The long haul to long-haul carbon dioxide pipeline development in the US

Numerous carbon capture projects have been announced in the US following the passage of the Investment Infrastructure and Jobs Act (IIJA) and the Inflation Reduction Act (IRA). These pieces of legislation contain various tax credits, incentives, and funding opportunities to support carbon capture development. While those incentives significantly shift the economics of carbon capture projects – prompting that slew of announcements – potential challenges remain in bringing those projects to market. We have outlined the potentially lengthy nature of the Class VI permit approval process for carbon sequestration wells. Likewise, the permitting regime for pipelines and other enabling infrastructure is complex, layered, and can vary by geography.

Though these challenges are broadly applicable across the burgeoning industry, they are not uniformly applicable. The specific challenges a project faces will depend on where a potential market participant sits in the value chain and how advantaged the project is geographically and geologically. Wider commercialization of carbon capture technology is likely to need infrastructure build-out targeting carbon dioxide transportation so that a wider group of emitters is able to pursue carbon capture and sequestration (CCS). Without transportation, the use of carbon capture will be relegated to projects located either near an existing carbon dioxide pipeline or proximate to geologic storage, or to projects directly integrating use of captured carbon into their processes. Such a structure would leave anyone outside of those categories effectively sidelined, even if their projects had significant drive – whether from a regulatory or financial perspective – to capture their emissions.

In this article, we focus on the regulatory and other pre-construction or pre-conversion considerations that arise as right-of-way or conversion decisions are made to develop carbon capture infrastructure. We specifically focus on long-haul pipelines, which are the most efficient way to transport carbon dioxide at scale.[1]

[1] CO2 can be transported by pipeline, ship, rail, or truck. Transport by rail and truck, most common in the food and beverage industry in the US, tends to be for smaller volumes. Transport by ship for similar uses takes place in Europe today. Volume and ship distance are major considerations for transport given the much higher relative cost of rail and truck on a ton basis.

The US has by far the largest carbon dioxide pipeline system in the world at some 5,200 miles, transporting some 66 million metric tons per annum (MTPA). Its geographic concentration in the Gulf Coast largely mirrors its historic use to support enhanced oil recovery. While that historic footprint may advantage some Gulf Coast projects, it still leaves portions of the US reliant on greenfield pipeline development to transport carbon dioxide to sequestration sites.

In some cases, regulation and federal spending that target support to carbon capture appear to be reliant on the development of transportation infrastructure. For example, the Department of Energy’s Regional Clean Hydrogen Hubs Program is awarding up to USD 7bn in funding for seven clean hydrogen hubs, five of which include blue hydrogen, and by virtue carbon sequestration. The Department of Energy is also allocating up to USD 2.5bn in funding for carbon capture demonstration projects. As we covered last year, the Environmental Protection Agency’s new clean power plant rules, which were just finalized in late April 2024 but are facing numerous challenges, now rely on carbon capture technology as a central pillar to reduce emissions from coal and natural gas power plants.

Granted, there is some federal support for carbon dioxide transportation infrastructure. The IIJA appropriates USD 2.1bn for low-interest loans and grants through the Carbon Dioxide Transportation Infrastructure Finance and Innovation (CIFIA) program for large-capacity common carrier transport projects, including pipelines. This May, a funding opportunity was reopened for up to USD 24m for front-end engineering and design, or FEED, studies for carbon dioxide transport, with first priority given to pipelines with two or more capture sources connected to geologic storage or conversion locations. In May 2023, the Biden administration also asked Congress to provide federal authority in siting hydrogen and carbon dioxide pipelines and storage infrastructure. Even if such federal authority comes into play, it typically only applies to pipelines that are interstate, not intrastate. While these announcements underscore some degree of federal recognition of the need for infrastructure development and support, they are not necessarily effective in streamlining development. The potential deployed capital is small in relation to the cost of even a single long-haul pipeline, and the federal permitting authority has no clear time line to implementation, or scope of authority.

Three long-haul greenfield pipelines and one conversion of an existing natural gas pipeline to carbon dioxide service were recently proposed, promising to expand the carbon dioxide transportation system to areas outside of its traditional footprint (see figure 2).[2] They have been proposed to transport carbon dioxide from emitters to sequestration sites in the northern Great Plains and Midwest. All four pipelines have included existing ethanol plants as potential shippers.

