements on companies operating in the energy industry.
A number of statutes, regulations and frameworks are under development or have been issued by various provincial regulators that oversee oil sands development, including the Joint Canada-Alberta Implementation Plan for Oil Sands Monitoring, and the Lower Athabasca Regional Plan (LARP) that implements a land-use regime in the Athabasca oil sands. These statutes, regulations and frameworks relate to such issues as tailings management, water use, air emissions and land use. While the financial implications of statutes, regulations and frameworks under development are not yet known, the company is committed to working with the appropriate regulatory bodies as they develop new policies, and to fully complying with all existing and new statutes, regulations and frameworks as they apply to the company's operations.
In general, there remains uncertainty around the outcomes and impacts of climate change and environmental laws and regulations, whether currently in force or enacted in the future. It is not currently possible to predict the nature of any future requirements or the impact on the company and its business, financial condition, results of operations and cash flow. We continue to actively work to mitigate our environmental impact, including taking action to reduce GHG emissions, investing in renewable forms of energy such as wind power and biofuels, continuing land reclamation activities, installing new emissions abatement equipment, investing in research and development and
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working to advance other environmental technologies such as solvent based extraction techniques.
The scope of recent environmental regulation and initiatives has had an impact on many areas important to Suncor's operations, some of which are summarized in the following subsections.
Climate Change
Suncor operates in many jurisdictions that have regulated, or have proposed to regulate, industrial GHG emissions. Those jurisdictions that have regulated GHG emissions generally have policies based on (i) caps on the intensity of GHG emissions including absolute GHG emissions limits, (ii) a cap-and-trade system, (iii) a tax, (iv) a hybrid of a tax and a cap-and-trade system, or (v) policies including other measures such as low carbon fuel and renewable fuel standards. Suncor participates in the consultation process for the design of proposed regulations and other efforts to harmonize regulations across jurisdictions within North America, both directly with government and indirectly through industry associations.
International Climate Change Agreements and Treaties
The Government of Canada has committed, pursuant to an agreement at the United Nations Framework Convention on Climate Change Conference of the Parties (UNFCCC COP) held in Copenhagen, Denmark, in 2009 (Copenhagen Accord), to reducing its GHG emissions by 17% below 2005 levels by 2020, in line with the reduction commitment made by the U.S. The Copenhagen Accord does not contain any binding commitments for reducing CO2 emissions, nor does it include any discussion of compliance mechanisms. The 2014 UNFCCC COP, held in Lima, Peru, continued to focus on creating a process and plan for all UN members to reach an agreement on 2020 commitments by the 2015 UNFCCC COP to be held in Paris, France. Countries are asked to pledge their intended nationally determined contributions by June 30, 2015.
Canadian Federal GHG Regulations
The Government of Canada continues to pursue harmonization with the U.S. (where appropriate) and has already implemented regulations on two of Canada's largest sources of emissions, being transportation and thermal electricity generated from coal (which includes petroleum coke). In line with the U.S., Canada has adopted a renewable fuels standard, mandating that 5% of gasoline supply come from renewable sources such as ethanol and that 2% of diesel supply come from bio-diesel. The Canadian federal government continues to address emissions of specific sectors of the economy and has been engaged in negotiations with the Canadian oil and gas industry on proposed regulations for the sector while ensuring the industry remains globally competitive. It is expected that provincial governments will enter into equivalency agreements for their own regulations with regard to a future federal regulation.
Canadian Provincial GHG Regulations
At the 2014 Canadian Premiers' conference, the leaders of all 10 provinces and three territories released an updated Canadian Energy Strategy (CES) that included renewed vision and principles for enhanced actions on clean energy and climate change in Canada. CES work, expected to wrap up in summer 2015, includes an enhanced focus on subnational co-operative climate change mitigation action, and highlights carbon pricing and carbon capture and storage.
In the absence of a federal GHG emissions policy, various Canadian provinces have responded with their own GHG emissions reduction targets and passed legislation enabling regulation of large GHG emitters. Suncor is committed to fully complying with existing regulations and will continue to constructively engage the appropriate governmental bodies in meaningful dialogue in an effort to develop a harmonized system which focuses on achieving actual reduction goals and sustainable resource development.
In July 2007, pursuant to the Specified Gas Emitters Regulation (SGER) enacted under the Climate Change and Emissions Management Act (Alberta), facilities in Alberta emitting more than 100,000 tonnes of CO2 equivalent (CO2e) per year became subject to intensity limits (GHG emissions per unit of production) and are required to reduce their intensity limits by 12% from an established baseline. Four facilities operated by Suncor in Alberta (Oil Sands Base plant, MacKay River operations, Firebag operations and the Edmonton refinery) are subject to, and continue to comply with, this legislation. For the 2013 compliance year, the total cost to comply with the SGER was approximately $9 million. Compliance under the SGER was achieved through reduced emissions per unit of production, and purchase and retirement of internally generated emission performance credits (EPCs) and externally purchased offset credits. The cost of compliance was slightly lower than the $15/tonne CO2e under Alberta's Climate and Emission Management Fund (Alberta Technology Fund) due to the realized cost for purchasing offsets and emission performance credits. For the 2014 compliance year, the total compliance costs to Suncor are estimated to be between $13 million and $18 million, based on a cost of $15/tonne of CO2e. The SGER was originally statutorily mandated to be renewed and is subject to possible revision in September 2014. That time frame has been extended to June 30, 2015, and it is currently unknown what changes will be implemented under any revised SGER.
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Several Canadian provinces (including British Columbia, Ontario and Quebec) are members of the Western Climate Initiative (WCI), a multi-jurisdictional partnership, whose members also include individual U.S. states. WCI was created in 2007 to address climate change with the initiative to reduce greenhouse gas emissions at the regional level to 15% below 2005 levels by 2020.
The Province of British Columbia enacted a carbon tax in 2008, which is capped at $30/tonne of CO2e through 2018. This carbon tax is revenue neutral, in that revenues are recycled back to taxpayers via tax reductions, and is applied on consumption. Suncor's natural gas production and gathering facilities, and refined product distribution terminals in B.C. do not exceed the 25,000 tonne reporting threshold under these regulations. The purchaser or user of fuels pays the B.C. carbon tax which is collected by Suncor and forwarded on to the government.
As of January 1, 2014, Quebec's cap-and-trade system became formally linked to the WCI. Allowances and offsets are fungible across the WCI. The California Cap-and-Trade Program and Quebec Cap-and-Trade System held their first joint carbon allowance auction on November 25, 2014. Suncor's Montreal refinery is subject to Quebec's cap-and-trade system for GHG emissions because it produces more than 25,000 tonnes of CO2e per year. Emitters must verify their emissions during specified compliance periods (the first period having commenced January 1, 2013 and ending December 31, 2014), and must either reduce their emissions or purchase eligible compliance mechanisms to cover their emissions above a specified cap. Quebec is responsible for setting the cap for the province and allocating allowances to emitters in its jurisdiction. For the 2014 compliance year, the total cost to comply under the Quebec cap-and-trade system was approximately $1.5 million. Effective January 1, 2015, the second compliance period under WCI commenced to cover emissions from transportation fuels and combustibles. As a wholesale transportation fuels distributor, Suncor is subject to the second compliance period based on the anticipated annual GHG emissions attributed to the use of fuel distributed to consumers and fuel consumed by Suncor. This second compliance period will end on December 31, 2017. The third compliance period, whose procedures will be identical to the second, will begin on January 1, 2018 and end on December 31, 2020. For the 2015 compliance year, the projected total compliance costs are estimated to be $72 million, consisting of $70 million to cover emissions attributed to the distribution of transportation fuels and $2 million attributed to stationary emissions at Suncor's Montreal refinery. It is expected that the majority of the compliance costs covering the emissions from transportation fuels will be passed through to the consumer, resulting in a net compliance cost anticipated to be less than $5 million.
In mid-2014, the premiers of Ontario and Quebec agreed to strengthen bilateral co-operation on a range of issues, including climate change and carbon pricing. Ontario continues to consult with stakeholders on the development of a GHG reduction program for Ontario's industrial sector, intended to achieve equivalency with federal government regulation.
U.S. GHG Regulations
The U.S. supports a clean energy standard that would reduce GHG emissions from the power sector and increase the use of cleaner sources of energy, including natural gas, nuclear power and "clean" coal. It is expected that the U.S. will work to advance the 2013 Climate Action Plan to reduce GHG emissions. In the absence of other federal legislation on GHG emissions, the current administration of the United States is endorsing the U.S. Environmental Protection Agency (EPA) to regulate GHG emissions under the Clean Air Act, starting with the thermal power sector. The implications on the oil and gas industry being regulated under the EPA and the timing of such regulations remain unknown. In the meantime, the EPA has implemented a mandatory GHG reporting rule for all large facilities (emitting greater than 25,000 tonnes of CO2e per year), which includes Suncor's refinery in Commerce City, Colorado.
The EPA has also mandated Renewable Fuel Standards 2, which encourages ethanol blending of up to 15% from the current 10% limit. Several factors will impact the ability of refiners and producers to achieve these requirements, including the lead time required for fleet turnover, the ability of retail stations to simultaneously provide both 10% and 15% fuels, and the inherent liability for ensuring consumers use the appropriate fuel for their vehicle.
The State of California passed AB32, which provides for a Low Carbon Fuel Standard (LCFS). After years of litigation around the constitutionality of AB32, the U.S. Supreme Court on June 30, 2014 validated the state's efforts to address climate change. AB32 was the first program in the U.S. to take a comprehensive, long-term approach to addressing climate change, and does so in a way that aims to improve the environment and natural resources while maintaining a robust economy in California. AB32 requires California to reduce its GHG emissions to 1990 levels by 2020.
International Regulations
Phase III (2008-2012) of the European Union Emissions Trading Scheme (EU ETS), which is applicable until 2020, impacts Suncor's non-operated offshore assets in the U.K. and Norway sectors of the North Sea. The EU ETS requires that member countries set emissions limits for installations in their country covered by the scheme and assigns such installations an emissions cap. Installations may meet their
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cap by reducing emissions or by buying allowances from other participants. Phase III will include a transition from gratis allocation to auctioning allowances.
As part of its ongoing business planning, Suncor assesses potential costs associated with CO2 emissions in its evaluation of future projects, based on the company's current understanding of pending and possible GHG regulations. Both the U.S. and Canada have indicated that climate change policies that may be implemented will attempt to balance economic, environmental and energy security concerns. In the future, the company expects that regulation will evolve with a moderate carbon price signal, and that the price regime will progress cautiously. Suncor will continue to review the impact of future carbon constrained scenarios on its strategy, using a price range of $15 to $60/tonne of CO2e as a base case, applied against a range of regulatory policy options and price sensitivities.
Land Use
In 2012, the Government of Alberta approved the LARP, which covers land-use restrictions in the Lower Athabasca region of Alberta, which includes leases in Suncor's Oil Sands segment. The LARP, developed as part of the Land-Use Framework under the Alberta Land Stewardship Act, identifies new conservation areas, as well as management frameworks to ensure the continued regional quality of air, surface water and groundwater. The new conservation areas do not overlap any of Suncor's leases. The management frameworks formalize a number of regulatory tools that are already used by the government to manage environmental aspects of oil sands development, including the use of environmental cumulative effects management on a regional scale, and may require Suncor to have greater participation in the evaluation of environmental issues. The frameworks include the following:
Additional environmental management frameworks for surface water quantity and tailings management (see below) are expected to be finalized in early 2015.
