Advanced transmission technologies (ATTs) can help utilities meet the rising levels of demand that are stressing the grid, according to a report released Sept. 17 by the Massachusetts Institute of Technology’s Center for Energy and Environmental Policy Research (CEEPR).
ATTs are a suite of technologies that include grid-enhancing technologies (GETs). The most widely used ones are dynamic line ratings, advanced power flow control devices, topology optimization and high-performance conductors.
“Increased use of advanced transmission technologies can play a major role in meeting this demand growth quickly and cost-effectively,” the report says. “However, electricity market structures — which disincentivize investment in innovation — are impeding progress towards modernizing the electric grid.”
“A Roadmap for Advanced Transmission Technology Adoption” was written by Grid Strategies President Rob Gramlich, along with CEEPR Fellow Brian Deese and Research Associate Anna Pasnau, both of whom previously worked at the White House for President Joe Biden.
The technologies have been used for decades and are more widely deployed abroad. In the U.S., the lack of incentives for transmission providers, information provided to regulators and some features of electricity markets hold them back, according to the report. The profit structure of electricity markets does not offer the right incentives for transmission providers to adopt many forms of ATTs, despite their consumer benefits and the ability to quickly add transmission capacity to the grid, it says.
“Under the current electricity industry regulatory structure, utilities earn profits from capital expenditures, meaning that they are incentivized to make more costly capital investments (e.g., building a new power plant) over changing their operating expenses or lowering and smoothing demand for electricity — even when those capital expenditures ultimately increase costs for consumers,” the report says.
The “capex bias” is an accepted and well-known feature of cost-of-service regulation, according to the report. It disincentivizes utilities from deploying GETs because they would avoid the need to invest in new transmission — cutting their capital expenditures and thus their profits. Part of regulators’ job is to prevent utilities from taking advantage of that bias and ensure investments are in line with consumer interests, the report says.
“However, both transmission providers and regulators can struggle to identify the best way to expand capacity against a backdrop of multiple options, and for some technologies, they need new modeling practices to assess benefits,” the report says. “Transmission providers and their regulators have historically focused their cost-benefit analyses on a narrow set of risks and thus are slow to scale innovations, preferring the status quo.”
Some policies around ATTs already have improved, with states passing laws aimed at encouraging them, the report notes. Other policies have sought to align utility incentives with key performance metrics; FERC Order 1920 requires transmission providers to consider ATTs in the planning process.
Those steps are in the right direction, but the paper proposes five more to spread the use of ATTs across the grid:
Regulators should require the use of ATTs in certain contexts, with the paper suggesting FERC require DLRs on highly congested lines to increase their capacity at one-tenth the cost of reconductoring. The Department of Energy should adopt a national conductor efficiency standard, which would ensure utilities use more efficient lines that can cut line losses by 30%.
Transmission providers and regulators should have to conduct robust analyses of the value of ATTs for the electric grid. Order 1920 requires they be considered, but it lacks specificity on how robust of an analysis will be required. The paper suggests states adopt laws requiring more stringent analyses to complement the FERC rule.
FERC should create financial incentives for transmission providers to adopt ATTs where they provide high benefits. The commission should adopt a shared-savings incentive nationally, giving utilities a cut of ratepayer savings from GETs adoption, and where possible state legislators should authorize additional returns on equity for ATT investments.
The commission should require transmission providers to share additional information publicly so third parties can evaluate ATT adoption and hold utilities accountable when they fail to make sensible investments.
FERC should open up the planning process for a third party to work on deploying ATTs. The paper suggests the commission could require transmission providers to release relevant data to the National Renewable Energy Laboratory, or another qualified nonprofit entity, to come up with plans for each grid operator to adopt ATTs and update them on a regular basis.
INDIANAPOLIS — MISO’s quarterly public meetup with its board of directors put on display the unrelenting rift between the RTO’s planners and the Independent Market Monitor over MISO’s $21 billion in upcoming long-range transmission planning.
At a Sept. 17 Markets Committee meeting of the MISO Board of Directors, MISO IMM David Patton encouraged a recess on the proposed $21 billion second long-range transmission plan (LRTP) portfolio until MISO agrees to rework its 20-year view of its system and the benefit estimation of the transmission.
“We should pause this process and get to the bottom of this before we allow it to move on,” Patton told board members. “The problem is we don’t have a credible, ‘what-will-the-world-look-like’ scenario if we don’t build this transmission.”
Senior Vice President of Planning and Operations Jennifer Curran said MISO believes it has devised a valuable portfolio and stands by its conservative, 1.9:1 benefit-to-cost estimate.
“I think we have a different philosophy on benefits that leads to a fundamental disagreement,” she told the board.
“We can’t perfectly predict the future. But through the use of scenarios, we can develop the most robust portfolio using the modeling we have available today,” Vice President of System Planning Aubrey Johnson said.
Johnson said the LRTP can be interpreted as “skating to where the puck will be.” He said recent load growth shows MISO’s top-end, most radical planning scenario is likely, when some stakeholders thought it outlandish five years ago.
Johnson said even scaling back MISO’s decarbonization benefit for areas of the footprint where the value of decarbonization isn’t openly acknowledged, the portfolio still would have 1.3:1 benefit-cost ratio.
Multiple stakeholders urged MISO not to entertain the IMM’s request for an assumptions and benefits rework.
ITC’s Brian Drumm said MISO leadership should reject the Monitor’s calls to “develop and test against an alternate reality” regarding LRTP transmission planning.
Drumm said it’s “irresponsible and dangerous” for Patton to assume MISO won’t experience a major load shed event simply because it never has or assume members will make plans independently to dodge one.
“Stakeholders have chosen to solve the reliability imperative through long-range planning and particularly” the second LRTP portfolio, Drumm argued. “The IMM’s request is inappropriate because MISO’s role is to plan regional transmission, not to serve as an integrated resource planner.”
