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Suncor-wide GHG emissions actual and estimates

Footnotes 1 - 9 apply

Suncor-wide GHG emissions intensity actual and estimates

Footnotes 1 - 9 apply

(1) Estimates are based on current production forecasts and methodologies. The tables contain forward-looking estimates and users of this information are cautioned that the actual GHG emissions and emission intensity may vary materially from the estimates contained in the table.

(2) Data from 1990 to 2000 does not include Suncor's U.S. operations.

(3) Data here includes both direct and indirect CO2e emissions, whereas the data included in the Alberta SGER reports are direct only. No credit is taken for GHG reductions due to cogen credits.

(4) Data and estimates for 2007 forward include the St. Clair ethanol plant.

(5) Data and estimates have changed from previous year's reports due to Oil Sands methodology changes that reflect the inclusion of biomass, a methodology change in the calculation of fugitive emissions using flux chamber data, and revisions to emissions factors and calculations based upon AESRD's request. These changes are also consistent with the methodology used for SGER Bill 3 reporting.

(6) Data for 2009 and future years includes the full-year emissions for all Petro-Canada operated properties acquired in the 2009 merger, even though the merger did not close until Aug. 1, 2009. This is to allow for a consistent comparison to past and future years.

(For certain business units, combined Suncor / Petro-Canada data is provided for some years prior to 2009 but this is not reflected in the Suncor-wide rollup.

(7) The Business-As-Usual (BAU) line shown in previous years has been removed as it is no longer applicable to the merged company. A new BAU line may be added in the future once a new baseline has been developed.

(8) The Suncor-wide emissions intensity uses Net Production, which is the sum of Net Facility Production minus all internal intra- and inter-BU product transfers, to remove any double counting. The sum of the BU intensities will therefore not equal the Suncor-wide intensity.

(9) Suncor-wide emissions are inclusive of emissions from the pipeline from Oil Sands to the Edmonton Refinery, which are not included in individual business unit values. The emission total for this source for 2012 was 47,500 tonnes CO2e.

Definitions:

Direct GHG emissions: Emissions from sources that are owned or controlled by the reporting company.

Indirect GHG emissions: Emissions that are a consequence of the operations of the reporting company, but occur at sources owned or controlled by another company (e.g., purchased electricity, steam, or hydrogen).

Absolute (total) emissions: The total GHG emissions (direct and indirect emissions) of a facility or reporting company.

Emission intensity: Ratio that expresses GHG emissions per unit of physical activity or unit of economic value (e.g., here it is tonnes of CO2e emissions per unit of net processed volume in cubic metres).

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Oil sands GHG emissions actual and estimates

Footnotes 1 - 5 apply

Oil Sands GHG emissions intensity actual and estimates

Footnotes 1 - 5 apply

(1) Estimates are based on current production forecast and methodologies. The tables contain forward-looking estimates and users of this information are cautioned that the actual GHG emissions and emission intensity may vary materially from the estimates contained in the table.

(2) Data here includes both direct and indirect CO2e emissions, whereas the data included in the Alberta SGER report is direct only. No credit is taken for GHG reductions due to cogen credits.

(3) Data and estimates have changed from previous year's report due to Oil Sands methodology changes that reflect the inclusion of biomass, a methodology change in the calculation of fugitive emissions using flux chamber data, and revisions to emission factors and calculation methodologies based upon AESRD's request. These changes are also consistent with the methodology used for SGER Bill 3 reporting.

(4) Historical Environment data for Oil Sands from 2005 to 2008 includes our Firebag in situ operation, where appropriate, as well as our mining operations. In 2009 In Situ (Firebag and MacKay River) began reporting as its own business unit. Data for 2009 and forwards includes only Oil Sands base plant mining / extraction / upgrading and Poplar Creek cogen operations. The Poplar Creek cogen is owned and operated by a third party but is part of the Suncor operating agreement and air licence, and therefore all cogen emissions count toward Oil Sands total direct emissions.

(5) The GHG volumes from 2009 have been restated due to a change in hydrogen plant allocation and diesel emission methodology.

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Water Withdrawal and Consumption

* Beginning in 2009, includes consolidated post-merger data.

** The 2011 values were revised from previous years' reports due to data and process improvements in 2012 which improved the understanding of site conditions for specific facilities.

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Energy Intensity

* Beginning in 2009, includes consolidated post-merger data.

(1) Oil Sands data in 2008 included Firebag operations. Since 2009 Firebag has been included in In Situ business unit.

(2) Previously called Natural Gas.

(3) In Situ data includes Firebag and MacKay River operations.