Reclamation and Tailings
In February 2009, the Energy Resources Conservation Board (ERCB) of Alberta, now the Alberta Energy Regulator or AER, released Directive 74 Tailings Performance Criteria and Requirements for Oil Sands Mining Schemes. The directive establishes performance criteria for tailings operations and requirements for the approval, monitoring and reporting of tailings ponds and plans. Suncor's new tailings management strategy TROTM was approved by the ERCB in June 2010. Suncor's mine plan is designed to facilitate the implementation of TROTM by providing space for the drying of tailings and ensuring adequate storage capacity for tailings from the Millennium and North Steepbank areas. Syncrude's tailings management plan was approved by the ERCB in 2010 and incorporates a multi-pronged approach that includes freshwater capping, composite tailings technology (accelerates water from tailings with additives), and the separation of water and tailings through the use of centrifuges.
The Government of Alberta also has in place the Mine Financial Security Program (MFSP), which holds oil sands miners responsible for all aspects of the remediation and surface reclamation work at their mine sites, and for the custody of the site until a reclamation certificate has been issued by the government. The MFSP requires a base amount of security for each project, which Suncor has provided in the form of letters of credit, and which would provide the funds necessary to safely secure the site. Suncor is in compliance with the MFSP. Additional security may be required under other conditions, such as failure to meet current reclamation plans, or when the estimated remaining production life of the mine reaches certain levels; however, Suncor has not been required to provide any additional security. The MFSP has been designed by the Government of Alberta to include a periodic review of the program to ensure it is functioning properly and provide early warning of any potential risks.
Alberta Environment and Sustainable Resource Development is currently finalizing the Tailings
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Management Framework (TMF). The TMF builds on, but does not replace, existing provincial legislation and policy on tailings management (such as Directive 74) and reclamation. The TMF is expected to establish fluid tailings volume triggers and limits to manage fluid tailings accumulation within oil sands mine tailings ponds. In addition, it is anticipated that the TMF will result in technological innovations in tailings management and reduce the overall volumes of fluid fine tailings associated with oil sands mining and extraction.
Joint Canada Alberta Implementation Plan for Oil Sands Monitoring
In 2012, Canada and Alberta adopted the Joint Canada Alberta Implementation Plan for Oil Sands Monitoring (Monitoring Plan). The intent of the Monitoring Plan is to provide scientifically rigorous, comprehensive, integrated and transparent environmental monitoring, including an improved understanding of the cumulative environmental impact of oil sands development. The total costs to the industry of enhanced monitoring under the Monitoring Plan have been estimated at approximately $50 million per year. The costs to Suncor under the Monitoring Plan are estimated at approximately $10 million per year.
Alberta has since created the Alberta Environmental Monitoring, Evaluation and Reporting Agency (AEMERA). AEMERA will steward the Monitoring Plan on behalf of the province and in conjunction with the Government of Canada.
Industry Collaboration Initiatives
For areas of environmental concern, the need for energy companies to increase collaboration with each other, and with their respective stakeholders, is a particularly critical issue for the oil sands industry. Suncor is a founding member of COSIA and is committed to collaborative action to accelerate improvements in environmental performance, including tailings, water, land and GHG emissions. COSIA works with other collaborative networks to share knowledge and expertise about new technologies and innovation related to environmental performance.
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Suncor is committed to a proactive program of enterprise risk management intended to enable decision-making through consistent identification of risks inherent to its assets, activities and operations. Some of these risks are common to operations in the oil and gas industry as a whole, while some are unique to Suncor. The company's enterprise risk committee (ERC), comprised of senior representatives from business and functional groups across Suncor, oversees entity-wide processes to identify, assess and report on the company's principal risks.
Volatility of Commodity Prices
Our financial performance is closely linked to prices for crude oil in our upstream business and prices for refined petroleum products in our downstream business, and, to a lesser extent, to natural gas prices in our upstream business, where natural gas is both an input and output of production processes. The prices for all of these commodities can be influenced by global and regional supply and demand factors, which are factors that are beyond our control and can result in a high degree of price volatility.
Crude oil prices are also affected by, among other things, global economic health and global economic growth (particularly in emerging markets), pipeline constraints, regional and international supply and demand imbalances, political developments, compliance or non-compliance with quotas agreed upon by OPEC members, decisions by OPEC not to impose quotas on its members, access to markets for crude oil, and weather. These factors impact the various types of crude oil and refined products differently and can impact differentials between light and heavy grades of crude oil (including blended bitumen), and between conventional and synthetic crude oil.
Refined petroleum products prices and refining margins are also affected by, among other things, crude oil prices, the availability of crude oil and other feedstock, levels of refined product inventories, regional refinery availability, marketplace competitiveness, and other local market factors. Natural gas prices in North America are affected primarily by supply and demand, and by prices for alternative energy sources.
In addition, oil and natural gas producers in North America, and particularly in Canada, may receive discounted prices for their production relative to certain international prices, due to constraints on the ability to transport and sell such products to international markets. A failure to resolve such constraints may result in continued discounted or reduced commodity prices realized by oil and natural gas producers such as Suncor.
Through the latter half of 2014 and into 2015, world oil prices have declined significantly. A prolonged period of low and/or volatile prices could affect the value of our upstream and downstream assets and the level of spending on growth projects, and could result in the curtailment of production from some properties and/or the impairment of that property's carrying value. Accordingly, low commodity prices, particularly for crude oil, could have a material adverse effect on Suncor's business, financial condition, results of operations and cash flow, and may also lead to the impairment of assets, or the cancellation or deferral of Suncor's growth projects.
Government Policy
Suncor operates under federal, provincial, state and municipal legislation in numerous countries. The company is also subject to regulation and intervention by governments in oil and gas industry matters, such as land tenure, royalties, taxes (including income taxes), government fees, production rates, environmental protection controls, safety performance, the reduction of GHG and other emissions, the export of crude oil, natural gas and other products, the company's interactions with foreign governments, the awarding or acquisition of exploration and production rights, oil sands leases or other interests, the imposition of specific drilling obligations, control over the development and abandonment of fields and mine sites (including restrictions on production) and possibly expropriation or cancellation of contract rights.
Changes in government policy or regulation, or interpretation thereof, could impact Suncor's existing and planned projects as well as impose costs on compliance resulting in increased capital expenditures and operating expenses. Changes in government policy or regulation can also have an indirect impact on Suncor, including opposition to new North American pipeline systems, such as the Keystone XL or the Northern Gateway proposals. The result of such changes can also lead to additional compliance costs and staffing and resource levels, and also increase exposure to other risks to Suncor's business, including environmental or safety non-compliance and permit approvals.
Income Taxes
Pursuant to the previously disclosed 2013 proposal letter from the Canada Revenue Agency (CRA), in 2014, the company received a Notice of Reassessment (NOR) from the CRA regarding the income tax treatment of realized losses in 2007 on the settlement of certain derivative contracts. The total amount of the NOR including tax, penalty and interest was approximately $920 million. Also during the year:
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Royalties
Royalties can be impacted by changes in crude oil and natural gas pricing, production volumes, and capital and operating costs by changes to existing legislation or PSCs, and by results of regulatory audits of prior year filings and other unexpected events. The final determination of these events may have a material impact on royalties payable to provincial and local governments and on the company's royalties expense.
The occurrence of any of the foregoing could have a material adverse effect on Suncor's business, financial condition, results of operations and cash flow.
Operational Outages and Major Environmental or Safety Incidents
Each of Suncor's primary operating businesses Oil Sands, E&P, and Refining and Marketing demands significant levels of investment in the design, operation and maintenance of facilities, and, therefore, carries the additional economic risk associated with operating reliably or enduring a protracted operational outage.
The company's businesses also carry the risks associated with environmental and safety performance, which is closely scrutinized by governments, the public and the media, and could result in a suspension of or inability to obtain regulatory approvals and permits, or, in the case of a major environmental or safety incident, fines, civil suits or criminal charges against the company.
Generally, Suncor's operations are subject to operational hazards and risks such as fires, explosions, blow-outs, power outages, severe winter climate conditions and other extreme weather conditions, rail car incident or derailment and the migration of harmful substances such as oil spills, gaseous leaks or a release of tailings into water systems, any of which can interrupt operations or cause personal injury or death, or damage to property, equipment, the environment, and information technology systems and related data and control systems.
The reliable operation of production and processing facilities at planned levels and Suncor's ability to produce higher value products can also be impacted by failure to follow operating procedures or operate within established operating parameters, equipment failure through inadequate maintenance, unanticipated erosion or corrosion of facilities, manufacturing and engineering flaws, and labour shortage or interruption. The company is also subject to operational risks such as sabotage, terrorism, trespass, theft and malicious software or network attacks.
In addition to the foregoing factors that affect Suncor's business generally, each business unit is susceptible to additional risks due to the nature of its business, as follows:
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Although the company maintains a risk management program, which includes an insurance component, such insurance may not provide adequate coverage in all circumstances, nor are all such risks insurable. It is possible that our insurance coverage will not be sufficient to address the costs arising out of the allocation of liabilities and risk of loss arising from Suncor operations.
The occurrence of any of the foregoing could have a material adverse effect on Suncor's business, financial condition, results of operations and cash flow.
Regulatory Approval and Compliance
Before proceeding with most major projects, including significant changes to existing operations, Suncor must obtain various federal, provincial or state permits and regulatory approvals. Suncor must also obtain licences to operate certain assets. These processes can involve, among other things, stakeholder consultation, environmental impact assessments and public hearings, and may be subject to conditions, including security deposit obligations and other commitments. Suncor can also be indirectly impacted by a third party's inability to obtain regulatory approval for a shared infrastructure project. Compliance can also be affected by the loss of skilled staff, inadequate internal processes and compliance auditing.
As part of ongoing operations, the company is also required to comply with a large number of EH&S regulations under a variety of Canadian, U.S., U.K. and other foreign, federal, provincial, territorial, state and municipal laws and regulations. Failure to comply with these regulations may result in the imposition of fines and penalties, production constraints, reputational damage, operating and growth permit applications, censure, liability for cleanup costs and damages, and the loss of important licences and permits.
Failure to obtain, comply with or maintain regulatory permits and approvals, or failure to obtain them on a timely basis or on satisfactory terms, could result in delays, abandonment or restructuring of projects and increased costs, all of which could have a material adverse effect on Suncor's business, financial condition, results of operations and cash flow.
Project Execution
There are certain risks associated with the execution of our major projects and the commissioning and integration of new facilities within our existing asset base.
Project execution risk consists of three related primary risks:
Project execution can also be impacted by:
The occurrence of any of the foregoing could have a material adverse effect on Suncor's business, financial condition, results of operations and cash flow.
Fossil Fuel Industry Reputation
Suncor works within an environment characterized by concerns over climate change, with environmental limits seen as a legitimate constraint on economic growth and increased activism and public opposition to fossil fuels. In addition, the social value proposition of resource deployment is being challenged.
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Future laws and regulations may impose significant liabilities on a failure to comply with their requirements. Concerns over climate change and fossil fuel extraction could lead governments to enact additional or more stringent laws and regulations applicable to Suncor.
Changes in environmental regulation could impact the demand, formulation or quality of our products, or by requiring increased capital expenditures or distribution costs, which may or may not be recoverable in the marketplace. The complexity and breadth of changes in environmental regulation make it extremely difficult to predict the potential impact to Suncor.
Climate Change
Suncor continues to actively monitor the international and domestic efforts to address climate change. While it currently appears that GHG regulations and targets will continue to become more stringent, and while Suncor will continue efforts to reduce the intensity of its GHG emissions, the absolute GHG emissions of our company are expected to rise as we pursue a prudent and planned growth strategy. Increases in GHG emissions may impact the profitability of our projects, as Suncor may be subject to incremental levies and taxes.
