2012 GHG performance - Suncor's 2013 Report on Sustainability

2012 GHG performance - Suncor's 2013 Report on Sustainability

2012 GHG performance - Suncor's 2013 Report on Sustainability

2012 GHG performance - Suncor's 2013 Report on Sustainability

View the latest Report on Sustainability

2012 GHG performance

Our Report on Sustainability provides an annual accounting of Suncor’s greenhouse gas (GHG) emissions, both in terms of absolute emissions and emissions intensity. The latter is calculated by using full-year net production and the carbon dioxide equivalent (CO2e) volumes emitted.

Production

As reported in our 2012 Annual Report, total upstream production averaged 549,100 barrels of oil equivalent per day (boe/d) through the course of 2012, compared to 546,000 boe/d in 2011. Oil Sands production (excluding Syncrude) averaged 324,800 barrels per day (bbls/d) in 2012, compared to 304,700 bbls/d in 2011.

Download the 2012 Annual Report (PDF 139 pp., 776 KB)

The most significant production change: a 75% growth in production at Suncor's Firebag in situ operations, due to the ramp up of Firebag Stage 3 and the commissioning of Firebag Stage 4 facilities in 2012. Annual bitumen production from Firebag increased to 104,000 bbls/d in 2012, from 59,500 bbls/d in 2011. Oil Sands production (excluding Syncrude) averaged 324,800 barrels per day (bbls/d) in 2012, compared to 304,700 bbls/d in 2011.

However, Suncor's overall production was impacted by upgrader reliability in Oil Sands as well as planned maintenance and unplanned repairs related to the Terra Nova offshore turnaround.

Production numbers in Suncor's Annual Report are for upstream volumes only, and include production from non-operated assets. This differs from production numbers used in Suncor's Report on Sustainability, which includes 100% of the production at Suncor-operated facilities only, and also includes downstream throughput volumes of saleable products. For the purposes of our sustainability report, total production in 2012 was approximately 49.1 million cubic metres, compared to 48.8 million cubic metres in 2011.

Please note: the sum of the individual Suncor facilities production will not equal the reported net corporate production. Inter- and intra-business unit product transfers (hydrocarbon streams that pass through more than one Suncor facility) are removed from the corporate and business unit totals to give the net production. This is done to prevent double-counting of hydrocarbon streams sent for further processing inside the company.

  • Individual facility intensities are calculated based on net facility production.
  • Business unit intensities are calculated based on net facility production totals minus intra-business unit material transfers.
  • Corporate GHG intensity is calculated based on net corporate production which also removes inter-business unit transfers.

Overall absolute emissions and emissions intensity

Absolute full-year carbon dioxide (CO2) emissions in 2012 totalled 20.8 million tonnes, compared to 18.8 million tonnes in 2011 — a 11.1% or two megatonne increase. This was mainly due to 1,470 kilotonnes of CO2e emissions from the ramp up of Firebag 3, the commissioning of Firebag 4, and negligible increase from Mackay River.The remaining 0.7 megatonne increase was due to a methodology improvement at the Oil Sands base plant for fugitive emissions sources.

Using globally accepted GRI protocols, Suncor's reported corporate GHG emissions intensity increased by 10.5% in 2012 over 2011. The increase was mainly due to the ramp up of Firebag 3 and commissioning of Firebag 4. When an in situ plant is commissioned, steaming occurs for a period of time before full oil production rates are reached, so the initial intensity of the expansion facilities can be quite high for the first few months. Also contributing to the increase was a change in methodology at the Oil Sands base plant, as well as an extended turnaround at the Terra Nova floating production, storage and offloading (FPSO).

Intensity increases at our in situ operations were partially offset by intensity decreases at North America Onshore, Edmonton refinery and the St. Clair ethanol plant.

All numbers included are for significant operated facilities and properties only and represent 100% of the direct and indirect emissions at these facilities. Data is not broken down by working interest and does not include non-operated facilities.

Suncor 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 (BU's), combined Suncor / Petro-Canada data is provided for some years prior to 2009 but this is not reflected in the Suncor-wide roll-up.

(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 express 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).