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Lost-time Injury Frequency

* Exposure hours and lost time injuries data, beginning in 2009, includes consolidated post-merger data.

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Environmental excellence goals

Air goal

Air goal: Reduce air emissions by 10% by 2015

Historical data updates were made to 2011 Oil Sands and 2009 - 2011 R&M air emission numbers due to update in emission factors and inclusion of additional sources.

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Energy goal

Energy goal: Improve energy efficiency by 10% by 2015

The energy intensity metrics for the Environmental Excellence Performance Goal are different from the Performance Indicators section of this report due to the production definitions used. The Environmental Excellence process is based on business unit performance, therefore the production numbers reflect the net performance within each business unit. The Performance Indicators are corporate-wide net metrics, therefore the Performance Indicator production numbers are lower than the sum of individual business unit production used in the Environmental Excellence Performance Goals.

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Land goal

Land goal: Increase reclamation of disturbed land area by 100% by 2015

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Water goal

Water goal: Reduce freshwater consumption by 12% by 2015

From 2011 to 2012, the fresh water consumption metric for Oil Sands, and Refining and Marketing was updated to include industrial runoff withdrawal as described in the Oil Sands, and R&M Performance Indicators section of this report. The water goal performance metrics (2007-2012) have not yet been updated to reflect this change. 2011 In Situ water data updated to keep consistency with the metric.

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Environment

Suncor-wide GHG emissions actual and estimates

Footnotes 1 - 9 apply

Suncor-wide GHG emissions intensity actual and estimates

Footnotes 1 - 9 apply

(1) Estimates are based on current production forecasts and methodologies. The tables contain forward-looking estimates and users of this information are cautioned that the actual GHG emissions and emission intensity may vary materially from the estimates contained in the table.

(2) Data from 1990 to 2000 does not include Suncor's U.S. operations.

(3) Data here includes both direct and indirect CO2e emissions, whereas the data included in the Alberta SGER reports are direct only. No credit is taken for GHG reductions due to cogen credits.

(4) Data and estimates for 2007 forward include the St. Clair ethanol plant.

(5) Data and estimates have changed from previous year's reports due to Oil Sands methodology changes that reflect the inclusion of biomass, a methodology change in the calculation of fugitive emissions using flux chamber data, and revisions to emissions factors and calculations based upon AESRD's request. These changes are also consistent with the methodology used for SGER Bill 3 reporting.

(6) Data for 2009 and future years includes the full-year emissions for all Petro-Canada operated properties acquired in the 2009 merger, even though the merger did not close until Aug. 1, 2009. This is to allow for a consistent comparison to past and future years.

(For certain business units, combined Suncor / Petro-Canada data is provided for some years prior to 2009 but this is not reflected in the Suncor-wide rollup.

(7) The Business-As-Usual (BAU) line shown in previous years has been removed as it is no longer applicable to the merged company. A new BAU line may be added in the future once a new baseline has been developed.

(8) The Suncor-wide emissions intensity uses Net Production, which is the sum of Net Facility Production minus all internal intra- and inter-BU product transfers, to remove any double counting. The sum of the BU intensities will therefore not equal the Suncor-wide intensity.

(9) Suncor-wide emissions are inclusive of emissions from the pipeline from Oil Sands to the Edmonton Refinery, which are not included in individual business unit values. The emission total for this source for 2012 was 47,500 tonnes CO2e.

Definitions:

Direct GHG emissions: Emissions from sources that are owned or controlled by the reporting company.

Indirect GHG emissions: Emissions that are a consequence of the operations of the reporting company, but occur at sources owned or controlled by another company (e.g., purchased electricity, steam, or hydrogen).

Absolute (total) emissions: The total GHG emissions (direct and indirect emissions) of a facility or reporting company.

Emission intensity: Ratio that expresses GHG emissions per unit of physical activity or unit of economic value (e.g., here it is tonnes of CO2e emissions per unit of net processed volume in cubic metres).

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Oil sands GHG emissions actual and estimates

Footnotes 1 - 5 apply

Oil Sands GHG emissions intensity actual and estimates

Footnotes 1 - 5 apply

(1) Estimates are based on current production forecast and methodologies. The tables contain forward-looking estimates and users of this information are cautioned that the actual GHG emissions and emission intensity may vary materially from the estimates contained in the table.

(2) Data here includes both direct and indirect CO2e emissions, whereas the data included in the Alberta SGER report is direct only. No credit is taken for GHG reductions due to cogen credits.