Land Reclamation
There are risks associated specifically with the company's ability to reclaim mature fine tailings, with TROTM or other methods and technologies. Suncor expects that TROTM will help the company reclaim existing tailings ponds by reducing the volumes of fluid fine tailings. The inability of TROTM or any other methods of technology and/or the increase in time to reclaim tailings ponds could increase Suncor's decommissioning and restoration cost estimates.
Alberta's Land-Use Framework
The implementation of, and compliance with, the terms of the LARP may adversely impact our current properties and projects in northern Alberta due to, among other things, environmental limits and thresholds. Due to the cumulative nature of the plan, the impact of the LARP on Suncor's operations may be outside of the control of the company, as Suncor's operations could be impacted as a result of restrictions imposed due to the cumulative impact of development, by the operators in the area and not solely in relation to Suncor's direct impact.
Alberta Environment Water Licences
We currently rely on fresh water, which is obtained under licences from Alberta Environment, to provide domestic and utility water at our Oil Sands operations. Water licences, like all regulatory approvals, contain conditions to be met in order to maintain compliance with the licence. There can be no assurance that the licences to withdraw water will not be rescinded or that additional conditions will not be added to these licences. There can be no assurance that the company will not have to pay a fee for the use of water in the future or that any such fees will be reasonable. In addition, the expansion of the company's projects may rely on securing licences for additional water withdrawal, and there can be no assurance that these licences will be granted or that they will be granted on terms favourable to Suncor.
There is a risk that future laws or changes to existing laws or regulations could cause capital expenditures and operating expenses to increase or the demand for our products to decrease. There is also a risk that Suncor could face litigation initiated by third parties relating to climate change.
The occurrence of any of the foregoing could have a material adverse effect on Suncor's business, financial condition, results of operations and cash flow.
Change Capacity
In order to achieve Suncor's business objectives, the company must operate efficiently, reliably and safely, and, at the same time, deliver growth and sustaining projects safely, on budget and on schedule. The ability to achieve these two sets of objectives is critically important to Suncor to deliver value to shareholders and stakeholders. These objectives also demand a large number of improvement initiatives that compete for resources, and may negatively impact the company should there be inadequate consideration of the cumulative impacts of prior and parallel initiatives on people, processes and systems. There is also a risk that these objectives may exceed Suncor's capacity to adopt and implement change. The occurrence of any of the foregoing could have a material adverse effect on Suncor's business, financial condition, results of operations and cash flow.
Cost Management
Suncor is exposed to the risk of escalating operating costs in both its Oil Sands business and other businesses. Suncor's inability to successfully manage costs may constrain its ability to execute high-quality projects that deliver lower operating costs. Factors contributing to these risks include, but are not limited to, the skills and resource shortage and the long-term success of existing and new in situ technologies. The risk of escalating operating costs in both its Oil Sands business and other businesses could have a material adverse effect on Suncor's business, financial condition, results of operations and cash flow.
Market Access
Suncor anticipates higher production of bitumen in future years, due mainly to production growth from debottlenecking at MacKay River and growth projects at
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Fort Hills. The markets for bitumen blends or heavy crude are more limited than those for light crude, making them more susceptible to supply and demand changes and imbalances (whether as a result of pipeline constraints or otherwise). Heavy crude oil generally receives lower market prices than light crude, due principally to the lower quality and value of the refined product yield, and the higher cost to transport the more viscous product on pipelines, and this price differential can be amplified due to supply and demand imbalances.
There is a risk that constrained market access for oil sands production due to insufficient pipeline takeaway capacity, growing inland production and refinery outages, creates risk of widening differentials that could impact the profitability of product sales which could have a material adverse effect on our business, financial condition, results of operations and cash flow.
Information Security
The efficient operation of Suncor's business is dependent on computer hardware and software systems. Information systems are vulnerable to security breaches by computer hackers and cyberterrorists. We rely on industry-accepted security measures and technology to securely maintain confidential and proprietary information stored on our information systems. However, these measures and technology may not adequately prevent security breaches. There is a risk that any significant interruption or the failure of these systems to perform as anticipated for any reason could disrupt our business and could result in decreased performance, production, or increased costs, and could have a material adverse effect on Suncor's business, financial condition, results of operations and cash flow.
Financial Risks
Energy Trading and Risk Management Activities and the Exposure to Counterparties
The nature of Suncor's energy trading and risk management activities, which may make use of derivative financial instruments to hedge its commodity price and other market risks, creates exposure to significant financial risks, which include, but are not limited to, the following:
The occurrence of any of the foregoing could have a material adverse effect on Suncor's business, financial condition, results of operations and cash flow.
Exchange Rate Fluctuations
Our Consolidated Financial Statements are presented in Canadian dollars. The majority of Suncor's revenues from the sale of oil and natural gas are based on prices that are determined by, or referenced to, U.S. dollar benchmark prices, while the majority of Suncor's expenditures are realized in Canadian dollars. The company also holds substantial amounts of U.S. dollar debt. Suncor's results, therefore, can be affected significantly by the exchange rates between the Canadian dollar and the U.S. dollar. The company also undertakes operations administered through international subsidiaries and, so, to a lesser extent, Suncor's results can be affected by the exchange rates between the Canadian dollar and the euro, and the Canadian dollar and the British pound. These exchange rates may vary substantially and may give rise to favourable or unfavourable foreign currency exposure.
The occurrence of any of the foregoing could have a material adverse effect on Suncor's business, financial condition, results of operations and cash flow.
Interest Rate Risk
We are exposed to fluctuations in short-term Canadian and U.S. interest rates as Suncor maintains a portion of its debt capacity in revolving and floating rate bank facilities and commercial paper, and invests surplus cash in short-term debt instruments. We are also exposed to interest rate risk when debt instruments are maturing and require refinancing, or when new debt capital needs to be raised. Unfavourable changes in interest rates could have a material adverse effect on Suncor's business, financial condition, results of operations and cash flow.
Issuance of Debt and Debt Covenants
Suncor expects that future capital expenditures will be financed out of cash generated from operations and borrowings. This ability is dependent on, among other factors, commodity prices, the overall state of the capital markets and investor appetite for investments in the energy industry generally and our securities in particular. To the extent that external sources of capital become limited or unavailable or available on unfavourable terms, our ability
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to make capital investments and maintain existing properties may be constrained.
If we finance capital expenditures in whole or in part with debt, that may increase our debt levels above industry standards for oil and gas companies of similar size. Depending on future development plans, we may require additional debt financing that may not be available or, if available, may not be available on favourable terms, including higher interest rates and fees. Neither the articles of Suncor (the Articles) nor its bylaws limit the amount of indebtedness that we may incur; however, we are subject to covenants in our existing bank facilities and seek to avoid an unfavourable cost of debt. The level of our indebtedness, from time-to-time, could impair our ability to obtain additional financing on a timely basis to take advantage of business opportunities that may arise and could negatively affect our credit ratings.
We are required to comply with financial and operating covenants under existing credit facilities and debt securities. We routinely review the covenants based on actual and forecast results and have the ability to make changes to our development plans, capital structure and/or dividend policy to comply with covenants under the credit facilities. If Suncor does not comply with the covenants under its credit facilities and debt securities, there is a risk that repayment could be accelerated and/or the company's access to capital could be restricted or only be available on unfavourable terms.
Rating agencies regularly evaluate the company and our subsidiaries. Their ratings of our long-term and short-term debt are based on a number of factors, including our financial strength, as well as factors not entirely within our control, including conditions affecting the oil and gas industry generally, and the wider state of the economy. Credit ratings may be important to customers or counterparties when we compete in certain markets and when we seek to engage in certain transactions, including transactions involving over-the-counter derivatives. There is a risk that one or more of our credit ratings could be downgraded, which could potentially limit our access to private and public credit markets and increase cost of borrowing.
The occurrence of any of the foregoing could have a material adverse effect on Suncor's business, financial condition, results of operations and cash flow.
Third-Party Service Providers
Suncor is reliant on the operational integrity of a large number of third-party service providers, including input and output commodity transport (pipelines, rail, trucking, marine) and utilities associated with various Suncor facilities, including electricity. A disruption in service by one of these third parties can also have a dramatic impact on Suncor's operations. Pipeline constraints that affect takeaway capacity or supply of inputs, such as hydrogen and power for example, could impact our ability to produce at capacity levels. Disruptions in pipeline service could adversely affect commodity prices, Suncor's price realizations, refining operations and sales volumes, or limit our ability to produce and deliver production. These interruptions may be caused by the inability of the pipeline to operate or by the oversupply of feedstock into the system that exceeds pipeline capacity. There can be no certainty that short-term operational constraints on pipeline systems arising from pipeline interruption and/or increased supply of crude oil will not occur. There is a risk that third-party outages could impact Suncor's production or price realizations, which could have a material adverse effect on Suncor's business, financial condition, results of operations and cash flow.
Foreign Operations
The company has operations in a number of countries with different political, economic and social systems. As a result, the company's operations and related assets are subject to a number of risks and other uncertainties arising from foreign government sovereignty over the company's international operations, which may include, among other things:
If a dispute arises in the company's foreign operations, the company may be subject to the exclusive jurisdiction of foreign courts or may not be able to subject foreign persons to the jurisdiction of a court in Canada or the U.S. In addition, as a result of activities in these areas and a
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continuing evolution of an international framework for corporate responsibility and accountability for international crimes, there is a risk the company could also be exposed to potential claims for alleged breaches of international law.
The impact that future potential terrorist attacks, regional hostilities or political violence may have on the oil and gas industry, and on our operations in particular, is not known at this time. This uncertainty may affect operations in unpredictable ways, including disruptions of fuel supplies and markets, particularly crude oil, and the possibility that infrastructure facilities, including pipelines, production facilities, processing plants and refineries, could be direct targets of, or collateral damage of, an act of terror, political violence or war. Suncor may be required to incur significant costs in the future to safeguard our assets against terrorist activities or to remediate potential damage to our facilities. There can be no assurance that Suncor will be successful in protecting itself against these risks and the related financial consequences.
Despite Suncor's training and policies around bribery and other forms of corruption, there is a risk that Suncor, or some of its employees or contractors, could be charged with bribery or corruption. Any of these violations could result in onerous penalties. Even allegations of such behaviour could impair Suncor's ability to work with governments or non-government organizations and could result in the formal exclusion of Suncor from a country or area, sanctions, fines, project cancellations or delays, the inability to raise or borrow capital, reputational impacts and increased investor concern.
The occurrence of any of the foregoing could have a material adverse effect on Suncor's business, financial condition, results of operations and cash flow.
Joint Arrangement Risk
Suncor has entered into joint arrangements and other contractual arrangements with third parties with respect to certain of its projects where other entities operate assets in which Suncor has ownership or other interests. The success and timing of Suncor's activities on assets and projects operated by others, or developed jointly with others, depend upon a number of factors that are outside of Suncor's control, including the timing and amount of capital expenditures, the timing and amount of operational and maintenance expenditures, the operator's expertise, financial resources and risk management practices, the approval of other participants, and the selection of technology.
