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North America Onshore

In 2009, as a result of the Suncor and Petro-Canada merger, the conventional upstream oil and gas facilities from both organizations were brought under common management and operation in the Natural Gas business unit. The number of facilities within the combined Natural Gas business unit of the merged company is much larger than those that were present in the Suncor business. Therefore, large differences in data are apparent between the 2009 operating year and the historical data.

All significant data changes from 2008 are due to the 2009 merger of Petro-Canada and Suncor Energy whereby all data reported is from the combined company facilities for the full 2009 reporting year. In 2010 and 2011, a number of Suncor's Natural Gas assets were divested which explains the downward trend in some of the indicators in this section.

Data included in the 2013 report consists of operated assets only. Thus, the North America Onshore performance indicator section reports on our operated North America Onshore assets, primarily in Western Canada.

On April 15, 2013 Suncor announced the sale of a majority of the conventional portion of its natural gas business in Western Canada, but retained a majority of its unconventional natural gas properties in British Columbia and unconventional oil assets in Alberta. Future reports will reflect this change.

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Environment

The A symbol () reflects data that has been assured by a third party. View a complete list of reviewed data to confirm the performance indicators that have been assured. In the "Footnote" column, click on the down-arrow symbol to display the footnote.

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Indicator Unit Footnote GRI indicator 2008 2009 2010 2011 2012
Production                
Processed volume million barrels of oil equivalent/year EN1 17.9 64.2 58.3 44.8 47.0

Footnote A:
Processed volume is the total amount of hydrocarbons processed at Suncor operated facilities. This includes production owned by Suncor as well as production owned by other companies and processed by Suncor. Processed volume is used to calculate intensities.

Processed volume million m3 of oil equivalent/year EN1 2.8 10.2 9.3 7.1 7.5

Footnote A:
Processed volume is the total amount of hydrocarbons processed at Suncor operated facilities. This includes production owned by Suncor as well as production owned by other companies and processed by Suncor. Processed volume is used to calculate intensities.

Air emissions              

Footnote B:
Beginning in 2009, air emissions data includes consolidated post-merger information. The 2009 air emissions are for all Suncor operated facilities within the merged company, which includes facilities from both of the Petro-Canada and Suncor organizations. 2010 data includes partial year estimates of emissions from sites operated by Suncor until divested during the 2010 reporting year.

Greenhouse gas (GHG) thousand tonnes CO2e/year EN16 430 1,862 1,703 1,035 995

Footnote C:
Greenhouse gas emissions are calculated based on the Canadian Association for Petroleum Producers (CAPP) Short-Form Emissions Calculation Method as described in the CAPP Guide: Calculating Greenhouse Gas Emissions (CAPP 2003). For Alberta facilities covered under the Alberta Environment & Sustainable Resource Development (AESRD) regulation, the data is consistent with Suncor's Specified Gas Emitters Regulation (SGER) Bill 3 reported Total Annual Emission (TAE) value, with one exception. The reported TAE in the SGER compliance report excludes indirect CO2 emissions. Suncor did not report any emissions from hydroflourocarbons (HFCs), Perflourocarbons (PFCs) or Sulphur hexaflouride (SF6). For BC facilities covered under the Cap and Trade Act reporting requirements, Western Climate Initiative (WCI) methodologies are used. Data includes partial year estimates of emissions from sites operated by Suncor until divested during the 2011 reporting year.

GHG emission intensity tonnes CO2e /m3 production   EN16 0.15 0.18 0.18 0.15 0.13
Sulphur dioxide (SO2) thousand tonnes/year EN20 1.4 7.5 5.6 3.3 3.6

Footnote D:
Total SO2 emissions from Suncor operated facilities. This total includes emissions from operated facilities required to report under regulatory reporting programs as well as those facilities not required to report under regulatory programs.

Sulphur dioxide emission intensity kg/m3 production   EN20 0.49 0.74 0.61 0.47 0.48
Nitrogen oxides (NOx) thousand tonnes/year EN20 2.7 12.1 10.9 7.6 6.9

Footnote E:
Total NOx emissions from Suncor operated facilities. This total includes emissions from operated facilities required to report under regulatory reporting programs as well as those facilities not required to report under regulatory programs.

