The need for uniform electric vehicle charging standards and the limits of state efforts to price carbon highlighted FERC’s technical conference on electrification and the grid of the future Thursday.
How electrification of the economy will unfold over the next few decades is unclear, speakers said, but there’s no question new technologies and expanded electricity usage will transform the U.S.
“Electrification is coming, no doubt about it, and it may be coming at a faster pace than some of us may have thought a few years ago,” Chairman Richard Glick said in wrapping up the conference. “And it’s going to have profound impact on a whole bunch of variants, I think — at the state level more directly but even at the federal level.”
The conference focused on the impact and risks of electrification, infrastructure requirements, transmission and distribution services provided by flexible demand and local, state and federal coordination (AD21-12).
Impacts
The first panel of the conference explored the current and future state of electrification in the U.S., discussing what is set to drive electrification and the magnitude and effects of the changes.
Katherine Hamilton, chair of 38 North Solutions and co-chair of the World Economic Forum’s Global Future Council on Clean Electrification, cited research by the Rocky Mountain Institute estimating that if electric power generation is decarbonized, emissions can be reduced by 30%. If systems in homes, businesses and transportation are electrified, Hamilton said, the U.S. can decarbonize by 70%.
Hamilton also pointed to an International Renewable Energy Agency report that predicted that renewable energy, electrification and energy efficiency together could provide 90% of the mitigation measures needed to reduce greenhouse gas emissions.
“If electrification is planned and deployed correctly, reliability and resilience should increase, not decrease,” Hamilton said. “Based on my experience with experts around the globe, no one has the perfect pathway to electrification, but most agree we need to get there.”
Jeff Dennis, general counsel and managing director of Advanced Energy Economy, said electrification of the U.S. economy is accelerating in response to a combination of low- and zero-carbon policy directives at the local, state and federal levels. He cited statistics that more than 204 cities and counties in 37 states have 100% clean energy commitments or achievements, saying cities are driving a significant portion of carbon-free renewable energy.
Dennis said the grid, including transmission systems and wholesale markets regulated by the commission, are the “foundation of decarbonization” and the electrification of the economy. Regional wholesale markets and expanded transmission systems, he said, are both essential to cost-effectively add gigawatts of low- to zero-carbon electricity generation needed to run the country.
Carlos Casablanca, managing director of distribution planning and analysis for American Electric Power, noted that as technologies become less expensive and more advanced, the business case for capital investment in electrification becomes “more attractive for everyone.”
AEP sees enough available capacity to handle the increased load in the near term using existing infrastructure, Casablanca said, but sees an immediate need to build new transmission to integrate increased renewable generation.
“The modernization of the grid, in combination with the penetration of more modern electrified loads and resources, is expected to enable a future where the active management of loads is possible to address emergent, real-time issues in the grid,” Casablanca said.
Infrastructure Needs: A Web of Connections
Asking how to manage the costs of electrification, including new transmission, and how to protect consumers, Commissioner Allison Clements said “the electrification scenario should implicate the whole planning process, from load forecasting” to demand response.
“Most of the answers here have come all the way down to the end user and all the way back up again, right?” said Asa Hopkins, vice president of Synapse Energy Economics, referring to the comments of his fellow panelists during the second session, which focused on infrastructure requirements. “It emphasizes the integrated natural consequences of the system as it will be, where the state of charge of a car in a driveway is a transmission asset.”
Electrification is but one piece of a larger societal transformation prompted by climate change, from public policy to information technology to the growth in renewable energy resources like solar and wind, Hopkins said.
This transition requires a shift from traditional, deterministic planning to a framework that’s more scenario-based, said Edison International CEO Pedro Pizarro, vice chairman of the Edison Electric Institute. “Load may increase by 60% by 2045 and peak demand by 40%, so it’s really ‘all of the above’ across the whole value chain.”
Glick asked panelists how much infrastructure investment electrification will require at both bulk system and local levels, and whether they see a risk of overbuilding, “given the lack of clarity on how quickly we’re going to get to electrification and how extensive it’s going to be.”
Larry Gasteiger, executive director of the trade association WIRES, estimated the need to increase transmission spending in the 2020s by as much as 50% over the average annual spending of $15 billion for the past decade. After 2030 it may require up to $40 billion per year, “which is a whopping 50 to 170% increase over annual investment over the past 10 years,” he said, calling the numbers “breathtaking.”
