GHG emissions management is an expected core competency for our business units (BUs). Each BU is required to review its GHG emissions profile and identify opportunities to make design and operating improvements that can reduce our emissions. Potential GHG emissions reduction projects are reviewed within our annual budget planning process and assessed against pre-determined selection criteria, including cost per tonne of CO 2 e abated. We call this annual exercise our marginal abatement cost curve (MACC) program, described in more detail within this section of the report.

All data presented herein is from January 1 to December 31, 2021. Footnotes to our performance metrics outline the scope and methodologies of our data reporting. The minimum boundary for reporting on environmental priorities is assets we operate. Current and updated targets and ambitions are outlined in near-, medium-, and long-term timeframes, followed by examples of emissions reduction projects in our business units.

Goals for Net Zero graph

These targets inform internal emissions reduction goals at the business level and support innovation on efficiency and emissions reduction, GHG regulatory risk mitigation and climate-related risk management throughout the life cycle of our assets.

Read more about our Plan for the Net-Zero Energy Transition in a presentation to the Interfaith Center on Corporate Responsibility in April 2022.

Near-Term Emissions Reductions (By 2025)

Our near-term targets have a priority focus on flaring and methane emissions.

Our 2025 targets are as follows:

  • Meet an additional 10% methane emissions intensity reduction target by 2025 from a 2019 baseline, adding to the 65% reduction we have achieved since 2015. We are also working with stakeholders on development of sector-wide methane targets that set a comparable standard.
  • Achieve a target of zero routine flaring by 2025, five years sooner than the World Bank initiative’s goal of 2030.


Total Methane Emissions bar chart Reducing methane emissions, even the small equipment leaks known as fugitive emissions, is a key part of our operations. Leak detection and repair (LDAR) is a work practice used to identify and repair leaking components, including valves, compressors, pumps, tanks and connectors, in order to reduce GHG emissions and increase efficiency. We fix leaks as soon as feasible, with many leaks repaired either the same day or within a few days of being detected. We have been voluntarily conducting pilots of new technologies at numerous facilities to determine effectiveness and scalability of next-generation detection technologies. This has included a wide range of tested technologies from ground-based to aerial, with each providing different strengths for different monitoring applications. The main objective with these technology pilots is to expeditiously identify, investigate and repair leaks associated with malfunctions and abnormal operating conditions, resulting in faster emissions mitigation. We continue to work with technology providers to develop and test technologies and we expect the technology will continue to improve over time.

Our methane emissions reductions come from voluntary reduction activities and from portfolio changes. Similar to overall greenhouse gas emissions in 2021, absolute methane emissions increased due to the acquisition of additional Permian assets, however our methane intensity declined to 2.6kg CO 2 e/BOE or 13% from our 2019 baseline.

Methane Emissions Intensity Target bar chart

In 2021, methane emissions totaled 1.8 million tonnes of CO₂e and constituted 9.6% of our total GHG emissions.


Total Flaring Volume bar chart 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.

Setting a target to get to zero routine flaring by 2025 is a key near-term action within our ambition to become a net-zero company by 2050. While our flaring emissions make up only about 9% of our total GHG emissions, the target will drive continued near-term focus on routine flaring reductions across our assets. Routine flaring is defined as flaring of associated gas that occurs during the normal production of oil in the absence of sufficient facilities to utilize the gas onsite, dispatch it to a market or re-inject it. Flaring for safety reasons, non-routine flaring or flaring gas other than associated gas is not included as part of the World Bank Zero Routine Flaring initiative.

In 2021, the total volume of flared gas was 20.5 BCF, an increase of 41% from 2020. The increase was a result of increased flaring in the Permian due to the acquisition of Concho Resources. It was also a result of the availability of more accurate data for estimating the volume of gas that is used as assist gas in our Eagle Ford asset.

While absolute flaring volumes increased, our flaring 1 intensity continues to decline, decreasing 4% in 2021. Routine flaring volumes were collected for the first time in 2021. Routine flaring represents only 5% of our total volume of gas flared.