(3) Data and estimates have changed from previous year's report due to Oil Sands methodology changes that reflect the inclusion of biomass, a methodology change in the calculation of fugitive emissions using flux chamber data, and revisions to emission factors and calculation methodologies based upon AESRD's request. These changes are also consistent with the methodology used for SGER Bill 3 reporting.

(4) Historical Environment data for Oil Sands from 2005 to 2008 includes our Firebag in situ operation, where appropriate, as well as our mining operations. In 2009 In Situ (Firebag and MacKay River) began reporting as its own business unit. Data for 2009 and forwards includes only Oil Sands base plant mining / extraction / upgrading and Poplar Creek cogen operations. The Poplar Creek cogen is owned and operated by a third party but is part of the Suncor operating agreement and air licence, and therefore all cogen emissions count toward Oil Sands total direct emissions.

(5) The GHG volumes from 2009 have been restated due to a change in hydrogen plant allocation and diesel emission methodology.

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In Situ GHG emissions actual and estimates

In Situ GHG emissions chart

(1) Estimates are based on current production forecast and methodologies. The tables contain forward-looking estimates and users of this information are cautioned that the actual GHG emissions and emission intensity may vary materially from the estimates contained in the table.

(2) Data here includes both direct and indirect CO2e emissions, whereas the data included in the Alberta SGER report is direct only. No credit is taken for GHG reductions due to cogen credits.

(3) For MacKay River, indirect emissions for electricity sold to the Alberta grid by the third-party cogen are not applicable, and only the indirect emissions from the electricity used at MacKay are counted. Starting in 2011 MacKay River implemented a new methodology for calculating indirect emissions to remain consistent with the third party cogen that is the source of these energy streams; therefore, previous years are higher than previously stated. This change is also reflected in the forecasted future years. Firebag cogen is owned and operated by Suncor and therefore all cogen emissions count toward our total direct emissions.

(4) Historically, Firebag was reported as part of Oilsands up to and including 2008. The 2008 Firebag data has already been reported as part of the Oilsands trend, but has been included again here so that a valid year-over-year comparison can be made. Readers are cautioned that this is "double-counting" and therefore all the numbers for 2008 will add up to more than the total 2008 Suncor-wide total; this is intentional and is for comparison purposes only.

(5) Values from 2007 and earlier include legacy Suncor facilities only. For comparison, values from 2008 (the year preceding the merger) include both legacy Suncor and Petro-Canada facilities. Data for 2009 includes the full-year emissions for all Suncor and Petro-Canada facilities acquired in the 2009 merger, even though the merger did not close until Aug. 1, 2009. This is to allow for a consistent comparison to past and future years. For historical Petro-Canada emissions please see the Report to the Community at suncor.com.

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North America Onshore GHG emissions actual and estimates

North America Onshore GHG emissions chart

(1) Estimates are based on current production forecast and methodologies. The tables contain forward-looking estimates and users of this information are cautioned that the actual GHG emissions and emission intensity may vary materially from the estimates contained in the table due to growth, development and/or dispositions.

(2) Data here includes both direct and indirect CO2e emissions, whereas the data included in the Alberta SGER report is direct only.

(3) The increase in 2009 is due to the merger with Petro-Canada; data prior to 2009 is for legacy Suncor properties only and does not include any Petro-Canada facilities. Data for 2009 includes the full-year emissions for all Suncor and Petro-Canada operated Natural Gas properties acquired in the 2009 merger, even though the merger did not close until August 1, 2009.This is to allow for a consistent comparison to past and future years. For historical Petro-Canada Natural Gas emissions please see the "Report to the Community" at http://www.suncor.com/.

(4) BC forecasted emissions are included in other

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Combined Canada and USA Refining & Marketing GHG emissions actual and estimates

Combined Canada and USA Refining & Marketing GHG emissions chart

(1) Estimates are based on current production forecast and methodologies. The tables contain forward-looking estimates and users of this information are cautioned that the actual GHG emissions and emissions intensity may vary materially from the estimates contained in the table.

(2) Data here includes both direct and indirect CO2e emissions, whereas the data included in the Alberta SGER report is direct only.

(3) Historical data and estimates for 2007 until 2008 previously included the St. Clair Ethanol Plant. The ethanol plant data has been removed from the historical data in order to include it in the historical data for Renewables.

(4) The numbers are gross operated volumes and do not include reductions from ethanol and cogen credits.

(5) The BAU line shown in previous years has been removed as it is no longer applicable to the merged company. A new BAU line may be added in the future once a new baseline has been developed.

