ERO officials urged state policymakers in a webinar to work with their utilities and regional entities to understand the reliability challenges and opportunities presented by the transition to renewable energy resources.
The May 29 webinar was hosted by Midwest Reliability Organization CEO Sara Patrick, with participation by NERC, ReliabilityFirst and SERC Reliability, with the goal of giving state regulators a clearer picture of how grid reliability has been affected by the deployment of inverter-based resources (IBRs) such as wind, solar and battery facilities.
Howard Gugel, NERC’s vice president of regulatory oversight, emphasized that “education is key” and recommended the regulatory community learn “as much as [they] can about these resources, how they’re going to be interconnected and integrated … and how your state policy can help influence” the reliability impact to end users.
Gugel pointed out that summer peak demand in North America increased by 3% between 2012 and 2022, according to NERC’s analysis, while peak capacity decreased by 4%. In addition, wind, solar and batteries grew as a share of generation from 2.9% in 2012 to 9% in 2022, while the share comprising coal and oil shrank from 34.2% to 22%.
The growth of IBRs and retirement of traditional generation has significant implications for reliability, Gugel explained. During a “wind drought” last year in ERCOT, SPP and MISO, installed wind generation with a total capacity of 60 GW generated only 300 MW at some points, he said. With demand likely to continue growing, especially in areas where transportation and heating are transitioning quickly to electricity, Gugel said policymakers need to understand the implications of renewable energy mandates.
“At this point, we’re retiring generation faster than we’re putting it on. And there’s going to be a point at which there’s not going to be excess energy available there,” Gugel said. “And so we’ve [all] got to work together to ensure that we’re getting adequate capacity and energy installed in the system to meet the needs of our customers and to keep those lights on at all times.”
The task is not as simple as replacing retired baseload generation with equivalent solar or wind capacity, Gugel added, presenting a simple example of 100 MW of baseload. Assuming the sun shines for eight hours, to replace this generation, a utility must provide 100 MW of solar capacity, 400 MW of batteries to discharge at the same rate during the night and an additional 200 MW of solar just to charge the batteries for eight hours.
Gugel reiterated that NERC is doing its part to address IBR-related reliability concerns, citing the ERO’s work on developing registration criteria for the new resources and reliability standards to address their performance concerns. (See NERC Says IBR Work Proceeding as Planned.) Other presenters pointed out that IBRs also can be assets for reliability, noting their responsiveness compared to traditional generation.
Asked by Patrick about the cost of complying with the new standards, Gugel acknowledged states must recognize this potential burden but should not let it stop them from implementing the policies to safeguard the grid for the future.
“There’s going to be a cost for compliance with any type of regulation [that] will be rolled into [electric] rates,” Gugel said. “I don’t expect that to be substantial, but I’m not going to sit here and say that it’s not going to cost anything. But frankly, all existing generation has a cost for compliance. … So there will be somewhat of a cost for this, but it’s small, based on the reliability benefit that we’re going to receive from it.”
A recent study from the U.S. Department of Energy finds that managed charging ― that is, shifting the time electric vehicles charge to off-peak hours ― could be critical to controlling the costs of building charging networks and local electric distribution systems needed to power them.
By 2032, those rules could put an extra 3.9 million plug-in EVs of all classes on the road in those states ― bringing the cross-state total to 20 million EVs ― along with 2.3 million additional EV chargers. But, the study finds, managed charging could halve the number of new substations needed and cut additional grid investments by $700 million.
The study provides even more granular figures, based on a unique “bottom-up” methodology developed by Kevala, a grid analysis firm, which partnered with the National Renewable Energy Laboratory and the Lawrence Berkeley National Laboratory on the project. Drilling down to the parcel level, researchers were able to model the kinds of chargers that might be installed on individual feeders between 2027 and 2032.
Again, managed charging could cut the number of extra feeder lines needed ― to carry power from substations to end users ― from 125 to 75, and the number of additional service transformers needed from 30,000 to 21,000.
As defined in the study, managed charging not only shifts the time when charging occurs, but also minimizes its speed “such that the session is completed just prior to [an EV’s] departure from that location.”
