2013 GHG performance - Suncor’s 2014 Report on sustainability

2013 GHG performance - Suncor’s 2014 Report on sustainability

2013 GHG performance - Suncor’s 2014 Report on sustainability

2013 GHG performance - Suncor’s 2014 Report on sustainability

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2013 GHG performance

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Our Report on sustainability provides an annual accounting of our 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 from Suncor-operated facilities.

Production

As reported in our 2013 Annual Report, total upstream production averaged 562,400 barrels of oil equivalent per day (boe/d) through the course of 2013, compared to 549,100 boe/d in 2012. Oil Sands production (excluding Syncrude) averaged 360,500 barrels per day (bbls/d) in 2013, compared to 324,800 bbls/d in 2012.

Read the 2013 Annual Report (PDF 139 pp., 776 KB)

Our Oil Sands business delivered another record-setting year in 2013, resulting in an 11% increase in annual production at Oil Sands operations and record synthetic crude oil (SCO) production. These results were achieved despite a major turnaround in the second quarter and third-party outages that impacted Oil Sands operations during the year.

The fourth quarter of 2013 marked the completion of the ramp-up at Firebag, with daily production rates reaching approximately 95% of capacity. Completion of the Firebag ramp-up contributed to a 31% increase in annual production at Firebag in 2013, compared to 2012. Over the past three years, we have nearly tripled our production at Firebag. We are now the largest in situ producer, with more than 210,000 bbls/d of production capacity from our Firebag and MacKay River operations.

Production numbers in our Annual Report are for upstream volumes only, and include our net share of production from non-operated assets as well as operated assets. This differs from production numbers used in our Report on sustainability, which includes 100% of the production at Suncor-operated facilities upstream only, and also includes downstream throughput volumes of saleable refined products from Suncor-operated refineries and lubricants plant. For the purposes of our sustainability report, total production in 2013 was approximately 49.8 million cubic metres, compared to 49.1 million cubic metres in 2012.

Please note: the sum of the individual facilities production volumes will not equal the reported net corporate production. Inter- and intra-business-unit product transfers (hydrocarbon streams that pass through more than one 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 within 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 2013 totalled 20.6 million tonnes, compared to 20.3 million tonnes in 2012 – a 1.4% or 0.3 megatonne increase. This was mainly due to 1.2 megatonnes of CO2e emissions from the ramp up of Firebag expansion phases 3 and 4, with a majority of the increase coming from the Firebag phase 4. This was partially offset by the sale of most of our onshore conventional oil and gas properties in late 2013.

Using internationally accepted Global Reporting Initiative protocols, our 2013 corporate GHG emissions intensity remained relatively flat as compared to 2012 (0.1% decrease). Upstream intensity increases at our MacKay River in situ facility were offset by intensity decreases at the Terra Nova offshore operation, Firebag in situ facility and Oil Sands base plant. Downstream, intensity increases at the Montreal refinery, Edmonton refinery, Commerce City refinery and St Clair ethanol plant were offset by intensity decreases at the Sarnia refinery and Mississauga-based Lubricants facility. Improvements in the reliability of our base plant operations also helped to offset intensity increases. These improvements were achieved even with the completion of planned upgrader maintenance and unexpected third-party fuel supplier outages.

Read about the emission factors that went into calculating our 2013 GHG performance

Please note: All numbers included are for material 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.

GHG emissions (absolute and intensity)

Suncor-wide absolute GHG emissions, Suncor-wide greenhouse gas emissions intensity

(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 and 2000 do not include Suncor's U.S. operations, 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) Data here includes both direct and indirect CO2e emissions, whereas the data included in the Alberta SGER reports and other regulatory reports are direct emissions only. No credit is taken for GHG reductions due to cogen credits or purchased offsets. Emissions have been calculated using facility-specific methodologies; various reference methodologies accepted by jurisdictions where each facility is required to report GHG emissions. Where a jurisdiction has a prescribed methodology, it is followed and if none exists, the most applicable and accurate methods available are used to quantify each emission source. Beginning with 2013 data, the latest global warming potentials issued by the Intergovernmental Panel on Climate Change in their 2007 or Fourth Assessment report have been used to calculate CO2e. Historical data has not been updated to reflect this change as it does not impact corporate-wide emissions materially.

