Scope 1 and Scope 2 emissions reduction activities

Marginal abatement cost curve (MACC) process

During our annual budget planning process, we use the MACC process to collect potential operational greenhouse gas (GHG) emissions reduction projects from our business units (BUs), prioritize them based on their cost and reduction volume, and implement the most cost-effective projects. The MACC plots the break-even cost of carbon dioxide equivalent (CO₂e) reduction, considering capital and operating cost, and the potential increased revenue for each project against the cumulative GHG emissions that can be reduced.

Project funding may be based on criteria including but not limited to:

• Regulation: Existing or anticipated.
• Cost efficiency: Cost per tonne of CO₂e abated.
• Durability: Reduces emissions permanently.
• Adoption readiness: Reliable technology, systems and processes proven to reduce emissions by the forecasted amount. 
• Strategic: Scalability, repeatability, timing, risk and other means of justification.

We typically consider projects that are expected to provide the greatest overall contribution in reducing our GHG emissions with a break-even cost of below $60/tonne CO₂e, as well as projects that anticipate forthcoming regulatory changes. By prioritizing and confirming projects through the MACC process with Low Carbon Technologies team colleagues, BUs are able to embed emissions reduction efforts within their budgets and long-range plans (LRPs). Our goal is to allow innovation, flexibility and accountability at the local level while providing support, guidance and oversight from corporate peers. This approach allows BUs to reprioritize and adjust within their budgets to account for regulatory and/or technology changes while maintaining consistency in process. This enhances our company’s competitive advantage in playing a vital role through the energy transition.

In 2023, ConocoPhillips supported nearly 90 emissions reduction projects across our global operations through the MACC. These projects address improvements relating to methane and flaring, electrification, process optimization, efficiency, and include strategic pilots and studies. We prioritized methane and flaring projects in support of our near-term methane and flaring initiatives in 2023.

• Methane venting: Eliminate natural gas-driven pneumatics and modify facilities to reduce natural gas venting.
• Flaring: Eliminate flares where possible; incorporate vapor recovery units at facilities where economically and technically viable; recover waste gas for sales.
• Electrification: Reduce combustion needs on drilling and completions; electrify operations and pursue renewable energy sources where viable and economic.
• Optimization and efficiency: Streamline process equipment and facilities, tanks and equipment; improve waste heat utilization, insulation and power distribution. Consolidate older tank battery facilities to modern facilities to take advantage of existing emissions control equipment while improving operating efficiency.

To progress projects and achieve reductions in these areas, we have set up regional teams in North America, Australia, China and Europe to use the MACC process. Operational GHG emissions management is an expected core competency for our BUs managing oil and gas production. Those BUs are required to review their GHG emissions profile and identify opportunities to enable design and operating improvements that can reduce emissions. Output from the MACC informs our annual budget, LRP and technology strategy.

In 2023, we spent approximately $350 million on Scope 1 and Scope 2 emissions reductions¹ and low carbon opportunities. Emissions reduction activities resulted in approximately 0.8 million tonnes per annum (MTPA) in CO₂e reductions.

Projects below the line are economic and have a negative breakeven cost of carbon.² Projects above the line are not economic without considering cost of carbon — the taller the bar, the higher the breakeven cost of carbon. The width of the bar indicates the annual operational emissions abatement that would occur should the project be undertaken — the wider the bar, the greater the emissions abated.

 

Methane and emissions detection technologies

Lower 48

Eliminating gas-driven pneumatic devices

Pneumatic device replacements are among the highest priority emission reduction projects across the Lower 48, as they account for some of the more significant methane emissions sources and have a competitive cost of abatement. With thousands of gas-driven pneumatic devices in service, our operations and engineering teams have made significant progress on our multi-year large-scale retrofit campaign. Each conversion increases revenue by keeping gas in the sales line while allowing us to maintain regulatory compliance with new legislation or anticipated federal guidelines.

Greenfield designs at new facilities include devices using supplied air instead of produced gas to reduce natural gas emissions from pneumatics. We currently have a multi-year pneumatics replacement program estimated for completion by the end of the decade. The next phase of the program will retrofit up to 65,000 pneumatic devices at existing sites across Lower 48.

