Performance data

Notes on performance data for Suncor's 2018 Report on Sustainability

1. Overview

Performance data provided throughout our Report on Sustainability in tables and graphs includes social, environmental and economic indicators from the 2018 reporting year with 5-year trends, where feasible. Economic data is reported in a consistent manner with our Annual Report. These notes provide additional details on boundary conditions, and changes in methodologies, definitions, business segment structure changes or changes to historical data. We also implement our own internal guidelines and definitions for data gathering and reporting.

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2. Reporting boundaries

Environmental and social performance data is collected and reported for all facilities operated by Suncor (100%, not adjusted for Suncor’s ownership share), and our joint venture interests operated by other organizations are not included. Facilities are subject to annual planned and unplanned maintenance activities, which may impact consistent year-over-year trends. Facilities that are purchased subsequently operated by Suncor in the middle of a reporting year are pro-rated based on the date of operatorship.

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3. Summary of business segments and operations included in performance data:

1. Suncor-totals reflect consolidation of data where relevant and applicable.
2. Upstream (Oil Sands Base) include Millennium and North Steepbank mining, extraction and integrated upgrading facilities, integrated Poplar Creek cogeneration facility (owned and operated by Suncor as of 2015), and associated infrastructure for these assets, but does not include Syncrude.
3. Upstream (Fort Hills)
4. Upstream (Oil Sands In Situ operations) data includes oil sands bitumen production from Firebag and MacKay River operations and supporting infrastructure.
5. Upstream Exploration & Production (E&P) includes:
   • E&P Terra Nova FPSO vessel situated off the east coast of Canada.
   • E&P North America Onshore (NAO) natural gas assets operated by Suncor. Assets were significantly divested from 2013-2015, and data were reported until the date of sale.
   • Additional information about our E&P business can be found at www.suncor.com.
6. Downstream (Refining and Supply) includes refining operations in Montreal, Sarnia, Edmonton, and Commerce City Colorado. Suncor previously operated a lubricants business in Mississauga, Ontario, which was sold on February 1, 2017. 2017 performance data reflects this sale. Other assets include a petrochemical plant and sulphur recovery facility in Montreal, and product pipelines and terminals in Canada. Additional information about our downstream business is available at www.suncor.com.
7. Renewables includes wind power facilities operated by Suncor, and in graphs are reported with the St. Clair ethanol plant, located in Ontario.

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4. Notes on operational performance and production

1. See “Advisories”, as barrels of oil equivalent and cubic metres of oil equivalent may be misleading indicators of value.
2. Oil Sands Base production is gross sweet and sour synthetic crude oil associated with mining, extraction and upgrading and includes unprocessed volumes. This may be different than production reported in our Annual Report.
3. Fort Hills production is partially upgraded bitumen associated with the Paraffinic Froth Treatment Process (PFT).
4. In Situ production is net bitumen sales associated with total plant saleable product.
5. East Coast (Terra Nova) production is total amount of product sold, not flaring or internally produced fuel.
6. Refining & Supply net production is reported on a business unit level, where transfers between our facilities have been removed from facility production totals.
7. St. Clair ethanol plant production is ethanol produced and converted to cubic metres of oil equivalent, on an energy basis.
8. Wind energy production is in megawatt hours, from Suncor operated wind facilities, (100% - not adjusted for ownership).
9. Our refineries that blend ethanol into gasoline are Sarnia, Montreal, Commerce City and Edmonton.

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5. Notes on greenhouse gas emissions (GHG)

5.1 GHG emissions factors

Emissions factors allow us to estimate GHG emissions from a unit of available activity data (e.g. quantity of fuel consumed or product produced). The metric we use in our Report on Sustainability for reporting GHG emissions is metric tonnes of carbon dioxide equivalent (CO₂e). This common unit for reporting GHGs represents volumes of gases that have been studied to have an impact on the global atmosphere. CO₂e means that individual GHGs have been multiplied by their assessed global warming potential (GWP) compared to carbon dioxide (CO₂). This report (and our 2014-2018 Reports on Sustainability) uses the 100-year GWPs issued by the Intergovernmental Panel on Climate Change’s (IPCC’s) fourth assessment report (2007), which aligns to several jurisdictions of GHG reporting, including Environment Canada and the U.S. Environmental Protection Agency.