(6) Values from 2007 and earlier include legacy Suncor facilities only. For comparison, values from 2008 (the year preceding the merger) include both legacy Suncor and Petro-Canada facilities. Data for 2009 includes the full-year emissions for all Suncor and Petro-Canada facilities acquired in the 2009 merger, even though the merger did not close until August 1, 2009. This is to allow for a consistent comparison to past and future years. For historical Petro-Canada emissions please see the "Report to the Community" at http://www.suncor.com/.

(7) R&M Indirect emissions include emissions from purchased third-party merchant hydrogen plants as it is a "major outsourced activity".

(8) R&M Direct emissions do not include CO2 transfers to third parties such as the food and beverage industries as they do not meet the definition for "CO2 releases". For the purposes of this report, CO2 volumes sold to third parties are considered to be Scope 3 Indirects from products.

(9) Re-reported emissions for 2009 include adding the indirect emissions from purchased hydrogen and subtracting CO2 sales volumes.

(10) Sarnia's 2010 emissions were revised upon further review by third party assurance.

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International & Offshore GHG emissions actual and estimates

International & Offshore GHG emissions chart

(1) Estimates are based on current production forecast and methodologies. The tables contain forward-looking estimates and users of this information are cautioned that the actual GHG emissions and emission intensity may vary materially from the estimates contained in the table.

(2) I&O Properties were obtained with the Petro-Canada merger in August 2009. For historical Petro-Canada emissions please see the "Report to the Community" at http://www.suncor.com/.

(3) Data here includes both direct and indirect CO2e emissions. No credit is taken for GHG reductions due to offsets.

(4) Historically, I&O operated properties have included Hanze since the Veba Oil aquisition in May 2002, Terra Nova start-up in January 2003, and De Ruyter start-up in September 2006. The Netherlands properties (Hanze and De Ruyter) were sold in 2010, therefore some historical data is unavailable. All efforts have been made to provide the best data possible, but somemust be approximated in order to show the performance trend.

(5) Data is for Suncor operated facilities only, and does not include our interests in non-operated joint ventures.

(6) Terra Nova production historically has only included oil sales and not flaring and internally produced fuel. To be consistent with the other major facilities, for 2011 we did include those additional production volumes, but did not revise previous years. For the 2012 reporting year and forecasted future data, the production metric for all years including 2011 has been readjusted to only include oil sales (consistent with historical).

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Renewables GHG emissions actual and estimates

Renewables GHG emissions actual and estimates

(1) Estimates are based on current production forecast and methodologies. The tables contain forward-looking estimates and users of this information are cautioned that the actual GHG emissions and emission intensity may vary materially from the estimates contained in the table.

(2) Data here includes both direct and indirect CO2e emission. No credit is taken for GHG reductions due to ethanol lifecycle GHG reductions.

(3) Historically, ethanol numbers for 2007 until 2008 were reported in R&M Canada. Those numbers have been backed out of R&M and placed here.

(4) The GHG and production numbers for the Ethanol Plant are constant from year-to-year as the plant runs at ~100% essentially all the time. Production is dependent on how much corn we can purchase and how much ethanol we can sell, which are predictable and mainly within our control.

(5) The capacity of the plant was doubled in 2011 to 400 million litres of ethanol per year.

(6) Beginning in 2012, Renewables includes total emissions (direct and indirect) from operated wind farms and the St. Clair ethanol plant. No credit is taken for generated wind offsets and generated electricity is not reflected as production in the intensity metric.

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SO2 emissions intensity

SO<sub>2</sub> emissions intensity chart

* Beginning in 2009, includes consolidated post-merger data.

(1) Oil Sands data in 2008 included Firebag operations. Since 2009 Firebag has been included in In Situ.

(2) This business unit was previously called Natural Gas.

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NOx emissions intensity

NO<sub>X</sub> emissions intensity chart

* Beginning in 2009, includes consolidated post-merger data.

(1) Oil Sands data in 2008 included Firebag operations. Since 2009 Firebag has been included in In Situ.

(2) This business unit was previously called Natural Gas.

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Water consumption intensity

Water consumption intensity chart

*Beginning in 2009, includes consolidated post-merger data.

(1) Oil Sands data in 2008 included Firebag operations. Since 2009 Firebag has been included in In Situ business unit.

(2) Previously called Natural Gas

(3) In Situ data includes Firebag and MacKay River operations.

(4) International and Offshore water withdrawal data for 2009 included only potable water. The increase in 2010 data is due to the inclusion of sea water in water withdrawn.

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Land use at oil sands

Land use at oil sands chart

(1) Reduction in 2009 land disturbed is a result of the removal of In Situ data.

