The Jones Act is costing Americans billions in higher energy costs and delaying the deployment of green energy sources. To address these costs, in addition to the energy supply and environmental consequences of the status quo, lawmakers must reassess the utility of the act.

The Merchant Marine Act of 1920 — commonly called the Jones Act — is an obscure shipping law that requires vessels transporting goods between two U.S. ports be American-made, manned, and flagged. Originally motivated by principles of national security and protectionism, the law was passed to complement a wartime reinvigoration of domestic shipbuilding that saw the U.S. construct one of the most dominant merchant fleets in the world. A century later, however, the Jones Act now presents a major hurdle for domestic offshore energy projects and fuel transportation, resulting in higher energy prices for Americans and slower deployment of cleaner energy sources.

The U.S. offshore wind industry, already plagued by high interest rates, permitting delays, shoddy port infrastructure, supply chain issues, and recent high-profile turbine breakdowns, is desperately searching for ways to improve project costs and expediency. Building offshore wind turbines requires shipping enormous individual components to be assembled on-site, miles from land. In most countries, this is done using specialized vessels called wind turbine installation vessels (WTIVs). With no Jones Act-compliant WTIVs of its own, the U.S. employs smaller compliant vessels instead, which take significantly more trips to and from project sites, raising project costs and emissions. Currently, the U.S. only has one WTIV under construction — Dominion’s Charybdis — which has taken both years and hundreds of millions of dollars to build. Building and deploying Jones Act-compliant WTIVs is far more costly than simply enlisting foreign-owned ones, and that cost is ultimately reflected in project price tags. President Biden’s Bipartisan Infrastructure Law thankfully includes funding for port upgrades which will alleviate some of the infrastructure bottlenecks, but Jones Act reform, in addition to long overdue permitting reform, is essential for scaling offshore wind to meet our energy goals.

The act also has economic and climate implications for LNG markets. The U.S. is a major producer of natural gas, but domestic pipeline infrastructure–particularly in New England–is inadequate to satisfy consumer demand and balance the grid, and attempts to spur new projects are thwarted by neighboring states. This creates a local reliance on shipped LNG to bridge the gap, but foreign-owned vessels bringing gas from the Gulf of Mexico cannot sail to a second U.S. port, necessitating imports from abroad and slowing supply chains in a region where harsh winters make adequate seasonal energy supplies critical. And given New England’s poor electricity and gas pipeline infrastructure, many households there burn extra-dirty fuel oil for home heating that emits more greenhouse gas instead.

Because the U.S. does not possess any of its own Jones Act-compliant LNG tankers, shipped LNG that the Northeast does receive comes from Trinidad and Tobago and other distant countries. These import inefficiencies widen the rift between supply and demand, further inflating already disproportionately-high energy prices for New Englanders. With no foreseeable plans to revamp domestic shipbuilding to produce compliant LNG tankers, the law leaves regions like New England vulnerable to supply chain disruptions and stuck with an expensive and emissions-intensive energy system. These risks, in tandem with energy security concerns spurred by the war in Ukraine, motivated the New England governors to jointly request that the Department of Energy suspend Jones Act restrictions in 2022. A group of New England senators also wrote to DOE about inflated energy prices, citing increased U.S. exports as the cause of supply shortages. In reality, the Jones Act’s shipping rules and disjointed pipeline infrastructure limit supply mobility and leave consumers in the Northeast cut off from the rest of the country’s gas market, beholden instead to exports from abroad and the volatile international LNG trade.

Source: Esri ArcGIS

Energy transportation challenges imposed by the Jones Act also have heightened consequences for Americans outside the mainland. Geographically isolated places such as Alaska, Hawaii, and Puerto Rico are subjected to shipping constraints, cost burdens, and emergency response threats. In fact, the White House had to waive Jones Act requirements for LNG shipments to Puerto Rico in 2022 to enable the territory to recover from devastating hurricanes. And aside from LNG, Jones Act shipping restrictions on petroleum and oil products force Americans to forfeit roughly $769 million in unrealized consumer surplus annually — a conservative estimation which excludes areas with further inflated prices like Alaska, Hawaii, and Puerto Rico.

