Greenhouse gas emissions
We aim to manage our greenhouse gas emissions through improved operational energy efficiency and reductions in flaring and venting
Oil and natural gas companies generate greenhouse gases (GHGs) in almost every aspect of their work, from the finding, extracting and processing of hydrocarbon resources to the transforming and delivery of these resources to customers. During these processes, the most significant GHG emissions come from the combustion of fossil fuels for energy, the flaring and venting of gas and also from process and fugitive sources.
The science of global climate change is increasingly clear. In response to this, the regulation of greenhouse gas emissions is increasing globally with this trend expected to continue. As these regulations develop, our emissions may become subject to emission pricing schemes (such as is already the case with the EU Emission Trading Scheme); our products subject to fuel, product, and energy specifications; and our operations subject to direct regulatory requirements
The science of global climate change is increasingly clear. In response to this, the regulation of greenhouse gas emissions is increasing globally with this trend expected to continue. As these regulations develop, our emissions may become subject to emission pricing schemes (such as is already the case with the EU Emission Trading Scheme); our products subject to fuel, product, and energy specifications; and our operations subject to direct regulatory requirements
Many of these regulatory programmes are in the detailed development stage with the final structure and impacts quite uncertain. Some of these regulations are, or are likely to be, subject to numerous legal challenges, leading to an additional degree of uncertainty in the wider industry regarding the future regulatory landscape.
Our approach
BP aims to manage its operational GHG emissions through operational energy efficiency, reductions in flaring and venting, and by factoring a carbon cost into our investment appraisals and the engineering design of new projects.
Greenhouse gas emissions targets
BP established an absolute GHG emissions target in 1998. Initially this led to the implementation of a large number of cost-effective emission reduction initiatives and actions. In 2008, we concluded that an enterprise-wide GHG emissions target was no longer practical or useful in driving emissions reduction at the plant and operational level.
Instead, we decided that a local approach to GHG emissions management was more practical and we have since focused our efforts on energy efficiency and reducing flaring and venting where it is relevant for local business management.
Internal carbon price
We factor a carbon cost into our investment appraisals and engineering designs for some new projects. We do this in order to assess, and protect the value of, our new investments under future scenarios in which the cost of carbon emissions is higher than it is today. We require larger projects, and those for which emissions costs would be a material part of the project, to apply a standard carbon cost to the projected GHG emissions over the life of the project. The standard cost is based on our estimate of the carbon price that might realistically be expected in particular parts of the world. In industrialized countries, this standard cost assumption is currently $40 per tonne of CO2 equivalent. We use this cost as a basis for assessing the economic value of the investment and as one consideration in optimizing the way the project is engineered with respect to emissions.
Our performance
Our direct GHG emissions were 59.8 million tonnes (Mte) in 2012, compared with 61.8 Mte in 2011, a decrease of 2.0 Mte versus 2011. The chart below provides our historical direct GHG emissions for the past five years.
| Table of emissions | |||||
|
2008 | 2009 | 2010 | 2011 | 2012 |
| Direct carbon dioxide (CO2) (million tonnes (Mte)) | 57.0 | 60.4 | 60.2 | 57.7 | 56.4 |
| Direct methane (Mte) | 0.21 | 0.22 | 0.22 | 0.20 | 0.17 |
| Direct greenhouse gas (GHG) (Mte CO2 equivalent (CO2e)) | 61.4 | 65.0 | 64.9 | 61.8 | 59.8 |
| Indirect carbon dioxide (CO2) (Mte) | 9.2 | 9.6 | 10.0 | 9.0 | 8.4 |
| We report greenhouse gas (GHG) emissions on a CO2-equivalent basis, including CO2 and methane. This represents all consolidated entities and BP's share of equity-accounted entities except TNK-BP. | |||||
The chart below helps to explain the year-on-year variance in BP’s reported direct GHG emissions in more detail.
The net effect of acquisitions and divestments is a decrease of 0.7 Mte, primarily the result of the sale of upstream assets as part of our divestment programme. Operational changes led to a decrease of 0.7 Mte, principally due to temporary reductions in activity at some of our upstream sites and one of our major US refineries and lower mileage by our shipping vessels.
Improvements made by our businesses to calculate their emissions more accurately resulted in a net decrease of 0.4 Mte. Actions taken by our businesses to sustainably reduce their emissions amounted to a reduction of 0.2 Mte. We have been measuring such sustainable reductions in our operational GHG emissions every year since 2002, and the running total by the end of 2012 was approximately 8.5 million tonnes.
We also separately report the indirect CO2 emissions associated with the import of electricity, heat or steam into our operations. The table below provides a breakdown of our GHG emissions data for the past five years. A full breakdown of our current and historical data going back to 1998, including an option to filter this data by business segment, can be found in our HSE charting tool.