The study also notes that managed charging programs are best suited to home and commercial depot locations, where EVs are parked on a regular schedule and therefore “are considered most likely to have margins for adjusting charging speed without negatively impacting vehicle availability.”
The resulting reductions in peak demand could be significant. Rather than demand spiking in the late afternoon or early evening, when EV owners arrive home and plug in their cars to recharge, managed charging could keep demand curves relatively flat, with some variation throughout day.
While the study is limited only to the effects of EV power demand and managed charging on distribution systems, the flexibility provided could have even broader system benefits when combined with other distributed energy resources on a feeder, said Troy Hodges, a data science manager with Kevala.
“One last benefit of doing this at the parcel level is not only do we know which vehicles are on those feeders, but we also have … simulated the non-EV loads on the feeders,” Hodges said during a May 22 webinar on the report. “So, from there, we can start modeling a managed charging technique that is more responsive to the dynamic needs of particular equipment on the grid.”
In one model scenario incorporating non-EV loads, the study found “further distribution cost savings, particularly on high-EV-penetration feeders,” Hodges said. In one example in California, managed charging incorporating non-EV loads cut peak demand by an additional 25%, he said.
Flattening the duck: The DOE study also looks at the impact of managed charging on California’s famous duck curve. | DOE
“It really drove home the value on these high-penetration EV residential areas or commercial areas with fleet depots,” Hodges said. “This type of more advanced, active control approach could really have a big impact.”
First Time, Every Time
Distribution grid planning has emerged as a vital part of EV charger installation, with lack of capacity on local systems slowing the deployment of chargers along the nation’s highways. Funded with $5 billion from the Infrastructure Investment and Jobs Act, the National Electric Vehicle Infrastructure (NEVI) program was created to help build out a network of 500,000 direct current (DC) fast chargers on major routes by 2030, but to date has installed eight stations with a total of 33 charging ports in six states.
In its most recent NEVI update, the Joint Office of Energy and Transportation estimated the U.S. now has more than 183,000 public charging ports, but fewer than a quarter of those — 41,065 — are DC fast chargers. In addition, 9,472 public chargers, both Level 2 (L2) and DC fast chargers, are classified as “temporarily unavailable” — that is, not working.
Depending on the EV and capacity of the chargers (NEVI-funded chargers must be at least 150 kW), DC fast chargers can recharge a battery to 80% capacity in 20 to 60 minutes. Typically used for home or workplace charging, L2 chargers can take several hours to repower an EV.
The Multi-state Study is one of several DOE initiatives aimed at overcoming barriers to more rapid expansion of charging networks, efforts that have become increasingly urgent as the November election looms and growth in EV sales has slowed. According to Kelley Blue Book, Americans bought 268,909 EVs in the first three months of 2024, up a modest 2.6% over the first quarter of 2023, when EVs scored a 46.4% jump over the first quarter of 2022.
Along with price, consumers’ concerns about EVs’ range and charger speed and availability are the most commonly cited brakes on the wider adoption of electric vehicles, Kelley said.
DOE and the Joint Office launched the National Charging Experience (ChargeX) Consortium in August 2023 to help consumers get over those bumps. A public-private initiative, the consortium is focused on ensuring “that any driver of any EV can charge on any charger and have it work the first time, every time,” said ChargeX Director John Smart.
The group includes industry stakeholders, along with consumer advocates, academics and state government officials, who collaborate on “complex issues … that no single company can solve on their own,” Smart said during a May 23 webinar providing a progress report on the group’s efforts.
“To truly understand the customer experience, we need more metrics … that are used and measured uniformly across the industry, so that everyone’s speaking the same language, so that we’re properly measuring and therefore improving the customer experience,” Smart said.
Top priorities include developing minimum standards ― or key performance indicators (KPIs) ― that will provide the benchmarks needed to make charging more predictable and reliable.
Breaking down the KPIs
Frank Marotta Jr., assistant manager for charging network reliability at General Motors, detailed how the consortium breaks down a customer’s experience at a charger into discrete elements, each with its own KPI.
“How effective are the mapping tools drivers can be using to locate the station? How effective are they at actually getting the vehicle right up to the plug?” Marotta said.