Emissions highlights

What follows are highlights and explanations describing the most noteworthy emissions variances at some of our operations. Where emissions were relatively flat or stable, no commentary is offered. However, emissions totals and variances for all of our operated facilities are available in the data section of this report.

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Oil Sands

Absolute emissions at Suncor's mineable operations grew by 8.1% in 2012, and emissions intensity increased by 10.1% compared to 2011.

Oil Sands absolute emissions and emissions intensity both increased in 2012. This was due to reliability challenges that lead to increased flaring and also further improvements made to our Alberta Environment and Sustainable Resource Development (AESRD) approved measurement and reporting methodology.

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.

In Situ

The overall absolute emissions and emissions intensity at our in situ oil sands operations increased in 2012. Absolute emissions increased by 56% compared to 2011, and emissions intensity increased by 6.1%. The increases were due to the ramp up of our Firebag 3 expansion project and commissioning of Firebag 4. The rise in absolute emissions reflects added steam generation required for increased production. The rise in emissions intensity is due to the fact that, during the initial months of a new in situ plant, significant steaming is required to condition the 'cold' reservoir, while production rates are initially limited. As production ramps up, it is expected that emissions intensity should decline.

Absolute emissions at Firebag 1 and Firebag 2 increased slightly due to an increase in production, therefore requiring additional steam generation. Emissions intensity at Firebag 1 and 2 decreased due to the addition of new infill wells, which require less additional steam to heat the reservoir when compared to other new wells due to their placement near existing wells.

Reported MacKay River absolute emissions, as well as emissions intensity, both increased slightly, mainly due to the addition of new wells that are still in the preliminary steaming stage (similar to the Firebag expansions) and therefore have not yet reached their optimal production capacity.

In Situ GHG Emissions

(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.

International & Offshore

Terra Nova emissions were essentially unchanged over 2012, but production was lower due to natural reservoir declines and 27 days of planned downtime for maintenance. The off-station project was a large turnaround in 2012 that brought the Terra Nova FPSO from the Terra Nova field to the Marystown shipyard for regular maintenance and upgrades. As a result, the emissions intensity per cubic metre of oil increased by 29%. As oilfields mature, the total amount of fluid produced is often roughly stable but the water fraction increases; oil production decreases but the equipment needed to move the total fluid still has to work as hard as ever to accommodate the extra water. Currently, Terra Nova is the only International & Offshore asset operated by Suncor.

International and Offshore GHG Emissions

(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).

North America Onshore

North America Onshore* emissions dropped mainly due to asset sales of older properties, and improved performance at the Hanlan Robb gas plant. Absolute emissions dropped by 3.9% and intensity improved 8.7% over the previous year.

North America Onshore GHG Emissions

(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

Refining & Marketing

Emissions in 2012 at our Refining & Marketing facilities increased by 2% compared to 2011, while GHG intensity decreased by 1.5 %. The intensity decrease was primarily due to record refinery utilization and an increase in the Edmonton refinery's nameplate capacity.

Refining & Marketing GHG Emissions

(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.

Renewables

Suncor is a significant player in renewable energy in Canada. Our investments to date are focused on wind power and biofuels.

St. Clair ethanol plant

Suncor has been blending ethanol in our retail fuels since 1992. Suncor opened the St. Clair ethanol plant in Mooretown, Ont., in 2006 and completed a $120 million expansion of that facility in 2011.

The St. Clair plant has the capacity to produce 400 million litres of corn-based ethanol annually. It is the largest single ethanol plant in Canada and accounts for roughly 30% of national production. Absolute emissions increased slightly by 5.3% and emissions intensity decreased by 7.1% in 2012 as the facility comes off its recently completed expansion in 2011.

Wind power

Wind power is one of the fastest growing sources of electricity generation in the world. Suncor is currently involved in six operating wind farm projects — two of which are operated by Suncor and four of which are non-operated. The total installed wind capacity of these operations is 255 megawatts, enough to power about 100,000 Canadian homes.

2012 represents our first full year of operations at our operated wind farms located in Alberta and Ontario. This is therefore the first year that resulting GHG emissions have been included in reporting. These wind power projects produce electricity which is not converted to a production metric in this report. Produced power has been accounted for as a net negative indirect energy use in renewables.

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.