On the potential for overbuild, Gasteiger said “the real risk is in the potential for underbuilding. Given the need for electrification and needs associated with meeting clean energy goals and resilience of the system, we have a tremendous amount of investment to go. We’re in a hole right now.”
It takes a long time to build transmission, but the need will come quickly when the change comes, so “the main thing is to make sure we’re not caught short,” said Jordan Bakke, senior manager of policy studies for MISO.
In New England the challenge will be managing the integration of massive amounts of offshore wind generation, said Roger Kranenburg, vice president of energy strategy and policy at Eversource Energy, which is partnering with Ørsted on the Revolution Wind and South Fork projects.
“The last mile of infrastructure that exists is very valuable in any transportation industry, so the challenge for us is how do we reimagine the use of that infrastructure,” he said.
“We see the near-term transition needs as predominantly for connecting new supply, which means offshore wind” in New England, Kranenburg said. “In managing that, regional transmission is going to be key, and more [locally] we also see the need for transmission and distribution investment for solar. We’ve got pockets within New England where it’s constrained.”
Gary Rackliffe, vice president of market development and innovation for Hitachi ABB Power Grids, said that new digital technologies are key at the distribution level for the ability to work with customers, and that “storage is also a game changer” on both sides of the meter, providing flexibility to better match generation with load.
The grid is going through two transformations, said Ric O’Connell, executive director of utility consultancy GridLab.
“We’re electrifying a lot of end-use loads over the next 15 years at the same time that we’re decarbonizing the grid, so we see 40% more wind, solar and batteries in the 90% [clean electricity standard] scenario through 2035 than without electrification,” O’Connell said.
Services from Flexible Demand
Speakers in the third panel discussed regulatory and technical barriers to the wider use of EVs as system resources.
FERC Order 2222 helped level the playing field for distributed energy resources, but more needs to be done to break down market hurdles and let EVs fulfill their potential to provide a range of grid services, said Pamela MacDougall, senior manager of grid modernization for the Environmental Defense Fund.
“I do firmly believe that electric vehicles have a vital role in providing grid services both at the distribution and the transmission levels … keeping in mind they are actually batteries on wheels, storage services equivalent to what a fixed battery storage can provide,” MacDougall said.
Depots for fleets of medium- and heavy-duty EVs often include behind-the-meter solar and battery storage on site, providing the potential for aggregating those resources, she said.
“However, unlocking the benefits of [EVs and other DERs] will require intentional technical and market design to enable DERs to be integrated into power markets, system planning and operations to ensure they receive appropriate compensation for the benefits they provide to customers and the system,” MacDougall said in her written comments.
“Through recent actions, particularly Order No. 2222, the commission has started a process for the needed integration,” she said. “[But] commission actions, such as opening this docket, are crucial next steps to elicit more extensive information and evidence necessary to ensure increasingly effective, efficient, resilient and competitive electric markets while accelerating the economic and policy-driven transition to clean energy technologies free of commission-jurisdictional barriers.”
MacDougall recommended removing obstacles to EV participation.
“For example, electric vehicles, having a physical battery on board, are often limited to demand response or utility-based time variant rates to offer grid services,” she wrote. “However, these resources [can] be active participants in the energy markets and provide frequency balancing services, peak and ramp reduction, congestion management, voltage control and capacity services, just to name a few. If resource types are able to respond and provide reliable services, they should be allowed to participate in the market for these purposes.”
“Further, regarding ownership, a growing trend for large businesses and fleets is to allow a third party to install and operate the charging infrastructure often coupled to behind the meter solar and storage,” MacDougall said. “Under the current interconnection rules, in order to sell into PJM, for example, the RTO requires that the owner of the meter … sign a wholesale market participation agreement (WMPA), rather than allowing the owner of the DER to do so.
“This causes unnecessary barriers to wholesale participation, as signing a WMPA can be a deterrent to installing a DER for many businesses, as it potentially triggers federal jurisdiction by FERC, creating an unknown new regulatory obligation,” she said. “A third-party financer or the party responsible for the operation and maintenance of the DER should be able to sign the WMPA, as this would streamline the process for consumers and better align the market with common DER financing models.”