Nitrogen oxides emission intensity kg/m3 production   EN20 0.96 1.19 1.17 1.07 0.93
Volatile organic compounds (VOCs) thousand tonnes/year EN20 0.49 6.42 0.71 0.49 0.45

Footnote F:
Total VOC emissions from Suncor operated facilities. This total includes emissions from operated facilities required to report under regulatory reporting programs as well as those facilities not required to report under regulatory programs.

Benzene tonnes/year EN20 -- 53.9 18.6 10.6 12.6

Footnote G:
In 2011 benzene emissions decreased because many of the 2010 divested facilities had dehydrators which are a relatively large source of benzene emissions in the upstream oil and gas industry.

VOC emission intensity kg/m3 production   EN20 0.17 0.63 0.08 0.07 0.06
NPRI on-site releases thousand tonnes/year   EN20 5.9 25.0 14.9 14.0 13.0
Total gas flaring million m3/year   OG6 5.1 11.8 10.5 8.4 10.2
Solution gas flaring million m3/year   OG6 0.1 0.5 0.7 0.3 1.0
Other flaring sources million m3/year   OG6 5.0 11.3 9.8 8.02 9.23
Flared gas intensity m3/m3 production   OG6 1.8 1.2 1.2 1.2 1.5
Energy consumption                
Total energy use million gigajoules   EN3/4 3.6 20.2 17.3 12.2 11.8
Direct energy use million gigajoules EN3 3.4 19.4 16.7 11.8 11.5

Footnote H:
Direct energy is energy consumed on-site by Suncor operated facilities. Indirect energy includes imported electricity, steam, heating and cooling duty from third parties. In 2011, energy use decreased due to divestments that occurred in late 2010 and 2011.

Indirect energy use million gigajoules EN4 0.2 0.8 0.6 0.4 0.3

Footnote H:
Direct energy is energy consumed on-site by Suncor operated facilities. Indirect energy includes imported electricity, steam, heating and cooling duty from third parties. In 2011, energy use decreased due to divestments that occurred in late 2010 and 2011.

Energy intensity gigajoules/m3 production   EN3/4 1.27 1.97 1.80 1.71 1.58
Energy saved through conservation and efficiency improvements thousand gigajoules   EN5 127 342 505 395 36
Water use                
Water withdrawal million m3   EN8 0.26 0.49 0.65 0.55 0.54
Water withdrawal intensity m3/m3 production   EN8 0.09 0.05 0.07 0.08 0.07
Water returned million m3 EN21 0.03 0.05 0.00 0.00 0.00

Footnote I:
In North America Onshore, water returned is comprised of precipitation water released from run-off ponds. As this precipitation is not included in the water withdrawal indicator, precipitation as water returned is not recorded as it would skew the water consumption and water returned volumes. Beginning in 2010 precipitation is not included in water returned; in previous years, precipitation was included as water returned.

Water consumption million m3     0.23 0.44 0.65 0.55 0.54
Water consumption intensity m3/m3 production     0.08 0.04 0.07 0.08 0.07
Produced water million m3 OG5 0.44 0.24 2.61 2.12 1.77

Footnote J:
Produced water is all formation and other water brought to the surface during the normal course of our natural gas production process.

Waste management              

Footnote K:
Beginning in 2011, in order to better align with the GRI reporting standard, Suncor has expanded the number of indicators for which it collects and reports data in the Waste Management category.

Hazardous waste generated thousand tonnes EN22 4.6 4.0 3.1 5.2 4.0

Footnote L:
In 2011, North America Onshore compiled all waste data from our major receivers (compared to 2010 which only tracked manifested waste) to provide more accurate waste reporting.

Hazardous waste incinerated tonnes   EN22 -- -- -- 17.1 19.5
Hazardous waste deep well injected
tonnes EN22 -- -- -- 3,617.8 85.6

Footnote M:
This is variable year to year based on operations conducted.

Hazardous waste landfilled
tonnes   EN22 -- -- -- 75.0 91.5
Hazardous waste otherwise disposed tonnes   EN22 -- -- -- 1,492.0 3,764.7
Non-hazardous waste generated thousand tonnes EN22 45.4 161.5 39.6 80.3 178.3

Footnote N:
An increased volume of non-hazardous waste generated in 2012 is primarily due to remediation and reclamation activities including biopile removal.