These co-owners may have objectives and interests that do not coincide with and may conflict with Suncor's interests. Major capital decisions affecting joint arrangements may require agreement among the co-owners, while certain operational decisions may be made solely at the discretion of the operator of the applicable assets. While joint venture counterparties may generally seek consensus with respect to major decisions concerning the direction and operation of the assets and the development of projects, no assurance can be provided that the future demands or expectations of the parties relating to such assets and projects will be met satisfactorily or in a timely manner. Failure to satisfactorily meet demands or expectations by all of the parties may affect our participation in the operation of such assets or in the development of such projects, our ability to obtain or maintain necessary licences or approvals, or the timing for undertaking various activities. In addition, disputes may arise pertaining to the timing and/or capital commitments with respect to projects that are being jointly developed, which could materially adversely affect the development of such projects and Suncor's business and operations.
The occurrence of any of the foregoing could have a material adverse effect on Suncor's business, financial condition, results of operations and cash flow.
Technology Risk
There are risks associated with growth and other capital projects that rely largely or partly on new technologies and the incorporation of such technologies into new or existing operations, including that the results of the application of new technologies may differ from simulated or test environments. The success of projects incorporating new technologies cannot be assured. Advantages accrue to companies that can develop and adopt emerging technologies in advance of competitors. The inability to develop, implement and monitor new technologies may impact the company's ability to develop its new or existing operations in a competitive or profitable manner, which could have a material adverse effect on Suncor's business, financial condition, results of operations and cash flow.
Skills, Resource Shortage and Reliance on Key Personnel
The successful operation of Suncor's businesses and our ability to expand operations will depend upon the availability of, and competition for, skilled labour and materials supply. There is a risk that we may have difficulty sourcing the required labour for current and future operations. The risk could manifest itself primarily through an inability to recruit new staff without a dilution of talent, to train, develop and retain high-quality and experienced staff without unacceptably high attrition, and to satisfy an employee's work/life balance and desire for competitive compensation. The labour market in Alberta has been historically tight, and while the current economic situation has partially moderated this effect, it remains a risk to be managed. The increasing age of our existing workforce adds further pressure. Materials may also be in short supply
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due to smaller labour forces in many manufacturing operations. Our ability to operate safely and effectively and complete all our projects on time and on budget has the potential to be significantly impacted by these risks and this impact could be material.
Our success also depends in large measure on certain key personnel. The loss of the services of such key personnel could have a material adverse effect on the company. The contributions of the existing management team to the immediate and near-term operations of the company are likely to continue to be of central importance for the foreseeable future.
Labour Relations
Hourly employees at our Oil Sands facilities, all of our refineries, certain of our lubricants operations, certain of our terminalling and distribution operations, and our Terra Nova FPSO are represented by labour unions or employee associations. Any work interruptions involving our employees, contract trades utilized in our projects or operations, or any jointly owned facilities operated by another entity presents a significant risk to the company and could have a material adverse effect on Suncor's business, financial condition, results of operations and cash flow.
Competition
The global petroleum industry is highly competitive in many aspects, including the exploration for and the development of new sources of supply, the acquisition of crude oil and natural gas interests, and the refining, distribution and marketing of refined petroleum products. We compete in virtually every aspect of our business with other energy companies. The petroleum industry also competes with other industries in supplying energy, fuel and related products to consumers.
For Suncor's Oil Sands segment, a number of other companies have entered, or may enter, the oil sands business and begin producing bitumen and SCO, or expand their existing operations. It is difficult to assess the number, level of production and ultimate timing of all potential new projects or when existing production levels may increase. During recent years, a global focus on the oil sands through increasing industry consolidation that has created competitors with financial capacity has significantly increased the supply of bitumen, SCO and heavy crude oil in the marketplace. The impact of this level of activity on regional infrastructure, including pipelines, has placed stress on the availability and cost of all resources required to build and run new and existing oil sands operations.
For Suncor's Refining and Marketing business, management expects that fluctuations in demand for refined products, margin volatility and overall marketplace competitiveness will continue. In addition, to the extent that our downstream business unit participates in new product markets, it could be exposed to margin risk and volatility from either cost and/or selling price fluctuations.
There is a risk that increased competition could cause costs to increase, put further strain on existing infrastructure and make margins for refined and unrefined products to be volatile which could have a material adverse effect on Suncor's business, financial condition, results of operations and cash flow.
Land Claims
First Nations people have claimed Aboriginal title and rights to portions of Western Canada. In addition, First Nations people have filed claims against industry participants relating in part to land claims, which may affect our business. At the present time, we are unable to assess the effect, if any, that these land claims may have on our business.
Litigation Risk
There is a risk that Suncor may be subject to litigation, and claims under such ligation may be material. Various types of claims may be raised in these proceedings, including, but not limited to, environmental damage, breach of contract, product liability, antitrust, bribery and other forms of corruption, tax, patent infringement and employment matters. Litigation is subject to uncertainty and it is possible that there could be material adverse developments in pending or future cases. Unfavourable outcomes or settlements of litigation could encourage the commencement of additional litigation. Suncor may also be subject to adverse publicity associated with such matters, regardless of whether Suncor is ultimately found liable. There is a risk that the outcome of such litigation may be materially adverse and/or we may be required to incur significant expenses or devote significant resources in defence against such litigation, the success of which cannot be guaranteed.
Dividends
Our payment of future dividends on our common shares will be dependent on, among other things, our financial condition, results of operations, cash flow, the need for funds to finance ongoing operations, debt covenants and other business considerations as the company's Board considers relevant. There can be no assurance that Suncor will continue to pay dividends in the future.
Control Environment
Based on their inherent limitations, disclosure controls and procedures and internal controls over financial reporting may not prevent or detect misstatements, and even those controls determined to be effective can provide only
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reasonable assurance with respect to financial statement preparation and presentation. Failure to adequately prevent, detect and correct misstatements could have a material adverse effect on Suncor's business, financial condition, results of operations and cash flow.
DIVIDENDS
The Board of Directors has established a policy of paying dividends on a quarterly basis. We review our dividend policy from time-to-time with regard to our financial position, financing requirements for growth, cash flow and other factors which our Board of Directors considers relevant. The Board approved an increase in the quarterly dividend to $0.23 per share from $0.20 per share in the first quarter of 2014. In July 2014, the Board of Directors approved a per share increase of $0.05 to Suncor's quarterly dividend to $0.28 per common share. Dividends are paid subject to applicable law, if, as and when declared by the Board.
Year ended December 31 | 2014 | 2013 | 2012 | ||||
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Cash dividends per common share ($) | 1.02 | 0.73 | 0.50 | ||||
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DESCRIPTION OF CAPITAL STRUCTURE
The company's authorized share capital is comprised of an unlimited number of common shares, an unlimited number of preferred shares issuable in series designated as senior preferred shares, and an unlimited number of preferred shares issuable in series designated as junior preferred shares.
As at December 31, 2014, there were 1,444,119,940 common shares issued and outstanding. To the knowledge of the Board of Directors and executive officers of Suncor, no person beneficially owns, or exercises control or direction over, securities carrying 10% or more of the voting rights attached to any class of voting securities of the company. The holders of common shares are entitled to attend all meetings of shareholders and vote at any such meeting on the basis of one vote for each common share held. Common shareholders are entitled to receive any dividend declared by the Board on the common shares and to participate in a distribution of the company's assets among its shareholders for the purpose of winding up its affairs. The holders of the common shares shall be entitled to share equally, share for share, in all distributions of such assets.
Petro-Canada Public Participation Act
The Petro-Canada Public Participation Act requires that the Articles of Suncor include certain restrictions on the ownership and voting of voting shares of the company. The common shares of Suncor are voting shares. No person, together with associates of that person, may subscribe for, have transferred to that person, hold, beneficially own or control otherwise than by way of security only, or vote in the aggregate, voting shares of Suncor to which are attached more than 20% of the votes attached to all outstanding voting shares of Suncor. Additional restrictions include provisions for suspension of voting rights, forfeiture of dividends, prohibitions against share transfer, compulsory sale of shares, and redemption and suspension of other shareholder rights. The Board may at any time require holders of, or subscribers for, voting shares, and certain other persons, to furnish statutory declarations as to ownership of voting shares and certain other matters relevant to the enforcement of the restrictions. Suncor is prohibited from accepting any subscription for, and issuing or registering a transfer of, any voting shares if a contravention of the individual ownership restrictions results.
Suncor's Articles, as required by the Petro-Canada Public Participation Act, also include provisions requiring Suncor to maintain its head office in Calgary, Alberta; prohibiting Suncor from selling, transferring or otherwise disposing of all or substantially all of its assets in one transaction, or several related transactions, to any one person or group of associated persons, or to non-residents, other than by way of security only in connection with the financing of Suncor; and requiring Suncor to ensure (and to adopt, from time-to-time, policies describing the manner in which Suncor will fulfil the requirement to ensure) that any member of the public can, in either official language of Canada (English or French), communicate with and obtain available services from Suncor's head office and any other facilities where Suncor determines there is significant demand for communication with, and services from, that facility in that language.
Credit Ratings
The following information regarding the company's credit ratings is provided as it relates to the company's cost of funds and liquidity. In particular, the company's ability to access unsecured funding markets and to engage in certain collateralized business activities on a cost-effective basis is primarily dependent upon maintaining competitive credit ratings. A lowering of the company's credit rating may also have potentially adverse consequences for the company's funding capacity for growth projects or access to the capital markets, may affect the company's ability, and the cost, to enter into normal course derivative or hedging transactions and may require the company to post additional collateral under certain contracts.
The following table shows the ratings issued by the rating agencies noted therein as of December 31, 2014. The credit ratings are not recommendations to purchase, hold or sell the debt securities inasmuch as such ratings do not comment as to the market price or suitability for a particular investor. Any rating may not remain in effect for any given period of time or may be revised or withdrawn entirely by a rating agency in the future if, in its judgment, circumstances so warrant.
Senior Unsecured |
Outlook |
Canadian Commercial Paper Program |
U.S. Commercial Paper Program |
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Standard & Poor's (S&P) | A- | Stable | A-1 (low) | A-2 | |||||
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Dominion Bond Rating Service (DBRS) | A (low) | Stable | R-1 (low) | R-1 (low) | |||||
|
|||||||||
Moody's Investors Service (Moody's) | A3 | Stable | Not rated | P-2 | |||||
|
SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014 69
S&P credit ratings on long-term debt are on a rating scale that ranges from AAA to D, representing the range of such securities rated from highest to lowest quality. A rating of A by S&P is the third highest of 10 categories and indicates that the obligor had strong capacity to meet its financial commitments. However, the obligor is somewhat more susceptible to the adverse effects of changes in circumstances and economic conditions than higher rated obligors (rated AA or AAA). The addition of a plus (+) or minus (-) designation after the rating indicates the relative standing within a particular rating category. S&P credit ratings on commercial paper are on a short-term debt rating scale that ranges from A-1 to D, representing the range of such securities rated from highest to lowest quality. A Canadian rating by S&P of A-1 (low) is the third highest of eight categories and a U.S. rating of A-2 is the second highest of six categories, indicating a slightly higher susceptibility to the adverse effects of changes in circumstances and economic conditions, although the obligor's capacity to meet its financial commitment on the obligation is satisfactory.
DBRS credit ratings on long-term debt are on a rating scale that ranges from AAA to D, representing the range of such securities rated from highest to lowest. A rating of A by DBRS is the third highest of 10 categories and is assigned to debt securities considered to be of good credit quality, with the capacity for the payment of financial obligations being substantial, but of a lesser credit quality than an AA rating. Entities in the A category may be vulnerable to future events, but qualifying negative factors are considered manageable. All rating categories other than AAA and D also contain designations for (high) and (low). The absence of either a (high) or (low) designation indicates the rating is in the middle of the category. The assignment of a (high) or (low) designation within a rating category indicates relative standing within that category. DBRS's credit ratings on commercial paper are on a short-term debt rating scale that ranges from R-1 (high) to D, representing the range of such securities rated from highest to lowest quality. A rating of R-1 (low) by DBRS is the third highest of 10 categories and is assigned to debt securities considered to be of good credit quality. The capacity for the payment of short-term financial obligations as they become due is substantial, with overall strength not as favourable as higher rating categories. Entities in this category may be vulnerable to future events, but qualifying negative factors are considered manageable. The R-1 and R-2 commercial paper categories are denoted by (high), (middle) and (low) designations.
