CARMEL, Ind. — MISO is hesitant to grant a request from Michigan to give dispensations to distributed energy resources from its mandated affected studies that gauge transmission system impacts.
Michigan regulators and utilities’ recent bid to allow DERs to altogether skip out on MISO’s affected system-style studies might be shortsighted, said MISO Senior Manager of Resource Utilization Kyle Trotter.
“Generally, we are supportive of this particular issue; however, we’re not quite sold on an exemption from the whole process,” Trotter said during an Oct. 16 Planning Advisory Committee meeting.
Trotter emphasized the need for appropriate reliability assessments for DER additions. He said MISO cannot ignore DERs’ potential to affect local transmission systems and neighboring systems. Trotter said MISO needs some “touchpoint in place” to maintain visibility of DERs, continue to meet NERC reliability standards and have an idea of which interconnection points on the system are congested for its interconnection queue.
“We need to see what’s happening at those transmission-distribution interface. We need to keep visibility into what’s happening whether those DERs go through the MISO study process or not,” Trotter said.
Trotter also said MISO’s upcoming compliance with FERC Order 2222, which will allow aggregated DERs into the MISO markets, presents another reason to keep tabs on DERs.
“We would like to know about these before they show up and register for the market,” Trotter said.
Last year, MISO decided it would evaluate the need for a review of DERs when they can inject 5 MW of power at the substation level during system peak load and if they can force a 1% change in line loading. TOs screen for the 5 MW injection capability, while the RTO ascertains whether the DERs could influence a 1% line-loading change.
If the DER is shown to impact both reliability criteria, MISO issues a report that triggers its existing facilities study and could lead to network upgrades. TOs pay a $60,000 study deposit to MISO per substation that is required to be studied for DER impacts. MISO refunds any portion it doesn’t use for the studies. (See MISO Creating Means to Gauge Impacts of DER Interconnections.)
In July, Michigan utilities and the Michigan Public Service Commission asked MISO to rethink a study requirement for DERs that might influence the grid. They said MISO’s study process is burdensome, costly and limits efforts to integrate DERs on the grid. (See Michigan Utilities Call for Opt-Out on MISO DER Affected System Studies.)
Some stakeholders said MISO’s DER-affected system studies are redundant considering that MISO’s transmission owners already study DERs’ influence under transmission expansion planning and that MISO is devising a registration process for DERs that want to participate in markets.
ITC’s Ruth Kloecker agreed that MISO’s study process seems duplicative. She also said MISO’s 5 MW threshold seems too severe.
“5 MW of injection? I don’t know how that can seriously impact the transmission system,” Kloecker said.
Erik Hanser, a staffer with the Michigan Public Service Commission, asked if MISO sees a way to cut back study requirements on DERs.
Trotter said MISO would like to continue DER awareness and likely would maintain MISO’s policy of having TOs vet DER additions and notify MISO if an impact study is warranted. He said there’s a possibility DER additions could skip a “full MISO study and associated costs in some instances.”
With downed power lines and poles from hurricanes Helene and Milton still a painful memory for many, the U.S. Department of Energy on Oct. 18 announced almost $2 billion in new funding from the Infrastructure Investment and Jobs Act aimed at improving grid reliability and resilience.
The latest round of Grid Resilience and Innovation Partnerships (GRIP) awards will go to 38 projects across 42 states and the District of Columbia. The grants will be used to expand grid capacity and speed up interconnection to meet burgeoning power demand from new manufacturing and data centers, said Secretary Jennifer Granholm during an advance press call Oct. 17.
“The funding couldn’t come at a more critical time,” Granholm said. “Energy demand, as we know, is rising nationwide, and it is straining our outdated grid infrastructure, and as climate change worsens, we’re seeing more frequent and devastating storms like Helene and Milton.”
The projects selected for the GRIP awards will expand capacity on regional grids by 7.5 GW and add 300 miles of new lines and upgrade an additional 650 miles of lines with advanced conductors and other grid-enhancing technologies (GETs), according to a DOE press release.
President Joe Biden announced six of the projects ― all located in the Southeast ― during a visit to Florida on Oct. 13. The Tennessee Valley Authority (TVA) scored the largest award, $250 million, which will fund 84 “subprojects” in disadvantaged communities across eight states, adding more than 2,400 MW of capacity, according to a DOE fact sheet.
The federal dollars also will be used for the first interconnection tie — cables — allowing for power transfers between TVA and the Southwest Power Pool, providing TVA and its local utilities with an additional 800 MW of electricity.
In Florida, Gainesville Regional Utilities (GRU) is slated to receive $47.5 million for distribution grid upgrades including reconductoring, undergrounding and transformers. DOE’s project description notes that this “diverse portfolio of grid hardening and modernizing technologies and equipment will increase the grid’s intelligence and build system capacity for the adoption of clean energy, grid-edge technologies and electric vehicles.”
GRU CEO Ed Bielarski said he wants the utility to be a model “to further innovate and enhance [system] resilience and storm response, including in disadvantaged communities.”
The GRIP program includes three separate funding streams: the Grid Innovation grants, announced in August, and the just-announced GridResilience Utility and Industry grants and Smart Grid grants. Pending the election results, DOE is planning a third round of funding for 2025.
Speaking at the advance press call, John Podesta, Biden’s senior adviser on international climate policy, said the U.S. needs the grid to be “larger, stronger and more reliable. To effectively tackle the climate crisis and stay on course to reach 100% clean energy by 2035, we need to double our current transmission capacity in that time frame.”