Non-hazardous waste incinerated
tonnes   EN22 -- -- -- 2.7 0.0
Non-hazardous waste deep well injected
tonnes   EN22 -- -- -- 922.3 549.1
Non-hazardous waste landfilled
tonnes   EN22 -- -- -- 57,008.6 148,980.3
Non-hazardous waste otherwise disposed tonnes   EN22 -- -- -- 22,351.7 28,800.0
Drilling waste disposed or treated tonnes OG7 -- -- -- -- 465.0

Footnote O:
New GRI Oil and Gas Sector Supplement indicator for 2012 and reflects the first year of reporting. Inclusive of drilling mud waste from drilling operations. This value has not been captured in the hazardous waste generated and non-hazardous waste generated values.

Waste reused/recycled/recovered off-site tonnes   EN22 72 454 288 133.1 164.8
Land disturbance and reclamation                
Total number of producing wells     530 5,186 4,783 4,840 4,902

Footnote P:
Historically this number was determined in accordance with Interest Well reports. Since 2010, both public and regulatory agency databases were mined and compared with Suncor wells with associated yearly production volumes.

Suncor-operated producing wells       333 4,978 4,623 4,716 4,797
Number of shut-in/suspended production wells     163 472 1,057 1,143 1,339

Footnote Q:
A shut-in well is taken out of production by shutting off flow at the wellhead, often with the expectation of resuming production in the future. A suspended well is a shut-in well on which additional subsurface isolation procedures have been performed and which is usually taken out of production due to poor economics. If a suspended well is not brought back into production, it is taken out of service as per regulatory requirements. Since 2010, the inactive and suspended well lists from the Western Canadian regulatory agencies (Energy Resources Conservation Board (ERCB), Government of Saskatchewan (SK) Energy and Resources and British Columbia Oil and Gas Commission (BCOGC)) were utilized in determining this total.

Number of wells undergoing reclamation   EN13 35 385 476 285 270

Footnote R:
Since 2010, for the purpose of the Report on Sustainability, the number of wells undergoing reclamation include abandoned sites in the care and custody of North America Offshore (NAO) Surface, Land, Logistics and Construction Liability Management group that are categorized (i.e., site status) as Phase I, Phase II, Risk Management, Remediation and Reclamation. Sites categorized with the status 'Pre-Screening' were not included. Further explanation of each category is detailed in Suncor's Draft Remediation - Reclamation Framework document. These are sites we are actively working on in some form or another, with the end goal being closure/obtaining closure through a Reclamation Certificate or alternative certification.

Number of reclamation certificates received
    EN13 5 6 2 0 2
Compliance                
Major incidents   LA7, SO8 0 0 0 0 1

Footnote S:
Major incidents are environment, health or safety incidents that result in a permanent disability or fatality, punitive action by government, having catastrophic environmental impact, or significant impact to the company's reputation.
In 2012 an oil well blowout and fire occurred at the Suncor well site in the Altares field, 69 kilometres west of Fort St. John, B.C.

Regulatory contraventions   EN28 31 51 60 26 32

Footnote T:
A regulatory contravention is an environmental incident that breaches a regulatory limit (prescribed threshold required by legislation, approval or permit from a regulatory authority) or requirement (any law, act, regulation, license, standard, approval, directive and/or permit applicable to Suncor's activities"  and that triggers formal regulatory reporting.

Air quality exceedances     EN28 10 21 16 3 4
Water effluent exceedances     EN28 0 0 -- -- --
Reportable spills   EN23 18 38 20 16 15

Footnote U:
Reportable spills are defined in accordance with federal and provincial regulations.

Spills to watercourses     EN23 0 1 0 0 0
Total volume of spills m3   EN23 34 446 25 46 204.85
Regulatory fines $ EN28 51,500 0 0 2,120 12,080

Footnote V:
Regulatory fines associated with late production accounting filings.

Environment, Health & Safety (EH&S) management                
Projects to reduce GHG emissions and reductions achieved thousand tonnes
CO2e/yr
  EN7 -- -- 25,631.70 29,324.00 24,937.43
EH&S professionals on staff   EN30 7 23 55 38 41

Footnote W:
This number also includes the International & Offshore Environment, Health and Safety professionals on staff.