Drumm added that the industry is aware that significant loss of load events will occur again and become more pronounced by extreme weather. He said avoiding just one widespread load shedding event can more than cover the $21 billion price tag of LRTP II.
The Union of Concerned Scientists’ Sam Gomberg said MISO isn’t going far enough in incorporating climate risk assessments in long-range transmission planning. He said the RTO should anticipate changing weather patterns to inform system planning so it doesn’t end up trying to solve the challenges of extreme weather on the fly in the control room.
Gomberg also said MISO is correct to value decarbonization in transmission planning. He said Patton’s argument that federal production tax credits already fully value decarbonization and MISO’s benefit metric is redundant “borders on absurd” and gives too much credit to Congress to objectively put a price on the social cost of carbon.
MISO Director Phyllis Currie asked if the RTO has a stance on planning for increased climate impacts on the system.
“I think our primary objective is to reflect our members’ objectives. We really follow the lead of our members [rather] than taking an independent view of climate change,” Curran said. However, Curran added that from an operations standpoint, MISO uses analytics and machine learning to forecast weather events that historically haven’t occurred.
“David Patton consistently misunderstands the benefits of regional backbone lines … [and] doesn’t like long-term scenario-based planning,” Sustainable FERC Project attorney Lauren Azar argued to board members. Azar said the IMM appears to want MISO to “go backwards” into the “balkanized system” that existed before the RTO’s creation.
Azar rhetorically asked board members to place a monetary value on the 210 lives lost when the lights went out on Texas residents during Winter Storm Uri.
Azar said the IMM should stick to its original purpose of “mainly markets” and advised MISO not to pay for the IMM’s opinions on transmission planning through its IMM budget.
The MISO IMM has made some stakeholders uneasy with his interest in MISO’s long-range transmission planning and public criticism of the 20-year fleet and benefit estimates MISO uses. Since last year, some have said the IMM oversteps his role.
MISO’s board of directors has included a $250,000 allowance in the Monitor’s $10 million budget next year to “monitor ratings and identify transmission withholding and compliance” associated with ambient adjusted line ratings requirements it will roll out under FERC Order 881. The line item and data collection of transmission data caused consternation among MISO transmission owners.
MISO staff will be “actively discussing what data” transmission owners must provide, MISO Director Trip Doggett said.
Equity and community engagement have not been high priorities for the RTOs, ISOs, utilities and other organizations that have primary responsibility for planning the nation’s transmission system — a situation that historically has resulted in siting and permitting delays and, in some cases, yearslong litigation.
But the U.S. Department of Energy and Pacific Northwest National Laboratory (PNNL) want to change that narrative with a new initiative ― the Inclusive Transmission Planning (ITP) project ― which will provide technical assistance to grid planners seeking to integrate equity and community input into their projects up front, rather than as an add-on.
Speaking at a Sept. 17 webinar on the ITP, Emma Hibbard, a technical advisor in DOE’s Grid Deployment Office, laid out the rationale for the new program.
“Timely transmission deployment is essential to increase grid reliability and resilience and lower costs for consumers, as well as pave the way to a clean energy future, but often public acceptance of new transmission development can constrain [or] delay deployment,” Hibbard said. “There’s also an increasing awareness that positive outcomes for transmission development really hinge on ensuring positive and equitable outcomes for all, including disadvantaged and rural communities along transmission routes.”
Hibbard acknowledged that FERC, state regulators and many grid planners are working to improve transparency and public participation. But, she said, “there’s a need for more information and more support around energy equity and the relationship to transmission planning, and … new approaches to soliciting and integrating community input, in addition to what is already existing.”
The webinar provided an overview of the ITP program, which is offering two tracks of technical assistance — but no funding — for grid planning organizations.
“Tier 1 is really about education, outreach and capacity building,” said Paul Wetherbee, an advisor on regional energy system planning at PNNL. “We’re really talking about educating and building awareness of energy equity concepts” — for example, providing a presentation “describing the main pillars of energy equity and how they would fit into the transmission planning process, or how to think about that in terms of your existing transmission planning processes.”
In Tier 2, “we’re going to do a deep dive with the applicant into the pool and go into some of [the] details of other transmission planning processes and metrics,” Wetherbee said. Topics “might include developing quantitative energy equity metrics, putting that together with the existing data sets and working with the applicant to go through their current … transmission planning metrics” and cover energy equity measures.
Tier 2 could also look at how to integrate energy equity into cost allocation metrics and transmission economics, he said.
Both tracks will incorporate three components, said Jennifer Yoshimura, the principal investigator for the program at PNNL. A series of listening sessions will begin in October to gather input from a broad range of stakeholders “to understand opportunities for participation as well as barriers,” Yoshimura said. The listening sessions for transmission planners are scheduled for Oct. 1 and Oct. 16.
The ITP will also develop research and resource materials for the general public as well as grid planners “to increase inclusivity as well as equitable outcomes,” she said. The technical assistance component will focus on “capacity building for transmission planners to look at how to incorporate energy equity and justice objectives within their planning processes and paradigms.”
Applications for the program are now open, with a final deadline of Oct. 31, Wetherbee said. Applications will be reviewed in November, and program participants will be announced in December. Both tiers will kick off in January 2025 and run through November.
Eligibility is strictly limited to grid planning organizations, including RTOs, ISOs, utilities and power marketing administrations, such as the Bonneville Power Administration, but DOE and PNNL are looking for diverse participants for each tier, based on geography and equity issues, Wetherbee said.
Tribes often do not have dedicated grid planners, but DOE on Sept. 17 also announced a Tribal Nation Transmission Program, which will provide “educational resources, training and on-call assistance from technical experts and researchers from the National Renewable Energy Laboratory.”
‘We Didn’t Start with Equity’
The historic and ongoing challenges for new approaches to inclusive grid planning are complex, Yoshimura said in her opening remarks at the webinar.