Technical Hurdles
Peter Klauer, CAISO’s senior adviser for smart grid technology, said the ISO has “developed multiple market participation platforms for flexible demand to provide transmission services in its markets. … [But] CAISO believes there is far greater opportunity to unlock the potential of flexible demand to help ensure reliable transmission operations in the grid of the future.
“The grid of today and the future includes increased variability and uncertainty,” Klauer said in his written submission to FERC. “Within the CAISO, we continue to set new limits for minimum net load during the day and three-hour ramps in the evening. The ability of flexible demand to shape and shift the load curve can provide a huge value to mitigate the operational conditions reflected by the duck curve.”
CAISO has taken part in vehicle-grid integration pilot programs since 2011 and successfully demonstrated vehicle-to-grid (V2G) participation in its wholesale markets, “where EV aggregations demonstrated the ability to respond to five-minute energy dispatch as well as four-second frequency regulation control,” Klauer wrote. “The current state of development for V2G technologies is relatively nascent, but the technologies exist and continue to evolve rapidly, reducing costs and improving interoperability.”
Because EVs’ main function is transportation, using them as grid resources could prove costly and inefficient in some cases, he said.
“Because the majority of these resources interconnect on the distribution system, often behind the customer meter, the distribution system operator must conduct reliability studies and assessments, which may result in distribution system upgrades and other costs to ensure the participation of these resources does not harm the reliability of the grid,” Klauer wrote.
“In addition, there are costs associated with a resource participating in the wholesale market. Given the smaller nature of some newly electrified resources, current methods of providing wholesale market-based services may be too costly and outweigh the benefit of obtaining services from these resources as compared to traditional resources.”
He also said a new system of coordination and information exchange between the distribution system operator, the transmission operator and third-party aggregator is necessary. “Little or no real-time coordination exists today to ensure that a market dispatch to an aggregation of newly electrified resources on the distribution system is feasible and reliable.”
Local, State and Federal Coordination
The conference’s final panel dealt with how local, state and federal government agencies should coordinate their activities to facilitate electrification and ensure that the grid is equipped to handle the additional load.
In written comments, Washington Utilities and Transportation Commissioner Ann Rendahl said that while her commission does not have authority over all utilities within the state (which contains a large number publicly owned utilities overseen by local governments), it can use its position to convene stakeholders to discuss and coordinate complicated, multijurisdictional issues such as transportation electrification.
“Coordination on electrification, particularly transportation electrification, the impacts of electrification on the electric grid, and transmission planning and development cannot occur without coordination between states and local jurisdictions, or without similar coordination between state, regional, and federal governmental entities,” Rendahl wrote.
“We are conditioned to stay in our own swim lanes or our own silo or whatever reference you want to use,” Rendahl said during the conference. “We need to be able to talk and share and debate like we are today on how best to accelerate electrification and achieve goals and targets we all have.” A lack of coordination could result in inefficient investments and prolong the time for achieving targets, she added.
But Rendahl cautioned that coordinated efforts should still provide state and local governments the flexibility to address local conditions.
Rendahl wrote that state and federal officials should coordinate efforts to develop interoperable protocols and standards for EV charging networks. She said the UTC’s policy statement on EV supply equipment (EVSE) states that “the public interest would be served by greater interoperability that allows customers to move seamlessly between networks, and allows network data to be made available to utilities and state and local governments for system planning purposes.”
Interoperability must extend to processes as routine as how drivers pay for charging, Rendahl said. State officials must recognize that utilities installing EVSE in their service territories will rely on third parties to offer charging, payment and billing services.
The federal government can play a role in ensuring that low-income communities and communities of color benefit from the transition to a cleaner transportation system, she said. “Local and state government entities know and serve their communities, while the federal government can provide technical and financial resources and coordinate across states.”
In her filed comments, Rhode Island Public Utilities Commissioner Abigail Anthony wrote that the federal government could assist state electrification efforts “by using its resources and reach” to lower upfront costs for EVs and efficient heating equipment. She said the federal government could also implement policies that ensure “strong, sustainable, equitable and predictable” price signals that help reduce the carbon intensity of transportation and heating.
Anthony said states looking to transition to cleaner energy struggle to lower costs on their own because their influence is limited to relatively small markets. “This is because these states must collect enough funds to jumpstart the transition to clean electricity, but not so much that they cause migration — and carbon leakage — to other energy systems and jurisdictions that lag behind on fighting climate change,” she said.