“We have waiting probability, which is basically the probability that at least one port might be available to deliver energy when the EV arrives,” he said. “And under starting to charge, we have two KPIs … one that is meant to measure the effort required to actually start the charging session and then … the time required to actually get that session initiated.”
Another priority is communication between EVs and chargers, and chargers and the cloud, Smart said. “What is needed to allow the industry to scale, and specifically as more makes and models of chargers come to market and more makes and models of electric vehicles, how do we ensure that they all work together going forward?”
The answers will include better sharing of diagnostic data between stakeholders and improving interoperability “to efficiently verify that every charger works with every vehicle,” Smart said.
Market growth and the resulting need for interoperability and better grid planning are coming. While only a handful of NEVI projects are online now, the Joint Office has reported that 36 states have at least issued their first solicitation for chargers, and 23 have made conditional awards or agreements for more than 550 charging stations, each with four or more ports.
U.S. public EV charging ports by month | Joint Office of Energy and Transportation
The Joint Office’s checklist for state planners includes early communication with utilities to prepare for the interconnection of NEVI-funded stations.
Also, consumer range anxiety could begin to taper off, with DOE reporting that 19 EV models that were on the market in 2023 could travel 300 miles or more on a charge, up 35% from 14 such models in 2022.
While noting that “everything about EVs is controversial,” Kelley expects market growth to continue, driven by the increase in available models and some price reductions. The slowdown could be a sign that EVs are becoming mainstream in some parts of the country, Kelley said. “Segment growth typically slows as volume increases.”
Rural electric cooperatives face challenges different from investor-owned utilities as they pursue clean energy goals, the leader of Tri-State Generation and Transmission Association said.
Tri-State CEO Duane Highley was the featured speaker in a May 28 webinar hosted by the American Clean Power Association. He pointed out that the customers served by cooperatives often are spread farther apart than IOUs’ customers and that the communities that cooperatives serve often have high rates of poverty.
Tri-State CEO Duane Highley | American Clean Power
But one of the biggest differences is coal, which is in the crosshairs of most decarbonization scenarios. The Power Plant and Industrial Fuel Use Act of 1978 had the effect of steering cooperatives toward coal-burning plants at a time when they were rapidly expanding generation capacity, Highley said. As a result, they are more reliant on coal than other power industry sectors.
“And now as we make a transition, it’s especially challenging because to reduce carbon emissions, we’re retiring coal, which for us is the majority,” he said. “So when you talk about, ‘Oh, just shut down your coal plant,’ what if that’s over half of your capacity in one plant?”
Forty-one of Tri-State’s 44 members are electric distribution cooperatives and public power districts. They serve more than 1 million customers across nearly 200,000 square miles in Wyoming, Colorado, Nebraska and New Mexico.
ACP CEO Jason Grumet asked Highley how Tri-State is managing its transition from coal to renewables.
Tri-State’s board and its member-owners were supportive of the move, Highley replied, as long as the result was reliable and affordable.
“So that’s what we’re doing, and we’re doing it at what I’d call light speed for a utility,” he said. “We … are building hundreds and hundreds of megawatts of wind and solar. And people who said ‘you can’t do that and keep the lights on’ are wrong. We’re able to do this and prove reliability at an accelerated level.”
To meet reliability needs, Tri-State is overbuilding renewables and looking forward to long-duration energy storage technology maturing, he said. And it is retaining fossil backup.
“We’re going to keep a lot of gas and oil generation around because we have to have it for reliability,” he said.
Tri-State’s proposed resource plan calls for a new combined cycle gas-burning plant with carbon capture and sequestration capacity retrofitted later.
Highley is excited about the potential of small modular reactors as well, again as a backstop for reliability. But he thinks they are at least a decade away and that cooperatives cannot be first adopters; someone else must take the risk of proving the concept.
Tri-State also needs to be in an RTO, to transfer power between regions and balance out spikes or lulls in intermittent power generation, Highley said.
“And that’s why we’ve been so much an advocate for promoting the western expansion of the Southwest Power Pool. And we believe it’ll be starting up the first quarter of 2026 in our area,” he said.
Along with the challenges unique to cooperatives, Highley laid out some that are common across the power industry: rapid growth of demand and constraints on transmission to meet that demand.