Traditional industry metrics — such as the System Average Interruption Duration Index, or SAIDI — focus on “system averages that can hide vulnerabilities at the household level,” she said. “We see an increase of threats and vulnerabilities involved, whether individuals with ill intentions to harm substations or transmission lines [at risk from] increasing wildfires. …
“Within transmission planning processes, we have seen an emphasis and research focusing on integrated distribution planning, as well as energy transitions on the generation side,” she said. “But there are a lot of opportunities still needed to include equity and equity objectives within transmission planning” in ways that drill down to the granular, household level.
A question-and-answer session following the official presentation reflected some of the challenges ahead.
One participant asked if the ITP program would address ways to improve the National Environmental Policy Act process, the environmental reviews that can slow down and delay the siting and permitting of transmission projects.
Bethel Tarekegne, a PNNL research engineer, said whether the program would cover NEPA was still being discussed, while Yoshimura stressed that NEPA reviews are primarily part of siting and permitting processes, not planning. The Grid Deployment Office has other programs focused on siting and permitting, she said.
DOE and PNNL staff also were asked if they could provide any examples of transmission planning that resulted in equitable participation or outcomes, but none of them could.
“A lot of transmission today is really built around reliability, economics and public policy,” said Patrick Maloney, a power system engineer at PNNL. Lacking examples, he suggested that “allocation of costs might be thought of as a way to bring some equity into the transmission planning process.”
Yoshimura also came up empty on examples. “Our systems and institutions and policies, we didn’t start with equity, yet we’re trying to get to equitable outcomes,” she said. “And so, I think projects like this, listening sessions, case studies and how we learn from each other will help us move in the direction that we need.”
NYISO presented its final interim staff recommendations for the demand curve reset for 2025-2029 at the Installed Capacity Working Group’s meeting Sept. 10, with minor updates to some metrics.
The recommendations remain largely the same as the draft presented in August, with the two-hour battery energy storage system (BESS) as the representative lowest-cost peaker plant technology. (See NYISO Presents Draft Recommendations for Demand Curve Reset.)
As part of calculating the cost of new entry for a hypothetical peaker plant, Zach Smith, senior manager of capacity and new resource integration for NYISO, said the ISO opted to factor in land lease payments for the construction period for the hypothetical peaker. Interconnection costs were modified downward across all zones outside of Long Island. The new derating factor for the BESS also was discussed.
Smith said the interconnection costs were estimated to be higher because it was assumed peakers would require 345 kV, but 200-MW battery storage systems can connect to lower-voltage lines, which cost less. “And it appears to be better aligned with the actual interconnection requests that we are seeing,” Smith added.
“The change here is that we force the battery to charge more before the peak load window,” said Paul Hibbard, principal of Analysis Group.
Hibbard said the change causes negligible differences to net EAS revenue across all zones, aside from Long Island, which saw a 12% drop.
Derating Factor Headaches
Smith said NYISO was recommending a 2.5% derating factor for BESS peakers. The derating factor was calculated as a weighted average of the derating factors that batteries should expect to receive across their 20-year amortization period.
NYISO does not yet have a class average for BESS units. “The ICAP Manual (Section 4.5) currently establishes that the initial derating factor a new BESS would receive upon entering the ICAP market is based on the NERC class average equivalent demand forced outage rate (EFORd) of pumped hydro storage until three energy storage resources are participating in the ICAP market and have sufficient historical operating data to establish a ‘NYISO class average’ EFORd for energy storage resources,” the ISO said.
The 2.5% derating factor is based on the assumption that any new BESS would have an initial 9.19% derating factor — the current class average for pumped hydro — for its first year of operation. The derating factor for the second year would be 5.6%, which is the average of 9.19% and 2%, which is the derating factor estimated by NYISO’s consultants. NYISO then assumes a 2% derating factor for years 3 to 20 of the estimated life of the battery. The average over those 20 years is about 2.5%.
But this prompted questions from stakeholders.
“I don’t understand how you can make this change without making companion changes to the manual,” said Doreen Saia, of Greenberg Traurig. “The unit that comes online next year isn’t going to get 2.5%. It’s going to get 9.19% unless and until we make changes to our actual rules.”
Smith clarified the derating factor would be 9.19% for the first year and the average of the 9.19% and the actual availability of the BESS for the rest of its operating life.
“A unit’s derating factor, once it has sufficient operating experience, is always based on its actual production,” Smith said.
Open Questions, Open Frustrations
Smith went over several questions NYISO still was reviewing, such as how to take into account sales tax for BESS labor, operations and maintenance costs; investment tax credits for the transmission lines to the plants; and costs of debt and equity.
Some stakeholders were unhappy that several longstanding questions were not answered and not addressed in the open questions. They said they wanted to see cost declines for battery units included in the analysis.
“The ISO has recently shown the assumptions that it’s doing in the study with the Department of Public Service and the transmission owners, and it shows an expectation of more than a 50% decline in battery storage costs over the next 10 years,” said Mark Younger of Hudson Energy Economics. This meant a decline in revenues for the battery units; thus, NYISO’s net cost of new entry was about 45% too low.
Another stakeholder was disappointed NYISO was not proposing to include revenues for BESS units that come from outside wholesale markets, which could include incentive programs from the state and utilities.
“I think it severely overstates the net CONE of these facilities and therefore it will impose very high, unnecessary costs on New York consumers,” they said.
“Without additional modification, the compliance timelines and related provisions of the rule are not workable and are destined to trigger an acceleration in the pace of premature retirements of electric generation units that possess critical reliability attributes at the very time when such generation is needed to support ever-increasing electricity demand because of the growth of the digital economy and the need to ensure adequate backup generation to support an increasing amount of intermittent renewable generation,” they wrote. EPA’s final rule would strain their ability to maintain the reliability of the electric grid, they argued.
The grid operators had proposed a “reliability safety valve” that would help mitigate their concerns, but EPA did not include that in the final rule, nor did it explain why, they noted. The grid operators had wanted EPA to provide upfront, clear criteria on the “remaining use of life and other factors” and enforcement discretion; the creation of a subcategory of generators needed for reliability; offering states guidance on how to use a reliability valve; and the creation of “regional reliability allowances” that generators could use in emergencies to avoid penalties under the rule.