(2) Following Alberta Environment & Sustainable Resource Development’s (AESRD) issuance of standards for Geographic Information Systems (GIS) spatial data reporting in 2010, Suncor re-digitized all permanent reclamation areas and removed disturbance feature types (such as roads, power lines, pipelines, etc.) that occurred post-reclamation.

This resulted in a removal of 96.3 hectares of re-disturbance from the total of reclaimed areas prior to 2010. As such, the changes in the reclamation areas for each year and the total area permanently reclaimed to the end of 2010 have been updated to reflect these changes. Reclaimed lands have not been certified as such. For further details on the definition of reclaimed, see the legal notice at the end of this publication.

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Energy use

Energy use chart

* Beginning in 2009, includes consolidated post-merger data.

(1) Oil Sands data in 2008 included Firebag operations. Since 2009 Firebag has been included in In Situ business unit.

(2) Previously called Natural Gas

(3) In Situ data includes Firebag and MacKay River operations.

(4) Suncor-wide total energy is inclusive of energy from the pipeline from Oil Sands to the Edmonton Refinery, which are not included in individual business unit values. The energy total for this source for 2012 was approximately 282,000 GJ.

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Installed wind capacity

Installed wind capacity chart

* Production capacity at wind farms in which Suncor is a partner or operator.

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Social

Recordable injury frequency

Recordable injury frequency chart

* Exposure hours and recordable injuries (lost time, medical aid and restricted work), beginning in 2009, includes consolidated post-merger data.

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Major incidents

Major incidents chart

* Major incidents result in fatalities, permanent disability, punitive action by government, or catastrophic environmental impact, or significant impact to the company’s reputation. In 2012 an oil well blowout and fire occurred at the Suncor natural gas well site in the Altares field, 69 kilometres west of Fort St. John, B.C.

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Suncor employees

Suncor employees chart

* Includes all full-time, part-time, temporary and casual employees.

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Diversity

Diversity chart

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Employee turnover

Employee turnover chart

* Employee turnover is the percentage of full-time and part-time employees who leave the workforce under any circumstances in a year.

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Community investment

Community investment chart

* Community Investment data, beginning in 2009, includes consolidated post-merger data.

In 2010, Suncor and the Suncor Energy Foundation started using a new funding priority, Sustainable Communities, to categorize funding directed at programs focused on building capacity within the community. In 2011, Suncor launched a new Community Investment strategy with a new set of funding priorities.

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Economic

Net production

Net production chart

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Taxes and royalties

Taxes and royalties chart

* Does not include excise taxes collected and remitted by Suncor.

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Purchase of goods and services

Purchase of goods and services chart

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Capital and exploration expenditures

Capital and exploration expenditures chart

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Industry benchmarking

Mined and upgraded GHG emission intensity

Mine and upgraded GHG emissions intensity chart

1. Suncor numbers differ from those seen in the 2007 Report on Sustainability industry benchmarking data section, as Canadian Association of Petroleum Producers (CAPP) calculations for oil equivalent production were used to allow for direct comparison between CAPP industry-wide data and Suncor data

2. 2009 was the year of the merger and thus includes both Petro-Canada and Suncor data, all prior years to 2009 do not include Petro-Canada assets

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Oil sands GHG emission intensity

Oil sands GHG emissions intensity

1. Suncor numbers differ from those seen in the 2007 Report on Sustainability industry benchmarking data section, as CAPP calculations for oil equivalent production were used to allow for direct comparison between CAPP industry-wide data and Suncor data

2. 2009 was the year of the merger and thus includes both Petro Canada and Suncor data, all prior years to 2009 do not include Petro-Canada assets

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In-situ GHG emissions intensity

In Situ GHG emissions intensity

1. Suncor numbers differ from those seen in the 2007 Report on Sustainability industry benchmarking data section, as CAPP calculations for oil equivalent production were used to allow for direct comparison between CAPP industry-wide data and Suncor data

2. 2009 was the year of the merger and thus includes both Petro Canada and Suncor data, all prior years to 2009 do not include Petro-Canada assets

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Oil sands SO2 emissions intensity

Oil sands SO<sub>2</sub> emissions intensity chart

1. 2009 was the year of the merger and thus includes both Petro Canada and Suncor data, all prior years to 2009 do not include Petro-Canada assets

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Oil Sands NOx emissions intensity

Oil sands NO<sub>X</sub> emissions intensity chart

1. Historical NOx numbers were updated in 2011 to reflect National Pollutant Release Inventory (NPRI) submissions from Suncor legacy

2. 2009 was the year of the merger and thus includes both Petro-Canada and Suncor data, all prior years to 2009 do not include Petro-Canada assets

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