The major impacts of using the GWPs issued by the IPCC’s fourth assessment report are that emissions from methane increase slightly due to an increase in the GWP factor from 21 to 25. Emissions from nitrous oxides (N₂O) decrease slightly with that factor decreasing from 310 to 298. Other GHGs have also had their GWPs adjusted but have little to no material impact on our total GHG emissions.

5.2 Measuring potential GHG emission sources

As an integrated energy company spanning multiple jurisdictions, sectors and operations, we use several different externally developed and publicly accepted emission factor protocols to develop facility-specific emission calculation methodologies. We select the appropriate protocol for the site-specific fuel type and composition, emission source, facility or jurisdiction being considered. As required by regulators and verified by external auditors, we use internationally accepted GHG protocols and methodologies in determining our overall emissions profile.

In addition to using fuel-specific emission factors, some GHG emissions are calculated using process- or equipment-specific consumption rates in units such as ‘run-hours’ and not fuel volumes. Many of our sites have complicated processes that require specific emission factors and methodologies to accurately calculate their emissions.

Primarily, our sites use protocols and methodologies that are required by their operating jurisdiction. However, if no prescribed methodology is required, it may be necessary to use a combination of standardized methodologies at a single facility due to site and sector-specific details that may not be completely covered by a single standard or regulation. On occasion, more accurate emission factors – measured, calculated from compositional data, or manufacturer-supplied – may be available for specific equipment. These are used whenever and wherever appropriate to ensure we gather the best quality data and use the most accurate measures.

Specific emission factors are calculated from actual measured data rather than applying generic estimated default factors as frequently as possible. In other cases, such as when calculating indirect emissions from externally purchased electric power, we use factors primarily from site-specific factors if available, secondarily where prescribed by regulation and finally, from published emission factors for remaining emission sources.

Due to the unique nature of each site, we have more than 1,400 standard emission factors in our Environmental Information Management System that are applied at different sites. This number does not include thousands of additional factors that are calculated daily for different fuels and sites based on fuel composition analysis. These factors give us real-time gas composition and resulting carbon content.

5.3 The role of regulation in GHG reporting

Many jurisdictions have, or are in the process of developing, prescriptive regulations that specify which factors can be used. For example, the EPA and regulators in Western Climate Initiative jurisdictions such as Quebec, Ontario and British Columbia all required operators to use specified factors for the 2018 reporting year.

Alberta requires large emitting facilities to use the standard methodology and emission factors in the Carbon Competitiveness Initiative Regulation (CCIR) submission. Each of our sites that report through the CCIR successfully generated positive (approved) verifications for the 2018 reporting year at a reasonable level of assurance.

5.4 GHG Standard practices and methodologies

External agencies have developed industry-accepted standard methodologies that operators can choose to use in the absence of prescribed methods. The standard practices and methodologies we follow are widely accepted, well researched and documented so that the numbers produced are verifiable by governments and third parties, and are consistently applied from year to year.

A partial list of these standard methodologies and guidance documents includes:

• American Petroleum Institute Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Natural Gas Industry, 2009
• IPCC Guidelines for National Greenhouse Gas Inventories, 2006
• US EPA Mandatory Greenhouse Gas Reporting Rule
• IPCC fourth assessment report 2007
• World Business Council for Sustainable Development/World Resources Institute Greenhouse Gas Protocol: A Corporate Accounting and Reporting Standard 2004
• Environment Canada Greenhouse Gas Inventory 1990 – 2007 Report 2009
• Intergovernmental Panel on Climate Change 2006 Guidelines for National Greenhouse Gas Inventories
• Western Climate Initiative (WCI) Design for the WCI Regional Program, July 2010
• National Renewable Energy Laboratory Life Cycle Assessment of Hydrogen Production via Natural Gas Steam Reforming
• Albeta Quantification Methodologies for the Carbon Competitiveness Incentive Regulation and the Specified Gas Reporting Regulation (Version 1.1)
• O. Reg. 452/09: Guideline for Quantification, Reporting and Verification of Greenhouse Gas Emissions 2018
• Regulation respecting mandatory reporting of certain emissions of contaminants into the atmosphere 2018
• Environment Canada Facility Greenhouse Gas Reporting Program: Canada's Greenhouse Gas Quantification Requirements 2018
• Environment Canada National Inventory Report , 1990-2016