Getting there will mean continued public and private investments, better interregional transmission planning and “cutting through red tape” to get projects sited, permitted and built, Podesta said.
Project Priorities
The IIJA provided $10.5 billion for the GRIP program, heralded as one of the largest public investments in the nation’s electric infrastructure. With the Oct. 18 announcement, $7.6 billion has been awarded.
In general, awardees must at least match the number of federal dollars, and with the current announcement, DOE said the almost $2 billion in GRIP awards would draw in an additional $2.2 billion in private investment.
Announced exactly one year ago, on Oct. 18, 2023, the first round of awards, totaling $3.46 billion, included 58 projects in 44 states. According to a senior administration official, 53 of those projects now have signed contracts with DOE. The projects announced in August are in contract negotiations, which also will begin for the latest round of awardees.
DOE officials have said repeatedly that once an awardee has a signed contract, the funds will be committed and safe from any claw-back, regardless of the outcome of the election.
Each round of GRIP awards has focused on different administration priorities. The first round leaned heavily toward projects that could improve resilience at the distribution level, had strong support from state and community officials and could move forward quickly.
Transmission projects were the top priority for the awards announced in August, with projects deploying GETs securing six of the eight awards. The largest award, $700 million, went to the North Plains Connector transmission project, a 420-mile, high-voltage direct current line running from Montana to North Dakota.
This round clearly prioritizes grid upgrades to improve resilience in areas especially vulnerable to extreme weather and to get more power online to meet rising demand. The projects are geographically diverse, with money going to red and blue states. Investor-owned utilities, municipals and electric cooperatives are on the list, as well as some technology companies.
In North Dakota, the Montana-Dakota Utilities Co. and Innovative Energy Alliance Cooperative were awarded close to $15.6 million for a project to upgrade a 54-mile segment of the state’s grid, adding new advanced conductors to expand capacity. Other upgrades include “installing software, sensors and interfaces for online weather data, allowing for dynamic line rating and quicker system response,” according to DOE.
Alabama’s Tombigbee Electric Cooperative, with about 45,000 members, is slated to receive $11.1 million for system upgrades including new storage to shave peak demand and distributed energy management and outage management systems. The project also will reconductor existing lines and install new lines.
In Florida, Chicago-based Switched Source will partner with Florida Power & Light to deploy its automated distribution power flow control technology on lines in disadvantaged communities especially vulnerable to extreme weather. The $47.7 million award could help cut outages by 10%, improve energy efficiency across the system and help integrate distributed resources, such as solar and electric vehicles.
LITTLE ROCK, Ark. — SPP stakeholders on Oct. 15 approved what one member called an “historic” transmission plan that will eclipse any previous portfolio by a factor of five.
The grid operator’s 2024 Integrated Transmission Plan’s portfolio includes 89 projects, including more than 1,900 miles of rebuilt or new EHV transmission, with a projected cost of $7.65 billion. That’s more than half the $12 billion of transmission facilities that SPP has directed, members have built or are building.
The ITP assessment cleared the Markets & Operations Policy Committee with 95% approval. It will go before SPP’s Board of Directors on Oct. 29 with passage almost guaranteed, considering stakeholders’ approval margin.
“This is a monumental day in SPP history,” Sunny Raheem, the RTO’s director of system planning, said at the MOPC. “That brings into question, is it affordable?”
Staff said their study of the plan’s two futures found benefit-to-cost ratios over 40 years of 8.9 and 8.2, about three points higher than any previous ITP assessment. They also expect the 2024 portfolio to be fully paid back within its first three years.
“We think [it’s] really needed to allow SPP to maintain a reliable system, be prepared for the changing resource mix, and, of course, load growth,” she said. “We were amazed and pleasantly surprised at the very strong levels of benefits relative to cost in this portfolio, and I think that that should make everyone feel fairly comfortable with supporting it.
“This is a large transmission portfolio for SPP, but it should not be a surprise,” McIntire added.
SPP COO Lanny Nickell said that during the MOPC’s discussion of the plan, he leaned over and asked the committee’s chair, Alan Myers, “When is the last time we had $7.6 billion of investment on the table with this kind on consensus behind it?”
“I don’t remember that. To me, that’s remarkable,” Nickell said. “It’s remarkable that the members all see value for the most part. Now, I know there are some that are concerned about certain projects, and you know the magnitude of cost associated with certain projects, but for the most part, the support for the projects that are in this portfolio is fantastic.”
The portfolio’s size is driven by rapidly increasing and electrified oil and gas load in the Southwest and the Dakotas, some population growth, and the usual wave of data centers and crypto miners. SPP said the ITP considered a “uniquely sharp increase” in load at multiple sites across the SPP footprint, compared to previous ITP assessments, and used the information to inform decisions made while crafting the portfolio.
The 2024 assessment’s Year 2 load is up 9.7% and 12.9% for the 2023 ITP’s Year 10 respective summer and winter projections. It projects a 25% increase in demand by 2030, a nearly 14 GW increase from its 2023 record peak of 55.89 GW. According to SPP’s report, “minimal load growth” has been accelerated by new customers asking to be connected to the grid as soon as possible.
“Uniquely sharp” load increases in New Mexico led to staff’s recommendation for SPP’s first 765-kV line, the Phantom-Crossroads-Potter project from the Texas Panhandle to southeastern New Mexico. Staff said the project has a $4.1 billion net adjusted production cost value beyond its $2.13 billion cost and a 3.1 benefit-to-cost ratio in Year 40.