Ultimately, lawmakers must reassess the utility of the Jones Act. A protectionist law passed in the spirit of national security is no longer doing its job when it poses looming energy and economic concerns, and even stifles the industry it was designed to protect. Its limitations seem especially frivolous considering that the U.S. has no LNG carrier fleet of its own–and a reported 30-year timeline for building one–while countries such as South Korea are already building them more cheaply and efficiently. The lack of compliant LNG and wind turbine installation vessels, in tandem with the eye-popping costs and timelines for building them domestically, make foreign-flagged alternatives a sensible option if we could only use them.

The obvious solution is to repeal the Jones Act, however the political blowback from powerful proponents of domestic industry could be significant — despite the billions of dollars in potential economic output that would follow. At minimum, specific carve-outs or exemptions must be made for foreign specialized energy carriers to promote energy and economic security, particularly in at-risk regions. A large-scale subsidized campaign of domestic shipbuilding could offer another option in theory, but in practice the combination of high costs, fiscal and political uncertainty, existing difficulties with subsidized Navy shipbuilding, and the current availability of non-U.S. ships all strongly suggest that allowing foreign specialized energy vessels to travel between U.S. ports is the best course of action, at least in the short-term.

Until we adopt such reforms, the harmful effects of the outdated Jones Act are a stark reminder that ensuring security and reliability of clean energy–now and in the future–requires a regulatory regime that is not anchored to the past.

Source: Teresa Jordan. https://gdr.openei.org/files/899/GPFA-AB_Final_Report_with_Supporting_Documents.pdf.

Next-generation geothermal technology shows promise as a clean and potentially abundant baseload power source with relatively limited environmental tradeoffs. One method, Enhanced Geothermal Systems (EGS), uses drilling technology developed for hydraulic fracturing to access ubiquitous heat sources deep below the surface. EGS has yet to become a major component of the U.S. grid and few plants have been built east of the Mississippi despite indications of feasibility. To solve two of the largest hurdles inhibiting the adoption of EGS (underinvestment and public skepticism toward renewables), the Progressive Policy Institute (PPI) urges the U.S. Department of Energy to provide funding for three EGS pilot plants in Pennsylvania and West Virginia, energy-exporting states that produce large quantities of fossil fuels and show high geothermal potential. This will demonstrate EGS’ widespread viability, bolster public and political support for the technology, and garner increased investment for accelerated rollout.

Legacy geothermal systems are costly and rely on existing underground water reservoirs as a heat source, which limits their viability to areas with preexisting geothermal activity and abundant water resources. In contrast, Enhanced Geothermal Systems do not require onsite water supply and can be sited in most areas with sufficient subsurface temperatures. By 2050, the U.S. will require 700-900 GW of additional clean firm energy capacity; EGS has the potential to fill 90 GW of this demand, providing enough power to supply more than 65 million homes. Unlike most renewables, EGS can supply consistent baseload power and heat, and requires a smaller ground footprint than wind and solar. Furthermore, it leverages many existing technologies such as subsurface drilling and hydraulic fracturing used in oil and gas extraction, facilitating rapid rollout and providing career transition prospects for fossil fuel workers. EGS has yet to be implemented at scale, but project costs, drill times, and permitting constraints have all fallen rapidly as interest and investments grow. The Department of Energy’s Pathways to Commercial Liftoff plan advocates for EGS pilot locations in different regions to prove its widespread adaptability; thus far, geothermal projects have mostly been limited to the Basin and Range region in the western U.S., where high subsurface temperatures abound. Nevertheless, DOE’s next pilot funding opportunity will be inclusive of proposals for East Coast sites.

Small EGS pilot projects have been constructed in Massachusetts and Maryland to provide heating and cooling; however, no energy-producing pilot plants have been constructed in the eastern U.S. Although the West contains the majority of viable geothermal sites, the DOE has identified West Virginia and Pennsylvania as highly feasible EGS locations. These states are also known for their outsized roles in producing fossil fuels and exporting energy. Coal remains a core resource in this region; nearly 90% of West Virginia’s electricity is generated using coal (compared to ~7% from renewables), and citizens pay hundreds of millions in subsidies to keep coal plants operational, even as relative costs balloon. Pennsylvania is the nation’s second-largest coal exporter, trailing only West Virginia; renewables produce only 4% of its electricity, excluding its four aging nuclear plants. As fossil fuels face more stringent legislative constraints, these states risk losing their status as energy exporters if they continue to rely on hydrocarbons.