State efforts to raise funds through increased charges on electric bills would become “counterproductive,” she said, because they would increase electricity prices relative to those of transportation and heating fuels — or even electricity in other jurisdictions.
“The federal government should find ways to help states accelerate adoption of cleaner transportation and heating equipment while avoiding counterproductive price signals,” she said.
Anthony said the additional load from electrification will require upgraded and expanded transmission and distribution systems, put upward pressure on supply costs, and increase the need for new clean energy resources. She hopes that increased demand will result in lower electricity rates as fixed costs are spread across a greater volume of sales.
Anthony pointed out that much of the “resource adequacy” for heating customers in her state is provided by individual residents and businesses keeping their oil tanks full and furnaces maintained.
Heating electrification on a large scale will centralize RA planning at the grid level. She warned that “it would be pointless and costly to tear out oil and gas boilers and furnaces only to build new oil and gas peaking plants.” Anthony’s preferred outcome would be reliance on “cost-effective” distributed RA as much as possible in the transition to electrification.
“Regulators should examine how programs and markets would best allow for distributed electric and non-electric resources to provide clean resource adequacy so they can fairly compete with more centralized solutions,” she said.
Philip Jones, executive director of the Alliance for Transportation Electrification (ATE), wrote that utilities should take the lead role in developing transportation electrification plans (TEPs), which should be performed outside the “traditional” assessment of resources and loads in an integrated resource plan.
“The utilities know their systems in the most detail and are responsible for integrating these new loads reliably into the grid. TEPs should include utility plans and programs to encourage the market development of electric vehicles and EV infrastructure,” Jones said.
“Robust planning should be encouraged,” Jones said. “Developing a comprehensive TEP for review by the commission is a critical first step, and initially, these are best performed outside of a traditional IRP process. Programs and tariffs flow from the TEP.”
Jones thinks third-party EV service providers are also a “critical component” of the “EV ecosystem” through the provision of hardware and software, “and they need to play a key role along with utilities and others in building out this infrastructure.”
ATE thinks the EV sector must ensure interoperability standards and open protocols as it scales up in size, Jones said. “These are necessary to ensure a smooth customer experience as the nation transitions to EVs.”
The group also believes that any utility or organization hosting chargers should have the authority to require such standards and protocols in its procurement process and encourages state commissions “to use their authority to condition the use of ratepayer funding of EV infrastructure in such a way.”
FERC Commissioner Mark Christie asked the panelists how state-level rate design could facilitate the rollout of EVs, particularly with respect of time-of-use rates.
“I’m an economist masquerading as a planner, so you probably know where I’ll come down on this one,” said Bob Ethier, vice president of system planning at ISO-NE. “As we increase our level of electrification, it’s only become more and more important that we have those price signals sent out to customers.”
Emeka Anyanwu, Energy Innovation and Resources Business Unit officer at Seattle City Light, pointed to the need to keep equity in mind when thinking about time-of-use rates.
“A lot is predicated on the ability of consumers to have the flexibility to take advantage of those temporal pieces, so it will be important to make sure that we decide time-of-use rates so that they consider different lifestyles and different considerations,” Anyanwu said.
Glick asked what his agency should do on both the infrastructure and grid services side to help prepare for the “next step” in electrification.
“In in my view, FERC clearly has this critical role in planning for electrification,” said former FERC Chair Norman Bay, now a partner with Willkie Farr & Gallagher. “FERC has the authority and the responsibility to develop the policies that can enable electrification and can do this by focusing on [the] traditional priorities that it has had, including markets and competition, infrastructure development and innovation.”
Glick also asked about the need for coordination between states and RTOs/ISOs, whether with respect to transmission planning or “even in terms of how the markets will function in the future to address the changes that are coming with electrification.”
“The ties between [ISO-NE] and the states have grown stronger over the last 10 years in terms of coordination,” Ethier said, pointing to past EV, electric heating, solar and energy efficiency forecasts driven by data from states. “So we have a history of that and it’s ramping up, but it’s going to have to increase exponentially going forward.”
Ethier said transmission upgrades have historically been driven by clear-cut reliability criteria, with the RTO ultimately making build or upgrade decisions. In the future, ISO-NE will “have to work much more closely with the states to decide what is the right thing to build when there’s more uncertainty because it’s their constituents’ money that’s going to be spent and because it’s almost certainly not appropriate for us to make that decision.”