[2] Other carbon dioxide pipelines at various states of development have also been announced including three that recently received USD 9m in investment through the Department of Energy’s Fossil Energy and Carbon Management office.

As we noted last year, long-haul carbon dioxide pipelines have come up against a host of issues including eminent domain – through which private property is acquired for public use – landowner and advocacy group opposition, and permit denials. The regulatory environment for pipeline construction is incredibly complex and the scope of applicability is not clear cut. Indeed, the issues have been acute enough that the Navigator pipeline has been canceled and the two other long-haul greenfield projects delayed. Importantly, these issues are not unique to carbon dioxide pipeline development. Other pipeline transportation infrastructure projects have faced similar issues, including the interstate Mountain Valley natural gas pipeline in the US Northeast. While in some cases such issues can impact projected in-service dates and estimated costs, they do not necessarily represent insurmountable barriers.

For natural gas pipelines, the Federal Energy Regulatory Commission (FERC) has clear federal jurisdiction for siting, construction, and operations. For carbon dioxide pipelines, however, there is no single federal entity that issues certificates of public convenience and necessity to help support eminent domain authority for the initial siting phase of any project. This leaves authority over eminent domain with individual states. Eminent domain law can vary significantly from state to state and represents a complicating factor in bringing projects into service. If the eminent domain process is not applicable, an easement, or right-of-way, may be required from a landowner.

Adding complexity to any pipeline project is its length, whether it crosses state lines, and how many pipeline tie-ins, or laterals, are required. In the case of carbon dioxide pipelines, sequestration hubs can help share costs, manage risks, and allow smaller emitters to participate. Thus, the underlying transport to that hub may involve multiple laterals to serve more emitters and, in turn, require potential additional landholder easements.

In determining a pipeline route and finalizing the right-of-way, numerous potential regulations and reviews may come into play. The extent to which these are applicable may vary by project, depending on its footprint, or by locality. The intricacies of the consultations and stakeholder groups involved in the initial phases and siting of a project all can impact time to market and cost.

Land use and environmental reviews are major considerations. The extent of the environmental review process can vary depending on whether there is federal or local jurisdiction. For example, the National Environmental Policy Act (NEPA) comes into force when there is federal involvement, whether a project crosses federally controlled land or waterways, uses federal funds, or affects air or water quality regulated under federal law. In these cases, projects must conduct an environmental assessment (EA) or complete an environmental impact statement (EIS), unless they receive a categorical exclusion from the lead agency involved that the federal “action” poses no significant environmental harm. The EIS is the most rigorous of the reviews and is triggered when a project is deemed to potentially “significantly affect the quality of the human environment.” A supplement to the EIS may also be required if there are new circumstances or information relative to the action. The Fiscal Responsibility Act has now put a firm time limit – namely, a one-year review period for an EA – on the lead federal agency involved in a project. The lead agency is generally that with the greatest degree of involvement, if multiple agencies cooperate, or the agency with the most relevant expertise. The more comprehensive EIS now subjects lead agencies to a two-year time limit for review. A project that is subject to NEPA may still need to comply with local or state environmental reviews.

Even if a proposed project falls outside of NEPA authority, it does not preclude a local-level EA or EIS. The requirements for such environmental reviews can vary by region. For example, the Minnesota Public Utilities Commission voted unanimously to require Summit Carbon Solutions to undergo an EIS for the portions of the line running through the state. The Winnebago Tribe of Nebraska – an Iowa landholder – requested an EIS for both the Navigator and Summit pipelines in Iowa. That request was denied by the Iowa Utility Board. It argued that the project fell under its statutory authority and that an EIS was not required at the state level. It added that the project would need to exhibit evidence and environmental studies for relevant permits anyway.

Pipeline construction across water crossings and wetlands typically requires a Clean Water Act (CWA) Section 404 authorization from the U.S. Army Corps of Engineers.[3] Section 404 of the CWA “establishes a program to regulate the discharge of dredged or fill material into waters of the United States, including wetlands.” Because the categorization of “waters of the United States” is fairly broad, some pipes may find themselves with a multitude of water crossings along a proposed pipeline route. While a general permit is issued for certain categories of activity – and often for oil and gas pipelines or electrical utility lines – an individual permit may be required if the activity in review is thought to have potentially significant impacts. For projects that may have hundreds of water crossings, filing individual permits can add significant complexity, time, and costs if a general permit is deemed out of scope. At a high level, section 404 authorization requires the requester to show they have avoided impacts to waters, minimized impacts where they do occur, and that compensation will be made for unavoidable impacts.