“There’s definitely growth coming, and it is exceeding what we had been previously forecasting,” he said, citing electric vehicles and overall electrification as the primary causes, along with data centers that can consume a gigawatt apiece.
“There’s just not a utility that I know of in the West that has a gigawatt of surplus capacity that they say, ‘Hey, I’m not using it right now. Would you like to hook up?’” Highley said.
“Plus the transmission question,” he added. “There are very few areas on the grid where you can drop hundreds of megawatts of load without making some significant transmission investments. And what we’ve seen in the past is it can take anywhere from five to 15 years to get a new transmission line built.”
Highley gave a nod to the state and federal policymakers who set decarbonization goals but don’t have to do the actual work of meeting them.
“We can make lots of growth. We just can’t make maybe as much as fast as people would like to see [in] some instances.”
The United States is a step closer to its first potential floating offshore wind farm.
The Bureau of Ocean Energy Management said May 28 it has completed its environmental assessment of the state of Maine’s request for a lease area where it could place a research array. It found the lease and the site assessment work that would be done on it would have no significant impact on the environment.
BOEM offered the state a research lease May 24. Maine must accept or reject BOEM’s offer or request modifications within 30 days.
Gov. Janet Mills (D) responded in a prepared statement May 28 that the lease offer is a “major milestone” for the state in its efforts to site offshore wind and that her administration looks forward to reviewing it.
Floating wind turbines are a relatively new technology only now beginning to be installed on a larger scale. The technology is still being developed and tested, and at this point it is more expensive and complicated than the fixed-bottom turbine technology that has come into widespread use worldwide over the past three decades.
For years, Maine has sought to be a leader in floating wind in the United States — as a way to extract emissions-free electricity from its lengthy but deep coastal waters and to build a new industry. (See Maine Finalizes Offshore Wind Roadmap.)
The University of Maine has been researching the concept and execution for more than a decade, and generated electricity with a downscaled turbine it set afloat in 2013/14.
In October 2021, Maine requested the research lease that has now been offered.
It would allow the state to place up to 12 turbines with a combined rating of up to 144 MW on up to 9,728 acres within a 34,596-acre research lease area 28 nautical miles southeast of Portland.
BOEM’s final environmental assessment determined the likely impacts of the research array would be negligible or negligible to minor.
In its news release, BOEM Director Elizabeth Klein said: “Floating wind technology can make offshore wind a reality in the Gulf of Maine. BOEM will continue to work in partnership with the state of Maine as we move forward to facilitate the responsible development of offshore wind in this region, as well as the deployment of floating offshore wind technology nationwide.”
In her press release, Mills said: “Offshore wind offers our state a tremendous opportunity to harness abundant clean energy in our own backyard, to create good-paying jobs and drive economic development, and to reduce our over-reliance on fossil fuels and fight climate change.”
As it advances Maine’s research lease request, BOEM simultaneously is setting the stage for commercial offshore wind development in the Gulf of Maine.
In April, it proposed an auction for eight lease areas totaling nearly 1 million acres and holding a potential 15 GW of capacity. Six of the eight commercial areas would be well south of the research area, closer to the outer arm of Cape Cod than to Maine. (See Wind Energy Lease Areas Designated in Gulf of Maine, Oregon.)
New Jersey Gov. Phil Murphy has directed the state Board of Public Utilities (BPU) to advance the opening of its fifth offshore wind solicitation by 15 months as the state scrambles to recover the time lost when Danish developer Ørsted abandoned two of the state’s first three projects.
Murphy (D) said advancing the solicitation from the third quarter of 2026 to the second quarter of 2025 “builds upon the momentum of the state’s growing offshore wind industry” as it strives to reach its goal of installing 11 GW of OSW capacity by 2040.
The May 28 announcement comes as concern about the effectiveness and public benefit of wind generation continues to surface at public hearings. It emerged at legislative budget hearings on the finances of the BPU and at a permit hearing for the state’s now-leading OSW project — Atlantic Shores — held May 14 by the state Department of Environmental Protection (DEP).