Moody's credit ratings are on a long-term debt rating scale that ranges from Aaa to C, which represents the range from highest to lowest quality of such securities rated. A rating of A by Moody's is the third highest of nine categories. Obligations rated A are subject to low credit risk. They are considered upper-medium grade. For rating categories Aa through Caa, Moody's appends numerical modifiers 1, 2 or 3 to each generic rating classification. The modifier 1 indicates that the obligation ranks in the higher end of its generic rating category; the modifier 2 indicates a mid-range ranking; and the modifier 3 indicates a ranking in the lower end of that generic rating category. A rating of P-2 by Moody's for commercial paper is the second highest of four rating categories and indicates a strong ability to repay short-term obligations.
Suncor has paid each of S&P, DBRS and Moody's their customary fees in connection with the provision of the above ratings. Suncor has not made any payments to S&P, DBRS or Moody's in the past two years for services unrelated to the provision of such ratings.
70 SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014
Our common shares are listed on the TSX in Canada and on the NYSE in the U.S. The price ranges and the volumes traded on the TSX for the year ended December 31, 2014, are as follows:
TSX
Price Range (Cdn$) |
Trading Volume | ||||||
High | Low | (000s) | |||||
|
|||||||
2014 | |||||||
|
|||||||
January | 38.15 | 35.92 | 49 837 | ||||
|
|||||||
February | 37.23 | 34.70 | 50 099 | ||||
|
|||||||
March | 38.80 | 36.04 | 57 815 | ||||
|
|||||||
April | 42.88 | 38.21 | 57 526 | ||||
|
|||||||
May | 43.47 | 41.41 | 49 118 | ||||
|
|||||||
June | 47.18 | 41.71 | 54 607 | ||||
|
|||||||
July | 46.00 | 43.59 | 44 246 | ||||
|
|||||||
August | 44.72 | 41.59 | 46 009 | ||||
|
|||||||
September | 44.61 | 39.96 | 66 233 | ||||
|
|||||||
October | 41.30 | 35.17 | 91 914 | ||||
|
|||||||
November | 40.81 | 35.66 | 77 392 | ||||
|
|||||||
December | 38.17 | 30.89 | 105 160 | ||||
|
For information in respect of options to purchase common shares of Suncor and common shares issued upon the exercise of options, see the Share Capital note to the 2014 audited Consolidated Financial Statements, which is incorporated by reference into this AIF.
On November 25, 2014, Suncor issued an aggregate of US$750 million 3.60% notes due in 2024, and on November 26, 2014, Suncor issued an aggregate of $750 million 3.10% medium term notes, series 5 due in 2021.
SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014 71
DIRECTORS AND EXECUTIVE OFFICERS
Directors
The following individuals are directors of Suncor on the date hereof. The term of each director is from the date of the meeting at which he or she is elected or appointed until the next annual meeting of shareholders or until a successor is elected or appointed.
Suncor Directors Name and Jurisdiction of Residence |
Period Served and Independence |
Biography | |||
|
|||||
Mel E. Benson(1)(2) Alberta, Canada |
Director since 2000 Independent |
Mel Benson is president of Mel E. Benson Management Services Inc., an international consulting firm working in various countries with a focus on First Nations/corporate negotiations. Mr. Benson is also part owner of the private oil and gas company Tenax Energy Inc. and sits on the board of the Fort McKay Group of Companies, a community trust organization, as well as Oilstone Energy Services, Inc., based in Houston, Texas. Mr. Benson retired from Exxon International and Imperial Oil Canada in 2000 after a long career as an operations manager and senior member of project management. While based in Houston, Texas, Mr. Benson worked on international projects based in Africa and the former Soviet Union. Mr. Benson recently became a member of the community advisory board for the Alberta Land Institute through the University of Alberta. Mr. Benson is a member of Beaver Lake Cree Nation, located in northeast Alberta. In 2015, Mr. Benson was inducted into the Aboriginal Business Hall of Fame. | |||
|
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Jacynthe Côté(2)(3) Quebec, Canada |
Director since 2015 Independent |
Jacynthe Côté was president and chief executive officer of Rio Tinto Alcan from February 2009 until June 2014 and she continued to serve in an advisory role until her retirement on September 1, 2014. Prior to 2009, she served as president and chief executive officer of Rio Tinto Alcan's Primary Metal business group, following Rio Tinto's acquisition of Alcan Inc. in October 2007. Ms. Côté joined Alcan Inc. in 1988 and she served in a variety of progressively senior leadership roles during her career, including positions in human resources, environment, health and safety, business planning and development and production/managerial positions in Quebec and England. Ms. Côté is a director of the Royal Bank of Canada and Finning International Inc. She also serves as a member of the advisory board of the Montreal Neurological Institute and of the board of directors of École des Hautes Études Commereciales Montreal. Ms. Côté has a Bachelor's degree in Chemistry from Laval University. | |||
|
72 SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014
Dominic D'Alessandro(3)(4) Ontario, Canada |
Director since 2009 Independent |
Dominic D'Alessandro was president and chief executive officer of Manulife Financial Corporation from 1994 to 2009 and is currently a director of CGI Group Inc. For his many business accomplishments, Mr. D'Alessandro was recognized as Canada's Most Respected CEO in 2004 and CEO of the Year in 2002, and was inducted into the Insurance Hall of Fame in 2008. Mr. D'Alessandro is an Officer of the Order of Canada and has been appointed as a Commendatore of the Order of the Star of Italy. In 2009, he received the Woodrow Wilson Award for Corporate Citizenship and in 2005 was granted the Horatio Alger Award for community leadership. Mr. D'Alessandro is a FCA, and holds a Bachelor of Science from Concordia University in Montreal. He has also been awarded honorary doctorates from York University, the University of Ottawa, Ryerson University and Concordia University. | |||
|
|||||
W. Douglas Ford(1)(4) Florida, USA |
Director since 2004 Independent |
W. Douglas Ford was chief executive, refining and marketing for BP p.l.c. ("BP") from 1998 to 2002 and was responsible for the refining, marketing and transportation network of BP as well as the aviation fuels business, the marine business and BP shipping. Mr. Ford is currently a director of Air Products and Chemicals, Inc. He is also a member of the board of trustees of the University of Notre Dame as Trustee Emeritus. | |||
|
|||||
John D. Gass(1)(2) Florida, USA |
Director since 2014 Independent |
John Gass is former vice president, Chevron Corporation, a major integrated oil and gas company, and former president, Chevron Gas and Midstream, positions he held from 2003 until his retirement in 2012. He has extensive international experience, having served in a diverse series of operational positions in the oil and gas industry with increasing responsibility throughout his career. Mr. Gass serves as a director of Southwestern Energy Co. and Weatherford International Ltd. He is also on the board of visitors for the Vanderbilt School of Engineering and is a member of the advisory board for the Vanderbilt Eye Institute. Mr. Gass graduated from Vanderbilt University in Nashville, Tennessee, with a bachelor's degree in civil engineering. He also holds a master's degree in civil engineering from Tulane University in New Orleans, Louisiana. A resident of Florida, he is a member of the American Society of Civil Engineers and the Society of Petroleum Engineers. | |||
|
|||||
Paul Haseldonckx(2)(3) Essen, Germany |
Director since 2002 (Petro-Canada 2002 to July 31, 2009) Independent |
Paul Haseldonckx was a member of the management board of Veba Oel AG (Veba), Germany's largest downstream oil and gas company, including Aral AG gas stations in Europe. Mr. Haseldonckx represented Veba's interests at the board of the Cerro Negro joint venture, an in situ oil sands development including an upgrader, during the construction and early production phase. Mr. Haseldonckx holds a Master of Science and has completed Executive Programs at INSEAD, Fontainebleau and IMD, Lausanne. | |||
|
SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014 73
John R. Huff(1)(2) Texas, USA |
Director since 1998 Independent |
Mr. Huff has served as chairman of the board of directors of Oceaneering International, Inc. ("Oceaneering") since 1990 and served as its chief executive officer from 1986 to 2006. Prior to joining Oceaneering, Mr. Huff served as chairman, president and chief executive officer of Western Oceanic, Inc. from 1972 to 1986. Mr. Huff also serves as a director of Hi Crush Partners LP. Mr. Huff is a member of the National Academy of Engineering. In addition, Mr. Huff is a past member of the National Petroleum Council and a past director of the National Ocean Industries Association and the International Association of Drilling Contractors, and served on the U.S. Department of Transportation's National Offshore Safety Advisory Committee. He is a past director of the American Bureau of Shipping, the U.S. Coast Guard Foundation, Law of the Sea Institute and Marine Resources Development Foundation, a past trustee of the Houston Museum of Natural Science, and past chairman of the Texas Bowl. Mr. Huff attended Rice University and received a Bachelor's degree in Civil Engineering from the Georgia Institute of Technology and attended the Harvard Business School's Program for Management Development. Mr. Huff is a registered professional engineer in the state of Texas and a member of the Explorers Club. | |||
|
|||||
Jacques Lamarre(2)(3) Quebec, Canada |
Director since 2009 Independent |
Jacques Lamarre is past president and chief executive officer of SNC-Lavalin, a position he held from May 1996 until his retirement in May 2009. Mr. Lamarre is an Officer of the Order of Canada and a founding member and past chair of the Commonwealth Business Council. He is also past chair of the board of directors of the Conference Board of Canada and a founding member of the World Economic Forum's Governors for Engineering & Construction. Currently, he serves as a director of PPP Canada Inc. and is a member of the Engineering Institute of Canada, Engineers Canada and the Ordre des ingénieurs du Québec. Mr. Lamarre holds a Bachelor of Arts and a Bachelor of Arts and Science in Civil Engineering from Université Laval in Quebec City. He also completed Harvard University's Executive Development Program. In addition, Mr. Lamarre holds honorary doctorates from the University of Waterloo, the University of Moncton and Université Laval. Among others, he has previously served on the board of the Royal Bank of Canada. | |||
|
74 SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014
Maureen McCaw(2)(3) Alberta, Canada |
Director since 2004 (Petro-Canada 2004 to July 31, 2009) Independent |
Maureen McCaw was most recently executive vice-president of Leger Marketing (Alberta) and formerly president of Criterion Research, a company she founded in 1986. Ms. McCaw is chair of the CBC Pension Fund Plan board of trustees and is a director of the Canadian Broadcasting Corporation, the Alberta Securities Commission and the Edmonton International Airport. She also serves on a number of other boards and advisory committees, including the Institute of Corporate Directors, the Nature Conservancy of Canada and MacEwan University, Faculty of Business, as well as being past chair of the Edmonton Chamber of Commerce. Ms. McCaw completed Columbia Business School's executive program in financial accounting and has an ICD.d. | |||
|
|||||
Michael W. O'Brien(3)(4) Alberta, Canada |
Director since 2002 Independent |
Michael O'Brien served as executive vice president, corporate development, and chief financial officer of Suncor Energy Inc. before retiring in 2002. Mr. O'Brien is a director and chair of the Audit Committee of Shaw Communications Inc. In addition, he is past chair of the board of trustees for the Nature Conservancy Canada, past chair of the Canadian Petroleum Products Institute and past chair of Canada's Voluntary Challenge for Global Climate Change. He has previously served on the boards of Teresen Inc., Primewest Energy Inc. and CRA International. | |||
|
|||||
James W. Simpson Alberta, Canada |
Director since 2004 (Petro-Canada 2004 to July 31, 2009) Independent |