Facility design

We aim to avoid methane emissions as much as practical. We have evaluated ways to improve wellpad and central facility design at both new and existing sites to reduce GHG emissions, including emissions capture and suppression and installing vapor recovery units. For example, in 2023 we completed dozens of projects in the Permian and Bakken to retrofit vapor recovery units on existing brownfield sites to capture tank emissions and reduce flaring.  We also removed over 60 brownfield site flares in the Eagle Ford for further GHG emissions reductions in 2023.

Leak detection and repair

We use a variety of leak detection and repair (LDAR) tools 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 regulatory requirements. These innovative 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.

In 2023, we conducted approximately 13,500 handheld optical gas imaging (OGI) surveys and approximately 7,900 aerial surveys across our Lower 48 assets to detect leaks and quickly repair them. While this is a regulatory requirement in many areas, approximately 75% of the surveys were done on a voluntary basis. These surveys continue to provide a better understanding of where leaks occur and how we can minimize fugitive emissions.

Informal inspections

ConocoPhillips personnel visit sites as part of their routine duties or in response to operational issues. They identify anomalous operating conditions that may contribute to audio, visual or olfactory (AVO) indications of potential leaks. We conduct formal AVO inspections to identify potential leaks at sites where regulatorily required. Additionally, we perform these inspections periodically on a voluntary basis on most other sites where not regulatorily required, 

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.   

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. ConocoPhillips also continues to pilot and utilize innovative methods of monitoring, including some airborne and ground-based systems, in addition to the above LDAR methods either required by or based on regulatory requirements. The pilot programs and deployments of innovative technologies discussed below are not used for regulatory purposes. 

Continuous monitoring

In addition to our reduction efforts, we have been conducting pilots of new technologies across our operations to determine effectiveness and scalability of next-generation detection technologies. We have piloted various continuous monitoring technologies, including ground-based sensors, as well as investing in Longpath Technologies, which offers continuous monitoring capabilities utilizing lasers. We are also in the process of broadly deploying targeted point-source monitoring on equipment like flares and tanks, while integrating process control technologies based on both regulatory compliance and our learnings through participation in OGMP 2.0. Because continuous monitoring is an evolving space, we will continue to evaluate the feasibility and effectiveness of our methane monitoring programs based on available technologies and learnings from the program.

While continuous monitoring technology has worked well to expeditiously identify and mitigate leaks, it is not used for regulatory measurement purposes at this time. Our reported 2023 emissions for the U.S. are based on EPA-mandated methodologies for estimating and reporting GHG emissions. An anticipated outcome of OGMP 2.0 is that in the future, enhanced measurement-based information can be incorporated into methane emissions calculations. Read more about our OGMP 2.0 efforts.

Canada

In our Canada BU, we have installed emission monitors on a drilling rig to actively monitor diesel fuel consumption, natural gas consumption and engine loads, increasing accuracy of emissions measurement on the rig. The rig was also outfitted with a battery and natural gas generators to reduce GHG emissions intensity and operate the rig at reduced fuel costs. Battery backup can also double as temporary engine replacement, necessitating one less engine to be online.

Flaring

Lower 48

We continue to progress toward our target of zero routine flaring by the end of 2025. We have reduced flaring by utilizing closed-loop completions, central gas gathering systems and vapor recovery units (VRUs). We direct condensate to sales pipelines and improve uptime through operational excellence (a major focus for all our operating facilities). Pipeline constraints are not a cause of routine flaring for us in the Lower 48 or anywhere else in our portfolio.

• Since 2022, the Bakken operations team has focused on MACC projects to reduce routine flaring. Projects have included treatment of sour gas, flare capture, de-bottlenecking and auto-curtailment when offtake is restricted. We also have increased our VRU runtime which increases gas sale volumes from previously flared gas. The execution of these projects resulted in a 2023 associated gas flaring intensity reduction of about 50%.
• Many of the initiatives developed in the Bakken are being replicated in the Eagle Ford and Permian fields. A 2022 meeting of asset managers and operational leaders established alignment on best operating practices for flaring.
• Our Eagle Ford team has been focused on decommissioning tanks and flares to reduce overall field flaring. Fluids are commingled and processed at larger central facilities to reduce equipment counts in the field and more effectively manage emissions mitigation.
• In the Delaware Basin, we built and operate our own gathering system, which enables more flexibility and connections to multiple third-party processors. We also developed and implemented facility design changes to reduce flaring from tanks.
• We use 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.

