Marginal Abatement Cost Curve Process

Investments which Reduced GHG Emissions
Technology Area	Stage of Development	2018-2022 Investments
Energy efficiency	Applied research and development	$5 million
	Pilot demonstration	$63 million
	Small-scale commercial deployment	$207 million
	Large-scale commercial deployment	$63 million
Methane detection and reduction	Applied research and development	$4 million
	Pilot demonstration	$2 million
	Small-scale commercial deployment	$20 million
	Large-scale commercial deployment	$54 million
Other emissions reductions	Applied research and development	$8 million
	Pilot demonstration	$9 million
	Small-scale commercial deployment	$23 million
	Large-scale commercial deployment	$163 million

During our annual budget planning process, we use the 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. 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: 

• Cost: Cost per metric ton of CO₂e abated. 
• Sustainable reduction: Reduces emissions permanently. 
• Scalability: Can be scaled up to provide additional emissions reductions. 
• Technology readiness: Systems and processes proven to reduce emissions by the forecasted amount.  
• Repeatability: Can be replicated in other business units. 

We typically consider projects that are expected to provide the greatest overall contribution in reducing our GHG emissions with a low break-even cost of up to $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 were 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 2022, ConocoPhillips spent about $150 million to support low carbon opportunities and more than 90 emissions reduction projects across our global operations through the MACC. These projects address improvements relating to venting and flaring, electrification, process optimization, efficiency, and include strategic pilots and studies. In 2022 we prioritized methane and flaring projects in support of our near-term methane and flaring initiatives. 

• Methane venting:  Eliminate gas-driven pneumatics and modify facilities to reduce gas venting. 
• Flaring: Incorporate vapor recovery units at facilities; recover waste gas for sales. 
• Electrification: Reduce combustion needs on drilling and completions; electrify operations and pursue renewable energy sources; conduct basin-wide electrification study in the Permian. 
• Optimization and efficiency: Streamline 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. Output from the MACC informs our annual budget, LRP and technology strategy. 

Projects below the line are economic and have a negative breakeven cost of carbon.¹ Projects above the line are not economic without considering cost of carbon — the taller the bar, the higher the breakeven cost of carbon. When considering the cost of carbon, projects below the $60/tonne breakeven point will generally be considered for funding. The width of the bar indicates the annual emissions savings that would occur should the project be undertaken — the wider the bar, the greater the emissions savings.   

We have allocated nearly $300 million in the 2023 capital and operating budgets 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. 

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.

Methane 

Lower 48

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 2022 we completed dozens of projects in Permian and Bakken to retrofit vapor recovery units on existing brownfield sites to capture tank emissions and reduce flaring.  

We participate in The Environmental Partnership, a coalition of about 100 oil and natural gas API member companies working to improve methane emissions management. The program has utilized Bridger Photonics to fly aircraft at a program-determined frequency over industry assets, including those of ConocoPhillips. In 2022, through our work in the Partnership, we conducted flyovers of our Permian and Eagle Ford assets to survey approximately 450 sites from the air. Further, as part of our commitment, we have focused on two key areas: 

• LDAR programs: In 2022, we conducted approximately 9,200 handheld OGI surveys and 3,400 aerial surveys across our Lower 48 assets to detect leaks and quickly repair them. While this is a regulatory requirement in many areas, over 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. See more about detection and monitoring technology in the following section. 
• 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 currently have a multi-year pneumatics replacement program that will retrofit up to 46,000 pneumatic devices at existing sites across Lower 48, estimated for completion by 2031. 

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 begun to execute our first large-scale retrofit campaign in New Mexico with plans to continue to ramp up programs in other states. 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.

Canada

Our 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. 

Detection and Monitoring 

Lower 48 

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. For example, we have installed nearly 2,000 fixed methane monitoring devices at nearly 400 sites throughout our Permian, Eagle Ford and Bakken assets. 

While continuous monitoring technology has worked well to expeditiously identify and mitigate leaks, that technology is not used for regulatory measurement purposes at this time. Our reported 2022 emissions for the U.S. are based on EPA-mandated methodologies for estimating and reporting GHG emissions. A desired outcome of OGMP 2.0 is that in the future, measurement-based information can be incorporated into methane emissions calculations.  

ConocoPhillips submitted our OGMP 2.0 Implementation Plan in May 2023. Most of our assets are already reporting at Level 3 with line of sight to Level 4.2 Reporting through OGMP 2.0 will help us make better informed decisions about where to prioritize our efforts to have the maximum impact on reducing our emissions footprint. We have also been actively engaged with other OGMP 2.0 members to ensure that the previously EU-focused guidance could be translated and applicable to a U.S. context. Key differences between EU-based operators and U.S.-based operators generally include: 

• EU energy companies tend to have more concentrated facilities, while U.S. companies operate thousands of wells over large geographic areas, often with operators interspersed. 
• EU joint ventures are typically associated with a single large asset involving wells and associated infrastructure, typically including only a few large shareholders. In contrast, U.S. development typically occurs at a single well level and can involve many partners, some with small interest.   

Read more about OGMP 2.0 and other external collaborations.