$125M Payment
The state has pushed ahead undeterred since October, when Ørsted abandoned two of the state’s first three OSW projects, Ocean Wind 1 and 2. The BPU awarded two new projects in January at the conclusion of its third solicitation. And within weeks of Ørsted’s withdrawal, Murphy directed the BPU to speed up the normal two-year cycle between solicitations and prepare for the fourth solicitation, which opened in April and will close July 10. (See New Jersey Opens 4th Offshore Wind Solicitation.)
Murphy said in a release announcing the accelerated timeline for the fifth solicitation that Ørsted has agreed to pay the state $125 million in a settlement to “release claims against each other arising out of or related to the Ocean Wind Projects.”
The developer has agreed to put $200 million into an escrow fund New Jersey could spend on other wind-related projects. The law also required the developer to post a performance security of $100 million for the completion of the project, which would be forfeited if the project failed to reach commercial operation. Lawmakers set up the provision to strengthen the requirements on Ørsted in return for the state allowing the developer to receive federal tax credits awarded to support OSW projects. The credits otherwise would otherwise have gone to help state ratepayers. (See NJ Lawmakers Back Ørsted’s Tax Credit Plea.)
Gov. Phil Murphy (D) | Gov. Phil Murphy
Murphy also said the state would “pause” its planned second solicitation for offshore infrastructure projects using the State Agreement Approach (SAA), which would allow coordinated offshore wind transmission planning with regional grid operator PJM.
The BPU completed its first SAA process in October 2022, awarding $1.07 billion for transmission upgrades to deliver 6,400 MW of offshore wind generation to the PJM grid. BPU officials said it would save ratepayers hundreds of millions of dollars, but the solicitation award covered only upgrades to the landside portion of the transmission. (See NJ BPU OKs $1.07B OSW Transmission Expansion.)
The BPU planned the second SAA to solicit coordinated transmission alternatives for the offshore portion of the transmission lines. But FERC on May 13 released Order 1920, the long-awaited final rule on long-term regional transmission planning and cost allocation. The order is of particular relevance to PJM’s ongoing interconnection queue reform process, Murphy said.
His release said he paused the SAA process to give BPU staff the “opportunity to fully evaluate the implications of the new FERC rule and participate in PJM’s process to ensure the best outcome to meet New Jersey’s transmission needs at the least cost to ratepayers.”
Efficiency Questioned
If all goes to plan, OSW projects now in the pipeline would account for about half — 5.25 GW — of New Jersey’s 11-GW goal. Aside from the 1,510-MW Atlantic Shores project, the state in January approved the 1,341-MW Attentive Energy Two project and the Leading Light project, with two phases of 1,200 MW each.
The state’s wind projects have faced opposition from the commercial fishing industry and tourism-related businesses. That skepticism was present at the May 14 hearing of the Senate Budget and Appropriations Committee, at which Republican senators pushed back on the BPU’s aggressive drive to line up wind projects. They questioned whether the state should launch an initiative in which it has little experience, for which the technology is new, and for which the eventual cost to ratepayers is unknown.
As he opened the hearing for lawmakers’ questions of BPU officials, Chairman Sen. Paul Sarlo (D), called the OSW projects “very controversial, as you know, politically charged” and queried whether the BPU is concerned the projects “may run the risk of not coming to fruition.”
Sen. Douglas J. Steinhardt (R), assessing the program’s recent history, was more direct.
“With so much uncertainty surrounding projects that are currently already underway, or were already underway and suspended, do you believe it is appropriate to open a new round of solicitation for future projects?” he asked BPU President Christine Guhl-Sadovy, referring to the fourth solicitation.
Given the rising costs, isn’t it “a bit sort of a quixotic quest and a tilt at windmills, no pun intended there,” he asked.
Great Opportunity
Guhl-Sadovy brushed aside his concerns.
“Offshore wind is really a once-in-a-lifetime opportunity to bring not only clean energy to New Jersey, but [also] billions of dollars in economic benefits, tens of thousands of jobs across the state, primarily in South Jersey,” Guhl-Sadovy said.
Sitting next to Guhl-Sadovy, Tim Sullivan, CEO of the New Jersey Economic Development Authority (EDA), which has funded much of the state’s OSW infrastructure investment, faced questions about the agency’s determination to position the state as an East Coast leader in offshore wind, quickly building an industry from scratch.