Natural Gas environment footnotes
A Processed volume is the total amount of hydrocarbons processed at Suncor operated facilities. This includes production owned by Suncor as well as production owned by other companies and processed by Suncor. Processed volume is used to calculate intensities.
B Beginning in 2009, air emissions data includes consolidated post-merger information. The 2009 air emissions are for all Suncor operated facilities within the merged company, which includes facilities from both of the Petro-Canada and Suncor organizations. 2010 data includes partial year estimates of emissions from sites operated by Suncor until divested during the 2010 reporting year.
C Greenhouse gas emissions are calculated based on the Canadian Association for Petroleum Producers (CAPP) Short-Form Emissions Calculation Method as described in the CAPP Guide: Calculating Greenhouse Gas Emissions (CAPP 2003). For Alberta facilities covered under the Alberta Environment & Sustainable Resource Development (AESRD) regulation, the data is consistent with Suncor's Specified Gas Emitters Regulation (SGER) Bill 3 reported Total Annual Emission (TAE) value, with one exception. The reported TAE in the SGER compliance report excludes indirect CO2 emissions. Suncor did not report any emissions from hydroflourocarbons (HFCs), Perflourocarbons (PFCs) or Sulphur hexaflouride (SF6). For BC facilities covered under the Cap and Trade Act reporting requirements, Western Climate Initiative (WCI) methodologies are used. Data includes partial year estimates of emissions from sites operated by Suncor until divested during the 2011 reporting year.
D Total SO2 emissions from Suncor operated facilities. This total includes emissions from operated facilities required to report under regulatory reporting programs as well as those facilities not required to report under regulatory programs.
E Total NOx emissions from Suncor operated facilities. This total includes emissions from operated facilities required to report under regulatory reporting programs as well as those facilities not required to report under regulatory programs.
F Total VOC emissions from Suncor operated facilities. This total includes emissions from operated facilities required to report under regulatory reporting programs as well as those facilities not required to report under regulatory programs.
G In 2011 benzene emissions decreased because many of the 2010 divested facilities had dehydrators which are a relatively large source of benzene emissions in the upstream oil and gas industry.
H Direct energy is energy consumed on-site by Suncor operated facilities. Indirect energy includes imported electricity, steam, heating and cooling duty from third parties. In 2011, energy use decreased due to divestments that occurred in late 2010 and 2011.
I In North America Onshore, water returned is comprised of precipitation water released from run-off ponds. As this precipitation is not included in the water withdrawal indicator, precipitation as water returned is not recorded as it would skew the water consumption and water returned volumes. Beginning in 2010 precipitation is not included in water returned; in previous years, precipitation was included as water returned.
J Produced water is all formation and other water brought to the surface during the normal course of our natural gas production process.
K Beginning in 2011, in order to better align with the GRI reporting standard, Suncor has expanded the number of indicators for which it collects and reports data in the Waste Management category.
L In 2011, North America Onshore compiled all waste data from our major receivers (compared to 2010 which only tracked manifested waste) to provide more accurate waste reporting.
M This is variable year to year based on operations conducted.
N An increased volume of non-hazardous waste generated in 2012 is primarily due to remediation and reclamation activities including biopile removal.
O New GRI Oil and Gas Sector Supplement indicator for 2012 and reflects the first year of reporting. Inclusive of drilling mud waste from drilling operations. This value has not been captured in the hazardous waste generated and non-hazardous waste generated values.
P Historically this number was determined in accordance with Interest Well reports. Since 2010, both public and regulatory agency databases were mined and compared with Suncor wells with associated yearly production volumes.
Q A shut-in well is taken out of production by shutting off flow at the wellhead, often with the expectation of resuming production in the future. A suspended well is a shut-in well on which additional subsurface isolation procedures have been performed and which is usually taken out of production due to poor economics. If a suspended well is not brought back into production, it is taken out of service as per regulatory requirements. Since 2010, the inactive and suspended well lists from the Western Canadian regulatory agencies (Energy Resources Conservation Board (ERCB), Government of Saskatchewan (SK) Energy and Resources and British Columbia Oil and Gas Commission (BCOGC)) were utilized in determining this total.
R Since 2010, for the purpose of the Report on Sustainability, the number of wells undergoing reclamation include abandoned sites in the care and custody of North America Offshore (NAO) Surface, Land, Logistics and Construction Liability Management group that are categorized (i.e., site status) as Phase I, Phase II, Risk Management, Remediation and Reclamation. Sites categorized with the status 'Pre-Screening' were not included. Further explanation of each category is detailed in Suncor's Draft Remediation - Reclamation Framework document. These are sites we are actively working on in some form or another, with the end goal being closure/obtaining closure through a Reclamation Certificate or alternative certification.
S Major incidents are environment, health or safety incidents that result in a permanent disability or fatality, punitive action by government, having catastrophic environmental impact, or significant impact to the company's reputation.
In 2012 an oil well blowout and fire occurred at the Suncor well site in the Altares field, 69 kilometres west of Fort St. John, B.C.
T A regulatory contravention is an environmental incident that breaches a regulatory limit (prescribed threshold required by legislation, approval or permit from a regulatory authority) or requirement (any law, act, regulation, license, standard, approval, directive and/or permit applicable to Suncor's activities"  and that triggers formal regulatory reporting.
U Reportable spills are defined in accordance with federal and provincial regulations.
V Regulatory fines associated with late production accounting filings.
W This number also includes the International & Offshore Environment, Health and Safety professionals on staff.