Norway

We are advancing several measures to reduce operational GHG emissions in the Greater Ekofisk Area in the North Sea. This includes installation of automation measures on gas turbines and a control panel on the main process platform in Ekofisk. Another measure finalized in 2023 was the Rotating Equipment Opportunity Project (REOP), significantly reducing CO₂ emissions from the pipeline compressors. We are planning to apply the same project for the gas lift compressor at an Eldfisk platform in 2025.

Operational efficiency

Canada

Reducing the GHG emissions intensity of our oil sands operations continues to be a priority for our Canada operations. We co-inject non-condensable gas (NCG) with steam to reduce steam requirements and improve thermal efficiency, reduce GHG emissions intensity and enhance incremental oil 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 anticipated GHG intensity reductions. Further, we have installed flow control devices on SAGD producer and injector wells with steam block capabilities to further reduce SOR and reduce shut-in occurrences.

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 the BU developed a new co-injection alternative, “NCG Lite,” to allow for the continued injection of NCG during curtailment without the need to install additional infrastructure.

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. This approach aims to reduce surface footprint and provides increased bitumen production without additional steam injection, thereby reducing GHG emissions intensity and operating costs.

These projects benefited from financial support provided through Emissions Reduction Alberta (ERA). ERA invests the proceeds from its carbon pricing scheme to reduce GHG intensity and strengthen the competitiveness of new and incumbent industries and accelerate Alberta’s transformation to a low-carbon economy.

Norway 

At the Teesside Oil Terminal, we are working on various emissions saving projects such as steam boilers burner management system rationalization, crude oil charge pump electrical drive change-out, and a number of different energy-saving ideas.

Electrification and alternative power

Lower 48

We expect that dual fuel capabilities and electric power solutions for drilling and hydraulic fracturing will be viable technologies to lower operational emissions by replacing diesel usage with field gas or compressed natural gas (CNG) while improving productive time by reducing maintenance and generating more usable horsepower.

In the Lower 48, some drilling rigs utilize technologies to target reduction in diesel usage and the associated emissions. For example, rigs in the Eagle Ford use automation and road maps for engine load management while in the Permian they utilize grid electricity when available. In the Bakken, we have converted rigs to dynamic gas blending and recently connected one rig directly to the grid. Automation allows the rigs to run diesel-driven power generators more efficiently and also reduces trucking in the area. Dynamic gas blending reduces diesel consumption by utilizing natural gas. Connecting rigs to the grid nearly eliminates diesel power generation on location.

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 hydraulic fracturing operations, we aim to use CNG, liquefied natural gas (LNG), and self-sourced field gas to power our dual gas blending fleets as well as 100% natural gas power generation for electric hydraulic fracturing (e-frac) fleets. This has since been broadly adopted in the Permian, and the same concept has been utilized in nearly all Bakken and Eagle Ford completion activities as well.

In the Eagle Ford and the Permian, we successfully converted a hydraulic fracturing fleet to use field gas, reducing diesel consumption and lowering our emissions footprint. Natural gas reciprocating engines power the e-frac fleet, leading to emissions reductions of more than 30% compared to a conventional diesel fleet.

We also seek emissions reduction opportunities with our supply chain partners. In the Permian, for example, our completions group partnered with a sand supplier to change the proppant delivery and logistics business in the Delaware Basin which includes a miles-long electrified conveyer belt. The multi-year contract will ensure supply of the highest quality product in the market and yield logistics savings in 2025. Other examples include local sand mining and high-capacity sand trucking. These projects target reductions in emissions, truck count and traffic incidents.

We also are evaluating opportunities to use power from the grid or alternative energy. We led a large, multi-stakeholder study that aimed to better understand the long-term load demand for the Permian Basin as well as impacts to the grid and upgrades that may be required if the basin were to fully electrify. As part of this project, we have engaged in infrastructure and electrification solutions with several other Permian operators representing about 40% of Permian Basin production. This resulted in the Electric Reliability Council of Texas (ERCOT) developing a reliability plan for Permian which secured regulatory approval in late 2024.

In Q3 2024, we generated first power at Pegasus solar farm in the Midland Basin, our first company owned development. This 10 megawatt (MW), behind-the-meter project provides renewable energy directly to our operations. We continue to evaluate additional renewable energy projects, concentrating on projects that can provide power directly to our facilities to reduce Scope 1 and Scope 2 emissions.