Medium-Term Emissions Reductions (By 2030)


In July 2022, ConocoPhillips joined the Oil and Gas Methane Partnership (OGMP) 2.0 Initiative, a voluntary, public-private partnership between the United Nations Environment Programme, the European Commission, the Environmental Defense Fund and over 80 oil and gas companies. OGMP 2.0 has emerged as a global gold standard for methane emissions measurement and reporting and is aimed at minimizing methane emissions from global oil and gas operations. Our membership demonstrates our commitment to contributing to climate mitigation and delivering on our methane reduction objectives and targets by collaborating with industry peers to accelerate best practices in our operations.

As part of OGMP 2.0, we plan to report methane emissions for all material sources from both operated and non-operated assets according to our reporting boundaries. In line with the Initiative’s guidance, we plan to incorporate source-level and site-level measurements when estimating methane emissions from our operations. In conjunction with these commitments and in response to achieving our near-term methane target four years early, we have set a new medium-term target to achieve a near-zero methane emissions intensity by 2030. This near-zero target is defined as 1.5kg CO 2 e/BOE or approximately 0.15% of natural gas produced.

GHG Emissions

In September 2021, we strengthened our medium-term GHG emissions intensity reduction target to 40-50% by 2030 from a 2016 baseline and also expanded the target to apply to both a gross operated and net equity basis. The target covers Scope 1 and Scope 2 gross operated and net equity emissions as these are the emissions over which we have the most control. Our Scope 1 and Scope 2 GHG emissions and emissions intensity calculations directly measure our 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.

Intensity Reduction Target bar charts

The company has already progressed toward meeting this target over the past several years. Between 2016 and 2021, we achieved a 32% intensity reduction on a gross operated basis through a combination of specific emissions reduction projects and asset changes. Continued capital allocation actions are expected to have a combined impact of lowering GHG emissions intensity by roughly 8-18% as we increase production from assets with low intensity, such as those in the Permian Basin, and achieve reductions from near-term projects.

The target includes emissions that are related to production and excludes emissions from our aviation and polar tankers fleets. This may give rise to small differences between the intensity we report for our GHG target purposes and the intensity we report for our annual metrics. Over the past 5 years, this difference has been less than 2%, or 1 kg CO 2 e/BOE.  In 2021, our total gross operated GHG emissions, in CO 2 equivalent terms, were approximately 18.7 million tonnes.

The acquisition of additional assets in the Permian has contributed to an increase in absolute emissions in 2021. In addition, we implemented voluntary production curtailments across various assets during the 2020 economic downturn, which impacted total emissions.

GHG emissions intensity target progress

GHG emissions change graphic

Net Equity and Non-Operated Emissions

Net Equity based GHG Emissions pie Compared to our gross operated emissions, our net equity emissions were slightly lower in 2021 as a result of our operating partners’ activities, at 18.3 million tonnes CO 2 e. However, our net equity intensity is higher at 32.4 kg CO 2 e/BOE than our gross operated intensity of 26.6 kg CO 2 e/BOE, showing increased efficiency in our operated assets. About 40% of our net-equity emissions are from non-operated assets. Because we approach net-zero as a shared challenge, we look to influence our joint operating partners’ climate risk strategies and net-zero targets and align our emissions reductions activity. We have initiated a concerted effort to advance this joint approach in our Alaska and Australia business units, opening dialogue on critical emissions reductions with our key operating partners.

Long-term Emissions Reductions (By 2050)

Net-Zero Roadmap graphic The long-term pathway to achieving our net-zero emissions ambition by 2050 starts with proven, well-defined actions for Scope 1 and 2 emissions, while also advancing less mature but potentially economically and technically viable low-carbon opportunities. The aggregated near- and medium-term efforts described in previous sections set the foundation for our roadmap to net-zero emissions represented in the Net-Zero Roadmap. The shading on the bars represents the level of maturity today.

The first step of the roadmap includes continuing the well-established, identified operational Scope 1 and 2 projects that are currently underway. The identification and implementation of these projects are supported by strong internal process and capabilities. Continuous portfolio high grading is also a mature capability in ConocoPhillips. The bottom two bars of the roadmap show carbon capture opportunities and offsets. A multi-disciplinary Low Carbon Technologies organization, comprised of some of our best technical, financial, business development and commercial talent, is overseeing these channels.