Staff also incorporated extreme winter weather scenarios into its latest ITP after two recent storms stressed the grid with low temperatures from the Canadian border into the Texas Panhandle. The extended cold temperatures led to above-normal energy use, fuel availability issues and in 2021, the first directed load shed in SPP’s history.
SPP identified and recommended notifications-to-construct for projects to help support the system during extreme weather events.
“We’ve needed to address the resilience issue after Winter Storm Uri and Winter Storm Elliott for a couple of years,” Nickell told RTO Insider. “That has been something that needs to be addressed, and [members] recognize this does that. They not only appreciate the benefits of reducing congestion, but they also appreciate the fact that it solves the reliability and resilience needs that we needed to address.”
Stressing that he was not speaking for all members, Nickell said the $7.65 price tag was a “secondary component” because of the ITP’s huge value to the SPP grid.
Mike Wise, Golden Spread Electric Cooperative’s senior vice president of regulatory and market strategy, complimented SPP for using “decision quality” concepts and including it in the assessment’s analysis.
“I can’t stand in the way of what the analysis has shown here, but I do think SPP has done a good job,” he said.
Wise told RTO Insider that according to a back-of-the-envelope calculation and under certain conditions, the ITP could cost Golden Spread’s members more than $1 billion in additional transmission costs over the next 40 years. He attributed the lack of discussion over the costs to transmission users not understanding the ITP assessment’s assumptions.
“These are 40-year investments,” he said. “Who bears the risk if the load doesn’t come?”
SPP’s ITP still pales in comparison with MISO’s first two long-range transmission plan (LRTP) portfolios, which have a combined cost of nearly $32 billion. MISO is advancing the LRTP package for its board’s approval at the end of the year. (See MISO Affirms Commitment to $21.8B Long-range Tx Plan in Final Workshops.)
The commission also granted a request by NERC and WECC to fund the Western Transmission Expansion Coalition’s (WestTEC) transmission planning study over the next two years by releasing $2.2 million in total from the Peak Reliability Donation Reserve and approved the REs’ use of penalties to grow its financial reserves and reduce its 2025 assessments.
The ERO submitted the budgets to the commission following their acceptance by the ERO’s Board of Trustees at its August meeting in Vancouver. (See “Budgets Headed to FERC,” NERC Board of Trustees/MRC Briefs: Aug. 15, 2024.) NERC CFO Andy Sharp said at the meeting that the final budgets are “materially consistent” with NERC’s three-year projection.
NERC’s 2025 budget is set to rise 8.2% over the previous year to $123 million, according to the ERO’s August filing. Drivers of the increase include an expected need to hire 13 new employees in reliability standards development, enforcement, the Electricity Information Sharing and Analysis Center, and other areas; investments in the ERO’s technology strategy; and planned increases in meetings and travel costs. The E-ISAC’s budget is also set to grow from $41.1 million to $43.8 million.
The budgets for the REs and WIRAB are set to grow as follows:
Midwest Reliability Organization — from $24.9 million to $26.8 million
Northeast Power Coordinating Council — $22.1 million to $25.7 million
ReliabilityFirst — $31.3 million to $33.4 million
SERC Reliability — $32 million to $35.4 million
Texas Reliability Entity — $19.2 million to $20.3 million
Western Electricity Coordinating Council — $35.4 million to $39.3 million
WIRAB — $831,492 to $831,561
The ERO’s total assessment for 2025 is to rise to $270.9 million, up from $241.4 million in 2024. This includes $108.4 million for NERC and $128.3 million in combined assessments for the REs and WIRAB.
WECC and NERC’s requested funding for the WestTEC project will see progressive releases from the funds donated by Peak Reliability upon its dissolution in 2019, with $500,000 released in 2024, $1.5 million in 2025, and $200,000 in 2026. The WestTEC study is to take place over the next two years and is intended to produce transmission portfolios for 10- and 20-year planning horizons. (See WestTEC Seeks to Close $2.1M Funding Gap Despite DOE Boost.)
NERC said the withdrawals will leave a balance of just over $1 million in the Peak Reserve.
Commissioner Judy Chang spoke approvingly about the project at this week’s meeting, calling WestTEC “a collaborative, voluntary interregional planning initiative” that will help meet the long-term needs of the Western Interconnection.
“The Western markets [have been] evolving over the last few years and will continue to evolve in the future … [WestTEC] is very valuable, and I think it’s a good use of Peak Reliability funds to support reliability across the West,” Chang said. “I look forward to seeing the results of those efforts, which [are] also being supported by funds from the Department of Energy.”
First-quarter electricity prices in CAISO markets were down sharply from the same period in 2023, despite sharp spikes during the January cold snap in the Pacific Northwest, the ISO’s Department of Market Monitoring said Oct. 17.
January’s extreme weather events were the “major story for the wholesale electricity markets in the first quarter of 2024,” Ryan Kurlinski, a DMM senior manager, said during a market issues and performance meeting covering Q1.
The winter event saw Pacific Northwest and Intermountain West balancing authority areas hit an average of about $150/MWh in the Western Energy Imbalance Market (WEIM), compared with $65/MWh in other BAs in the market. As a result, transfer capacity in the WEIM was frequently constrained, preventing lower-priced marginal energy in southern areas from setting lower prices in the north, the DMM found.