Section 401 of the CWA pertains to water quality at the state level whereas Section 404 pertains to filling and dredging in what would be considered federal waters. Section 401 is meant to preclude federal agencies from authorizing projects that result in discharge into US waters that impact water quality requirements. The Section 401 certification comes from a state or tribe after a review of how a given project would impact the water quality within its purview. Conditions can be imposed on such a certification. In some cases, this certification can involve a water quality anti-degradation review.

Projects may also require a biological opinion to ensure compliance with Section 7 of the Endangered Species Act (ESA), which is administered by either the U.S. Fish and Wildlife Service (FWS) or the National Marine Fisheries Service, for the protection of endangered or threatened species and their designated critical habitats. That opinion includes whether “reasonable and prudent measures” will be taken to limit the impacts, and in some cases conservation measures. Compliance with the ESA must be ensured before the issuance of a CWA 404 authorization. This biological opinion is necessary if a federal agency is involved with funding or authorizing an action.

The above is a non-exhaustive summary of major steps that may be needed to bring a pipeline online. However, numerous other steps may be applicable depending on a project’s route. Tribal consultations are a consideration for any portions of pipe going through tribal lands. The U.S. Federal Highway Administration also must authorize crossing an interstate, or the placing of pipeline beneath an interstate.

[3] Three states have the staff to administer their own 404 programs: Florida, Michigan, and New Jersey.

In some cases, leveraging existing pipeline assets that are available for conversion may be seen as an easier route to market given that the pipe has already navigated a permitting and siting process followed by construction. Indeed, the US has already seen the successful conversion of pipeline from one commodity to another before – a notable example being the Pony Express Pipeline, which was converted from crude oil service to natural gas in 1997 and then back to crude oil in 2014. Currently, there are also several other proposed conversions targeting crude oil to natural gas liquids. Though at a smaller scale, the 50-mile, 18-inch West Gwinville Pipeline was also previously converted from natural gas to carbon dioxide service.

Pursuing pipeline conversion for carbon dioxide service appears to have placed the Trailblazer pipeline as the most advanced in its route to market. This pipeline was most recently in service as a natural gas pipeline but received FERC approval in October 2023 to abandon natural gas service. While much of the main line of Trailblazer is seeking to be repurposed, laterals will still need to be constructed to connect emitters to the main line. Even if existing infrastructure is repurposed, it still may have easements and other issues to navigate in order to fully complete conversion for laterals and other equipment.

In early May, Tallgrass Energy initiated a binding open season for the Trailblazer conversion project.[4] The results of that open season, which closed on May 24, will give the market more insight on how advantageous offtakers consider pipe in the ground to be.

While the advantage is compelling, not every pipe will be an attractive option for conversion. The Trailblazer pipeline is fairly unique in its ownership structure in that it is a subsidiary of Tallgrass Energy, which has subsidiaries that operate two other proximate pipelines: the Rockies Express Pipeline (REX) and the Tallgrass Interstate Gas Transmission. REX, given its positioning and nearly parallel infrastructure across part of Trailblazer’s route, will be able to service the existing capacity of natural gas customers on the Trailblazer pipeline (see figure 4).

From a physical perspective, several modifications need to be made in order for a natural gas pipeline to be repurposed. Dehydration equipment to cut down water content is necessary to avoid pipeline corrosion. Additional compression facilities will likely be required to increase the pressure relative to that of a natural gas pipeline. These are in addition to other considerations including those meant to prevent deterioration of the pipeline.

We have focused, above, on the conversion of assets to carbon dioxide service. In some cases, however, the goal is adding extra capacity, rather than linking up new geographic markets. In these cases, looping of pipeline and additional pumping equipment can help expand capacity across an existing pathway.

[4] Tallgrass concluded a Community Benefit Agreement in late April that includes provisions for landowners that would see new pipeline laterals placed across their land. These include annual royalty payments based on the volume of carbon dioxide shipment instead of an up-front lump sum fee. It gives landowners rights to have the laterals built to connect to capture sources (in this case ethanol plants) removed if decommissioned. The agreement states that the environmental group Bold Alliance will not oppose the project in exchange for USD 600,000 in funding for training and equipment to first responders and USD 500,000 in donations to nonprofits on the pipeline route. Breach of the agreement can result in lawsuits to enforce its provisions.