Improvements made by our businesses to calculate their emissions more accurately resulted in a net decrease of 0.4 Mte. Actions taken by our businesses to sustainably reduce their emissions amounted to a reduction of 0.2 Mte. We have been measuring such sustainable reductions in our operational GHG emissions every year since 2002, and the running total by the end of 2012 was approximately 8.5 million tonnes.
We also separately report the indirect CO2 emissions associated with the import of electricity, heat or steam into our operations. The table below provides a breakdown of our GHG emissions data for the past five years. A full breakdown of our current and historical data going back to 1998, including an option to filter this data by business segment, can be found in our HSE charting tool.
Direct greenhouse gas emissions
We report greenhouse gas (GHG) emissions on a CO2-equivalent basis, including CO2 and methane. This represents all consolidated entities and BP's share of equity-accounted entities except TNK-BP.
Greenhouse gas intensity
Another way we look at performance is to review the emissions of direct GHGs per unit of production – using a consistent normalization methodology so that we can see the trends in GHG intensity over time. Performance in each of our major business sectors is discussed in more detail below.
Upstream
In our Upstream business, emissions per unit of production in 2012 were 29.2 teCO2e per thousand barrels of oil equivalent (mboe), which is unchanged from the intensity we reported in 2011.
The trend of increasing intensity over the past five years reflects decreasing production in our less GHG intensive areas and increasing intensity of some new areas as we develop more difficult resources. Also natural increases in intensity are occurring in many of our mature assets where oil and gas production declines at a faster rate than energy consumption. This normal increase in intensity is driven by declining reservoir energy and use of more energy/emissions intensive secondary and enhanced recovery techniques.
Although there may be annual fluctuations, over the long term it is likely that the carbon intensity of our upstream operations will continue to trend upwards as we move farther into technically-challenging and potentially more energy intensive areas.
The trend of increasing intensity over the past five years reflects decreasing production in our less GHG intensive areas and increasing intensity of some new areas as we develop more difficult resources. Also natural increases in intensity are occurring in many of our mature assets where oil and gas production declines at a faster rate than energy consumption. This normal increase in intensity is driven by declining reservoir energy and use of more energy/emissions intensive secondary and enhanced recovery techniques.
Although there may be annual fluctuations, over the long term it is likely that the carbon intensity of our upstream operations will continue to trend upwards as we move farther into technically-challenging and potentially more energy intensive areas.
Upstream - GHG intensity
Refining
In 2012 our refining GHG intensity metric decreased versus 2011. In 2012 we reported 901 teCO2e per utilized equivalent distillation capacity (UEDC), which is lower than the 917 teCO2e/UEDC reported in 2011. The decrease in intensity versus 2011 resulted primarily from higher utilization and improved operational efficiency at our Texas City refinery in 2012 after a significant period of maintenance activity in 2011. The downward trend since 2008 reflects improved utilization and energy efficiency at our refineries over that period.
Reducing emissions at our Kwinana refinery in Australia
At our Kwinana refinery in Australia, through the major refurbishment of an existing diesel hydrotreater unit, we reduced the fuel requirement at the site, which is expected to result in an emissions reduction of over 7,000 tonnes of CO2 annually. Using an improved technology design we were able to improve heat integration and keep more heat in the oil. This made it possible to reduce furnace firing, resulting in the unit using a lower amount of fuel gas. This has led to reduced CO2 emissions and cost savings at the site.
The carbon intensity will likely remain relatively flat or even decrease in certain refining operations because of improved energy efficiency even with the trend towards processing heavier crudes.
Refining - GHG intensity
Petrochemicals
Our petrochemicals businesses show a decrease in GHG intensity in 2012 to 293 teCO2e per thousand tonnes of production (kte) from 299 teCO2e/kte in 2011.
The downward trend since 2008, with the exception of a slight increase in 2011 from 2010, reflects on-going efficiency gains in our aromatics and acetyls businesses. We continue to seek efficiency gains across our petrochemicals businesses. One example this year is at our purified terephthalic acid and paraxylene plant in Geel in Belgium where modifications have been made to maximize the use of low pressure steam which has in turn reduced the fuel consumption of their boilers.
The downward trend since 2008, with the exception of a slight increase in 2011 from 2010, reflects on-going efficiency gains in our aromatics and acetyls businesses. We continue to seek efficiency gains across our petrochemicals businesses. One example this year is at our purified terephthalic acid and paraxylene plant in Geel in Belgium where modifications have been made to maximize the use of low pressure steam which has in turn reduced the fuel consumption of their boilers.
Petrochemicals - GHG intensity
Attestation
The information on this page forms part of the information reviewed and reported on by Ernst & Young as part of BP's 2012 sustainability reporting.
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