Marginal Abatement Cost Curve

We use a marginal abatement cost curve (MACC) process to collect potential GHG emissions reduction projects from our business units, prioritize them based on their cost and reduction volume, and implement the most cost-effective projects. Each year, the executive leadership team determines which projects to fund based on a number of criteria including capital efficiency (i.e. the lowest $/TeCO 2 equivalent), scalability, and repeatability among a few others. We fund projects that have a break-even cost of up to $60/Te CO 2 e, as well as projects that anticipate forthcoming regulatory changes. We have allocated $200 million in the 2022 capital budget to energy transition activities, a majority of which will address Scope 1 and 2 emissions reduction projects across our global operations selected through this program.

The projects sanctioned for 2022, some of which are multi-year projects, could represent a recurring annualized reduction of approximately one million tonnes of CO 2 e upon completion. These include production efficiency measures, methane and flaring intensity-reduction initiatives and asset electrification projects, specifically:

  • Methane : Switch instrumentation from gas-driven to air-driven pneumatics; modify facilities to reduce gas venting.
  • Flaring : Incorporate vapor recovery units at facilities; recover waste gas for sales.
  • Electrification and combustion : Reduce combustion needs on drilling and completions; electrify operations and pursue renewable energy sources; conduct basin-wide electrification study in the Permian; evaluate a project to electrify central facilities in a portion of our Eagle Ford operations.
  • Operational efficiency : Streamline facilities, tanks and equipment; improve waste heat utilization, insulation and power distribution.

For example, through our MACC process, we have progressed the piloting of steam additives in the Canadian oil sands to improve thermal efficiency, reduce GHG emissions intensity and enhance incremental oil production. In the U.S. Lower 48, we have changed the design of some new facilities to include instrument air packages rather than gas-driven devices, reducing methane emissions from those sites. To continue those reductions, we have set up regional teams in North America, Australia, Southeast Asia and Europe to use the MACC process to identify additional energy efficiency projects. Output from the MACC informs our annual budget, Long-Range Plan and technology strategy.

Marginal Abatement Cost Curve

Projects below the line are economic and have a negative breakeven cost of carbon. Projects above the line are not economic — the taller the bar, the higher the breakeven cost of carbon. The width of the bar indicates the annual emissions saving that would occur should the project be undertaken — the wider the bar, the greater the emissions saving.

Scope 1 and 2 reduction activities and MACC projects are described in the following section. Read more about our MACC process and the Net-Zero Roadmap.

Scope 1 and 2 Emissions Reduction Activities
Methane Detection in U.S. Operations

ConocoPhillips utilizes a variety of leak detection and repair (LDAR) tools throughout our operations to identify and repair methane leaks. First, we conduct LDAR surveys as required by NSPS Subpart OOOOa and other state regulatory frameworks. Second, we utilize various innovative technologies that go above and beyond those required by regulations. These technologies are deployed at selected assets with the intent of evaluating and understanding their limitations and advantages. In addition, ConocoPhillips participates in a variety of voluntary LDAR programs offered through industry organizations, trade associations and joint partnerships. Examples of technologies currently in use are summarized below.

Informal Inspections
ConocoPhillips personnel visit sites as part of their routine duties or in response to any operational issues at the sites. They identify any anomalous operating conditions that may contribute to audio, visual or olfactory (AVO) indications of potential leaks.

Audio Visual Olfactory (AVO) Inspections
We conduct formal AVO inspections to identify potential leaks at sites where regulatorily required, typically on a weekly basis. On most other sites where not regulatorily required, we perform these inspections periodically on a voluntary basis.

Instrument-based Method 21 Inspections
Where required by regulatory programs, we conduct LDAR inspections pursuant to requirements of U.S. EPA Reference Method 21, using an organic vapor analyzer.

Optical Gas Imaging (OGI) Camera Inspections
We perform periodic inspections at sites using OGI cameras where required by NSPS OOOOa regulations. In addition, at sites not subject to NSPS OOOOa regulations, we conduct periodic OGI inspections on a voluntary basis. In addition to the above LDAR methods either required by or based on regulatory requirements, ConocoPhillips continues to pilot and utilize innovative methods of monitoring, including some airborne and ground-based systems. The pilot programs and limited deployments of innovative technologies discussed below are not used for regulatory purposes.

Airborne Systems
We have piloted several aerial technologies that enable routine monitoring over a larger area and allow for inspection of multiple facilities at a time. Airborne systems are an established way of screening of emissions from an entire facility, a group of facilities or a wider geographic area.