5.5 Additional GHG notes

1. Forward looking GHG estimates are based on current production forecasts and methodologies and users of this information are cautioned that the actual GHG emissions and emission intensities may vary materially. Please see Advisories.
2. GHG emissions data from 1990 and 2000 do not include Suncor’s U.S. operations, or legacy Petro-Canada facilities, and only include business areas in operation during these years. These data points have been provided for historical comparability, consistent with previous sustainability reports.
3. GHG emissions are calculated using facility-specific and referenced methodologies accepted by the relevant jurisdictions each facility is required to report GHG emissions to. Methodology has been followed where a jurisdiction has a prescribed one and if none exist then the most applicable and accurate methods available are used to quantify each emission source.
4. Suncor-wide emissions intensity uses net production, which is the sum of net facility production minus all internal product transfers. The resulting net production is our Suncor product sales to market. The sum of the business unit GHG intensities therefore will not equal the Suncor-wide intensity.
5. In situ (MacKay River) indirect emissions methodology reported since 2014 include electricity purchased from the grid, purchased electricity and steam from the third party TransCanada cogen. Firebag cogeneration units are owned and operated by Suncor and therefore all cogen emissions contribute to total direct emissions including emissions associated with generating electricity that is sold to the AB grid.
6. Absolute (total) GHG emissions are the sum of direct and indirect emissions.
7. Direct (Scope 1) GHG emissions are from sources that are owned or controlled by the reporting company. Refining & Supply direct emissions do not deduct CO₂ transfers to third parties, such as the food and beverage industries.
8. Indirect (Scope 2) GHG emissions are energy-related emissions that are a consequence of our operations, but occur at sources owned or controlled by another company (e.g. purchases of electricity, steam, heat, and cooling). The indirect energy calculation methodology credits operations for electricity exported to external users and/or other Suncor facilities. Emissions are calculated based on actual supplier data where possible and published literature where supplier data is unavailable.
9. Indirect (Scope 3) GHG emissions include hydrogen purchased from third-parties and CO₂ volumes sold from our facilities to third-parties for further processing, and can fluctuate annually depending on supplier demand. This is consistent with provincial government reporting requirements. Additional scope 3 emissions include:
   • commercial air travel
   • leased buildings (Suncor Energy Center, East Canada and USA)
   • ground transportation services for employees and contractors
   • licensed fleet vehicles on site
10. Annual variance in indirect (Scope 3) emissions from 2016 - 2018 is attributed to the following:
    • reporting more information (more complete data set than 2017)
    • emission factors were updated for consitency
    • scope changes
    • actual data instead of estimated
11. 2018 Scope 3 inventory improvements allowed Suncor to report a more representative number and 2017 data has been restated for better alignment with the new calculation methodologies.
12. Suncor's GHG goal is designed to encourage business choices that reduce Suncor's emissions and the emissions in the global energy system. To support tracking our goal progress, Suncor developed a methodology that includes both direct emissions reductions from our operated assets and indirect reductions from the use of our products. The data in the GHG performance section reflects our direct operations emissions.Direct and indirect CO₂e emissions are included for this report. No cogen credit is taken for GHG reductions due to internally generated performance credits, purchased offsets, ethanol lifecycle GHG reductions or wind generated offsets.

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6. Notes on energy consumption

1. Total energy is equal to the sum of direct and indirect energy. Electricity that is produced and sold to the provincial grids by oil sands and in situ cogeneration units and operated wind farms is converted to an equivalent amount in GJs and deducted from total energy use.
2. Direct energy is primary energy consumed on-site by Suncor operated facilities.
3. Indirect energy includes imported electricity, steam, heating and cooling duty from third parties. The indirect energy calculation methodology credits operations for electricity exported to external users and/or other Suncor facilities.
4. The energy intensity of renewables business is based on energy input for ethanol production with wind energy production deducted from that total energy input.

