Scope 1 and Scope 2 Emissions
Our Scope 1 and Scope 2 GHG emissions and emissions intensity directly measure our climate performance and help us understand climate transition risk. For example, our ability to manage GHG emissions can help us measure resilience to emerging carbon tax regulation. Since 2009, we have carried out discretionary projects that have reduced our annual GHG emissions by nearly 7 million tonnes CO₂e compared to business as usual.
In 2018, our total gross operated GHG emissions, in CO₂ equivalent terms, were approximately 20.3 million tonnes, a decrease of about 1.4%, or 0.3 million tonnes, from 2017. Increased emissions associated with continued development of Surmont oil sands and increased drilling, production and flaring in Lower 48, were more than offset by increased CO₂ sales for beneficial use, discontinued operation of some assets, and methane reductions. Our overall GHG emissions intensity decreased by 2% in 2018.
We report our operated emissions in the following regions, countries and provinces in accordance with regulation:
- Australia: The National Greenhouse and Energy Reporting Act 2007 (NGER Act) and the National Greenhouse and Energy Reporting (Measurement) Determination 2008
- European Union: EU Emissions Trading System, Monitoring and Reporting Regulation Council Directive 2003/87/EC, as amended by Council Directive 2009/29/EC
- Norway: Greenhouse Gas Emission Trading Act of 17 December 2004
- United Kingdom: The Greenhouse Gas Emissions Trading Scheme Regulations 2012
- Alberta, Canada: The Climate Change and Emissions Management Act: Specified Gas Reporting Regulation, Alberta Regulation 251/2004
- British Columbia, Canada: Greenhouse Gas Industrial Reporting and Control Act: Greenhouse Gas Emission Reporting Regulation, British Columbia Reg. 249/2015
- Indonesia: Minister of Environment Regulation No. 12 of 2013 regarding Guideline for the Emission Load Calculation for Oil and Gas Industry Activities
- United States: 40 CFR 98 Subparts C,PP, UU & W — Stationary Combustion Sources; Suppliers of CO₂; Injection of CO₂; Petroleum and Natural Gas Systems.
Our corporate reporting system uses the rules, emission factors and thresholds for regulatory emissions with the following amendments. We use a facility threshold for reporting of 25,000 tonnes per year increasing the corporate emissions reported for Alberta, Canada, which uses a regulatory threshold of 100,000 tonnes per year. In our corporate reporting system, we include Scope 2 (emissions from imported electricity) which are not required under regulatory reporting.
Scope 3 Emissions
For oil and natural gas exploration and production companies, Scope 3 emissions fall primarily into the “use of sold products” category. Our GHG intensity target does not cover Scope 3 emissions. As an exploration and production company with no downstream assets we have no control over how the raw materials we produce are transformed into other products or consumed. We do, however, calculate our Scope 3 emissions annually based on net equity production numbers. In 2018 our Scope 3 emissions decreased by 5%, primarily due to decreased net production.
|Source||Estimated Million Tonnes CO₂e|
|Upstream transportation and distribution||1.6|
|Downstream transportation and distribution||1.9|
|Processing of sold products||19.9|
|Use of sold products||155.6|
Flaring is a regulated and permitted process for the controlled release and burning of natural gas during oil and gas exploration, production and processing operations. Flaring is required to safely dispose of flammable gas released during process upsets or other unplanned events, and to safely relieve pressure before performing equipment maintenance. Flaring is also used to control and reduce emissions of volatile organic compounds from oil and condensate storage tanks, and to manage emissions at well sites that lack sufficient pipeline infrastructure to capture gas for sale. Flaring has been reduced since 2014 by utilizing closed-loop completions, central gas gathering systems, vapor recovery units, directing condensate to sales pipelines and improving uptime through operational excellence (a major focus for all our operating facilities).
In 2018, our total volume of flared gas was 21.4 BCF, an increase of 22% from 2017. This was primarily due to the following increases:
- Gas production and flaring in assets where pipeline access and operating conditions could not accommodate the increased volume.
- Upset flaring events caused by a third-party gas gathering company.
- Facility shut-downs for maintenance.
- Number of wells requiring liquids removal.
- Volumes associated with flaring of storage tank and truck loading emissions.
Methane and Fugitive Emissions
Managing emissions, particularly methane, is one of our key priorities. Reducing emissions, even the small equipment leaks known as fugitive emissions, is a key aspect of our Global Onshore Well Management Principles. While there are differing methods and many measurement points, estimates of natural gas leakage rates between gas processing plants and electric power plants vary widely, from 0.7 to 2.6%.
We have standard operating procedures to detect and repair leaks. Audio-visual-olfactory (AVO) inspections are routinely performed during operator rounds to identify any leaks or other issues. Leak detection and repair (LDAR) is a work practice used to identify and quickly repair leaking components, including valves, compressors, pumps, tanks and connectors, in order to reduce GHG emissions and increase efficiency.
At many of our locations, especially high-rate producing wells and stand-alone compressor stations, we instituted a periodic voluntary fugitive monitoring program using forward-looking infrared (FLIR) cameras to enhance our LDAR. FLIR cameras create real-time images of gases or liquids leaking from pipes, vessels, tanks and other types of process equipment. FLIR surveys are completed at new or modified well sites and subsequent monitoring surveys are conducted at least annually. We fix leaks as soon as feasible, with many leaks repaired either the same day or within a few days of being detected. If additional time is required, we follow standard maintenance processes by adding the required repairs to our maintenance tracking system. After repairs are completed, inspections ensure that the repairs are successful. We implement engineered solutions and/or operational changes if we identify developing trends of systemic hardware problems.
In 2018, methane emissions were reduced by 0.3 million tonnes of CO₂e driven by an improved inventory of pneumatic devices, a decrease in equipment due to dispositions, replacement of pneumatic devices with electric solar pumps, and a change in the national calculation methodology for methane flaring in Australia. This was partly offset by the addition of sources not included in prior years.
We continually strive to make our operations more energy efficient. This can provide an environmental benefit through reduced emissions, as well as an economic benefit through lower production costs or greater sales revenue. Through the natural decline of production, as our fields diminish in size, they tend to require either the same, or in some cases, even greater amounts of energy to extract the product and transport it for processing or refining. Newer operations tend to be more energy intensive as well.
Total energy consumption in 2018 was 228 trillion British Thermal Units (BTUs), an increase of about 1.6%, due to increased production of both steam and hydrocarbons at our Surmont 2 facility in Canada and increased drilling and production in the Lower 48 Gulf Coast. This was partly offset by reductions from the discontinued operation of a field in the UK. About 98% of our consumption was from combustion of fuel for our own energy use and the remaining 2% was from purchased electricity. Purchased electricity decreased about 9% due to the sale of assets. Intensity, expressed as Trillion BTU/MMBOE, increased about 1%.
In 2018, we supplied consumers with approximately 1 trillion cubic feet (or 2.8 billion cubic feet per day) of natural gas. To put this in perspective, if all the natural gas we produced in 2018 had been used to replace coal for electricity generation, GHG emissions would have been reduced by approximately 52 million metric tons, more than double the company’s combined Scope 1 and Scope 2 emissions for the year.
The annual CDP survey collects a wide range of information concerning corporate efforts to manage climate change issues effectively and drive emissions reductions. It includes an emphasis on governance, strategy, actions and reporting to try to provide a complete view of companies’ performance for comparison. It also provides a view of sector performance. ConocoPhillips has participated in the survey since 2003. Our most recent CDP submission can be found in the 2018 CDP document.