Lower natural gas prices across the WEIM compared with Q1 2023 drove decreases in average electricity prices, despite the cold weather events. Prices at both California natural gas trading hubs decreased by more than 60% compared with 2023, helping undercut average power prices by 53%.
“In Q1 of 2024, after we get past the severe cold weather event up in the Pacific Northwest and into mid- and late January, prices significantly drop across the WEIM,” Kurlinski said. “Even with the severe cold weather event, high January prices in the Pacific Northwest and Intermountain West were about 20% lower in Q1 2024 on average compared to Q1 in 2023.”
Congestion and price separation between the Pacific Northwest and other BAAs continued into February and March, though prices were still lower than the previous year.
Congestion played a large role in market impacts during the January cold snap. Historically, congestion rent in the CAISO BA has been in the import direction over the interties, but Q1 saw a “huge spike” in export congestion rent over the ISO’s intertie constraints, symbolizing another one of the “most interesting and major stories of Q1 2024,” Kurlinski said.
“In Q1 2024, intertie congestion rent exploded to $133 million [from $13 million a year earlier]. $130 million of that was in the export direction,” most of which was on the Malin intertie in January, Kurlinski added.
Congestion rent on internal constraints in the CAISO BA in the day-ahead market decreased from $265 million in Q1 2023 to $125 million in 2024.
Additionally, transmission ratepayers lost around $53 million in congestion revenue rent auctions, up from $30 million in Q1 2023.
Kurlinski also noted that real-time balance offset costs in the CAISO area were $51 million in Q1 2024, down from $90 million in 2023. The primary driver of the uplift is load getting paid a different real-time price than generation.
Bid cost recovery (BCR) payments were also down to $41.5 million from $80.3 million in Q1 2023, largely due to a decrease in the residual unit commitment portion of BCR.
NEW SCOTLAND, N.Y. — Small-scale solar arrays in New York have surpassed 6 GW of capacity, meeting a milestone 2025 goal more than a year early.
It’s a bright spot in a state whose energy transition has been progressing more slowly than hoped.
Leaders of the transition and some of those helping to carry it out gathered at a new 5.7 MW solar farm Oct. 17 to celebrate the occasion and advocate for the addition of many more megawatts to follow.
The site itself is easy enough to reach, a smooth ride on main roads to the town of New Scotland, not far from the state offices where renewable energy policy is written, regulated and facilitated.
But the journey to reach the milestone achieved on this site was much longer: 235,803 distributed solar projects of every stripe had to be completed in every corner of the state before this one could push the combined nameplate capacity above 6 GW.
An uncounted additional number of projects dropped out of the pipeline along the way, just as utility-scale projects have seen high rates of contract cancellation in New York.
So why is distributed solar exceeding expectations by adding emissions-free capacity to the grid a few dozen kilowatts at a time? While multi-megawatt projects are lagging so badly the state is likely to miss a key 2030 renewables target codified in its climate law?
State support has allowed an ecosystem supporting distributed solar to grow to scale in New York, said Doreen Harris, president of the New York State Energy Research and Development Authority, one of the main architects and managers of the state’s energy transition.
These same policies send clear market signals that small solar is wanted and will be supported. In a telling indicator, New York — an expensive state with limited sunshine — is the nation’s leader in installed community solar capacity.
Smaller projects are nimbler, said Noah Ginsburg, executive director of the New York Solar Energy Industries Association. They face the same obstacles as large projects, with endless variations across hundreds of local permitting entities, but they can move and adjust quickly enough to not die on the vine.
“The timeline for getting a [distributed] project from idea to up and running, we’re talking three years,” he said. “You can navigate choppy waters and get projects over the finish line on that kind of timeline. And I just think New York has developed a really successful model.”
The 6 GW emerged with steady assistance from the state, including the $3.3 billion NY SUN initiative. The state estimates an additional $9.2 billion in private-sector investment has been a result.
The New Scotland project checks another box on the state’s list of priorities: It is one of the first community solar farms to participate in the Solar for All program. The savings achieved through its operation will be funneled to low-income ratepayers.
Moving Forward
Officials and guests at the ceremony spoke afterward to NetZero Insider about what went into reaching the 6 GW milestone and what comes next.
David Sandbank, NYSERDA’s vice president of distributed energy resources and transportation, said the state categorizes distributed solar as everything from residential rooftop arrays producing a few kilowatts on their best day to several-acre arrays rated at several megawatts, like the new one in New Scotland.
The cutoff is 5 MW for projects quantified in alternating current and a little more than 7 MW for those quantified in direct current.
“So if you talk in DC … I’d say the average home project is about 7 KW in this state. So 7 KW to 7 MW,” Sandbank said.
The next milepost is 10 GW of distributed solar by 2030. NYSEIA earlier this year called for kicking that up to 20 GW by 2035.
Distributed solar is a mainstay of NYSEIA’s 235 member companies, and obviously a priority for Ginsburg, but he says renewables are needed at every scale.
“My view on it is that for the state to hit its clean-energy goals, we need to accelerate utility-scale deployment,” he said.
The problem, Ginsburg said, is that some people overlook the contributions of small solar as they focus on major projects that would provide dozens or hundreds of megawatts.
“So, I try to remind people, 93% of the solar that’s up and running in New York is distributed scale; 6 GW is nothing to sneeze at,” he said.