Drone-mounted technology has proven effective in detecting and locating the source of leaks due to their low-altitude capabilities; we currently use these on an ad-hoc basis. We have also utilized airplanes with mounted sensors to fly over facilities to detect leaks. If leaks are suspected, operations personnel take action to verify and repair the leak. The airplane sensors can detect smaller leaks, but our experience indicates that their effectiveness at pinpointing exact locations can be diminished in areas where other facilities are in close proximity, like the Permian Basin. ConocoPhillips has worked with Scientific Aviation to fly fixed-wing aircraft carrying detection gear over our Permian assets. We have also contracted with LeakScout to periodically fly helicopters equipped with OGI cameras around select sites. This program has also proven effective in identifying leaks.

While many of these airborne technologies are good at detecting leaks, they do require personnel following up with hand-held OGI cameras to identify the exact location of the leaks and the equipment involved, after which we conduct repairs and ensure mitigation was successful.

Satellite-based detection technology is another large-scale leak detection option. Although its effectiveness is improving rapidly, it has limitations in areas where facilities are located within close proximity to one another, such as in the Permian. An additional drawback has been the inability to identify small to medium leaks. Recently launched satellites are showing promise in providing better imaging and allowing more frequent monitoring of specific facilities. Although ConocoPhillips has used satellite detection in the Permian, we plan to pause its use until the technology shows further improvement. Additionally, the company has implemented monitoring systems to monitor for leaks on a continuous basis, as described below:

Continuous Monitoring Systems: Scientific Aviation (Metal Oxide-based SOOFIE Sensors)
ConocoPhillips has worked with Scientific Aviation to develop and test continuous methane monitoring devices at select Lower 48 facilities to further enhance LDAR capabilities. The SOOFIE (Systematic Observations of Facility Intermittent Emissions) sensor is a relatively simple method that incorporates cost-effective metal oxide sensors. Three to six sensors are affixed to poles strategically placed around locations to maximize effectiveness during varying wind conditions. Any elevated methane concentrations picked up by the SOOFIE sensors are integrated into an automated machine learning system that considers details such as equipment location, distance, wind speed and direction to identify the most probable emissions source.

Lower 48 and Alaska
Setting a methane emissions intensity target ensures continued focus on methane emissions reductions, including designing new facilities to avoid methane emissions as much as practical. We have evaluated ways to improve well pad and central facility design to reduce GHG emissions, including emissions capture and suppression and installing vapor recovery units. For example, in 2021 we completed a project in the Bakken installing vapor recovery units on several new facility builds, as well as a project in the Permian installing a vapor return line on a central tank battery to reduce emissions from truck loading.

We are participating in API’s The Environmental Partnership, a coalition of about 100 natural gas and oil companies working to improve methane emissions management. The program utilizes Bridger Photonics to fly aircraft at a program-determined frequency over industry assets, including those of ConocoPhillips. As part of our commitment, we have focused on two key areas:

  • LDAR programs: In 2021, we conducted approximately 7,600 surveys across our assets to detect leaks and quickly repair them. While this is a regulatory requirement in many areas, over 50% of the surveys were done voluntarily. These surveys continue to provide a better understanding of where leaks occur and how we can minimize fugitive emissions.
  • Eliminating gas-driven pneumatic devices: Many of our greenfield designs at new facilities include devices to use supplied air instead of site gas to reduce natural gas emissions from pneumatics.

We continue to test and deploy new methane detection technologies, including continuous monitoring. For example, in Alaska we began a project in 2021 to install fuel flow meters on existing Kuparuk drill site heaters to more accurately calculate emissions.

While continuous monitoring technology is proving to work well for expeditiously identifying and mitigating leaks, our reported emissions for the U.S. continue to be based on the EPA-mandated methodology for reporting GHG emissions.

Our new development in Montney was designed to eliminate the majority of methane emissions by utilizing self-generated electricity and electric equipment rather than traditional natural gas driven equipment

SCOPE 1 – Direct GHG emissions from sources owned or controlled by ConocoPhillips.

SCOPE 2 – GHG emissions from the generation of purchased electricity consumed by ConocoPhillips.