Canada

We aim to ultimately electrify combustion sources at central processing facilities (CPFs) in Montney. We are working with local authorities and industry partners on the Montney greenfield electrification project that premises that after 2027, new CPFs will be equipped to run on either grid-generated electricity or electricity generated at the CPFs by natural gas from our operations. Once grid power is installed and available at the asset, we plan to decommission our natural gas generators.

China

Our operations in Bohai Bay, China are primarily powered by fuel gas from associated natural gas production from developed fields. The asset will increasingly face a fuel gas shortage by the late-2020s, increasing operating costs due to the need to purchase natural gas from the local market. To bridge this fuel gap, we are jointly working with the China National Offshore Oil Corporation (CNOOC) to connect all CNOOC-operated Bohai Bay oilfields to the onshore power grid.

Australia  

The Australia Pacific LNG (APLNG) facility on Curtis Island, Queensland began working on a hydrogen pilot to connect an electrolyzer to a fuel gas inlet pipe to generate and supply hydrogen to mix with fuel gas. The study is being assessed and piloted in 2023 and 2024 as information is gathered regarding its long-term feasibility.

Voluntary carbon offsets

While operational emissions reductions will initially drive our progress toward our net-zero emissions ambition, ultimately offsets are likely to be required to mitigate residual, hard-to-abate emissions. Our voluntary offset strategy includes developing a diversified portfolio of offsets from third-party projects and funds, as well as considering the development of our own offset projects. Our preference is projects in countries and regions in which we operate. While we do not anticipate the need to utilize offsets to achieve our medium-term targets and have not retired any voluntary offsets to date, we are investing now to build a portfolio of offsets for potential use and retirement in the future.

Our portfolio includes both:

• • Nature-based offsets: Relating to forestry and land use, agricultural improvements and grasslands or soil enrichment.
  • Technology-based offsets: Relating to energy efficiency, orphaned well management, refrigerant replacement and destruction of ozone depleting substances.

In 2023, we strengthened our offset project due diligence efforts including developer experience, technical frameworks and sustainability and stakeholder engagements.

We are looking closely at the progress of the Integrity Council for the Voluntary Carbon Market, an independent governance body that aims to set a global standard for high integrity in the voluntary carbon market. Their first announcements on project registries and protocols that meet their Core Carbon Principles were recently announced and we anticipate more announcements by year end.

Our commitments also include carbon offset funds such as Climate Asset Management’s Nature Based Carbon Fund (NBCF). Taking a landscape approach, the NBCF looks to invest in nature-based solutions projects that restore and conserve nature in developing economies. This provides long-lasting and verified positive impacts for biodiversity and communities and offers investors the carbon credits it procures. These project investments continue to diversify in Africa and the sub-continent, adding diversity outside our areas of operation.

Operational Net-Zero Roadmap

Many solutions to address hard-to-abate emissions still have significant technological gaps or commercial challenges. Recognizing this, we use an operational net-zero roadmap to identify and share ideas and concepts which direct our efforts toward studies, pilots and engagement with our industry peers, vendors, and academia. By placing these potential solutions in a roadmap which is distinct from our MACC program, the business can focus attention on what is achievable today while our technology development programs can direct collaborative efforts with peers and external stakeholders.

The company’s net-zero roadmap, like our scenario planning, is an illustrative, evergreen construct that will necessarily adjust over time in connection with various factors (including ongoing efforts and results, regulatory and/or technology changes, and future long-term plans that are subject to adjustment).

To drive accountability for the emissions that are within our control, our operating BUs own their own asset-specific version of a roadmap. BUs also identify technology solutions for hard-to-abate emissions and pilot new methods to reduce and accelerate emissions reductions. When rolled up, these BU roadmaps inform our technology development, operations and engineering teams, along with our development staff, as to where to direct efforts today, while allowing us to forecast and prioritize future needs. While our emissions reduction progress to date has not included the use of voluntary offsets, we are building a portfolio of offsets for potential use in the future.

The company-wide net-zero roadmap will also:

• Empower each BU to identify solutions specific to its needs.
• Leverage the MACC process to prioritize, study and pilot emerging technologies.
• Promote knowledge sharing across BUs on projects which are scalable or transferable.
• Provide optionality, addressing the uncertainty that comes with technology advancement.
• Be a means to help understand the challenges we face on our net-zero journey.

^{1. Emissions reduction projects include both voluntary and regulatory activities.}

^{2. New projects with a negative breakeven cost of carbon may continue to be brought forward for consideration each year as we advance our technology and identify possible new angles for emissions reductions.}