Rory Christian, chair of the state Public Service Commission, said this fact is not lost on policymakers. It also is clear that 6 or 10 or 20 GW of solar does not by itself allow fossil-fuel generation to be retired — solar’s capacity factor is too low in New York, particularly during the short and often cloudy winter days.
There are simultaneous efforts to develop other forms of emissions-free generation and storage to backstop intermittent solar and wind; to anticipate transmission and distribution needs and address them proactively; and to begin managing the other side of the equation — demand.
So while 6 GW of distributed solar is an achievement to be celebrated, it is a mile marker rather than a finish line, a piece of a strategy that still is being planned out.
“We know there’s a gap. It’s documented in the [state climate law]. We are working to address that gap, and we recognize that we need to do more, and so we have the plans in place to do more, and we’re figuring that out as we go,” Christian said.
“What are those dispatchable emissions-free resources? What will those be? How will those function? Where do we put them? We’re looking at that right now.”
Electric utilities are working on their part of the equation.
The new solar farm sits near a National Grid substation and almost beneath some of its transmission lines.
That proximity helps with development, but there are many other factors that go into siting and system planning, said Brian Gemmell, National Grid’s chief operating officer for electric. “It’s all about making [sure] that the reliability is there, the resilience, the infrastructure is appropriately sized for the project.”
The utility is investing billions of dollars in dozens of projects to make its upstate New York network ready for more renewables expected to be built there.
Hurdles to Clear
Dan Berwick, CEO of New Leaf Energy, the New Scotland project developer, said solar development is not an easy proposition in New York. Permitting is hard, interconnection is harder, costs are higher than in other states and profits are lower. But New Leaf keeps at it, he added, and now has nearly 200 projects in development statewide.
State leadership is committed to making renewable development happen, and that makes it possible to clear those hurdles.
“We keep investing, even though it’s tough, because New York has a unique winning formula. New York’s political leadership sets big, clear, bold goals, and then NYSERDA and the Department of Public Service execute on those goals,” Berwick said.
“No other state has a NYSERDA, and that is why there’s no other state where we will develop projects and make substantial investments in projects based only on what a state government says it will do, as opposed to what it has already done. That’s unique, and it’s very powerful.”
The area is a blend of suburban and rural, light industrial sites and homes mixing with fields and woods. It is a quick drive from the state Capitol, yet far enough removed from the city that some people expect to see trees and distant hills rather than solar panels. A nearby apple orchard is a longstanding agritourism destination.
New Scotland Town Supervisor Douglas LaGrange spoke about the balance struck as the project moved through its yearslong development and review.
New Scotland is one of New York’s Climate Smart Communities, he said, and wants to do its part to advance climate protection goals.
“It started years ago when … we saw the opportunity to bring solar into the town and accommodate it, but we wanted to balance it with the beauty of the town,” LaGrange said. “It’s a beautiful area. And there are those that might suggest that solar arrays aren’t the prettiest things in the world, but we came to a point where we could balance both.”
He added: “This is a perfect example of that all coming together.”
Steven and Wendy Burke have owned the 27-acre site for more than 20 years but never developed it themselves. A local farmer cut hay from the portion that was not wooded.
The couple support renewable energy development; she drives an electric vehicle. When they decided to lease their land for solar development, they got some friction from a few neighbors, but it was less about the panels than the effect of the panels.
“There was a couple neighbors that had [objected] in the beginning, not knowing what it was going to look like,” he said.
“Or had questions and how things were going to be done,” she continued, “and wanted to make sure that it wasn’t going to be unsightly, that there was going to be proper screening, that it was going to be maintained properly, which were valid questions, and the town was able to answer those questions.”
One of the more frequent questions, the Burkes and LaGrange both said, was whether the array would be visible from the landmark Thacher Park overlook atop a 700-foot escarpment two miles away.
It is not, thanks to the contour of the hill. And the line of mature trees at the solar farm’s perimeter blocks passing motorists’ view of the panels, save for a gap the driveway runs through.
A line of saplings transplanted inside will close that gap in a few years.
Ginsburg said this is a winning approach.
“I think the reality is that as a species, we are resistant to change, but ultimately we need clean energy in our state,” he said. “Projects like this can be built in a way that’s aesthetic and that’s beneficial.”
ATLANTIC CITY, N.J. — States can reap long-term savings by upgrading their onshore grids and coordinating transmission development to serve multiple offshore wind projects, but they’ll also face higher upfront costs, supply chain challenges and ratepayer concerns, speakers at a New Jersey conference said Oct. 11.
Planned and coordinated transmission upgrades could save billions of dollars across the OSW sector, but the complexity and extensive planning needed to bring different stakeholders and states together to craft solutions could take more than a decade, speakers at the Time for Turbines 7 conference in Atlantic City said.
New Jersey’s use of the State Agreement Approach (SAA) to create $1.07 billion in transmission upgrades that can deliver 6,400 MW of OSW generation to the PJM grid is a prime example of the benefits of planning, speakers told conference attendees.
Yet time is of the essence for all states, according to Abraham Silverman, assistant research scholar with the Ralph O’Connor Sustainable Energy Institute at Johns Hopkins University. The global market for transmission equipment is competitive, and developers need to line up their supply chain now to ensure equipment is available years ahead of when it’s needed, Silverman told the 150 developers, government officials, environmentalists and other stakeholders at the conference.
Abe Silverman, Johns Hopkins University | Christian Fiore
“States are making procurement decisions today that are going to be delivered in the early 2030s,” he said. “2030 is today.