Alaska 

We continue to test and deploy new GHG emissions detection technologies in Alaska, 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 from pre-combustion fuel gas. The project will continue through 2023. 

Canada 

In Canada, we installed emissions 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 then outfitted with a battery and natural gas generators to reduce GHG emissions 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 2025. We have reduced flaring by utilizing closed-loop completions, central gas gathering systems and vapor recovery units. We direct condensate to sales pipelines and improve uptime through operational excellence (a major focus for all our operating facilities). We do not routinely flare due to pipeline constraints in the Lower 48 or anywhere else in the portfolio.  

Project examples include: 

• In 2022, the Bakken operations team focused on MACC projects to reduce routine flaring. Projects focused on treatment of sour gas, flare capture, de-bottlenecking and auto-curtailment when offtake is restricted. The execution of these projects resulted in a year-over-year reduction of associated gas flaring by more than 60%.  
• In the Bakken, sour gas treatment projects had the largest impact on flare reduction. Sour gas that does not meet pipeline sales specifications will typically be flared or curtailed. Successful treatment has allowed gas to be marketed. We have also implemented production deferral practices when offtake is constrained, and we are progressing field-wide deployment of gas capture technologies. As of year-end 2022, these projects allowed treatment and sales of 5 million cubic feet of gas per day, reducing flared gas volumes. 
• Many of the initiatives developed in the Bakken are being replicated in Eagle Ford and Permian fields. A 2022 meeting of asset managers and operational leaders established alignment on standards for routine and safety flaring. 
• 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 CO₂ abatement. 
• Our Eagle Ford team is working to convert some gas assisted flares to air assist where economically feasible at large central facilities and individual well sites. Decommissioning tanks and flares is another approach being taken to reduce overall field flaring. 
• In parts of 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 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. 

Norway 

In the North Sea, we are working on multiple measures to reduce greenhouse gas emissions in the Greater Ekofisk Area. In 2022, we reduced our emissions from safety flaring by 26,000 tonnes per year using a new flare gas re-compressor installed at Ekofisk 2/4 J. Instead of gas being flared, it will now be sold to the European market. Another measure initiated in 2022 was the Rotating Equipment Opportunity Project (REOP), reducing CO₂ emissions from the pipeline compressor by 24,000 tonnes per year.  

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 GHG intensity reductions of approximately 20-30%. 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, 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 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 reduces surface footprint and provides increased bitumen production without additional steam injection, thereby reducing GHG emissions intensity and operating costs. 

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

Lower 48

At rigs in Eagle Ford and Permian, we have implemented solutions using batteries and load matching to reduce diesel usage and the associated emissions. These battery systems allow the rigs to run the diesel-driven power generators 50% less while also reducing trucking in the area. 

Australia

An early feasibility assessment is proposed to install a two-phase flashing liquid expander within the liquefaction section of a single train at APLNG. This will enable more efficient cooling and generation of excess electricity. It will also improve the energy efficiency of the liquefaction process, producing more LNG for the same compression power.  

Norway 

At the Teesside Oil Terminal, we are working on various emissions saving projects such as the Stabilization train convection bank cleaning, Steam boilers burner management system rationalization, Crude oil charge pump electrical drive change-out, in addition to a number of different energy-saving ideas.  

Electrification and Alternative Power

Lower 48

We are evaluating a focused range of renewable energy projects, concentrating on projects that can provide power directly to our facilities to reduce Scope 1 and 2 emissions. We are evaluating opportunities to use power from the grid, waste gas generators or alternative energy. 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.  

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, the project aims to use compressed natural gas and liquefied natural gas to power electric hydraulic fracturing (e-frac) fleets.  

In 2022, in Eagle Ford, 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 conducted pre-development work in 2021 and 2022 to evaluate the potential for wind and solar electric power generation for our operations in the Permian Basin. We led a large, multi-stakeholder study that aims 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 was to fully electrify. As part of this project, we have engaged on infrastructure and electrification solutions with several other Permian operators representing about 40% of Permian Basin production.  

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, with a project currently under construction. The project includes a miles-long electrified conveyor belt with the potential to reduce emissions, truck count and traffic incidents. The four-year contract will ensure supply of the highest quality product in the market and yield logistics savings by 2026.  

China

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. To bridge this fuel gap, we are jointly developing an offshore wind farm with CNOOC Renewables to supply power to the Penglai oilfield and support the fulfillment of the BU’s net-zero operational emissions reductions.  

The China BU is also reviewing other opportunities, including: 

• Building localized offshore wind turbines specific to the asset. 
• Developing shallow gas fields to increase supply to power operations. 
• Installing a transformer station and subsea cables tying into CNOOC’s regional offshore power grid that connects to onshore power facilities. 

Australia  

The Australia Pacific LNG (APLNG) facility on Curtis Island, Queensland, Australia is progressing a Battery Energy Storage System (BESS) to function as power backup in case of electricity generator failure. Currently APLNG is powered by gas turbine generators (GTGs) with one spare GTG running in reserve in the event another fails. A BESS would replace the spare GTG and act as the reserve electricity generator.      

In 2022, the Australia BU 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. Different electrolyzer technologies may be trialed throughout the pilot program.