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7. Notes on other air emissions

1. Graphs associated with SO₂ and _NOx emissions intensity only include facilities that are material sources of these emissions for our business. Oil Sands estimation accuracy for VOC emissions intensity is greater than +/- 10% and limited by currently accepted methodology and measurement instruments.
2. Other air emissions include SO₂, NO_x and VOC emissions.
3. The increase in Terra Nova’s VOC emissions and emissions intensity in 2018 was mainly due to the hydrocarbon blanket gas and recovery system being offline from January to October. The hydrocarbon blanket has been operational since November of 2018.
4. The increase in Terra Nova’s VOC emissions and emissions intensity was due to the hydrocarbon blanket gas and recovery system being offline for a large part of 2017 and 2018 when compared to ~ 100% operational in 2016. It is noted that that there was an error in total VOCs reported for Terra Nova in the 2018 report . The miscalculation that occurred in the storage and handling emissions is now corrected & reported in this 2019 report.
5. Air emissions include point and non-point sources.
6. We report to the Canadian National Pollutant Release Inventory and the US Toxic Release Inventory annually and additional information on our performance can be found through these reporting mechanisms.

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8. Notes on water use and return

1. Freshwater consumption and intensity graph: water withdrawal and consumption only includes facilities that are material sources of freshwater consumption for our business. Oil sands Base plant and Fort Hills in this graph does not include industrial runoff water, which is subject to annual variances based on precipitation. Withdrawal and consumption including industrial runoff volumes are shown in the performance data tables of our Report on Sustainability. Water measurement and estimation methodology on select Refining & Marketing operations is greater than +/- 10% uncertainty.
2. Oil sands freshwater withdrawal and consumption graph: the methodology for this graph does not include industrial runoff volumes. Withdrawal and consumption including industrial runoff volumes are shown in the performance data tables of our Report on Sustainability.
3. Water consumption is the total water withdrawn minus water returned and reflects quantity of water used and not returned to its proximate source or no longer available in its original form.
4. Freshwater consumption intensity is the volume of water consumed (m³) per volume of hydrocarbon produced (m³)
5. Oil sands base mining water withdrawal includes surface water, groundwater and industrial run-off water as per regulatory withdrawal licences and are subject to annual variances based on precipitation. Water returned is comprised of treated industrial waste-water and runoff from non-process areas that gets collected, diverted and eventually discharged to the environment (destination is the Athabasca River).
6. In Situ water withdrawal includes licenced groundwater wells, treated wastewater and industrial run-off water.
7. East Coast operations water withdrawal includes freshwater (transferred by vessel from St. John’s domestic water system) bunkered to the FPSO potable water tanks for domestic use on the facility. It also includes topside seawater intake flow used for process cooling and water injection for production purposes.
8. Refining & Marketing surface water withdrawal sources and return destinations vary by refinery facility location.
9. Fresh water consumption increased due to the start up of Fort Hills. Fort Hills is building up water inventory for recycling. As we better understand our operational water use and efficiency at site, we will continue to explore opportunities to further reduce water use.

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9. Notes on waste management

1. Waste volumes are dependent on site activities or periodic equipment maintenance and may fluctuate annually.
2. In situ waste that is sent to deep well injection is primarily related to blowdown from our SAGD operations at Firebag consisting of concentrated water impurities that accumulate during the steam generation process. This boiler feed water is intentionally wasted from the boilers to avoid concentration of impurities during continuing evaporation of steam. Deepwell disposal methods of this nature are safe, viable and part of normal operating parameters and our operations are within the disposal limits for these waste streams (regulated by the Alberta Energy Regulator). Our operations also have exceptionally high water recycle rates, above regulated levels.
3. Total waste generated increased in 2018 due to increased non-hazardous waste generated from construction at Burrard Terminal, increased production at in situ sites, and the commissioning and start up of Fort Hills.

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10. Notes on land disturbance and reclamation/tailings