“So if you are going out and buying it, [and] thinking about offshore wind, you need to have all the major questions answered” around what’s being built, voltage levels and suppliers, Silverman said. “And I think, frankly, a lot of us see what happens when developers don’t have their supply arrangements totally locked up, and we end up in real problems, and you get delays.”
Projects in Germany and Scotland are “going ahead and procuring their HVDC equipment and stockpiling it for future use,” said Janice Fuller, former Mid-Atlantic president at Anbaric, which specializes in developing transmission for OSW projects.
“The projects aren’t awarded, but they’re buying [the equipment], and they will have it ready,” Fuller said. “So that also puts us a little bit further behind in that global supply chain.”
Planning Initiatives
Procurement is just one challenge conference speakers said is facing New Jersey and other states as they try to prepare their grids for the 60% increase in transmission capacity needed to bring about widespread electrification, according to Princeton University’s 2021 Net-Zero America report.
The New Jersey Board of Public Utilities (BPU) says ratepayers will save $900 million from its project to upgrade onshore transmission infrastructure to link OSW projects to the grid. The BPU and PJM created the project under the SAA, and the BPU in February sought FERC approval to use the SAA in a second solicitation but later put that plan on hold.
“Essentially, what we are trying to do is avoid a bunch of individual onshoring efforts and to minimize environmental impacts, minimize community impacts, minimize project risk and risks of delays that may come from a bunch of one-offs coming in,” said BPU Executive Director Robert Brabston.
The order requires RTOs and ISOs to undertake long-term transmission planning — with a 20-year time frame, taking into account anticipated load growth, state laws and generation retirements. The plans must be updated every five years.
Brabston said New Jersey can benefit from Order 1920’s planning requirements by addressing the “vastly different networks in the state.” These range from the well-developed infrastructure in the north to areas in the south that were “built to cobble together the agricultural part of the state and the population centers.” While southern areas have the space to house data centers and grid-scale solar projects, the grid there “wasn’t built for it, it’s not ready for it,” he said.
“So we need to be able to do things like pursue grid-enhancing technologies, because you can’t just build all new pipes and wires for infrastructure,” he said. “If you’re going to modernize utilities, you’ve got to modernize the utilities. It’s not just new wires. It’s reconductoring. It’s all kinds of other stuff.”
That means “getting this project selection criteria updated so it takes more factors into account and is more transparent,” he said.
Collaborative Strategy
Long-term planning was also central to New Jersey and nine other East Coast states in July establishing the Northeast States Collaborative on Interregional Transmission to explore mutually beneficial interregional transmission to increase the flow of electricity among ISO-NE, NYISO and PJM, as well as assessing offshore wind infrastructure needs. (See 10 Northeastern States Sign MOU on Interregional Transmission Planning.)
“The theory is, if it saves $900 million when New Jersey does it alone, how much is it going to save when we work with Maryland, New Jersey and Delaware, or New York and New England and all the other places?” asked Silverman, who helped put together the coalition. He noted New York had also studied the benefits of creating an “offshore wind backbone” similar to New Jersey’s and found it would save ratepayers $500 million.
Silverman said it’s not just about the savings, but also improved reliability, faster interconnection times and “derisking” of projects “so that when we ask developers to put billions of dollars of capital at risk, they really feel comfortable coming to that table.”
“We’ve seen success within individual states or even on a regional basis, like New England. But we also need to get states talking to each other and cross over some of these artificial barriers.”
Cost Allocation Straitjacket
However, that kind of collaboration raises questions about technology standardization, Fuller said.
As generators bid their projects and suppliers try to determine how to prepare for projects that won’t break ground —or water — for another decade, it’s crucial for both sides to agree on uniform standard for the technology being used, she said.
“That plays into your ability to have mesh-ready projects, projects that could be brought together in the future and connected together,” she said.
Janice Fuller, former president, Mid-Atlantic, Anbaric | Christian Fiore
Another ongoing issue is who pays for the projects, Brabston said.
“One of the key things from a New Jersey perspective is trying to get out of this straitjacket of: If it’s a state policy thing, the state has to pay 100% by itself,” he said, which fails to account for the fact that “all states stand to benefit from this to a greater or lesser extent. We should be talking about cost allocation, not an all-or-nothing kind of thing,” he said.
Fuller called the New Jersey initiative the “canary in the coal mine” for other states and stakeholders, particularly because it received 80 bids from 13 developers. (See NJ BPU OKs $1.07B OSW Transmission Expansion.)
“I think the industry stood up, and other states stood up, and said, ‘Oh, that’s real. They got a real robust response with really creative solutions, and it’s going to have a tremendous ratepayer impact,’” she said.
One challenge is communicating the benefits to the public, Fuller said. She said renewable development often prompts skeptics to say, “Why do we need to do this? It’s going to impact our electric bills, and the ratepayers aren’t going to be able to tolerate that.”
But infrastructure upgrades can produce multiple benefits, including realizing substantial savings for consumers and reducing the number of cables and beach crossings needed, she said.
Fuller suggested using the phrase “benefit allocation” to make projects more palatable to the public.
“We always talk about cost allocation,” she said, but changing the term could show “it’s not just fair sharing of the cost, it’s understanding where the benefit lies, and so you’re paying your share of the benefit.”
ISO-NE is not planning to pursue development of simultaneously clearing seasonal capacity auctions as part of its capacity auction reform (CAR) project, Chris Geissler of ISO-NE told the NEPOOL Markets Committee (MC) on Oct. 16, updating stakeholders on the RTO’s most recent plans for its multiyear effort to overhaul its capacity market.