“If this is a once-in-a-lifetime opportunity, it’s also a once-in-a-lifetime opportunity to get this correct, or catastrophically incorrect, in my opinion,” Steinhardt said.
Sullivan acknowledged the risks of offshore wind. “Anytime we’ve got a new capital-intensive, regulatorily complex industry, you’re going to see fits and starts.” But the state must “focus on the competitive dynamics here, because other states want this leadership position.”
At a May 15 hearing of the Assembly Budget Committee, Assemblyman Gerry Scharfenburger (R) said he’s concerned the state is transitioning from fossil fuels in favor of solar and wind energy, whose “intermittent” characteristics would create “economic and environmental problems down the road.” He questioned the Murphy administration’s “prioritization of wind turbines over, say, nuclear energy.”
“I have no affinity for fossil fuels,” he said, adding that “I would put goose droppings in my car if it would make it run … We just have to look for the best alternative that is viable, is fiscally doable and is going to be there. It can’t be intermittent.”
Guhl-Sadovy said there was no preference against nuclear, which would account for 40% of the state’s electricity generation in state clean energy plans. She said the BPU believes in the sector economics.
“As we look at the clean energy that we’re investing in … we are going to see an economic development come to the state of New Jersey,” she said.
Nuclear or not
The role of nuclear energy also surfaced at the DEP’s May 14 hearing seeking public input on the Atlantic Shores project. The agency is assessing the developer’s request for waterfront development, coastal wetlands and other offshore environmental permits, as well as onshore permits for a transmission cable to run to the Cardiff substation in Egg Harbor Township.
Dennis DeForest, a member of Save the East Coast, a New Jersey group that opposes offshore wind, said the projects would damage the marine environment, disrupt neighborhoods when cables are run through them and hurt tourism. He added that voters never had a chance to vote on the issue.
“There’s really no reason for us to use this unreliable energy,” he said. “There’s other ways to create energy, clean green energy, right, through nuclear, with small nuclear reactors.”
Henry Waldron, a resident of Brigantine, one of the communities closest to the proposed OSW development, said the state already is too reliant on electricity produced by burning fossil fuels, and much of the power is imported from other states. He said his hometown — a barrier island near Atlantic City — already is affected by rising sea levels and damage to the beaches.
“New Jersey is already in a deficit for electricity,” he said, foreseeing brownouts by the middle of this decade.
“People talk small modular reactors,” which could be ready by 2040, but “big nukes” would take much longer, he said. “I don’t see anybody who’s yelling against wind offering their communities for more nuclear reactors. And a nuclear reactor would take 12 years (to build).”
NV Energy will commit to joining CAISO’s Extended Day-Ahead Market (EDAM), sources have told RTO Insider, a move that will end months of speculation among Western electricity sector stakeholders about whether the Nevada utility would choose EDAM over SPP’s Markets+.
The utility plans to make its intent public May 31 when it files an integrated resource plan with the Public Utilities Commission of Nevada, multiple sources closely involved with market developments in the West said.
NV Energy did not respond to a request for comment on the matter, a topic of increasing interest in the region, with multiple sources recently telling RTO Insider that the utility has been revealing its decision in favor of EDAM in private meetings. An NV Energy executive offered the clearest public signal yet on the utility’s leaning during a May 22 joint session of the CAISO Board of Governors and Western Energy Imbalance Market (WEIM) Governing Body. (See Is NV Energy Leaning to CAISO’s EDAM?)
The selection still must be approved by the PUCN. A 2021 Nevada law requires the utility to join an RTO by 2030, with the decision subject to approval by the commission, which has been hosting workshops exploring the two day-ahead market options in the West as part of its RTO proceeding. (See Nevada RTO Proceeding Examines EDAM, Markets+ Design.)
At one of those workshops, the Brattle Group presented data showing NV Energy stood to gain $62 million to $149 million in annual economic benefits from joining the EDAM, while it stood to lose as much as $100 million from withdrawing from CAISO’s Western Energy Imbalance Market (WEIM). The results of joining Markets+ ranged from a loss of $17 million compared with the status quo to a benefit of $16 million. (See Nev. RTO Effort Turns Focus to NV Energy Day-ahead Studies.)
Big Win for EDAM
NV Energy’s decision spells a major victory for the EDAM in its ongoing competition for members with SPP’s Markets+ day-ahead offering.