(4) Data and estimates have changed from previous years’ 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. Also, previous years’ emission updated numbers reflect changes including classifying purchased hydrogen emissions at Refining & Marketing facilities as an indirect scope 3 instead of an indirect scope 2, and a revised indirect scope 2 methodology for MacKay River.

(5) Data for 2009 and future years include 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 reported here.)

(6) 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.

(7) Refining & Marketing emissions are inclusive of emissions from the pipeline from Oil Sands to the Edmonton refinery, which is included in the Pipelines entity within R&M. The emission total for this source for 2013 was 51,304 tonnes CO2e.

Definitions:

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

Indirect GHG emissions: Energy-related 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 or steam).

Absolute (total) emissions: The total GHG emissions (sum of 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 total tonnes of CO2e emissions per unit of net processed volume in cubic metres).

Overall energy use and energy intensity

GHG emissions are closely linked to energy use with approximately 89% of direct GHG emissions being related to the consumption of energy for operations.

The following energy and energy intensity graphs show similar year over year trends to the GHG emissions and GHG emissions intensity graphs shown above. One of the key differences, however, is how energy generated as electrical power is treated.

Power generated by our cogeneration facilities (a highly efficient technology used to generate electricity from what would otherwise be waste heat) and wind farms is sold to provincial grids in the regions where facilities are located. This power is converted to an equivalent amount of energy and is deducted from our total energy use since it is sold as a product. Associated GHG emissions are not deducted from our total.  However, by producing this cleaner electricity and selling to the grid, we are off setting coal-fired power generations and reducing overall provincial GHG emissions.

Read more about cogeneration in OSQAR

Please note: All numbers included are for material operated facilities and properties only. They represent 100% of the direct and indirect energy use at these facilities. Data is not broken down by working interest and does not include non-operated facilities.

Suncor greenhouse gas emissions factors energy intensity

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

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

(3) Referred to in previous reports as International & Offshore. Historical data prior to 2010 included other international assets operated at that time. Since 2010 only energy use and production from Terra Nova off the east coast of Canada have been included.

(4) Refining & Marketing business energy use for 2010-2012 excludes the pipeline stations located on the pipeline from Oil Sands to Edmonton refinery. The energy associated with this source is included in the Suncor-wide total for 2010-2012 data. In 2013 this energy source was included within the R&M business unit and is also reflected in the Suncor-wide total.

(5) Renewables business unit is inclusive of the St. Clair ethanol plant for 2009-2013 and Suncor-operated wind farms for 2012-2013. Electricity that is produced and sold to provincial grids by the operated wind farms is converted to an equivalent amount in GJs and deducted from the total energy, which is why the 2012 and 2013 intensities decrease due to the startup of operated Suncor wind farms.

Suncor greenhouse gas emissions factors energy use

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

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

(3) Referred to in previous reports as International & Offshore. Historical data prior to 2010 included other international assets operated at that time. Since 2010, only energy use and production from Terra Nova off the east coast of Canada has been included.

(4) Refining & Marketing (R&M) total energy for 2010-2012 excludes energy from the pipeline from Oil Sands to the Edmonton refinery. The energy associated with this source is included in the Suncor-wide total for 2010-2012 data. The energy total for this source for 2013 was approximately 426,166 GJ.

(5) The Renewables business unit is inclusive of the St. Clair ethanol plant from 2009 to 2013 and operated Suncor wind farms for 2012-2013. Electricity that is produced and sold to provincial grids by the operated wind farms is converted to an equivalent amount in GJs and deducted from the total energy, which is why the 2012 and 2013 energy use values decrease due to the startup of operated Suncor wind farms.


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.

Emissions totals and variances for all operated facilities are available in the performance data section of this report.

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Oil Sands

Absolute emissions from our mine and upgrading operations decreased by 8.6% in 2013 as compared to 2012 because of lower fugitive emissions measurements.

Emissions intensity also decreased by 10.4% over the same period. The decrease can largely be attributed to improved reliability. Reliability improvements were achieved even with the completion of planned upgrader maintenance and unexpected third-party fuel supplier outages. We also saw record production during this time.