James Simpson is past president of Chevron Canada Resources (oil and gas). He serves as lead director for Canadian Utilities Limited and is on its Corporate Governance, Nomination, Compensation and Succession Committee, as well as being the chairman for its Audit Committee and Risk Review Committee. Mr. Simpson holds a Bachelor of Science and Master of Science, and graduated from the Program for Senior Executives at M.I.T.'s Sloan School of Business. He is also past chairman of the Canadian Association of Petroleum Producers and past vice chairman of the Canadian Association of the World Petroleum Congresses. | |||
|
|||||
Eira M. Thomas(1)(4) British Columbia, Canada |
Director since 2006 Independent |
Eira Thomas is a Canadian geologist with over 20 years of experience in the Canadian diamond business, including her previous roles as vice president of Aber Resources, now Dominion Diamond Corp., and as founder and CEO of Stornoway Diamond Corp. Currently, Ms. Thomas is chief executive officer and a director of Kaminak Gold Corporation, a mineral exploration company, and a director of Lucara Diamond Corp. | |||
|
SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014 75
Steven W. Williams Alberta, Canada |
Director since December 2011 Non-independent, management |
Steve Williams has served as the President of Suncor Energy Inc. since December 2011 and as Chief Executive Officer of Suncor Energy Inc. since May 2012. Mr. Williams is a fellow of the Institution of Chemical Engineers and is a member of the Institute of Directors. He is also one of 12 founding CEOs of Canada's Oil Sands Innovation Alliance (COSIA), a member of the advisory board of Canada's Ecofiscal Commission, and a member of the Canadian Council of Chief Executives. He is active in the community, having recently co-chaired the 2014 Canadian Olympic Hall of Fame Gala in Calgary as part of the 2014 Celebration of Excellence in Alberta that raised proceeds for the Canadian Olympic Foundation. He also serves as co-chair of Indspire's "Building Brighter Futures Campaign". | |||
|
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Michael M. Wilson(3)(4) Alberta, Canada |
Director since 2014 Independent |
Michael Wilson is former president and chief executive officer of Agrium Inc., a retail supplier of agricultural products and services and a wholesale producer and marketer of agricultural nutrients, which is headquartered in Calgary, a position he held from 2003 until his retirement in 2013. He previously served as executive vice president and chief operating officer. Mr. Wilson has significant experience in the petrochemical industry, serving as president of Methanex Corporation, and holding various positions with increasing responsibility in North America and Asia with Dow Chemical Company. Mr. Wilson has a bachelor's degree in chemical engineering from the University of Waterloo and currently serves on the boards of Celestica Inc., Finning International Inc. and Air Canada. He is also the chair of the Calgary Prostate Cancer Centre. | |||
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76 SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014
Executive Officers
The following individuals are the executive officers of Suncor:
Name | Jurisdiction of Residence | Office | |||
|
|||||
Steven W. Williams | Alberta, Canada | President and Chief Executive Officer | |||
|
|||||
Alister Cowan | Alberta, Canada | Executive Vice President and Chief Financial Officer | |||
|
|||||
Eric Axford | Alberta, Canada | Executive Vice President, Business Services | |||
|
|||||
Mark Little | Alberta, Canada | Executive Vice President, Upstream | |||
|
|||||
Mike MacSween | Alberta, Canada | Executive Vice President, Major Projects | |||
|
|||||
Stephen D.L. Reynish | Alberta, Canada | Executive Vice President, Strategy & Corporate Development | |||
|
|||||
Kris Smith | Ontario, Canada | Executive Vice President, Refining and Marketing | |||
|
|||||
Paul Gardner | Alberta, Canada | Senior Vice President, Human Resources | |||
|
|||||
Janice Odegaard | Alberta, Canada | Senior Vice President, General Counsel and Corporate Secretary | |||
|
As at February 23, 2015, the directors and executive officers of Suncor as a group beneficially owned, or controlled or directed, directly or indirectly, common shares of Suncor representing 0.05% of the outstanding common shares of Suncor.
Cease Trade Orders, Bankruptcies, Penalties or Sanctions
As at the date hereof, no director or executive officer of Suncor is or has been within the last ten years a director, chief executive officer or chief financial officer of a company (including Suncor) that:
As at the date hereof, no director or executive officer of Suncor, or any of their respective personal holding companies, nor any shareholder holding a sufficient number of securities to affect materially the control of Suncor:
No director or executive officer of Suncor has been subject to:
SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014 77
AUDIT COMMITTEE INFORMATION
The Audit Committee Mandate is attached as Schedule "A" to this AIF.
Composition of the Audit Committee
The Audit Committee is comprised of Mr. O'Brien (Chair), Ms. Côté, Mr. D'Alessandro, Mr. Haseldonckx, Mr. Lamarre, Ms. McCaw and Mr. Wilson. All members are independent and financially literate. The education and expertise of each member is described in the Directors and Executive Officers section of this AIF.
For the purpose of making appointments to the company's Audit Committee, and in addition to the independence requirements, all directors nominated to the Audit Committee must meet the test of financial literacy as determined in the judgment of the Board of Directors. Also, at least one director so nominated must meet the test of financial expert as determined in the judgment of the Board of Directors. The designated financial experts on the Audit Committee are Mr. O'Brien and Mr. D'Alessandro.
Financial Literacy
Financial literacy can be generally defined as the ability to read and understand a balance sheet, an income statement and a cash flow statement. In assessing a potential appointee's level of financial literacy, the Board of Directors evaluates the totality of the individual's education and experience, including:
Audit Committee Financial Expert
An "Audit Committee Financial Expert" means a person who, in the judgment of the Board of Directors, has the following attributes:
78 SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014
A person shall have acquired the attributes referred to in items (a) through (e) above through:
Audit Committee Pre-Approval Policies for Non-Audit Services
Our Audit Committee has considered whether the provision of services other than audit services is compatible with maintaining our auditors' independence and has a policy governing the provision of these services. A copy of our policy relating to Audit Committee approval of fees paid to our auditors, in compliance with the Sarbanes-Oxley Act of 2002 and applicable Canadian law, is attached as Schedule "B" to this AIF.
Fees Paid to Auditors
Fees paid or payable to PricewaterhouseCoopers LLP, the company's auditors are as follows:
($ thousands) | 2014 | 2013 | |||
|
|||||
Audit Fees | 6 590 | 6 108 | |||
|
|||||
Audit-Related Fees | 497 | 519 | |||
|
|||||
Tax Fees | 90 | 50 | |||
|
|||||
All Other fees | 15 | 60 | |||
|
|||||
Total | 7 192 | 6 737 | |||
|
Audit Fees were paid, or are payable, for professional services rendered by the auditors for the audit of Suncor's annual financial statements, or services provided in connection with statutory and regulatory filings or engagements. Audit-Related Fees were paid for professional services rendered by the auditors for the review of quarterly financial statements and for the preparation of reports on specified procedures as they relate to audits of joint arrangements and attest services not required by statute or regulation. Tax Fees for corporate tax filings and tax planning were paid in a foreign jurisdiction where Suncor has limited activity. All Other Fees were subscriptions to auditor-provided and supported tools. All services described beside the captions "Audit Fees", "Audit-Related Fees", "Tax Fees" and "All Other Fees" were approved by the Audit Committee in compliance with paragraph (c)(7)(i) of Rule 2-01 of Regulation S-X under the U.S. Securities and Exchange Act of 1934, as amended (the Exchange Act). None of the fees described above were approved by the Audit Committee pursuant to paragraph (c)(7)(i)(C) of Regulation S-X under the Exchange Act.
SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014 79
LEGAL PROCEEDINGS AND REGULATORY ACTIONS
There are no legal proceedings in respect of which we are or were a party, or in respect of which any of our property is or was the subject during the year ended December 31, 2014, nor are there any such proceedings known by us to be contemplated, that involve a claim for damages exceeding 10% of our current assets. In addition, there have not been any (a) penalties or sanctions imposed against the company by a court relating to securities legislation or by a securities regulatory authority during the year ended December 31, 2014, (b) any other penalties or sanctions imposed by a court or regulatory body against the company that would likely be considered important to a reasonable investor in making an investment decision, or (c) settlement agreements entered into by the company before a court relating to securities legislation or with a securities regulatory authority during the year ended December 31, 2014.
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
No director or executive officer, or any associate or affiliate of these persons has, or has had, any material interest, direct or indirect, in any transaction or any proposed transaction that has materially affected or is reasonably expected to materially affect us within the three most recently completed financial years or during the current financial year.
TRANSFER AGENT AND REGISTRAR
The transfer agent and registrar for our common shares is Computershare Trust Company of Canada at its principal offices in Calgary, Alberta, Montreal, Quebec, Toronto, Ontario and Vancouver, British Columbia and Computershare Trust Company Inc. in Denver, Colorado.
MATERIAL CONTRACTS
During the year ended December 31, 2014, we did not enter into any contracts, nor are there any contracts still in effect, that are material to our business, other than contracts entered into in the ordinary course of business, which are not required to be filed by Section 12.2 of National Instrument 51-102 Continuous Disclosure Obligations.
INTERESTS OF EXPERTS
Reserves and resources estimates contained in this AIF are based in part upon reports prepared by GLJ and Sproule, Suncor's independent qualified reserves evaluators. As at the date hereof, none of the partners, employees or consultants of GLJ or Sproule, respectively, as a group, through registered or beneficial interests, direct or indirect, held or are entitled to receive more than 1% of any class of our outstanding securities, including the securities of our associates and affiliates.
The company's independent auditors are PricewaterhouseCoopers LLP, Chartered Accountants, who have issued an independent auditor's report dated February 24, 2015 in respect of the company's Consolidated Financial Statements, which comprise the Consolidated Balance Sheets as at December 31, 2014 and December 31, 2013 and the Consolidated Statements of Comprehensive Income, Changes in Shareholders' Equity and Cash Flows for the years ended December 31, 2014 and December 31, 2013, and the related notes, and the report on internal control over financial reporting as at December 31, 2014. PricewaterhouseCoopers LLP has advised that they are independent with respect to the company within the meaning of the Rules of Professional Conduct of the Institute of Chartered Accountants of Alberta and the rules of the United States Securities and Exchange Commission.
80 SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014
DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NEW YORK STOCK EXCHANGE
As a Canadian issuer listed on the NYSE, we are not required to comply with most of the NYSE's rules and instead may comply with Canadian requirements. As a foreign private issuer, we are only required to comply with four of the NYSE's rules. These rules provide that: (i) Suncor must have an audit committee that satisfies the requirements of Rule 10A-3 under the Exchange Act; (ii) the Chief Executive Officer of Suncor must promptly notify the NYSE in writing after an executive officer becomes aware of any material non-compliance with the applicable NYSE rules; (iii) Suncor must provide a brief description of any significant differences between our corporate governance practices and those followed by U.S. companies listed under the NYSE; and (iv) Suncor must provide annual, and as required, written affirmations of compliance with applicable NYSE Corporate Governance rules.