West Virginia and Pennsylvania have something else in common: weak political support for traditional renewables and large energy workforces who remain skeptical of clean energy. From constraining federal clean energy programs to preventing the expansion of solar farms, West Virginia’s political leadership has repeatedly prioritized coal over clean energy. Although coal mining provides tens of thousands of jobs and billions of dollars in export revenue, continued dependence on coal is untenable. Coal’s declining appeal, along with cheaper natural gas and renewables, have diminished the industry’s workforce to its lowest size since 1890, and citizens now pay more for coal power than they would for other energy sources.

Pennsylvania is also no leader on clean energy; between 2013 and 2023, it ranked 49th in the nation in renewable energy growth, trailing behind only Alaska. This is due both to regulatory barriers and the abundant natural gas provided by the Marcellus Shale. New approaches are necessary to enhance the growth of renewables in these states, and the EGS rollout could provide a more politically palatable approach to clean energy.

The White House, along with the DOE, should provide funding from the Bipartisan Infrastructure Law (BIL) for three EGS pilot sites in West Virginia and Pennsylvania to be built by 2028. Considering the costs and pace of previous pilot plants, the depth of available thermal resources, and the foreseeable difficulties of EGS expansion in new regions, construction of the pilot plants should receive a budget of roughly $45-60 million. The BIL allocates funds for seven geothermal pilot plants; three pilot projects received such support after applying during the first round of proposals. The second round of prospective grants includes the possibility of Eastern EGS sites, and all efforts should be made to ensure that Appalachian sites are well-represented in the selected proposals. A multi-plant approach also reflects the DOD’s geothermal pilot program, which created sites at several bases in different states using contracts with three EGS companies. Creating multiple pilot plants proves feasibility in different geology and geography, reduces the likelihood of failure, and facilitates wider public and political engagement. Implementation should be coordinated with regional and local grid providers and energy agencies.

Source: NREL.  https://www.nrel.gov/gis/assets/images/geothermal-identified-hydrothermal-and-egs.jpg

Site selection should be based on several factors: high projected viability and low risk; proximity to existing electrical infrastructure; different geology and geography from existing EGS sites; and political viability. Three potential locations emerge as ideal candidates, given these considerations and in consultation with studies such as the DOE Liftoff plan and other feasibility research. One plant should be sited in northwest Pennsylvania, in order to prove viability in traditional natural gas country, utilize existing gas infrastructure, and facilitate outreach to the gas industry and workforce. Another should be located in northeast Pennsylvania, due to indicated geothermal potential, proximity to larger population centers, and to engage the area’s sizable energy workforce. The final plant should be constructed in northern West Virginia, which offers relatively abundant thermal resources, unique geology with limited natural gas reserves, a declining coal industry, and low support for traditional renewables. Selecting sites for test wells in the vicinity of recently closed coal plants would be ideal, given these locations’ existing transmission infrastructure, energy workforces, and political significance.

In tandem with pilot plant construction, 10-15% of the program’s budget should be allocated to public EGS education and to offer training for local fossil fuel workers. Pennsylvania already uses over 3% of its BIL funds for workforce development; this relatively larger budget to bolster the geothermal workforce reflects the lack of existing EGS plants in the region, as well as additional costs incurred through public education. These funds can be drawn from the initial pilot plant budget or through the $200 million provisioned in BIL for workforce development. This is a vital component of the process; without stakeholder engagement, especially to provide jobs and transparency and engagement for investors, pilot projects lose much of their value. For similar reasons, the program’s contracts and standards should be configured as models for future East Coast EGS projects and risk should be clearly allocated between involved parties.