Instead, they argued, the final rule unreasonably discounts that existing fossil generators will need to decide whether to commit to installing untested technology or retire their units years before the compliance deadline with state compliance proposals due in 2026. That could accelerate earlier retirements of generators, the grid operators said.
The rule requires 90% carbon capture and storage for coal plants that want to run after Jan. 1, 2039, as well as for new and modified natural gas units with capacity factors of 40% and above. Both categories of plants would need to install CCS systems by Jan. 1, 2032.
“None of EPA’s projected time frames reflect historical rates of adoption of CCS technology for electrical generation purposes, nor does EPA adequately consider the risks that the technologies will not mature in time for [electric generating unit] owners to deploy them,” the grid operators said.
EPA’s rule did include a short-term reliability mechanism, which requires the declaration of an energy emergency alert 2 before any compliance mitigation can take place.
“This short-term reliability mechanism that EPA did adopt in the rule thus unduly places the grid — and customers — at greater risk before any short-term relief would be available,” the grid operators said. They “should not have to wait until the heightened level of emergency that an EEA2 declaration represents; they should be able to take proactive measures to address reliability issues upon earlier evidence of deteriorating grid conditions as evidenced by declaration of an energy emergency alert 1.”
Compliance flexibility should kick in at EEA 1 because at that point, grid operators can still call on emergency generation. By waiting until an EEA 2, grid operators cannot act until they are in a real-time emergency.
For longer-term issues, states can ask for extended deadlines or lower technology standards, but the grid operators would like to see EPA offer more guidance on that process.
EPA is not responding to the initial briefs until next month, but the RTOs’ comments did generate some response from others. The Clean Air Task Force and Natural Resources Defense Council filed lengthy comments on grid reliability, arguing the rule was designed to give utilities and system operators the flexibility they need to maintain grid reliability.
“While EPA has considered reliability issues in its proposal, FERC is the agency with direct jurisdiction over electric reliability,” the organizations said. “As discussed above and as recognized by FERC, the electric grid is undergoing changes unrelated to the EPA proposal, and the proposed regulations are only incremental to these existing forces. FERC and the electric utilities have the responsibility and many tools available to them to ensure reliability as these grid changes occur.”
A PJM Market Implementation Committee discussion on expanding the demand response (DR) winter availability window to include a wider range of hours branched off into a broader conversation on how the resource class participates in the RTO’s capacity market.
Presenting on behalf of a coalition of demand response providers during the Sept. 11 meeting, Bruce Campbell, principal of Campbell Energy Advisors, said there is excess curtailment capability in the winter that is not being captured in the revised risk modeling and accreditation methodology implemented this year. The coalition includes the Advanced Energy Management Alliance (AEMA), the PJM Industrial Customer Coalition (PJM ICC), CPower, Enel and NRG Curtailment Solutions. (See FERC Approves 1st PJM Proposal out of CIFP.)
Drafted through the Critical Issue Fast Path (CIFP) stakeholder process conducted last year and approved by FERC in January, the changes shifted the bulk of reliability risk from summer to winter. The summer risk also was concentrated in a few mid-day hours, whereas the risk PJM has identified in the winter is more evenly spread across the day. Campbell said about 20% of the winter reliability risk is in hours not captured in the DR availability window, which is 6 a.m. to 9 p.m.
Paired with the “legacy” availability window, Campbell said the changes led to a significant derate in the amount of capacity DR resources can offer. The amount of DR offered into the 2025/26 Base Residual Auction (BRA), while unchanged in ICAP terms, was around 1,300 MW UCAP lower due to the changes, an amount he estimated could have pushed the auction clearing price down to $210/MW-day, rather than the $269.92/MW-day price posted on July 30. (See PJM Capacity Prices Spike 10-fold in 2025/26 Auction.)
In previous MIC discussions, Kerinia Cusick, president of the Center for Renewables Integration, representing Voltus, said PJM also is hampering the potential of load that can offer higher curtailment in the winter by capping capability at the lesser of winter peak load (WPL) or peak load contribution (PLC). She said that effectively limits winter curtailment by the lesser of the estimated potential in winter and summer.
Cusick argued PJM’s effective load carrying capability (ELCC) methodology further limits DR accreditation by assuming the resource class’s available curtailment is proportional to the system load being simulated against the peak load forecast. She said that approach reduces the incentive for consumers with load that is steady year-round to participate in DR programs and results in “double capping” in the winter when capability is limited to WPL and PLC.
Monitor Argues for New Definition of DR Performance Before Changes
Independent Market Monitor Joe Bowring said PJM must make changes to how performance is defined for DR before the resource’s availability window should be expanded. He said the current market design is flawed by not requiring DR resources to reduce their consumption during an emergency, instead mandating they maintain their load at or below their firm service level (FSL).
“While DR providers argue for a higher ELCC value, they ignore the fact that DR’s ELCC is based on assumed perfect performance, unlike thermal resources whose ELCC is based on actual performance during identified winter peak hours. DR ELCC should be based on performance data during the same winter peak hours, like other resources. If that were done, it is likely that the ELCC for DR would be much lower than it is, rather than the increase proposed by the DR providers,” Bowring said.
Presenting data from the December 2022 Winter Storm Elliott, he said many industrial DR participants already were offline or had reduced their consumption ahead of the Christmas holiday. When called upon during the performance assessment intervals (PAIs) seen on Dec. 23, he said 83% of resources already were at or below their WPL, a figure that increased to 90% when additional PAIs were declared the following day.
The low starting point for DR load during Elliott was a key factor in the low reduction in load provided by DR resources compared to their expected reduction, which is based on the energy load reductions estimates that DR providers submit to PJM in real-time. Those estimates are derived from a baseline set by recent load on similar hours and days.
