Utility-scale renewables and flexible, distributed renewables, some of the basic elements of deep decarbonization, are growing rapidly, but the transmission system needed to deliver and integrate them is not.

Recent studies, including the landmark and reportedly suppressed Department of Energy Seam study, show expanded transmission is critical. But two key barriers — where to put the new lines and how to pay for them — still slow development, according to a June 2020 Federal Energy Regulatory Commission report to Congress. Allocation of the new lines' costs remains unresolved, but new approaches to siting are attracting attention.

"Siting is one of the most intractable barriers," but "largely untapped" rights-of-way (ROWs) on already developed "brownfields," such as railroads and highways, could "alleviate the problem," former FERC Chair James Hoecker wrote on behalf of the Rail Electrification Council (REC) in a July filing with FERC on transmission planning incentives.

Hoecker's filing defines brownfields as "land already developed for another industrial or ground-disturbing purpose" and notes that "there are many potential kinds of available brownfields that may be suitable for co-development, railroads and highways among them."

These railways and "next generation" highways, in which transmission lines, electric vehicle charging infrastructure and broadband/5G infrastructure are co-located, could bypass objections of private landowners on transmission siting and streamline deployment.

Using existing ROWs is a feasible way to build the urgently-needed interregional transmission described in the Seam study, transmission authorities agreed. But to resolve the cost allocation barrier, stakeholders must recognize high voltage transmission's economic, reliability and resilience benefits, and its importance to deep power system decarbonization, they said.

The benefits of transmission expansion

New transmission that links the now largely disconnected halves of the U.S. power system can benefit customers and the environment, according to the DOE's National Renewable Energy Laboratory (NREL) Seam study. 

New high voltage alternating current (HVAC) or direct current (HVDC) transmission can increase the "transfer capability" across the seam separating the Eastern and Western Interconnections. That would deliver more and better renewable generation to system operators on both sides and allow "substantial energy and operating reserve sharing," the study found.

The resulting power system resource mix would improve the power system's reliability and resilience and return about $2.50 or more in benefits for every dollar invested in transmission expansion, the Seam study found.

DOE officials impeded release of the study's findings because of potential impacts on fossil fuel industries, InvestigateWest reported in August. But other studies have reached the same conclusions.

New HVAC and HVDC transmission linking the two interconnections and the country's regional power systems could save consumers up to $47.2 billion annually and reduce emissions "up to 80%" below 1990 levels by 2030, the Macro Grid Initiative, a stakeholder alliance supporting new regional and interregional transmission, reported.

It can also make the power system more stable, support recovery from outages, and "improve frequency response and ancillary services throughout the existing system," the FERC report to Congress added.

Transmission expansion "provides greater access to location-constrained resources" and improves opportunities to meet federal, state and local renewables mandates and policy goals, former FERC Chair Hoecker's testimony said.

The need for new solutions to expand transmission is emerging with the acceleration of demand for inter-regional resources to meet such needs, he added.

Transmission upgrades are expected to provide tens of billions of dollars in benefits for the Southwest Power Pool (SPP), the Midcontinent Independent System Operator (MISO) and the New England Independent System Operator by mid-century, a 2018 American Council on Renewable Energy paper reported.  

But siting requires "navigating" federal, state and local reviews, which can take "in excess of a decade," FERC Staff said. An alternative is transmission development in transportation corridors that could streamline the siting process and offer new revenue streams to the ROW owners from developer lease payments.

"Using existing rights-of-way for new high voltage transmission is definitely an advantage," said NGI Consulting Principal Morgan Putnam, whose Next Generation Highways whitepaper details one of the transportation corridor opportunities.

Two ROW solutions

Using state and federal highway ROWs for transmission accomplishes "two critical objectives," Putnam said. It "accelerates deployment" and it "prepares the system for transportation electrification so that in five years we are not waiting for upgrades to serve the growing load."

New demand for inter-regional renewable resources and lower costs for HVDC technology make these new concepts, once considered impractical, worth considering, he added.

State Departments of Transportation (DOTs) and the Federal Highway Administration already have compliance practices in place for working with utilities and independent transmission developers, he said. That will eliminate some difficulties of landowner-by-landowner and state-by-state lease and environmental approvals

"The land is already disturbed, and that could allow transportation system experts to obtain formal exclusions from environmental qualifications," Putnam added. "The goal is to obtain all approvals in under two years."

The Maryland Department of Transportation (DOT) has built solar systems on five of its facilities and sees Putnam's concept as "feasible," DOT Program Manager Eddie Lukemire said. We have not studied it, but "it is likely to be easier for developers to deal with one DOT than many private property owners" and "could give developers' access to Maryland's very low interest rates."

An HVDC system on highway ROWs, which would most likely be undergrounded, can be regional, interregional, or part of a national system, Putnam said. It would not "replace the existing AC system, but would be an overlay."

California's August blackouts "could have been served by renewable generation, sent from another region's AC distribution system through a national HVDC overlay to California's AC system," he added.

Some parts of the existing federal highway system "align well with the [potential] HVDC system identified by the Seam study," he said. But the concept would also initiate rural and urban infrastructure upgrades to proactively prepare the system for supporting transmission-constrained load pockets as electrification accelerates.

One example among many is the West Coast's heavily traveled I-5 corridor, which does not have the electrical infrastructure to support the expected need for heavy- and light-duty electric vehicle charging, according to The West Coast Clean Transit Corridor study. A second example is that the electrical infrastructure serving Seattle City Light service territory's heavy-duty vehicle charging stations will require significantly increased capacity, a 2019 Rocky Mountain Institute study found.