The CAR project encompasses ISO-NE’s ongoing work to improve resource capacity accreditation, reduce the time between auction and capacity commitment periods (CCPs), and split the annual CCPs into distinct seasons. The RTO aims to complete the project in time for the 2028/2029 CCP (CCP 19) and has delayed its next forward capacity auction for three years to develop the reforms. (See FERC Approves Additional Delay of ISO-NE FCA 19.)
ISO-NE previously had floated the possibility of simultaneously running the seasonal auctions for each year to enable generators to account for fixed annual costs and submit bids that are contingent on clearing in both seasons.
However, Geissler said the RTO is concerned that developing a simultaneous auction design could jeopardize the timeline of the CAR project.
“The time and resources needed to pursue such a design would take away from other parts of CAR, including the RAA modeling and accreditation efforts,” Geissler said, adding the RTO has “concluded that the risks of pursuing this approach for CCP 19 outweighed the benefits.”
Power generators and consumer groups have pushed for a simultaneously clearing seasonal auction, arguing that the design could reduce risks for generators and overall costs for consumers.
In comments submitted to ISO-NE in the summer, Calpine wrote it has “grave concerns” with a seasonal auction that does not account for generators’ annual costs, adding that “simultaneously clearing seasonal auctions, with offers for each season and the entire commitment period, must be in [the] CAR scope.”
Geissler said ISO-NE will consider developing a simultaneous seasonal auction design after the CAR project is complete.
ISO-NE is also not planning to include in the project a focus on correlated outages and resource start times, or reforms to how the capacity market treats retained resources, although the RTO may consider these aspects for development after CCP 19.
Modeling resource start times in the resource accreditation process has been a priority for some storage developers, but ISO-NE found “it is not feasible to consider resource start times for CCP 19 due to technical limitations,” Geissler said.
ISO-NE similarly determined it is infeasible to model correlated outages, citing data availability challenges and the limitations of the RTO’s resource adequacy modeling platform. Geissler noted that ISO-NE’s proposed approach to accounting for the region’s gas constraints will account for correlated outages stemming from limited gas availability.
While New England gas generators often struggle with fuel availability during cold days, outages due to extreme cold weather also pose a significant reliability risk. On Christmas Eve in 2022, resource outages during the evening peak triggered a capacity shortfall event, and ISO-NE said the outages “were caused by cold temperatures or mechanical problems, and not due to inadequate fuel supplies.”
Geissler also provided additional information on how the reformed capacity market will treat resources that are retained due to local transmission security concerns. He said resources operating under reliability-must-run contracts “are expected to offer into the day-ahead and real-time energy markets in a manner similar to other capacity resources” and “are economically committed and dispatched based on their energy supply offers.”
In an Oct. 9 memo, ISO-NE said it is not planning to change its current approach to pricing retained resources at $0 in the capacity supply curve.
Geissler noted that if ISO-NE finds a future need for resource retentions for energy security reasons, it “commits to simultaneously assessing and including a different pricing mechanism for stakeholder consideration.”
CAR Schedule
ISO-NE said it is planning to begin discussions with stakeholders on the detailed design of the prompt market and resource retirement reforms in early 2025, with the intention of filing this portion of the reforms in late 2025.
The RTO is planning to begin discussions on resource accreditation and the seasonal market design in late 2025 after the first phase of the project is complete.
Geissler emphasized that both filings will need to stand on their own given the uncertainty of FERC’s response.
The committee referred to the NEPOOL Generation Information System (GIS) Operating Rules Working Group a request from the Massachusetts Department of Energy Resources to update the GIS to include information “regarding when a facility became eligible under Massachusetts clean, alternative and renewable energy standards.”
Despite last week’s acceptance of PRC-029-1 (Frequency and voltage ride-through requirements for inverter-based resources) by NERC’s Board of Trustees, the ERO isn’t quite finished with the ride-through protection standard, the organization’s Director of Standards Development Jamie Calderon told NERC’s Standards Committee.
The board approved the new standard in a special meeting Oct. 8 after it passed its final industry ballot with a weighted segment average of 77.48%, following a sometimes-rocky development process that saw the board exercise its authority to bypass parts of the stakeholder approval process to meet FERC’s deadline for the standard. (See NERC Examining Lessons from IBR Standard Development.)
Calderon explained to the SC’s monthly conference call Oct. 16 that NERC staff had identified “some minor errata” in the standard and its implementation plan after they were submitted to the board, necessitating a few small wording updates:
changing the word “manufacture” to “manufacturer” in PRC-029-1
adding an effective date for the definition of “ride-through” in the implementation plan
removing the term “voltage” from the description of IBRs that cannot meet ride-through requirements in the implementation plan
The errata passed the committee’s vote unanimously. No further industry comment or ballot is necessary; the corrected version will be filed with FERC in the petition for approval of PRC-029-1.
Claudine Fritz of Exelon, noting the “rushed” development of the final standard, asked that NERC make sure to reserve time in the future for proofreading so such errors can be caught and corrected before board approval. Chair Todd Bennett of Associated Electric Cooperative explained that the ERO is conducting an internal effort to identify lessons learned from the development of PRC-029-1 and other IBR-related standards, as NERC Vice President of Engineering and Standards Soo Jin Kim previously told the board.