Bowring said that while those reduction estimates are used by PJM to get a sense of the amount of DR that could be available ahead of potential PAIs, they do not factor into capacity performance (CP) penalties assessed against resources that fail to deliver load reductions. Instead, CP penalties are assessed against DR resources that maintain a load above their FSL.
Campbell said the sector has made improvements to the load reduction estimates provided to PJM over the past year.
In an interview, Bowring told RTO Insider he thinks PJM should redefine what a DR resource is providing to require an explicit reduction in load, rather than an expectation a resource will be below its FSL. He called for the RTO to open a separate stakeholder process to reevaluate how DR participates in the capacity market.
Bowring drew a distinction between the redesign he is seeking for DR participation versus the stakeholder adoption of a Monitor proposal to eliminate energy efficiency (EE) from the capacity construct. While the latter also was initiated by PJM as a broad reconsideration of the role EE should play, Bowring argued EE does not provide a reliability benefit for consumers and has no place in the Reliability Pricing Model. With the right market design, he said, DR could provide dependable reductions in load when called upon.
“It’s not like EE — DR is a resource,” Bowring said. “And while it should be on the demand side, if everyone insists on keeping some of it on the supply side it should be demonstrated that it’s providing an incremental benefit to PJM.”
Energy efficiency providers disputed Bowring’s characterization of the resource’s value, arguing that capacity market revenues are used to incentivize the purchasing of more efficient devices, pushing the need for capacity lower. PJM filed governing document revisions with FERC that would eliminate EE on Sept. 6. (See PJM Asks FERC to Eliminate Energy Efficiency from Capacity Market.)
Bowring said his preference is for the DR to be shifted to the demand side of the market, to be compensated for a year-round reduction in peak loads with a corresponding diminished capacity bill. If stakeholders prefer for DR to remain on the supply side, he said it should be accredited through the same marginal ELCC approach applied to generators, evaluation of performance during emergencies should be based on metered reductions in electric consumption and precise participant locations should be known to PJM for nodal deployment.
“The DR approach in PJM is badly flawed. We believe that DR is an important resource, but to capture its potential, it has to be dealt with in a way that’s consistent with how PJM markets work. It has to be nodal, it has to be metered, it has to be verifiable … based on metered reductions, not on artificially made-up assumptions,” Bowring said.
Calpine’s David “Scarp” Scarpignato said metering the reduction a DR resource provides runs into challenges for longer deployments, where determining the reduction provided requires determining what the load would have been if the resource was not called on. He said if a resource was committed at 10 a.m., the reduction would be apparent for the initial intervals, but assessing performance at noon or 4 p.m. would rely on counterfactuals.
Cusick said DR is designed to be a planning product that provides a capacity reduction that can avoid the need for construction of new generation resources just to serve a few hours annually. She said Bowring’s vision would treat DR as both a capacity resource and energy product at once.
“That is precisely the point. All capacity resources have a must-offer obligation in the energy market,” Bowring said. “Capacity by itself is not an actual product. Capacity resources are paid in order to provide a reliable source of energy. The suggestion that DR should be exempt from the obligations of a capacity resource mean that, in that view, DR should not be a capacity resource.”
As energy demand — and demand peaks — scale up, virtual power plants are turning the energy industry’s traditional models of supply and demand on their heads, said Chloe Holden, an industry analyst at Advanced Energy United, in her opening remarks at a Sept. 16 webinar on the vital role VPPs could play in the U.S. clean energy transition.
“Virtual power plants … are large groups of distributed energy resources in homes and businesses that can be controlled remotely, so that we don’t have to rely on coordinating supply to meet demand,” Holden said. “Instead, we can schedule demand to match supply.”
The technology and business models are well proven, she said. For example, EnergyHub, a provider of demand side services, now manages more than 1.3 million “connected devices” ― including smart thermostats, batteries, electric vehicles and water heaters ― for more than 60 utilities across the country, according to Nick Papanastassiou, the company’s director of market development and regulatory affairs.
“We work with a network of about 50-plus [original equipment manufacturers] across all sorts of devices,” he said.
The U.S. has between 30 GW and 60 GW of VPPs online, Holden said. But the U.S. Department of Energy estimates that 80 to 160 GW more VPP capacity will be needed by 2030, and those millions of connected devices could provide 10% to 20% of the additional demand on the grid.
Holden, Papanastassiou and other speakers at the webinar explored the opportunities and obstacles facing VPP expansion, looking at residential and commercial and industrial programs as well as new electric vehicle-managed charging and vehicle-to-grid (V2G) programs.
An enthusiastic proselytizer for residential VPPs, Papanastassiou reeled off a list of benefits. Like traditional central power plants, they are dispatchable and reliable and can provide not only fast-response for peak demand, but also grid support services, he said.
“There are a lot of flavors of what a VPP could be,” Papanastassiou said. “But at its heart, it’s this notion that customers and devices are providing flexibility to the grid in a really valuable and harmonized way.”
He pointed to a demand management and energy conservation project EnergyHub worked on with Ontario’s grid operator, IESO. With upfront incentives and “a really robust, multichannel marketing effort,” EnergyHub helped enroll more than 100,000 smart thermostats in a VPP that delivered 134 MW of power during a peak demand event.
Carter Wood, who works on electric vehicle policy at Ford Motors, said the automaker continues to partner with utilities, such as DTE in Detroit, on managed charging and bidirectional, V2G programs. But he cautioned that VPPs based on EV batteries are a different value proposition from VPPs aggregating smart thermostats or other home appliances that cost considerably less. Scale will be linked to EV adoption rates.
Ford, like other automakers, has slowed its plans for rolling out new EV models. Carter said its F-150 Lightning electric pickup truck is its only model offering bidirectional charging that can be tapped for backup power or potential grid support. But as EV adoption scales, EV-based VPPs could supplant natural gas peaker plants, he said.
The 8½-by-11 Principle
Successful VPP programs need three basic elements to draw in customers, Papanastassiou said. “One, a compelling incentive to participate; two, a simple enrollment process supported by effective marketing, and three, a program that isn’t going to actively inconvenience them.”