Another ROW solution is along rail lines.

The SOO Green HVDC Link between MISO and the PJM Interconnection is soliciting generation to be carried by a proposed 2,100 MW underground HVDC line along major rail corridors.

It could break through "siting, permitting and market barriers" to deliver "abundant and inexpensive" Iowa renewables to Illinois, where renewables can be "more difficult and costly to develop," according to the project's website. It could add almost $1 billion to Iowa's economy and over $1.1 billion to the Illinois economy, analysis by Direct Connect found.

"The completion record of proposed interregional transmission projects is poor," Hoecker wrote in FERC testimony for REC. Transmission projects proposed for brownfield development, like the SOO Green Link, could eliminate much of the ROW and approvals complexity that "deters investment, delays renewables integration, and blocks access to clean energy," he wrote.

The electrification of the economy could add up to 200 GW of new load by 2050, according to REC. Developers and utilities are expected to spend $20 billion to $40 billion annually to modernize their distribution systems, but only a major build-out of the bulk transmission system can bring renewables from resource-rich, transmission-constrained regions to that load, REC said.

"A federal policy making an integrated nationwide high voltage transmission system a national objective is urgently needed and it can grow the economy," Hoecker added. "There is more than adequate investor money on the sidelines waiting for that kind of policy certainty."

Co-locating transmission in existing transportation ROWs will likely make development easier, which will be increasingly important as the economy is decarbonized, Director of New Product Research at Development at Nextera Analytics Aaron Bloom. Bloom worked with NREL and co-authored the Seam study, and is also chair of the Energy Systems Integration Group's System Planning Working Group.

The choice between rail line, highway and greenfield sites will be location by location, Bloom said. At strategically located DC converter stations along the ROWs, AC lines would radiate out like spokes to the underlying local AC distribution systems, he added.

Undergrounding HVDC lines along the ROWs would be more expensive than today's predominantly overhead AC lines, but the Seam study showed the benefits would quickly cover the costs, he said. That is because it is more efficient to use fewer HVDC wires to carry much larger capacities of electricity over longer distances.

But even if ROW shortcuts resolve siting issues, a financial barrier remains, Hoecker said. The standard is that costs should be allocated to beneficiaries, "but questions about where electrons go and who the beneficiaries are do not have clear answers."

Resolving ROWs "would do nothing about the challenge of allocating the hundreds of millions or billions of dollars in transmission line costs," Bloom agreed.

The last barrier

Developers are not currently building interregional projects because they are not satisfied with the way costs are allocated, Brattle Group Principal Johannes Pfeifenberger told the Midwestern Governors Association last November.

Local utilities are addressing local needs and getting paid through rates in the traditional way, he said. But inter-regional projects are not getting built because cost recovery becomes more complicated when it involves more than one utility's service territory.

If there is a solicitation for an inter-regional project, it will only be approved by transmission regulators if benefits exceed costs by a pre-set ratio, typically 1.25 to 1, Pfeifenberger said. Developers seeking to avoid the complexities of cost recovery across multiple territories can have their bids rejected by understating benefits to prevent reaching that ratio.

The Neptune line from New Jersey to Long Island and the Hudson line from New Jersey to New York City went forward only when local power authorities provided long-term contracts to assure cost recovery, Pfeifenberger said.

But inter-regional projects, some fully or almost fully permitted and long seen as having significant value, "can't get built because no developer will assume the costs," he added. Examples are the Lake Champlain Hudson Project for delivering Quebec hydropower to New York City and the TransWest Express projects for taking Wyoming wind to Utah and Nevada.

Because of potential cost recovery complexities for transmission projects whose costs would be allocated across all MISO ratepayers and be collected across multiple utility territories, developers avoid them, Pfeifenberger said. They assess the benefits as "too low to meet the required benefit-cost ratio and are rejected."

Building new lines also faces the "least common denominator trap" because inter-regional transmission planning entities evaluate only the "subset of benefits" they have in common and omit the broader and unique regional benefits, Pfeifenberger said. The result is that the benefits of interregional projects go unquantified and unrecognized and are not built because the costs are calculated at greater than the benefits, he added.

But with increasing and increasingly ambitious renewables mandates, inter-regional transmission will be needed to access the most cost-effective renewables, Pfeifenberger told the Midwestern governors. To get beyond today's practices limiting growth to "local" and "reliability" projects, policymakers and regulators must get beyond today's narrow perspectives.

Planners must separate benefit assessment from cost allocation, he said. First, they should identify whether projects are beneficial overall by recognizing, for instance, that interregional transmission can provide both energy to population centers and economic growth to remote, resource-rich areas.

Based on that, they could approve a "portfolio" of projects that equitably distributes benefits and justifies allocating costs across all ratepayers.

That type of solution has worked regionally, such as for Texas's $7 billion Competitive Renewable Energy Zone transmission expansion, according to a May 2019 American Wind Energy Association paper. For interregional projects, the key is "pre-specified qualification criteria" so that if a project meets any region's benefit-to-cost ratio, it would not face the least common denominator trap.

Cost allocation "is not a straightforward calculation," Bloom said. "But transmission upgrades are fundamental to making the system ready for deep de-carbonization and should be started as soon as possible, because if the transmission is built, everything in the distribution system will follow. That is why ideas like using transportation rights-of-way should be tried."