To minimize negative public reactions towards geothermal, this process should also be intentionally apolitical; investment in renewables can often trigger backlash if it is clearly tied with political interests, especially in conservative states. EGS also has the potential to incur criticisms from environmental groups due to its use of fracking technology. Hopefully, growing support for EGS from mainstream environmental organizations such as the Sierra Club and NRDC will diminish this risk. The NRDC notes, “While this connection (to the oil and gas industry and fracking) may initially give some pause, it creates a fantastic opportunity to deploy an already-trained workforce into an industry that could help secure our zero-emission electricity future.” Given the correct outreach and education strategy that eschews political bias, this campaign can appeal to legacy fuel producers and environmental activists.

Constructing EGS plants in Appalachia, a conservative and renewable-skeptical region with abundant fossil fuels and unique geography, would indicate geothermal’s widespread feasibility. Furthermore, demonstrating the similarities in technology and workforce requirements between geothermal power and fossil fuel industries would engage skeptical audiences and garner broader support for geothermal. EGS plants can make use of the qualified local energy workforces, providing employment and easing implementation. Crucially, funding remains the largest remaining constraint for EGS; the DOE notes that the Eastern geothermal rollout “could have an outsized impact on investor confidence.” Although the declining price of geothermal energy promises to meet DOE’s targets, the U.S. has yet to realize the full geographic potential of EGS. With commercial liftoff planned for 2030, DOE can best position geothermal for success by expanding its reach. The creation of Appalachian EGS facilities could markedly accelerate geothermal’s upscaling, thereby reducing U.S. emissions and facilitating a timely transition to zero-carbon energy.

The Federal Energy Regulatory Commission (FERC) recently finalized two rules for the country’s electricity grids that represent the most significant paradigm shift towards expansion in over a decade. Marking a renewed focus on long-neglected transmission policy, the rules fundamentally alter and begin to standardize the thicket of existing approaches to regional transmission planning by codifying principles of longevity, transparency, and engagement. FERC, the independent agency responsible for regulating interstate energy transmission and wholesale electricity markets, issued Orders 1920 and 1977 at a time of growing policymaker and consumer concern over the state of U.S. electricity infrastructure, which is managing a complex transition through the rise of more frequent extreme weather events, a shifting generation mix, and growing demand from end-use electrification, new manufacturing facilities, and data centers. Although more will be needed on the legislative front — particularly on permitting reform, something PPI has adamantly pushed for — FERC has made commendable progress on the planning side of transmission with these new rules.

The orders underscore the need for increased transmission capacity in our nation’s grid. As demand for electricity balloons, there is growing concern that the country’s transmission networks are hard-pressed to meet household and industry needs, and woefully underdeveloped to reach Biden’s electrification and clean generation goals in the next decade. Growing investment in clean energy generation across the United States faces a bottlenecked grid system caused in no small part by a convoluted set of planning processes. More broadly, the regulatory regime governing the electricity sector comprises an antiquated patchwork of utilities, commissions, and state and federal agencies, ill-suited to accommodate the rapid integration of new technologies or a coordinated, long-term approach to transmission planning.

The rules attempt to address these concerns by providing frameworks for a more collaborative and transparent regional approach to planning that encourages forward thinking and clears unnecessary siting holdups. Order 1920, which was approved 2-1 on a partisan basis with Democrat-appointed commissioners in the majority, contains a number of planning requirements, notably for transmission operators to produce scenario-based regional transmission plans with outlooks of at least 20 years, and to conduct this planning every five years using the best available data. The order also requires that operators determine how projects might achieve seven outlined economic and reliability benefits in the evaluation and selection of long-term regional transmission facilities, further ensuring that long-term transmission needs are considered and addressed cost-effectively. To encourage innovative approaches to transmission planning, Order 1920 obliges operators to consider grid-enhancing technologies (GETs) such as dynamic line ratings and advanced conductors, though without directly mandating their use — likely to avoid overreach, constitutional challenge, and to ensure these technologies are only deployed where doing so has explicit operational and financial advantages.