Raghav Murali, head of policy and government affairs at PowerFlex, agreed VPP programs need to be “simple and streamlined. I like to sort of refer to it as an 8½-by-11 principle,” he said. “If it’s too complicated to fit in a single sheet of paper, then we probably can’t sell it to customers.”
A subsidiary of EDF Renewables, PowerFlex works primarily with commercial and industrial customers, many of which look to VPPs to cut their energy bills and help the grid, Murali said.
He sees “reasonable, common-sense virtual power plant policies that can help these programs scale” as another key component for successful VPPs.
Speaking at AEU’s Sept. 16 webinar on VPPs were (clockwise from upper left) Raghav Murali, PowerFlex; Nick Papanastassiou, EnergyHub; Chloe Holden, AEU; and Carter Wood, Ford. | Advanced Energy United
Some utilities continue to offer more traditional demand response and energy conservation programs and have yet to embrace “a multi-technology stack,” Murali said. “There are certain programs that have onerous [air conditioning] cycling programs that have mandatory terms … [and] data privacy requirements that are completely out of step with what any company would agree to.”
He acknowledged concerns about “double-dipping” in measuring the performance of the different components or devices in a VPP but argued that submetering technology used with battery storage and electric vehicle chargers “is a more efficient and streamlined way to measure asset performance in a VPP paradigm.”
Both Murali and Wood called for tech-neutral regulations for VPPs. “Make sure they’re not ‘smart thermostat’ programs. Make sure they’re not ‘storage’ programs but are VPP or grid services programs that encompass the broad technology type,” Murali said.
“A lot of what we advocate for is, you know, treat [EVs] in same category as stationary storage,” Wood said. “We should be treated tech neutrally.”
Framing VPPs in a tech-neutral context could “become more and more pressing in communications to regulators and decision makers,” Holden said. “There are all these devices on the grid, and either they are tapped to their full potential or they’re not. So as demand rises, there’s a need to enable them to do what they’re technically capable of doing.”
Opponents of the Southeast Energy Exchange Market (SEEM) have argued the market does not provide the benefits to customers promised by its supporters and also violates FERC’s regulations (ER21-1111, et al.).
SEEM’s opponents were responding to a filing submitted by SEEM members in August that argued the market brings savings to consumers and should be allowed to continue. (See SEEM Members Respond to FERC Briefing Request.)
FERC had requested briefings from both supporters and detractors of SEEM as a step toward satisfying a D.C. Circuit Court of Appeals order from 2023 remanding the commission’s approval of the market. (See FERC Requests Briefings on SEEM After DC Circuit Order.)
The reply briefs were filed Sept. 12 by three groups representing various longstanding opponents of SEEM:
Public Interest Organizations (PIO) — a group of mostly environmental organizations including the Sierra Club, the Southern Alliance for Clean Energy, the Natural Resources Defense Council and the Partnership for Southern Equity.
Southern Renewable Energy Association (SREA) — a trade organization promoting renewable energy in seven Southeastern states whose members include National Grid, Invenergy and Ørsted.
Clean Trades — Advanced Energy United, the Clean Energy Buyers Association and the Solar Energy Industries Association.
The commission asked respondents to answer whether SEEM qualifies as a loose power pool under FERC Order 888 and whether the market’s requirements that entities transacting in it have a source and sink inside its footprint violate Order 888. SEEM members argued in their brief the market does not qualify as a loose power pool because “the commission has already found that NFEETS [the market’s non-firm energy exchange transmission service] is neither a discount nor a special rate” and that the D.C. Circuit did not find fault with FERC’s reasoning on that point.
However, the market’s opponents said this argument ignored the clear intent of the court’s remand order. The PIOs wrote that SEEM “has walked and quacked like an exclusive power pool” since its conception and criticized the commission and members for focusing “entirely on questions regarding definitional characterizations and technical limitations of SEEM.”
“These questions have already been asked and answered in the record and rejected by the court,” the PIOs wrote. “By delving deeply into the question of geographic limitations and alternative theories designed to justify SEEM’s existing design rather than address its core problems, both the briefing order and the utilities ignore the court’s broader concerns that SEEM’s overall design violates Order 888’s open access requirements.”
The PIOs said the D.C. Circuit’s ruling was intended to allow FERC, having seen SEEM in action, to reevaluate whether the market actually complies with Order 888. They said that contrary to supporters’ promises, “SEEM has demonstrated the need for Order 888’s protections” by systematically excluding independent power producers; the organizations claimed “no non-utility sellers have transacted in SEEM [and] just one non-SEEM utility participant” has joined the market.
‘Nominal Cost Savings’
Energy sales have been dominated by just a few utilities, the PIOs claimed, citing a report from SEEM’s market auditor showing that “a single seller accounted for between 30 and almost 80% of all sales” in the market’s first few months and the two largest sellers combined accounted for 55 to 90% of sales. The arrival of utilities from Florida in July 2023 lessened this dominance, but the PIOs observed that two sellers alone still account for more than 40% of all sales in each month.
The PIOs said that the lack of competition has resulted in only “nominal cost savings.” Sharing this view was SREA, which pointed out that while SEEM proponents originally projected benefits of $40 million annually, the market reported total benefits of $3.7 million in 2023, which “appears to be a gross benefit.” Taking estimates for annual non-centralized costs of $2.8 million and payments for legal work, auditing and platform development, SREA estimated an overall net cost of $824,591 per year.
SREA also cited data from the auditor to point out that trading on SEEM virtually shut down during the widespread blackouts arising from winter storms in December 2022, with less than 1,000 MWh traded on the platform between Dec. 23 and Dec. 27. The association also noted 53 hours this July, mostly at night, during which no trades occurred on SEEM at all. SREA quoted the market auditor’s report of “a statistically significant relationship” in which high demand is matched with decreased trading activity on SEEM.