More Standards Actions
Other actions approved by the SC this week include authorizing the posting of proposed standard EOP-012-3 (Extreme cold weather preparedness and operations) for a formal comment and ballot period. The comment period began Oct. 17, along with the opening of ballot pools. Voting will open Oct. 31 and close Nov. 5 along with the comment period.
This is NERC’s second time revising its cold weather standard in response to a FERC order. The commission accepted EOP-012-1 in 2023 but ordered revisions to be completed by this year. Those revisions resulted in EOP-012-2, which FERC accepted in June, with an order of additional changes to be completed by March 2025. (See FERC Orders Further Cold Weather Standard Modifications.)
The new standard is intended to address shortcomings identified by FERC in its predecessor, which include ensuring entities can understand the generator cold weather constraint criteria, allowing NERC to confirm the validity of cold weather constraints and clarifying implementation deadlines for corrective action plans.
NERC Manager of Standards Development Alison Oswald said the team is pursuing a shortened comment and ballot period — 20 days rather than the usual 45 — to improve its chances of meeting FERC’s deadline. At least two more ballots are planned after this.
In addition, the committee authorized appointing 12 members, including chair and vice chair, to the standard drafting team for Project 2024-02 (Planning energy assurance).
This is one of two teams working on this project, which is intended to create requirements for performing energy reliability assessments. The team approved at this week’s meeting will address assessments for the planning time horizon, while another team tackles assessments on the operational planning time horizon.
Elections on the Horizon
With 10 committee members’ terms expiring at the end of the year and one member resigning, the SC will hold elections to select their replacements in December.
Those with expiring terms are:
Amy Casuscelli, Xcel Energy (Segment 1)
Charles Yeung, Southwest Power Pool (Segment 2)
Vicki O’Leary, Eversource Energy (Segment 3)
Patti Metro, National Rural Electric Cooperative Association (Segment 4)
Jim Howell, Treaty Oak Clean Energy (Segment 5)
Justin Welty, NextEra Energy (Segment 6)
Venona Greaff, Occidental Chemical (Segment 7)
Philip Winston, independent (Segment 8)
William Chambliss, Virginia State Corporation Commission (Segment 9)
Steve Rueckert, WECC (Segment 10)
In addition, Peter Yost of Con Edison, whose term representing Segment 6 was to have expired at the end of 2025, has stepped down from the SC due to retirement, said Bennett, of Associated Electric Cooperative.
Nominations will be accepted from Oct. 21 to Nov. 12, NERC Standards Developer Dominique Love said, with the election held from Dec. 4-13. For Segment 6, the recipient of the most votes will serve the full two-year term, while the runner-up will serve out the remainder of Yost’s term.
FERC continues to fiddle with the return on equity MISO transmission owners can earn, this time setting the base amount at 9.98% while once again eradicating the risk premium model from the calculation.
The Oct. 17 order is the latest in a yearslong string of adjustments to the MISO TOs’ ROE and might represent a step closer to settling the more-than-decade-old debate over which rate inputs are appropriate (EL14-12, et al.).
FERC said when examining the case, it found no evidence that investors use the risk premium model, a conclusion it came to once before in 2019. The commission insisted it made “a principled and reasoned decision supported by the evidentiary record.”
By ousting the risk premium model, FERC again is down to relying on two models — the discounted cash flow (DCF) and the capital asset pricing (CAPM) — to establish a zone of reasonableness and set the ROE at its midpoint. FERC said the new zone of reasonableness is between 7.39 and 12.58%.
FERC ordered MISO TOs to adopt the 9.98% base ROE effective near the end of September 2016 and provide refunds to customers with interest for a 15-month refund period beginning with the date of the initial complaint Nov. 12, 2013.
The commission has tinkered with and set an assortment of ROEs for MISO TOs in recent years: In 2013, it was using a 12.38% rate; after the complaint from MISO transmission customers, it landed on a 10.32% rate in 2016, which was reduced to 9.88% in 2019 and then upped to 10.02% in 2020. FERC said in the latest order that it continued to find the circa-2013, 12.38% base ROE excessive.
FERC has cut the risk premium input once before, when it set the 9.88% base ROE, then changed course when it established the new ROE in 2020 under a Republican majority of commissioners. When formulating an ROE for the privately held MISO TOs, the commission attempts to formulate their stock price as if they were publicly traded. The risk premium model tries to emulate the cost of equity using the premium that investors would expect to earn on a stock investment over the return they would expect to earn on a bond investment.
FERC found the ROE case back on its docket because of the risk premium model’s inclusion since 2020. The D.C. Circuit Court of Appeals in 2022 vacated FERC’s 10.02% value. The court said it didn’t understand why FERC would spend pages describing the risk premium model’s shortcomings, circular nature and scarce use only to reinstate its application in 2020. (See DC Circuit Sends FERC Back to Drawing Board on MISO ROE.)
FERC left the other two models alone and continued to find a DCF zone of reasonableness at 6.97 to 12.07%, and the CAPM’s range is 7.80 to 13.09%.
While this time FERC said no further changes to the ROE methodology are necessary, it left the door open to including the risk premium model once again if parties can show that potential benefits outweigh concerns with the model.
The commission said it understood that cutting the risk premium model reduces the “diversity of inputs” and increases the weighting for the CAPM and DCF model. FERC said it could be open to using “a blended historical and forward-looking risk premium in the CAPM in future proceedings as a potential means to mitigate volatility concerns with the commission’s ROE methodology.”