SCOPE 3 – All other indirect GHG emissions as a result of ConocoPhillips’ activities, from sources not owned or controlled by the company.


Lower 48

We have reduced flaring 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).

  • Over 2019 and 2020 we worked with midstream gas gatherer OneOK to expand and optimize their gas processing infrastructure in the Bakken. We also worked to debottleneck our own facilities. In 2021, this work resulted in a 50% reduction in routine flaring compared to 2020, despite a ~40% increase in total gas production.
  • We have also implemented production deferral practices when offtake is constrained and we are progressing field-wide deployment of gas capture technologies.
  • In the Eagle Ford, we began a project in 2021 that uses an optical gas imaging (OGI) camera transmitter to send a feedback signal to the flare blower’s speed controller. This improves combustion of flare gases by allowing for continual air adjustment, ultimately resulting in CO 2 abatement.
  • In the Delaware Basin, we have built and operate our own gathering system, which enables more flexibility and connections to multiple third-party processors. We have also developed and implemented facility design changes to reduce or eliminate flaring from tanks.
  • We use Andium cameras to monitor flares at some sites. These cameras provide visual observation of flares that can be monitored at centralized locations, providing quick notice of any anomalous flaring events.

In the North Sea, we are reducing our safety flaring by installing a new flare gas re-compressor that will reduce emissions from the flare tower at Ekofisk 2/4 J by more than 90%, or 26,000 tonnes per year. Instead of gas being flared, it will now be sold to the European market.

Operational Efficiency


Reducing the GHG emissions intensity of our in situ oil sands operations continues to be a priority for our Canada operations. We are using technology to co-inject non-condensable gas (NCG) with steam to reduce steam requirements and increase production at Surmont. This allows for a reduction in the steam-to-oil ratio (SOR) and consequent reduction in GHG emissions intensity. The technology can be applied to almost any steam-assisted gravity drainage (SAGD) operation, resulting in GHG intensity reductions of approximately 15-35%. Early project results have been shared with Canada’s Oil Sands Innovation Alliance (COSIA) Innovation Plus consortia to encourage widespread deployment of the technology throughout Canada’s oil sands. In response to lower oil prices from the COVID-19 pandemic, in 2020 and 2021, the BU developed a new co-injection alternative, “NCG Lite,” to allow for the continued injection of NCG during curtailment without the need for additional infrastructure installation.

We are also piloting multilateral well technology including innovative drilling and completion methods and thermal junction technology in existing vertical wellbores to increase production from a single surface location. Thermal junction technology enables the drilling of multiple lateral sections without the need for additional above-ground infrastructure. These wells reduce surface footprint and provide increased bitumen production without additional steam injection, thereby reducing GHG emissions intensity and operating costs per barrel of bitumen.

Both technology projects have benefitted from financial support provided through Emissions Reduction Alberta (ERA). ERA invests the proceeds from carbon pricing paid by large industrial emitters into Alberta’s Technology Innovation and Emissions Reduction (TIER) regulation to reduce GHGs and strengthen the competitiveness of new and incumbent industries in Alberta. These investments help innovators develop and demonstrate GHG-reducing technologies that lower costs, improve competitiveness, and accelerate Alberta’s transformation to a low-carbon economy.

Lower 48

In the Permian, we began a study to evaluate the possibility of reinjecting produced gas along with injection water by utilizing the existing water injection system. This simultaneous water and gas injection has the potential to avoid gas processing downtime and allow for continuous operation of the asset. Another operational efficiency project in the Permian involves replacing diesel fuel with a battery pack and smart controller on drilling rigs. This aims to reduce the number of generators needed during high transient loads while also matching the number of generators running with the actual load required, reducing the total energy usage of the rig.


As an early feasibility assessment, the APLNG flashing liquid expander project proposes to install a two-phase flashing liquid expander within the liquefaction section of a single train at APLNG. Installing this expander improves the energy efficiency of the liquefaction process as a train can produce more LNG for the same compression power.

Electrification and Alternative Power

Lower 48

We evaluate opportunities to use power from the grid, waste gas generators or alternative energy such as solar rather than natural gas.

After a successful pilot in 2020, we initiated a project in 2021 to utilize lower-carbon alternative fuel sources in the Permian. Rather than relying solely on diesel fuel to power frack operations, the project aims to use compressed natural gas and liquefied natural gas to power electric frack fleets.