Oil Sands GHG emissions absolute and intensity

Suncor Oil sands absolute greenhouse gas emissions, Suncor Oil sands greenhouse gas emissions intensity

(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 or purchased offsets.

(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 in 2012, 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 and upgrading operations. In 2009 In Situ (Firebag and MacKay River) began reporting as its own business unit. Data for 2009 and forward 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 Poplar Creek 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.

Fort Hills

Sanctioned in 2013, the Fort Hills mining project will see us gradually bring on 180,000 bbls/day of production. We expect this to add over 3 mega-tonnes of CO2e to our operated emissions profile.

To determine how a change to Alberta’s current greenhouse gas regulation could impact this project, we applied our shadow carbon price. That means, in addition to using the existing penalty of $15/tonne CO2e on 12% of emissions, we also explored various regulatory scenarios.

For instance, if the existing carbon penalty were to increase to $40/tonne CO2e (or $55/tonne when considering inflation over the life of the project) on a steadily increasing percentage of project emissions, the projected change to the project’s internal rate of return (IRR) would be 0.10%. Now, if we apply the same $40/tonne CO2e as a flat carbon tax on all Fort Hills GHG emissions, the expected change in IRR is 0.39%.

The impact of higher carbon penalties is just one of many risks that are evaluated as part of project economics. When not applied equally to competing projects, it can create a competitive disadvantage.

Please note: The information above assumes a business environment based on $100/barrel Brent crude pricing and includes the use of emission performance credits as permitted under Alberta’s current regulatory regime.

In Situ

The overall absolute emissions and emissions intensity at our in situ oil sands operations increased in 2013. Absolute emissions increased by 32% compared to 2012, and emissions intensity increased slightly by 0.8%. Emissions increases were the result of the ramp-up of our Firebag 3 and 4 expansion project phases, with a majority of the increase coming from the Firebag 4 phase. The rise in absolute emissions reflects added steam generation required for increased production.

The slight increase in emissions intensity compared to the large increase in absolute emissions reflects the ramp up of the Firebag 3 and 4 expansions. Once reservoirs reach desired production levels and steady-state operation, emissions intensity typically decreases.

MacKay River absolute emissions and emissions intensity increased in 2013. This increase can be attributed to the addition of new wells that are still in preliminary steaming stage (similar to the Firebag expansions mentioned above) and have not yet reached their optimal production capacity.

In addition, a third-party cogeneration facility that is connected to our MacKay River in situ operation recently completed maintenance that required the facility to remain offline for a longer than normal period of time. This contributed to the increase in MacKay River’s emissions as steam demand was met locally rather than by the more efficient third-party cogeneration facility.

Suncor In Situ absolute greenhouse gas emissions, Suncor In Situ greenhouse gas emissions intensity

(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 or purchased offsets.

(3) For MacKay River, indirect emissions include electricity purchased from the grid, electricity purchased from the third party MacKay River cogen and purchased steam also purchased from the third party MacKay River cogen. Starting in 2013, MacKay River implemented a new methodology for calculating indirect emissions associated with energy streams purchased from the third party MacKay River cogen to remain consistent with the third party cogen that is the source of these energy streams; therefore, previous years are different than previously stated. This change is also reflected in the forecasted future years shown. Firebag cogen is owned and operated by Suncor and therefore all cogen emissions count toward Firebag’s total direct emissions including electricity sold to the grid.

(4) Historically, Firebag was reported as part of Oil Sands up to and including 2008. The 2008 Firebag data has already been reported as part of the Oil Sands 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.

Exploration & Production

East Coast Canada

Terra Nova emissions increased by 33% over 2012. This is largely due to a significant maintenance shutdown period in 2012 which resulted in lower-than-average annual emissions. Due to time required to complete the turnaround, we recorded fewer operational days in 2012 than in 2013. Production in 2013 was also higher than in 2012. As a result of the 2013 increase in operational days, emissions intensity per cubic metre of oil decreased by 18%. With this decrease, emission intensity levels are similar to 2011 – a more representative year than 2012.

Currently, Terra Nova is the only East Coast Canada asset we operate. Our other international and offshore production interests are joint ventures and not within our direct operational control. These joint venture operations are not included in this report.