1. Total land approved for development is consistent with the Government of Alberta’s Environmental Protection and Enhancement Act (EPEA) approved footprint for Suncor’s Base Plant operations, Fort Hills and our Firebag and MacKay River in situ operations, as mapped by GIS internally. Meadow Creek East is approved but not yet included.
2. Total land disturbed represents the total active footprint of our Base Plant mining operations, Fort Hills operations and approved in situ projects, which including the cumulative hectares (ha) for areas cleared of vegetation, soil disturbed, ready for reclamation, soils placed and permanently reclaimed. The categories used are consistent with reporting to the Alberta Energy Regulator (AER) in the annual reports.
3. Land reclaimed is land that is no longer being used for mine or plant purposes or in situ production purposes and has been permanently or temporarily reclaimed. This value is a subset of the total active footprint. Reclamation is presented as a cumulative number, therefore the total number of hectares reported from year to year may increase depending on whether reclamation has occurred or whether re-disturbance of previously reclaimed areas was required. Permanently reclaimed lands have met the authorized plans for soil placement and re-vegetation but have not been certified by the Alberta Energy Regulator.
4. Total volume of untreated fluid tailings total inventory at the end of the 2018 reporting period Base plant had 273 million m³, which is 37 million m³ below the approved fluid tailings profile. Base plant also had 119 million m3 of water stored for recycling in our tailings facilities.

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11. Notes on environmental compliance

1. New in 2018, we have improved the environmental compliance metrics we report on a company-wide level, which better align with our internal tools, processes and metrics and also to Global Reporting Initiative Standards. Our focus is always in incident prevention, and all spill events are recorded and investigated. Root cause is determined and remedial actions are implemented to minimize risk and chance of recurrence. Historical environmental compliance metrics using this improved methodology aren’t available; however, prior year environmental compliance information is accessible in past versions of our Report on Sustainability.
2. Environmental non-compliance data aligns with our Risk Matrix (defined by Suncor) and guiding principles for managing risk and reflects at minimum an event triggering a regulatory exceedance or non-compliance, resulting in a regulatory investigation and administrative actions and/or more stringent penalties imposed on Suncor.
3. Environmental regulatory fines also align to our Risk Matrix, and reflect financial penalties levied by the Regulator or the Courts and paid in the reporting year as a result of a regulatory non-compliance or exceedance. Includes administrative penalties, but not enforcement tickets.
4. Significant spills reflect unplanned or accidental release of material whose impact off property takes longer than 7 months to remediate, or on property one year or more to remediate or reclaim. These could be into the environment or into a location that does not usually contain the material, as specified by geographical regulation.
5. Our enterprise wide environmental compliance metrics help identify incidents with our the greatest environmental and regulatory risk. The intent of these metrics is to learn from environmental incidents in order to prevent reoccurrence and promote the consistent enterprise-wide application of appropriate mitigations.

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12. Notes on health and safety

1. Since 2014, health and safety data reported for Upstream Terra Nova represents our E&P business segment, including North America Onshore. This reflects the significant divestments in our conventional natural gas business since 2013.
2. Since 2014, Downstream Refining & Supply health and safety data includes our St. Clair ethanol plant. Our U.S. operations use the Occupational Health and Safety Administration (OSHA) definitions to classify their injuries, which differ slightly from Canadian standards.
3. Lost time injury is a work related injury that results in lost days from work. Fatalities are included in lost time injuries. Frequency is calculated as the number of lost time injuries multiplied by 200,000 (based on 100 workers working full time for one year) divided by the actual exposure hours. This tells us how many workers who are injured for every 100. Prime contractor incident data is excluded from this metric.
4. Recordable injury frequency is the number of recordable injuries (including medical treatment, restricted work access and lost time) multiplied by 200,000 (based on 100 workers working full time divided by the actual exposure hours). This tells us how many people are injured for every 100 workers in a calendar year. Prime contractor incident data is excluded from this metric.
5. Beginning in 2018, the health and safety data reflects the new regional organizational structure for Suncor’s operations in the Regional Municipality of Wood Buffalo (RMWB). This now reflects health and safety data for Suncor’s Fort Hills Operations and the Regional Services organization: a team which provides support services to Suncor’s assets in the RMWB.
6. Contractors refer to any organization, company or individual who provides goods and/or services to Suncor.
7. Fatalities are reported for employees and contractors (excluding prime contractors). The prime contractor for a work site is (a) the contractor, employer or other person who enters into an agreement with the owner of the work site to be the prime contractor, or (b) if no agreement has been made or if no agreement is in force, the owner of the work site. Prime contractors have full care, custody and control meaning they manage their own work and are responsible for maintaining safe working environments. Tragically 3 employees and two prime contractors were fatally injured in 2014. In 2017, a contract worker was fatally injured when inside an excavation.