We believe electric frack fleets are a viable technology to lower operational emissions by replacing diesel usage with field gas or CNG while improving productive time by reducing maintenance and generating more usable horsepower. We are also planning to conduct further field testing of e-frac fleets in our Lower 48 operations. Electric frack fleets can also be used in combination with diesel in dual-fuel frack fleets to reduce emissions associated with traditional frack operations. These innovations along with innovations in efficiency, water and safety are also providing significant cost savings and emissions reductions per well.

We are also conducting two feasibility studies in the Permian. The first is a solar plant study that aims to determine the feasibility of installing a photovoltaic solar plant to power operations and sell surplus energy to the current electricity provider. The study will also evaluate technical conditions for connection of the solar plant to the existing power grid.

The second is an infrastructure and electrification study. The first part of the study aims to find a solution for a dual problem: pipeline constraints for excess natural gas and a lack of water reuse/treatment options. Centralized water handling, including reverse osmosis and desalination, would be powered by in situ natural gas converted to electric compression. If successful, the project would provide an option to reuse produced water, avoid reinjection to saltwater disposal wells, limit natural gas sales at suboptimal prices, and pave the way for field electrification. To further the field electrification component, the second part of the study aims to better understand the long-term load demand for the total basin as well as upgrades that may be required if the basin was to fully electrify. This aspect of the project is especially important as we have a collective need to decarbonize the basin at a more rapid pace. As part of this project, we have engaged with several key Permian operators representing about 60% of Permian Basin production to collaborate on these infrastructure and electrification solutions.


Our operations in Bohai Bay, China are powered by fuel gas from associated natural gas production from developed fields. The asset will increasingly face a fuel gas shortage by the mid-2020s, increasing operating costs due to the need to purchase natural gas at local market rates. The China business unit (BU) is reviewing multiple opportunities to bridge the fuel gas gap, including:

  • Building localized offshore wind turbines specific for the asset.
  • Developing shallow gas fields to increase gas supply to continue powering operations.
  • Installing transformer station and subsea cables and tying into CNOOC regional offshore power grid that connects to onshore power facilities.
  • Jointly developing a large offshore wind farm with CNOOC Renewables to support the fulfillment of the BU’s net-zero emissions in the long run.

Norway’s carbon tax system and high-tax regime for oil and gas operations helps improve the economics of investing in electrification solutions. The Norway BU is investigating multiple options to achieve partial electrification in our Ekofisk operations, including:

  • Small-scale local offshore wind development (preliminary concept with two 10-14 MW turbines) to replace gas-powered turbines at Ekofisk, achieving about 60,000 tonnes of CO 2 emission reductions per year.
  • Connection to a possible future offshore wind power hub with subsea power cables connected to shore.

Addressing Scope 3 Emissions

Our role to address Scope 3 emissions and accelerate the energy transition includes several focus areas.

  • Advocating for policy to address end-use emissions through support of an economywide price on carbon.
  • Addressing upstream supply chain emissions by engaging with major suppliers on our Climate Risk Strategy.
  • Evaluating renewable energy into our operations through power purchase agreements or building solar or wind opportunities to support growing market demand of alternative energy.
  • Investing in low carbon opportunities and mitigation measures such as carbon capture and storage and hydrogen.

While we recognize that end-use emissions must be reduced to meet global climate objectives, we believe that setting a Scope 3 target for a Paris-aligned exploration and production company misplaces the focus on emissions reductions that can only occur in subsequent parts of the value chain and instead represents a prescribed curtailment of production. While a sector-wide reduction in demand for oil and natural gas products is foreseen as the transition progresses, our responsibility to shareholders is to strongly compete to supply that demand. We do so by striving for the lowest cost of supply, lowest GHG intensity production.

Although projections from a broad range of energy demand scenarios show a likely decline in oil and natural gas demand over coming decades, they also estimate that trillions of dollars of oil and natural gas investment will still be needed to ensure sufficient production capacity exists to meet even conservative demand projections.