Economic

In the "Footnote" column, click on the down-arrow symbol to display the footnote.

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Indicator Unit Footnote GRI indicator 2008 2009 2010 2011 2012
Production              

Footnote X:
Excludes volumes processed on behalf of others. These values are consistent with those found in Suncor's annual reports but differ from the processed production volumes in the natural gas environmental performance section, which does include volumes processed for others.

Thousand barrels of oil equivalent/day thousand barrels of oil/day EN1 36.7 74.4 95.8 64.7 53.8

Footnote Y:
Gas is converted to barrels of oil equivalent, assuming six million cubic feet of natural gas is equivalent to 1,000 barrels of oil.

Natural gas million cubic feet/day   EN1 202 398 522 357 290
Financials              

Footnote Z:
For complete disclosure and additional information see our 2012 annual financial report (PDF, 139p., 776 KB).

Net earnings $ millions   EC1 89 -199 441* -30 -245
Cash flow from operations $ millions   EC1 367 329 445 277 101
Tax and royalty credits earned $ millions EC4 11.5 8 14.98 14.2 12.4

Footnote AA:
Includes the Deep Gas Royalty Holiday Program and Alberta Royalty Tax Credit.

Investments                
Capital and exploration expenditures $ millions   EC1 342 320 178 137 154
Purchases                
Goods and services $ millions     458 1,151 359 260 327
Goods and services purchased in or from                
Canada $ millions     457 994 343 260 326
Local businesses/suppliers $ millions EC6 452 865 303 237 311

Footnote BB:
Local businesses/suppliers are those established in the region of operations (2009-2012 data includes Alberta and British Columbia operations).

North America Onshore economy footnotes
* Data for 2009 and prior years is presented in accordance with the previous GAAP standard. All values are consistent with Suncor's annual reports.
X Excludes volumes processed on behalf of others. These values are consistent with those found in Suncor's annual reports but differ from the processed production volumes in the natural gas environmental performance section, which does include volumes processed for others.
Y Gas is converted to barrels of oil equivalent, assuming six million cubic feet of natural gas is equivalent to 1,000 barrels of oil.
Z For complete disclosure and additional information see our 2012 annual financial report (PDF, 139p., 776 KB).
AA Includes the Deep Gas Royalty Holiday Program and Alberta Royalty Tax Credit.
BB Local businesses/suppliers are those established in the region of operations (2009-2012 data includes Alberta and British Columbia operations).

Social

North America Onshore social footnotes
CC On Jan. 31, 2011, Suncor's International & Offshore (I&O) and North America Onshore (formerly Natural Gas) businesses merged into a single organization called Exploration & Production (E&P). As a result of this business unit reorganization, health and safety data collected for North America Onshore also includes data for the I&O business unit.
DD Recordable injuries include lost time injuries as well as medical aid injuries. Medical aid injuries require medical attentions but do not result in an employee being absent from work. Recordable injury frequency is the sum of lost time and medical aid injuries per 200,000 hours worked.
EE Compares Natural Gas full-time base wage to the state of Alberta's minimum wage. In 2012, we used minimum wage as $9.75.
FF Includes support of the Suncor educational assistance plan that reimburses tuition upon successful completion of a course or program. 2009 data excludes Petro-Canada information due to differences in the systems that report this data.
GG Any externally hired regular full-time or regular part-time employee whose permanent start date falls within the reporting period.
HH North America Onshore experienced an increase in employee turnover as a result of 2009 merger.
II Beginning in 2010, this number is reported on a Suncor-wide level and the breakdown is not available.
JJ In 2012, there were no males in Business Support Roles.