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13. Notes on workforce

1. New employee hires are any externally hired regular full-time or part-time employee whose permanent start date falls within the reporting period.
2. Employee turnover is the percentage of employees who leave Suncor under any circumstance in the reporting year. Only terminations are included for full-time and part-time employees.
3. Suncor employees include regular full-time, regular part-time, students, casuals or temporary employees. Leaves, other than long-term disability, such as maternity, paternity, personal leave, as well as short-term disabilities, are considered active and are included.
4. Beginning in January 2015, as part of an overall cost management program that began in 2014 accelerated by a low crude price environment, Suncor reduced the size of our workforce primarily through our contract workforce, not backfilling attrition for non-critical positions, and employee reductions.
5. Long-term contractors are individual workers engaged as a Contractor to support short-term, variable work.
6. Unionized workforce data is only applicable in areas where there is a unionized environment.
7. Certain operating regions prohibit collecting information on gender; therefore diversity data may not be reflective of our entire workforce due to data availability. Workforce diversity is calculated based on information provided voluntarily by employees. Indicators referring to ethnicity and disability reflect only those employees who consented to release of this information.
8. Management is classified as front-line leaders, mid-level leaders, members of the management committee or members of the corporate committee.

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14. Notes on economic performance

1. Select economic figures have been calculated according to the International Financial Reporting Standards (IFRS). For complete disclosure of our financial information, see our 2018 Annual Report.
2. OS&G expenses are subject to historical restatements due to reclassifications within our income statement. Employee costs are reported in our Annual Report under Operating, Selling & General and include salaries, benefits and share-based compensation. Typically a portion of employee costs are capitalized as part of fixed assets.
3. Royalties and taxes paid include monies remitted to government, including income, property, and other taxes, Crown royalties, and lease bonuses and rentals.
4. Under GRI Standard 201-1, economic value retained reflects the direct economic value generated (revenues) minus economic value distributed (operating costs (including employee costs), taxes and royalties paid, distribution to shareholders and community investments).
5. As of June 1, 2016, Suncor no longer makes political contributions as a matter of policy, except in exceptional circumstances. Any such contributions will continue to be disclosed in this report.
6. Local goods and services spend reflects goods or services purchased in the area of operations. Suncor-wide spend excludes Syria and Libya.
7. Indigenous businesses include those with a minimum of 51% ownership by Indigenous individuals or organizations.
8. Values reported for Indigenous supplier revenues earned for 2013 include GST. Beginning in 2014, values reported reflect amounts captured in our enterprise software data management system, minus 5% GST.
9. Inclusion of contracts in the reporting year is based on the payment date, not the date of services rendered.
10. Indigenous supplier spend includes Canadian-wide spend across Suncor’s operations.
11. In prior years, the Enterprise Value was mistakenly reported as Market Capitalization, with the difference between the two being that Enterprise Value includes debt and deducts cash and cash equivalents. Going forward, we will continue to report the Enterprise Value. For disclosure on Market Capitalization, see our 2018 Annual Report.

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15. Notes on community investments

1. Since 2014, values for community investments have been calculated by Suncor and the Suncor Energy Foundation (SEF). The SEF is audited annually by PricewaterhouseCoopers (PwC).
2. Value of Time Donations is reported by employees to Suncor voluntarily. The hours represent hours volunteered during working hours.
3. Value of Management Cost Donations from 2014-2018 is for the Suncor Energy Foundation only.
4. External resources leveraged represents cash and in-kind value generated as a result of Suncor's involvement, but which is not a cost to the company (e.g. employee contributions through our SunCares employee programs, food donations, and matching donations from other funders).
5. The SEF is limited to providing donations to registered Canadian charitable organizations, and Suncor’s contribution to SEF represents donations, operating budget and appropriate allocations to a reserve fund which protects multi-year commitments going forward. Charitable contributions to the community made by the SEF are included in the disbursement values shown by funding priority.
6. Suncor launched a new SunCares employee program in 2017, and prior year data is not available. Corporate donations include corporate rewards, grants and the value of volunteer time during work hours. Employee personal donations include employee and retiree donations and donations made through the public SunCares Community Impact Portal.
7. In 2018, Suncor community investment and the SEF refreshed their strategy with a focus on three new priorities for funding – Energy Future, Indigenous Peoples and Community Resilience. 2018 data represents these new funding priorities.