Regarding the SEEM members’ assertion about NFEETS, the Clean Trades called their description of NFEETS as a pancaked rate a “post-hoc rationalization,” noting that members called the service “non-pancaked” when they first filed the SEEM agreement. Now, however, the Clean Trades said that members have called their previous description of NFEETS “shorthand.” They called on the commission to recognize the truth of the matter, as they described it, and treat SEEM as a loose power pool.
“The commission should reject the SEEM Members’ attempt to have their pancakes and eat them too,” the Clean Trades said. “The bottom line is that … SEEM represents a pooling arrangement that favors members over non-members through a ‘discounted’ rate. It is a textbook example of a ‘loose power pool’ and must satisfy the associated regulatory strictures.”
VALLEY FORGE, Pa. — The PJM Planning Committee and Transmission Expansion Advisory Committee meetings were originally scheduled for Sept. 10 but were rescheduled to Sept. 12 and 13, respectively.
Planning Committee
Voting on CIR Transfer Proposals Deferred to October
The PC on Sept. 12 voted to defer action on three proposals to rework the RTO’s process for transferring capacity interconnection rights (CIRs) from a deactivating generator to a new resource. The committee will vote on them at its next meeting, currently scheduled for Oct. 8.
Each of the packages is aimed at creating an expedited process to shift the transmission capability underlying the CIRs of a retiring unit to support the interconnection of a new resource. Proponents of the concept say it could alleviate the need for costly reliability-must-run (RMR) contracts to keep resources online while upgrades are made to the grid to pre-empt any transmission violations prompted by removing a generator.
The vote was delayed after the committee rejected an amendment to a proposal sponsored by Elevate Renewable Energy and the East Kentucky Power Cooperative. (See “Elevate Reviews CIR Transfer Proposal,” PJM PC/TEAC Briefs: July 9, 2024.)
The amendment, proposed by MN8 Energy, would have added thermal violation analysis to the studies to be conducted on projects seeking CIR transfers and expedited interconnection. MN8 had withdrawn its own package ahead of the meeting and thrown its support behind the Elevate-EKPC coalition.
The MN8 amendment would have required thermal studies on the peak and off-peak deliverability cases, but Elevate’s Tonja Wicks said the coalition could only accept studies on the off-peak case.
The issue of thermal studies gets to the heart of whether storage resources should be eligible for CIR transfers, with PJM arguing that the capability to charge off the grid could pose “material adverse impacts” not envisioned by the original interconnection studies conducted on the deactivating generator. The PJM proposal would outright disqualify storage and open-loop hybrids, whereas both the coalition and Independent Market Monitor packages would allow all resource classes to participate.
Coalition supporters argued storage is one of the best-suited resources for replacing deactivations owing to its quick installation time, minimal footprint and minimal environmental restrictions. Alternatives like renewable generation can require too much land to be viable for replacements in urban settings, such as the retiring Brandon Shores generator outside Baltimore, and the timeline for new nuclear is too lengthy to be suitable, they said.
The material adverse impact standard would also preclude many CIR transfers to resources with a different fuel type, PJM’s Ed Franks said. Any projects requiring network upgrades would be removed from the expedited process and moved to the general interconnection queue.
Both the PJM and coalition proposals would only allow CIR transfers to resources seeking to site at the same point of interconnection (POI) as the deactivating unit. The voltage would also be required to be the same, though the interconnection could be at a different breaker.
The coalition proposal comes with a nine-month time frame for most projects to get through the expedited process, with 60 days for initial application review, 180 days for a replacement impact study looking at any potential transmission violations and 30 days for the interconnection service agreement to be approved. Projects with minor network upgrades required would take an additional 90 days.
It would also allow the transfer process to begin before an official deactivation notice has been filed with PJM, allowing discussions between market participants and the RTO’s study process to begin quicker. PJM’s proposal would require an official notice before CIRs transfers could be initiated.
Interconnection studies on expedited projects would be conducted in parallel with Phase 2 studies being conducted on the contemporaneous cluster in the transitional cycle. PJM’s proposal would also place expedited studies at the second phase of the current cluster.
Franks said moving new CIR transfer requests up to be studied with the current cluster is one of the defining features of the packages. While the status quo does allow transfers, only submissions made before the start of the transition to the cluster-based process were sorted into either Transitional Cycle 1 or 2. Later requests must wait until the end of the transitional cycle to be studied as part of TC 1, which is not scheduled to begin reviewing applications until 2026. Franks said the proposals would also result in some cost savings over the status quo even after the transition is complete.
The Monitor’s proposal would break with the concept of bilaterally transferring CIRs to instead create a PJM-administered process when a deactivation study identifies transmission violations. The RTO would evaluate projects in the queue for any that could use existing headroom to resolve the violations, prioritizing those that could do so with a balance of speed and affordability. Generation developers would also be able to propose alterations to their projects or entirely new resources to meet the need. (See “Monitor Presents CIR Transfer Proposal,” PJM PC/TEAC Briefs: Aug. 6, 2024.)
“CIRs should go back in the pool and PJM should in a parallel have an expedited process in its control to move forward with any project that can solve the reliability problem,” Monitor Joe Bowring said. He argued that the coalition proposal would grant existing generators market power through their ownership of CIRs, while the Monitor proposes that CIRs end on the date of unit retirement.
Bowring also argued that putting the transfer of headroom under PJM’s control ensures that resources receiving CIRs are oriented toward resolving the transmission violations. It would also enable projects sited at different POIs to be expedited, including those that would require network upgrades. If no project in the queue addressed the identified reliability issue, PJM would run an auction for proposals to build new generation to address the reliability issue within a defined period of time.
If no transmission violations are associated with a deactivation, the CIRs would be made available to projects in the general queue cycles according to their cluster position. The same would be true of any CIRs not allocated through the expedited process. Bowring argued that the value behind interconnection rights is derived from the sum total of transmission investments across PJM and thus should not be considered the property rights of developers who paid for network upgrades as part of a generation interconnection.