Placing a requirement on efficient, ESG-focused, upstream companies like ConocoPhillips to meet a Scope 3 emissions reduction target could have the effect of shifting capital away from responsible operators toward less-accountable producers and jurisdictions. To meet a Scope 3 target, an exploration and production company would need to shift its capital to alternative energy products or curtail production. This capital shift would not necessarily reduce global emissions because it does not impact the oil and gas demand that is predicted across any Paris-aligned transition pathway. Other key considerations have also reinforced our rationale at ConocoPhillips not to set a Scope 3 target:

E&P Company versus Integrated Company

Pure play exploration and production companies do not have the opportunities to influence end-use emissions that integrated oil and gas companies hold through their ownership and control over the production and sale of end-use energy products. As an upstream producer, ConocoPhillips does not control how the commodities we sell are converted into different products or ultimately used, providing limited range of viable actions by the company beyond Scope 1 and 2 emissions reductions.

Double Counting

Enactment of a Scope 3 emissions target would inevitably result in duplication of end-use emissions accounting along the oil and natural gas value chain, making accurate accounting and credible target-setting extremely problematic. For example, the Scope 3 emissions from refining the oil we produce are a refiner’s Scope 1 emissions. The combustion of that oil in the form of an end-use product such as gasoline are also Scope 3 emissions for the producer of the oil, the refiner and the marketer. The combustion of gasoline is also a Scope 1 emission for distribution and transportation companies. Likewise, our Scope 3 emissions from the combustion of natural gas at a power station would be the electricity producer’s Scope 1 emissions and our own Scope 2 emissions for electricity purchased to run our operations. We are following the development of the Science Based Targets Initiative methodology for the oil and gas industry and have responded to their recent net-zero criteria consultation.

We believe that the most practical way to avoid double-counting of emissions and overlap of targets is for all companies to align with the Paris Agreement and set targets for their Scope 1 and 2 emissions.

Climate Policy to Address End-Use Demand and Emissions

We have been clear since our first Climate Change Position in 2003 that end-use emissions must be addressed to meet global climate commitments. Climate policies along with advances in technology and consumer choice will ultimately drive demand and end-use emissions. We accept that in the absence of full carbon capture and sequestration, demand for energy must shift toward low-carbon and non-carbon sources, so we take responsibility for encouraging that shift by the most practical and effective means available – our vocal support for carbon pricing that would cause a change in the choices made by end users, detailed in the Pubic Policy Engagement section. Our constructive advocacy for effective carbon pricing policy began when we became the first U.S. oil and gas company to join the United States Climate Action Partnership in 2007 and continued in 2018 when we joined the Climate Leadership Council as a founding member. It is also reflected in the fact that our main industry associations have now adopted positions on carbon pricing and other climate policy that align with our public positions.


We have reported annually on Scope 3 emissions in our CDP submissions since 2010 to acknowledge the role they play in climate risk assessment. We calculate Scope 3 emissions using the IPIECA 2016 Estimating Petroleum Industry Value Chain (Scope 3) Greenhouse Gas Emissions guidance based on net equity production numbers. We report the four largest categories of Scope 3 emissions that apply to our operations.

Dominic Macklon “The bulk of emissions occur in end-use. So the most effective and efficient means of reducing global emissions must include mechanisms that can directly impact consumer demand for carbon intensive energy.”

Dominic Macklon, executive Vice President, Strategy, Sustainability and Technology

For oil and natural gas exploration and production companies, Scope 3 emissions fall primarily into the “use of sold products” category. Though we do not control how our total production is ultimately processed into consumer products, we make the conservative assumption that the majority of production is ultimately burned as fuel by end users. We use the API Compendium GHG emissions factors for crude oil and natural gas burned as fuel. This method accounts for all possible GHG emissions that could be associated with end use of our production. Our assumption and method are especially conservative when the “double counting” issues inherent in Scope 3 estimations for an exploration and production company are taken into account.

We conservatively calculate the other three categories of Scope 3 emissions by taking our entire volume of crude and natural gas and applying the relevant transportation, distribution and processing emission factors from academic life cycle analyses, including the 2019 National Energy Technology Laboratory study: Life cycle analysis of natural gas extraction and power generation . In 2021, Scope 3 emissions increased in line with overall net production increase.

Source Estimated Million Tonnes CO₂e
Upstream transportation 4.4
Downstream transportation 9.2
Processing of Sold Products 13.4
Use of Sold Products 197.6

1 Calculated as million cubic feet per million BOE.