At a more fundamental level, however, is the question of how much existing natural gas pipeline capacity in the US is available for conversion. Attractive conversion opportunities must compete with those pipeline assets remaining in use to support their current lines of business. Thus, the universe of potential conversion options may be limited to pipelines that are experiencing lower capacity utilization while also seeing some of their long-term contracts expire, which would have otherwise guaranteed a revenue stream even if capacity were underutilized. Additionally, to consider conversion to another commodity, the midstream company needs to believe that market conditions are such that capacity utilization is unlikely to change significantly or that the tolling structure would be more beneficial under conversion. New end use markets for the current fuel must be considered. For example, in-service natural gas pipelines may see new market opportunities for delivery to hyperscaler or third-party data centers, especially to the extent that they can be arranged in such a way to avoid utility interconnection. Such delivery could potentially involve direct connection to the pipeline, through a microgrid or resilience asset for backup operation or through colocation with an existing power plant.

Companies with attractive conversion opportunities will also consider the economics of other substitutes, be that traditional hydrocarbon fuels or even shifting use of their assets toward other energy transition functions like hydrogen blending.

An underutilized pipeline may still have contracted customers. Existing firm service customers typically need to be accommodated after abandonment. That accommodation may involve transferred service to another line, like in the case of Trailblazer pipeline, or the construction of additional facilities like compressor stations and laterals to help redirect customers, as was the case for Pony Express natural gas customers when that pipeline was reconverted from natural gas service to oil.

Such transfer of service may not always be welcome by existing shippers. If customers are accommodated on third-party pipes, they will want assurance that there will not be interruptions or degradation to their service and that such a switch will not result in shipping rate changes. Another issue is that many of the emitters seeking to have their captured carbon transported are also natural gas users themselves, including ethanol facilities. Consequently, they will require infrastructure both to bring in fuel and also to transport captured carbon.

Geographically, some areas may have more potential assets for conversion. While a review of the capacity utilization of such pipelines is out of scope of this research, the brief discussion of general trends may be useful to understand pipeline prospects for conversion. The Trailblazer example is notable as it is a pipeline originating in the Rockies. There, natural gas flow dynamics were largely upended with the onset of manufacturing-style natural gas production, which originated in the US Northeast beginning at the turn of the last decade. Prior to that, Rockies production largely fed natural gas consuming markets in the East and Midwest, with pipes flowing west to east. As the Northeast became a major production center, some pipelines reversed direction, in effect backhauling gas from the Northeast toward the Midwest and Rockies in order to keep pace with the evolving market. Indeed, these dynamics partially helped spur the conversion of the Pony Express back to oil service and are factoring into the potential Trailblazer conversion.

Given the largest concentration of US ethanol plants currently in service is located near the footprint of natural gas pipelines that originally serviced the Rockies natural gas-producing region, there could be synergies to conversion of assets. However, even within the broader region, some pipelines are running close to capacity. The Bakken region is North Dakota is seeing egress strained as producers seek to harness associated gas from the Bakken, and main lines like the Northern Border Pipeline are running near full.

The US Gulf Coast has seen significant announcements for carbon capture projects and, relatedly, also has a high concentration of class VI well permits awaiting approval on both a well count and capacity basis. The region also continues to see greenfield natural gas pipeline announcements to accommodate associated production from Permian crude output and demand growth from the next wave of under-construction LNG export facilities and other energy-intensive manufacturing. New pipelines in the region will also help manage intermittency and flexibility in a system that is also experiencing electric load and population growth. Consequently, existing pipelines there may remain highly valued for natural gas service rather than conversion.

At the most simplistic level, a streamlined option – whether the emitter and sequestration are within the same fence line or if the geography allows for short-haul transport – presents an infrastructure advantage to a project, and potential advantages related to cost and time to market as well. With only a handful of permitted pore space locations for sequestration, the market is far from mature. However, it is increasingly clear that both well permits and carbon dioxide pipeline infrastructure would be the proverbial table legs to help support the carbon management industry. Without that, at present, emitters will be advantaged if they have proximity to sequestration capacity or the ability to integrate captured carbon into their own process, or that of a nearby offtaker. Failing that infrastructure development, even willing participants will struggle to be included in the carbon capture economy. For any industry that sees carbon intensity reduction as key to survivability, this could have longstanding repercussions.