“CIRs are a network resource, are essential to FERC-mandated open access, and derive their value from all the investments made by customers and generators over a long period,” Bowring said.
The committee endorsed a set of revisions to Manual 14F: Competitive Planning Process that remove out-of-date references and update details in the document.
PJM’s Brian Lynn said the changes were identified during PJM’s Long-term Regional Transmission Planning (LTRTP) workshops but were not adopted as the overall LTRTP changes were not voted on. Stakeholder focus has shifted to revising long-term planning through PJM’s compliance filing on FERC Order 1920.
First Read on Manual 21B Revisions
PJM’s Andrew Gledhill presented the first set of proposed revisions to the newly established Manual 21B, which details the rules for capacity resource accreditation. The changes would align the definition of dual-fuel combustion turbine and combined cycle units in the manual with revised Reliability Assurance Agreement definitions accepted by FERC in July (ER24-1988).
The change allows gas generators that are capable of operating on a secondary fuel after starting on their primary fuel to qualify as dual-fuel, a change sought by Calpine earlier this year. During the earlier stakeholder process, Calpine’s David “Scarp” Scarpignato said some gas units can start on a small amount of fuel already purchased and packed into the portion of the gas pipeline on generator property, even if the regional pipeline is offline. (See “Quick Fix for Dual-fuel Classification Endorsed,” PJM MRC Briefs: April 25, 2024.)
Transmission Expansion Advisory Committee
Supplemental Projects
During the TEAC meeting Sept. 13, FirstEnergy presented a $99.1 million project to rebuild its 138-kV New Departure substation to serve a new 540-MVA customer, with a 345-kV delivery point in the ATSI transmission zone.
The three-phased project would begin with adjusting relay settings at the substation, work that is expected to be completed in March 2025, followed by the rebuilding of the 138-kV infrastructure already present at the site. It would be reconfigured as a breaker-and-a-half switching station with nine breakers. The second phase, to be completed in May 2028, also includes cutting New Departure into the 138-kV Nasa-Greenfield and Ford-Greenfield lines. The first two phases together are estimated to cost $27 million.
The $72 million third phase involves building a new 345-kV ring bus at New Departure with four breakers and two 345/138-kV transformers. The facility would be looped into the 345-kV Davis-Besse-Hayes line with two new lines. An additional six 138-kV breakers would also be added to New Departure in the third phase, which FirstEnergy envisions being complete in November 2029.
Dominion presented the TEAC with a $35 million project to construct a new Old Limb Substation serving a data center complex in Prince William County, Va. | PJM
Exelon presented a $92.1 million project to rebuild its 10-mile 230-kV Ryceville-Morgantown line in the PEPCO zone, a line that the utility said is nearing its end of life at 56 years old. The work would include replacing 55 lattice towers with steel monopoles and new conductor. The project is in the engineering phase, with a projected in-service date of April 1, 2028.
Dominion Energy presented a $35 million project to construct a new 230-kV Old Limb substation to serve new data center load in its transmission zone. The new facility would be configured with a six-breaker ring arrangement cut into the Heathcote-Gainesville and Loudoun-Youngs Branch lines. Two new 230-kV tie-lines would be constructed between Old Limb and Youngs Branch, the latter of which would have two new breakers and terminal equipment installed.
The California Public Utilities Commission on Sept. 12 approved rules requiring the state’s three large investor-owned utilities to meet stricter timelines and targets for connecting electricity customers to the grid.
“Electricity is the fuel of our future, and the utility grid must be ready to meet customer needs for energization without delay,” said CPUC President Alice Reynolds. “This decision moves us forward by improving oversight, transparency and accountability to serve the needs of EV charging stations, new housing developments, building electrification and other customer requests for service.”
The timelines are meant to expedite the process for new and upgraded electrical services, enhance utility accountability, offer greater transparency for customers and support California’s climate goals, according to a CPUC press release.
The new rules apply to Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric.
If targets are met by IOUs, maximum timelines for grid connections could be reduced up to 49% compared with current operations, increasing the speed of energization for projects reliant on electricity connections, the press release notes.
The decision implements Senate Bill 410, known as the Powering Up Californians Act, and Assembly Bill 50, both of which direct the CPUC to define reasonable average and maximum energization timelines for new or upgraded electrical loads, publish biannual reports, establish a process for reporting delays and adopt remedial actions if they are exceeded.
SB 410 addresses the time necessary to complete customer energization requests, including upgrades to the distribution system and the extension of new electric service. It requires the commission to, no later than Sept. 30, 2024, establish the average and maximum time an IOU should take to complete upgrades or establish new service, as well as a method for customers to report instances when those energization targets are met.
“The bill recognizes that to meet California’s decarbonization goals, new customers must be promptly connected to the electrical distribution system, and existing customers must have their service level upgraded in a timely manner,” the decision said.
AB 50 requires the CPUC to determine the criteria for what is considered timely energization for electric customers. It also requires “each large electrical corporation that energized less than 35% of customers with completed applications exceeding 12 months in duration by Jan. 31, 2023, to submit a report to the commission, as specified, on or before Dec. 1, 2024, demonstrating that the large electrical corporation has energized 80% of customers with applications deemed complete as of Jan. 31, 2023, as specified.”
The CPUC’s decision sets a target for an average timeline of 182 days and a maximum timeline of 357 days for energization of the commission’s Rule 15 projects, which involve distribution line extensions for IOUs. For Rule 16, which refers to service line extensions typically associated with a single customer instead of multiple customers, the target sets an average timeline of 182 days and a maximum of 335 days for energization.
Rule 29, which refers to EV infrastructure, shares the same timelines, and several other energization timing targets are set for application decisions, circuit or substation upgrades, and main panel upgrades.
“As we move further along in the energy transition, we must ensure that all customers have timely access to electric service,” said CPUC Commissioner Darcie Houck. “This decision is a positive step forward in helping to meet California’s ambitious clean energy goals while appropriately balancing customer need and affordability with utility capabilities.”