The company has disclosed in its 2015 management proxy circular, which is available on our website at www.suncor.com, significant areas which the company does not comply with the NYSE Corporate Governance Standards. In certain instances, it is not required to obtain shareholder approval for material amendments to equity compensation plans under TSX requirements, while the NYSE requires shareholder approval of all equity compensation plans. Suncor, while in compliance with the independence requirements of applicable securities laws in Canada (specifically National Instrument 52-110 Audit Committees) and the U.S. (specifically Rule 10A-3 of the Exchange Act), has not adopted, and is not required to adopt, the director independence standards contained in Section 303A.02 of the NYSE's Listed Company Manual, including with respect to its audit committee and compensation committee. The Board has not adopted, nor is it required to adopt, procedures to implement Section 303A.05(c)(iv) of the NYSE's Listed Company Manual in respect of compensation committee advisor independence. Except as described herein, the company is in compliance with the NYSE Corporate Governance standards in all other significant respects.
ADDITIONAL INFORMATION
Additional information, including directors' and officers' remuneration and indebtedness, principal holders of our securities, and securities authorized for issuance under equity compensation plans, where applicable, is contained in our most recent management proxy circular for our most recent annual meeting of our shareholders that involved the election of directors. Additional financial information is provided in our 2014 audited Consolidated Financial Statements for our most recently completed financial year and in the MD&A.
Further information about Suncor, filed with Canadian securities commissions and the SEC, including periodic quarterly and annual reports and the 40-F, is available online on SEDAR at www.sedar.com and on EDGAR at www.sec.gov. In addition, our Standards of Business Conduct Code is available online at www.suncor.com. Information contained in or otherwise accessible through our website does not form part of this AIF, and is not incorporated into the AIF by reference.
SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014 81
ADVISORY FORWARD-LOOKING INFORMATION
AND NON-GAAP FINANCIAL MEASURES
This AIF contains certain forward-looking statements and forward-looking information (collectively, forward-looking statements) within the meaning of applicable Canadian and U.S. Securities laws and other information based on Suncor's current expectations, estimates, projections and assumptions that were made by the company in light of information available at the time the statement was made and consider Suncor's experience and its perception of historical trends, including expectations and assumptions concerning: the accuracy of reserves and resources estimates; commodity prices and interest and foreign exchange rates; capital efficiencies and cost-savings; applicable royalty rates and tax laws; future production rates; the sufficiency of budgeted capital expenditures in carrying out planned activities; the availability and cost of labour and services; and the receipt, in a timely manner, of regulatory and third-party approvals. In addition, all other statements and other information that address expectations or projections about the future, and other statements and information about Suncor's strategy for growth, expected and future expenditures or investment decisions, commodity prices, costs, schedules, production volumes, operating and financial results, future financing and capital activities, and the expected impact of future commitments are forward-looking statements. Some of the forward-looking statements and information may be identified by words like "expects", "anticipates", "will", "estimates", "plans", "scheduled", "intends", "believes", "projects", "indicates", "could", "focus", "vision", "goal", "outlook", "proposed", "target", "objective", "continue", "should", "may" and similar expressions.
Forward-looking statements in this AIF include references to:
Suncor's expectations about production volumes and the performance and costs of its assets, including:
The anticipated duration and impact of planned maintenance events, including:
Suncor's expectations about capital expenditures, and growth and other projects, including:
82 SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014
Also:
Forward-looking statements and information are not guarantees of future performance and involve a number of risks and uncertainties, some that are similar to other oil and gas companies and some that are unique to Suncor. Suncor's actual results may differ materially from those expressed or implied by its forward-looking statements, so readers are cautioned not to place undue reliance on them.
The financial and operating performance of the company's reportable operating segments, specifically Oil Sands, Exploration and Production, and Refining and Marketing, may be affected by a number of factors.
Factors that affect our Oil Sands segment include, but are not limited to, volatility in the prices for crude oil and other production, and the related impacts of fluctuating light/heavy and sweet/sour crude oil differentials; changes in the demand for refinery feedstock and diesel fuel, including the possibility that refiners that process our proprietary production will be closed, experience equipment failure or other accidents; our ability to operate our Oil Sands facilities reliably in order to meet production targets; the output of newly commissioned facilities, the performance of which may be difficult to predict during initial operations; the possibility that completed maintenance activities may not improve operational performance or the output of related facilities; our dependence on pipeline capacity and other logistical constraints, which may affect our ability to distribute our products to market; our ability to finance Oil Sands growth and sustaining capital expenditures; the availability of bitumen feedstock for upgrading operations, which can be negatively affected by poor ore grade quality, unplanned mine equipment and extraction plant maintenance, tailings storage, and in situ reservoir and equipment performance, or the unavailability of third-party bitumen; inflationary pressures on operating costs, including labour, natural gas and other energy sources used in oil sands processes; our ability to complete projects, including planned maintenance events, both on time and on budget, which could be impacted by competition from other projects (including other oil sands projects) for goods and services and demands on infrastructure in Alberta's Wood Buffalo region and the surrounding area (including housing, roads and schools); risks and uncertainties associated with obtaining regulatory and stakeholder approval for exploration and development activities; changes to royalty and tax legislation and related agreements that could impact our business; the potential for disruptions to operations and construction projects as a result of our relationships with labour unions that represent employees at our facilities; and changes to environmental regulations or legislation.
Factors that affect our Exploration and Production segment include, but are not limited to, volatility in crude oil and natural gas prices; operational risks and uncertainties associated with oil and gas activities, including unexpected formations or pressures, premature declines of reservoirs, fires, blow-outs, equipment failures and other accidents, uncontrollable flows of crude oil, natural gas or well fluids, and pollution and other environmental risks; the possibility that completed maintenance activities may not improve operational performance or the output of related facilities; adverse weather conditions, which could disrupt output from producing assets or impact drilling programs, resulting
SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014 83
in increased costs and/or delays in bringing on new production; political, economic and socio-economic risks associated with Suncor's foreign operations, including the unpredictability of operating in Libya and that operations in Syria continue to be impacted by sanctions or political unrest; risks and uncertainties associated with obtaining regulatory and stakeholder approval for exploration and development activities; the potential for disruptions to operations and construction projects as a result of our relationships with labour unions that represent employees at our facilities; and market demand for mineral rights and producing properties, potentially leading to losses on disposition or increased property acquisition costs.
Factors that affect our Refining and Marketing segment include, but are not limited to, fluctuations in demand and supply for refined products that impact the company's margins; market competition, including potential new market entrants; our ability to reliably operate refining and marketing facilities in order to meet production or sales targets; the possibility that completed maintenance activities may not improve operational performance or the output of related facilities; risks and uncertainties affecting construction or planned maintenance schedules, including the availability of labour and other impacts of competing projects drawing on the same resources during the same time period; and the potential for disruptions to operations and construction projects as a result of our relationships with labour unions or employee associations that represent employees at our refineries and distribution facilities.
Additional risks, uncertainties and other factors that could influence the financial and operating performance of all of Suncor's operating segments and activities include, but are not limited to, changes in general economic, market and business conditions, such as commodity prices, interest rates and currency exchange rates; fluctuations in supply and demand for Suncor's products; the successful and timely implementation of capital projects, including growth projects and regulatory projects; competitive actions of other companies, including increased competition from other oil and gas companies or from companies that provide alternative sources of energy; labour and material shortages; actions by government authorities, including the imposition or reassessment of taxes or changes to fees and royalties, such as the NORs received by Suncor from the CRA, Ontario, Alberta and Quebec relating to the settlement of certain derivative contracts, including the risk that: (i) Suncor may not be able to successfully defend its original filing position and ultimately be required to pay increased taxes, interest and penalty as a result; or (ii) Suncor may be required to post cash instead of security in relation to the NORs; changes in environmental and other regulations; the ability and willingness of parties with whom we have material relationships to perform their obligations to us; outages to third-party infrastructure that could cause disruptions to production; the occurrence of unexpected events such as fires, equipment failures and other similar events affecting Suncor or other parties whose operations or assets directly or indirectly affect Suncor; the potential for security breaches of Suncor's information systems by computer hackers or cyberterrorists, and the unavailability or failure of such systems to perform as anticipated as a result of such breaches; our ability to find new oil and gas reserves that can be developed economically; the accuracy of Suncor's reserves, resources and future production estimates; market instability affecting Suncor's ability to borrow in the capital debt markets at acceptable rates; maintaining an optimal debt to cash flow ratio; the success of the company's risk management activities using derivatives and other financial instruments; the cost of compliance with current and future environmental laws; risks and uncertainties associated with closing a transaction for the purchase or sale of an oil and gas property, including estimates of the final consideration to be paid or received, the ability of counterparties to comply with their obligations in a timely manner and the receipt of any required regulatory or other third-party approvals outside of Suncor's control that are customary to transactions of this nature; and the accuracy of cost estimates, some of which are provided at the conceptual or other preliminary stage of projects and prior to commencement or conception of the detailed engineering that is needed to reduce the margin of error and increase the level of accuracy. The foregoing important factors are not exhaustive.
Many of these risk factors and other assumptions related to Suncor's forward-looking statements and information are discussed in further detail throughout this AIF, including under the heading Risk Factors, and the company's management's discussion and analysis dated February 26, 2015 and Form 40-F on file with Canadian securities commissions at www.sedar.com and the United States Securities and Exchange Commission at www.sec.gov. Readers are also referred to the risk factors and assumptions described in other documents that Suncor files from time to time with securities regulatory authorities. Copies of these documents are available without charge from the company.
Non-GAAP Financial Measures Oil Sands Cash Operating Costs
Oil Sands cash operating costs and cash operating costs per barrel are non-GAAP financial measures, which are calculated by adjusting Oil Sands segment operating, selling and general expense (a GAAP measure based on sales volumes) for i) non-production costs that management believes do not relate to the production performance of Oil Sands operations, including, but not limited to, share-based compensation adjustments, costs related to the remobilization or deferral of growth projects, research, the expense recorded as part of a non-monetary arrangement involving a third-party processor, and feedstock costs for natural gas used to create hydrogen for secondary upgrading processes; ii) revenues associated with excess capacity, including excess power generated and sold that is recorded in operating revenue; and iii) the impacts of changes in inventory levels, such that the company is able to present cost information based on production volumes.
84 SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014
SCHEDULE "A"
AUDIT COMMITTEE MANDATE
The Audit Committee
The by-laws of Suncor Energy Inc. provide that the Board of Directors may establish Board committees to whom certain duties may be delegated by the Board. The Board has established, among others, the Audit Committee, and has approved this mandate, which sets out the objectives, functions and responsibilities of the Audit Committee.
Objectives
The Audit Committee assists the Board of Directors by:
The Committee does not have decision-making authority, except in the very limited circumstances described herein or where and to the extent that such authority is expressly delegated by the Board of Directors. The Committee conveys its findings and recommendations to the Board of Directors for consideration and, where required, decision by the Board of Directors.
Constitution
The Terms of Reference of Suncor's Board of Directors set out requirements for the composition of Board Committees and the qualifications for committee membership, and specify that the Chair and membership of the committees are determined annually by the Board. As required by Suncor's by-laws, unless otherwise determined by resolution of the Board of Directors, a majority of the members of a committee constitute a quorum for meetings of committees, and in all other respects, each committee determines its own rules of procedure.