Another significant new policy included in the order is a requirement to identify opportunities for in-kind replacements of existing facilities to be “right-sized” and thus increase their capacity in a cost-effective manner. Incumbent utilities will be offered federal rights of first refusal (ROFRs) to develop these “right-sized” facilities to avoid the construction of redundant transmission projects. The cost allocation provisions of Order 1920 mandate six-month engagement periods with predefined Relevant State Entities along with plans for a default cost allocation method for selected long-term transmission facilities. They also encourage loosely defined state agreements between providers and Relevant State Entities for selected participants to determine how project costs will be shared among stakeholders. These provisions, in tandem with a mandated process inviting states and consumers to fund some or all of facilities that would otherwise not meet operators’ selection criteria, enable consumers to only pay for projects that benefit them and highlight a renewed emphasis on transparency and state involvement in transmission planning.

Order 1977, which was approved with unanimous consent, complements the new planning framework by adding a backstop measure to prevent proposed projects from fading into obscurity when states fail to act. Specifically, it establishes a process for FERC to exercise its limited authority over siting transmission lines in accordance with amendments to Sec. 216 of the Federal Power Act enacted via the Bipartisan Infrastructure Law. The amendments clarified FERC’s authority to issue permits when state commissions have (i) not made siting determinations by one year following application submission or National Corridor designation, (ii) conditioned approval such that projects are no longer feasible or inadequately reduce capacity constraints, or (iii) denied an application. While affirming states’ primary role in the siting of transmission lines, the rule promotes timely review of siting applications and leaves room for FERC to preclude individual states from inhibiting projects that would be beneficial at the regional or national level.

The rule also introduces a Landowner Bill of Rights which ensures that landowners are notified of potential transmission line projects and permitted to intervene in open Commission proceedings, and codifies an Applicant Code of Conduct to facilitate good-faith engagement between applicants and landowners during the permitting process. To drive home the engagement imperative, transmission line applicants are further required to conduct outreach to environmental justice and Tribal communities. Mandated Environmental Justice Public Engagement Plans will be used to create Environmental Justice Resource Reports to identify impacted communities and detail the effects of projects, and similarly, Tribal Engagement Plans will feed into Tribal Engagement Resource Reports for the same purpose. These stakeholder engagement requirements will hopefully break the cycle of inadequate notification and litigation by residents and quicken project approval through a more proactive and transparent input process. But they must take into account a project’s broader dispersed benefits and avoid granting landowners and local communities an undue veto when entire regions stand to gain.

Taken together, the new rules lay down a much-needed groundwork for the future of transmission in the United States. They provide for a set of processes that bring together state, federal, and private entities to assess and develop long-term transmission projects to meet the needs of Americans in a more holistic and cost-sensitive way. Yet to a certain extent, these changes seem so obvious that many Americans might be surprised that such planning practices were not already in place. In reality, they represent only a fraction of the reforms needed to boost transmission development to the pace needed in order to restore reliability, meet growing demand, and enable the clean energy transition. These new planning mechanisms for enhanced project longevity and regional engagement are crucial in their own right, but as FERC Commissioner Allison Clements notes, more is needed than just the “raw ingredients” for states and transmission providers to build out the grid at a scale consistent with demand.

To keep this momentum, Congress needs to step in. There have been promising attempts at using legislation to speed up the environmental review and permitting process, but outside of the small changes included in the Fiscal Responsibility Act, Congress has not yet been able to hammer out an agreement on comprehensive permitting reform. With existing proposals such as the 2022 Manchin-Schumer deal and a range of transmission-specific bills including the SITE Act, FASTER Act, and SPEED and Reliability Act, there is ample opportunity to do so. And despite recent disagreements over a comprehensive permitting deal, the issue itself remains a bipartisan concern.

Without comprehensive permitting reform and steps to improve interregional planning on top of these regional transmission changes, these new FERC rules alone will not solve the transmission gridlock. Facilities connecting transmission regions are the most difficult type to plan, pay for, and permit under the current regime, despite their crucial role in limiting the impact of local extreme weather events and serving as the most important type of transmission line for connecting remote wind and solar resources to large cities and manufacturing hubs. Further executive and legislative action will be necessary to expedite energy projects like these, and while FERC has undoubtedly taken important steps toward optimizing the U.S. transmission infrastructure, building out a sufficient network will take leaps and bounds.