Suncor East Coast Canada absolute greenhouse gas emissions, Suncor East Coast Canada greenhouse gas emissions intensity

* East Coast Canada was historically referenced as International & Offshore, but since 2010 when Netherlands properties (Hanze and De Ruyter) were sold, data has only included Suncor’s Terra Nova offshore facility in eastern Canada. Historical data prior to 2010 references performance data from international operated facilities as well as the Terra Nova facility.

(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 suncor.com.

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

(4) Data is presented for Suncor-operated facilities only, and does not include our interests in non-operated joint ventures. Operated facilities are shown as 100%, not adjusted for Suncor’s ownership share.

(5) Terra Nova production historically only included oil sales and not flaring and internally produced fuel. In 2011, these additional production volumes were included; however, to be consistent with other major facilities the production metric has been readjusted to only include oil sales.

North America Onshore

North America Onshore (NAO) emissions decreased as we completed the sale of the majority of our conventional natural gas business in the third quarter of 2013. Absolute emissions dropped by 37% and intensity decreased by 10% over 2012.

Reported numbers for NAO represent properties that were owned throughout the year as well as divested properties up to their date of sale.

Suncor North America Onshore absolute greenhouse gas emissions, Suncor North America Onshore greenhouse gas emissions intensity

(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 or other regulatory reports are direct emissions 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 Aug. 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 suncor.com.

(4) The “Other” category’s forecasted emissions are included in the B.C. category.

Refining & Marketing

In 2013, GHG emissions and emissions intensity at our Refining & Marketing facilities remained relatively unchanged. Compared to 2012, emissions experienced a slight decrease of 0.3% while emission intensity increased by 0.2%. Completion of planned maintenance at several facilities resulted in a small decrease to production. This contributed to the incremental increase to emission intensity.

Suncor Canada, United States - Refining and Marketing absolute greenhouse gas emissions, Suncor Canada, United States - Refining and Marketing greenhouse gas emissions intensity

(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 and other regulatory reports are 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 and has been included in the historical data for the Renewables business unit.

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

(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.

(6) R&M emissions from purchased third-party merchant hydrogen plants have not been included in the total GHG emissions (direct + indirect) as these emissions do not meet the definition for an indirect (scope 2) emission source. These emissions are included in the indirect scope 3 emissions section of this report.

(7) 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 indirect scope 3 emissions from products, consistent with provincial government reporting requirement in Ontario and Quebec.

(8) Re-reported emissions for previous years include subtracting the indirect emissions from purchased hydrogen and CO2 sales volumes. Forecasted years also recognize this classification of purchased hydrogen and CO2 sales emission sources as indirect scope 3 emissions.

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

(10) Other category includes Burrard terminal and Pipelines. Pipelines include pipeline stations on the Oil Sands to Edmonton refinery pipeline in Alberta. Pipelines category has been included here starting in 2010 and in future years.

Renewables

We were an early entrant in the renewable energy business in Canada. Our investments to date are focused on wind power and biofuels.

St. Clair ethanol plant

We have been blending ethanol in our retail fuels since 1992. We opened the St. Clair ethanol plant in Mooretown, Ont., in 2006 and in 2011 we doubled the plant’s production capacity to 400 million litres of corn-based ethanol annually. It is the single largest ethanol production plant in Canada.

Absolute emissions and emissions intensity from the St. Clair ethanol plant remained relatively flat from 2012 to 2013 with only slight increases of 1.4% and 0.8% respectively. 

Wind power

We are currently involved in six operating wind farm projects – five of which are joint ventures. The total installed wind capacity of these operations is 255 megawatts, enough to power about 100,000 Canadian homes.

Performance data reported is for operated wind farms only. This includes the 20 MW Kent Breeze farm in Ontario and the 88 MW Wintering Hills farm in Alberta. In 2013, these two farms emitted only 159 tonnes CO2e and produced over 325,000 MWh – enough electricity to power about 27,500 Canadian homes. For reference, an equivalent size natural gas power plant producing a comparable amount of electricity would emit over 120,000 tonnes CO2e annually. That’s 755 times more emissions than our wind farms.

Suncor renewables absolute greenhouse gas emissions, Suncor renewables greenhouse gas emissions intensity

(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 or wind generated offsets.

(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 ethanol 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.