Functions and Responsibilities
The Audit Committee has the following functions and responsibilities:
Internal Controls
External and Internal Auditors
SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014 A-1
Financial Reporting and other Public Disclosure
Oil and Gas Reserves
Risk Management
Pension Plan
A-2 SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014
Security
Other Matters
Reporting to the Board
Approved by resolution of the Board of Directors on November 19, 2013
SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014 A-3
SCHEDULE "B" SUNCOR ENERGY INC. POLICY
AND PROCEDURES
FOR PRE-APPROVAL OF AUDIT AND NON-AUDIT SERVICES
Pursuant to the Sarbanes-Oxley Act of 2002 and Multilateral Instrument 52-110, the Securities and Exchange Commission (SEC) and the Ontario Securities Commission respectively have adopted final rules relating to audit committees and auditor independence. These rules require the Audit Committee of Suncor Energy Inc. ("Suncor") to be responsible for the appointment, compensation, retention and oversight of the work of its independent auditor. The Audit Committee must also pre-approve any audit and non-audit services performed by the independent auditor or such services must be entered into pursuant to pre-approval policies and procedures established by the Audit Committee pursuant to this policy.
I. Statement of Policy
The Audit Committee has adopted this Policy and Procedures for Pre-Approval of Audit and Non-Audit Services (the Policy), which sets forth the procedures and the conditions pursuant to which services proposed to be performed by the independent auditor will be pre-approved. The procedures outlined in this Policy are applicable to all Audit, Audit-Related, Tax Services and All Other Services provided by the independent auditor.
II. Responsibility
Responsibility for the implementation of this Policy rests with the Audit Committee. The Audit Committee delegates its responsibility for administration of this policy to management. The Audit Committee shall not delegate its responsibilities to pre-approve services performed by the independent auditor to management.
III. Definitions
For the purpose of these policies and procedures and any pre-approvals:
Audit-Related Services include:
Non-financial operational audits are not Audit-Related Services.
B-1 SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014
IV. General Policy
The following general policy applies to all services provided by the independent auditor.
SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014 B-2
V. Responsibilities of External Auditors
To support the independence process, the independent auditors will:
In addition, the external auditors will:
VI. Disclosures
Suncor will, as required by applicable law, annually disclose its pre-approval policies and procedures, and will provide the required disclosure concerning the amounts of audit fees, audit-related fees, tax fees and all other fees paid to its outside auditors in its filings with the SEC.
Approved and Accepted April 28, 2004
B-3 SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014
Appendix A Prohibited Non-Audit Services
An external auditor is not independent if, at any point during the audit and professional engagement period, the auditor provides the following non-audit services to an audit client.
Bookkeeping or other services related to the accounting records or financial statements of the audit client. Any service, unless it is reasonable to conclude that the results of these services will not be subject to audit procedures during an audit of Suncor's financial statements, including:
Financial information systems design and implementation. Any service, unless it is reasonable to conclude that the results of these services will not be subject to audit procedures during an audit of Suncor's financial statements, including:
Appraisal or valuation services, fairness opinions or contribution-in-kind reports. Any appraisal service, valuation service or any service involving a fairness opinion or contribution-in-kind report for Suncor, unless it is reasonable to conclude that the results of these services will not be subject to audit procedures during an audit of Suncor's financial statements.
Actuarial services. Any actuarially-oriented advisory service involving the determination of amounts recorded in the financial statements and related accounts for Suncor other than assisting Suncor in understanding the methods, models, assumptions, and inputs used in computing an amount, unless it is reasonable to conclude that the results of these services will not be subject to audit procedures during an audit of Suncor's financial statements.
Internal audit outsourcing services. Any internal audit service that has been outsourced by Suncor that relates to Suncor's internal accounting controls, financial systems or financial statements, unless it is reasonable to conclude that the result of these services will not be subject to audit procedures during an audit of Suncor's financial statements.
Management functions. Acting, temporarily or permanently, as a director, officer, or employee of Suncor, or performing any decision-making, supervisory, or ongoing monitoring function for Suncor.
Human resources. Any of the following:
Broker-dealer, investment adviser or investment banking services. Acting as a broker-dealer (registered or unregistered), promoter, or underwriter, on behalf of Suncor, making investment decisions on behalf of Suncor or otherwise having discretionary authority over Suncor's investments, executing a transaction to buy or sell Suncor's investment, or having custody of Suncor's assets, such as taking temporary possession of securities purchased by Suncor.
Legal services. Providing any service to Suncor that, under circumstances in which the service is provided, could be provided only by someone licensed, admitted, or otherwise qualified to practice law in the jurisdiction in which the service is prohibited.
Expert services unrelated to the audit. Providing an expert opinion or other expert service for Suncor, or Suncor's legal representative, for the purpose of advocating Suncor's interest in litigation or in a regulatory or administrative proceeding or investigation. In any litigation or regulatory or administrative proceeding or investigation, an accountant's independence shall not be deemed to be impaired if the accountant provides factual accounts, including testimony, of work performed or explains the positions taken or conclusions reached during the performance of any service provided by the accountant for Suncor.
SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014 B-4
Appendix B Pre-Approval Request Form
NATURE OF WORK | ESTIMATED FEES (Cdn$) |
|
Total | ||
Date | Signature |
B-5 SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014
SCHEDULE
"C" FORM 51-101F2 REPORT ON RESERVES DATA BY
INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR
To the board of directors of Suncor Energy Inc. (the "Company"):
We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society).
Independent Qualified |
Description and Preparation Date of |
Location of Reserves (Country or Foreign |
Net Present Value of Future Net Revenues Before Income Taxes ($ millions, discounted at 10%) |
||||||||||
Reserves Evaluator | Evaluation Report | Geographic Area) | Audited | Evaluated | Reviewed | Total | |||||||
|
|||||||||||||
GLJ Petroleum Consultants Ltd. | Oil Sands In Situ January 19, 2015 |
Canada | | 22 212 | | 22 212 | |||||||
|
|||||||||||||
GLJ Petroleum Consultants Ltd. | Oil Sands Mining January 8, 2015 |
Canada | | 18 760 | | 18 760 | |||||||
|
|||||||||||||
| 40 972 | | 40 972 | ||||||||||
|
EXECUTED
as to our report referred to above:
GLJ Petroleum Consultants Ltd., Calgary, Alberta, Canada, February 26, 2015
"Caralyn P. Bennett"
Caralyn
P. Bennett, P.Eng.
Vice-President
SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014 C-1
SCHEDULE
"D" FORM 51-101F2 REPORT ON RESERVES DATA BY
INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR
To the board of directors of Suncor Energy Inc. (the "Company"):
We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society).
Independent Qualified |
Description and Preparation Date of |
Location of Reserves (Country or Foreign |
Net Present Value of Future Net Revenues Before Income Taxes ($ millions, discounted at 10%) |
||||||||||
Reserves Evaluator | Evaluation Report | Geographic Area) | Audited | Evaluated | Reviewed | Total | |||||||
|
|||||||||||||
Sproule Associates Limited | East Coast Canada February 20, 2015 |
Newfoundland Offshore, Canada | |
8 095 | |
8 095 | |||||||
|
|||||||||||||
Sproule Associates Limited | North America Onshore February 20, 2015 |
Western Canada | | 78 | | 78 | |||||||
|
|||||||||||||
Sproule International Limited | North Sea February 20, 2015 |
North Sea, United Kingdom | | 5 895 | | 5 895 | |||||||
|
|||||||||||||
Sproule International Limited | Other International February 20, 2015 |
Libya | | 3 998 | | 3 998 | |||||||
|
|||||||||||||
| 18 066 | | 18 066 | ||||||||||
|
EXECUTED as to our report referred to above:
Sproule Associates Limited and Sproule International Limited, Calgary, Alberta, Canada, February 26, 2015
"Harry J. Helwerda"
Harry
J. Helwerda, P.Eng., FEC, FGC (Hon.)
President and Director
D-1 SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014
SCHEDULE "E" FORM 51-101F3 REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION
Management of Suncor Energy Inc. (the "Company") are responsible for the preparation and disclosure of information with respect to the Company's oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data, which are estimates of proved reserves and probable reserves and related future net revenues as at December 31, 2014, estimated using forecast prices and costs.
Independent qualified reserves evaluators have evaluated the Company's reserves data. The reports of the independent qualified reserves evaluators will be filed with securities regulatory authorities concurrently with this report.
The Audit Committee of the board of directors of the Company has:
The Audit Committee of the board of directors has reviewed the Company's procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with management. The board of directors has, on the recommendation of the Audit Committee, approved:
Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material.
"Steven W. Williams"
STEVEN
W. WILLIAMS
President and Chief Executive Officer
"Alister Cowan"
ALISTER
COWAN
Executive Vice President and Chief Financial Officer
"James Simpson"
JAMES
SIMPSON
Chair of the Board of Directors
"Michael W. O'Brien"
MICHAEL
W. O'BRIEN
Chair of the Audit Committee
February 26, 2015
SUNCOR ENERGY INC. ANNUAL INFORMATION FORM 2014 E-1
Suncor Energy Inc.
150 - 6 Avenue S.W., Calgary, Alberta, Canada T2P 3E3
T: 403 296 8000
suncor.com
UNDERTAKING AND CONSENT TO SERVICE OF PROCESS
A. Undertaking
Suncor Energy Inc. (the "Registrant") undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the staff of the Securities and Exchange Commission ("SEC"), and to furnish promptly, when requested to do so by the SEC staff, information relating to the securities in relation to which the obligation to file an annual report on Form 40-F arises, or transactions in said securities.
B. Consent to Service of Process
The Registrant has filed previously with the SEC a Form F-X in connection with the Common Shares.
DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROL OVER FINANCIAL REPORTING
See pages 72 and 73 of Exhibit 99-1 and page 61 of Exhibit 99-2.
ATTESTATION REPORT OF THE REGISTERED PUBLIC ACCOUNTING FIRM
See pages 74 and 75 of Exhibit 99-1.
AUDIT COMMITTEE FINANCIAL EXPERT
See pages 78 and 79 of Annual Information Form.
See page 25 of Annual Information Form.
FEES PAID TO PRINCIPAL ACCOUNTANT
See pages 79 of Annual Information Form.
AUDIT COMMITTEE PRE-APPROVAL POLICIES
See Schedule "B" of Annual Information Form.
APPROVAL OF NON-AUDIT SERVICES
See Schedule "B" of Annual Information Form.
OFF-BALANCE SHEET ARRANGEMENTS
See page 50 of Exhibit 99-2.
TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS
See page 50 of Exhibit 99-2.
IDENTIFICATION OF THE AUDIT COMMITTEE
See page 78 of Annual Information Form.
Pursuant to the requirements of the Exchange Act, the registrant certifies that it meets all of the requirements for filing on Form 40-F and has duly caused this annual report to be signed on its behalf by the undersigned, thereto duly authorized.
|
SUNCOR ENERGY INC. | |||
DATE: February 26, 2015 |
||||
|
PER: |
/s/ ALISTER COWAN |
Exhibit No.
|
Description | ||
---|---|---|---|
99-1 |
Audited Consolidated Financial Statements of Suncor Energy Inc. for the fiscal year ended December 31, 2014 | ||
99-2 |
Management's Discussion and Analysis for the fiscal year ended December 31, 2014, dated February 26, 2015 |
||
99-3 |
Consent of PricewaterhouseCoopers LLP |
||
99-4 |
Consent of GLJ Petroleum Consultants Ltd. |
||
99-5 |
Consent of Sproule Associates Limited, Sproule Unconventional Limited and Sproule International Limited |
||
99-6 |
Certificate of Chief Executive Officer Pursuant to Exchange Act Rules 13a-14(a) or 15d-14(a) |
||
99-7 |
Certificate of the Chief Financial Officer Pursuant to Exchange Act Rules 13a-14(a) or 15d-14(a) |
||
99-8 |
Certificate of the Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Enacted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |
||
99-9 |
Certificate of the Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Enacted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |
||
99-10 |
Supplementary Oil and Gas Disclosures (unaudited) |