The utility serves the majority of Nevada’s electricity users and is the balancing authority for the state. Its control area occupies a central position in the WEIM, functioning as the primary wheel-through point for energy transfers between the WEIM’s California participants — including the ISO — and PacifiCorp’s sprawling balancing authority area in the inland West.
PacifiCorp in April became the first entity to agree to sign an implementation agreement for the EDAM, sealing its participation in the market. (See PacifiCorp Fully Commits to CAISO’s EDAM.)
NV Energy’s membership in EDAM also would be consequential for Markets+ because the utility’s BAA sits between the territories of the entities that have shown the most interest in joining the SPP-run market, including the Bonneville Power Administration and Puget Sound Energy in the Northwest, and Arizona Public Service, Salt River Project and Tucson Electric Power in the Desert Southwest. The inclusion of Nevada’s transmission network in EDAM would limit the ability of those entities to transfer energy among each other in a geographically divided Markets+.
The decision also is significant for the West-Wide Governance Pathways Initiative. Backers of that effort in April issued a proposal to make stepwise changes to the governance of the WEIM/EDAM, with the objective of eventually putting the market under the authority of an independent “regional organization” after seeking changes to California law related to CAISO. (See Pathways Initiative to Act Fast on ‘Stepwise’ Governance Plan.)
But step 1 in that proposal entails elevating the “joint” authority the WEIM’s Governing Body currently shares with CAISO’s Board of Governors over WEIM matters to “primary” authority. Under the plan, the ISO would pursue that change with FERC only after the EDAM secures implementation agreements with a “set of geographically diverse” WEIM participants representing load equal to or greater than 70% of CAISO BAA annual load in 2022. With commitments from PacifiCorp, Balancing Authority of Northern California, Idaho Power, Los Angeles Department of Water and Power, and Portland General Electric, NV Energy has been cited by Pathways supporters as the entity needed to trigger that move.
NV Energy’s filing with the PUCN on May 31 will coincide with a monthly meeting of the Pathways Initiative’s Launch Committee, at which the committee is expected to vote on adopting step 1 of the governance proposal.
The CAISO Board of Governors and Western Energy Imbalance Market (WEIM) Governing Body voted unanimously May 22 to approve an expedited proposal to increase the ISO’s soft offer cap from $1,000/MWh to $2,000.
CAISO staff and stakeholders participating in the ISO’s Price Formation Enhancements (PFE) Working Group quickly crafted the plan as part of a strategy to improve the bidding prospects of energy-limited resources — such as battery storage and hydroelectric resources — ahead of late summer.
The ISO hopes to win FERC approval for the proposal by Aug. 1, the date that typically marks the start of the most challenging period for grid operations in the West because of declining hydro availability and the onset of what usually are the warmest conditions of the year in California’s load centers.
Grid operators across the region are preparing for the prospect of tight supplies this summer based on low water conditions in the Northwestern U.S. and the Canadian province of British Columbia.
“I see these changes as urgent, given the difficult hydro conditions in the Pacific Northwest. The market will benefit if more hydro resources are fully in the market as much as they can be,” Governing Body Chair Andrew Campbell said during the body’s joint session with the ISO’s board. “There’s urgency for batteries too. There’s so many batteries online this summer, and I support relying more on the market to manage charge and discharge rather than market operator directives.”
The two-part proposal is designed to allow energy-limited resources with “intraday opportunity costs” — specifically batteries and hydro — to factor those costs into their default energy bids (DEBs), but the new rules will apply to gas-fired generation as well. The ISO has emphasized that all resources will still need to justify the costs behind their bids. (See CAISO Moves for Expedited Change to Soft Offer Cap.)
Those opportunity costs arise on stressed days for the grid when supplies become tight, usually from extreme weather. In those circumstances, an energy-limited resource committed to the market at the $1,000/MWh soft offer cap can find itself dispatched at high prices occurring relatively early in the day, leaving it unable to provide energy later when prices are even higher.
To address the issue, the proposal seeks to revise CAISO’s rules related to FERCOrder 831, the 2016 directive that required RTOs and ISOs to limit the market bids of energy resources to the higher of either a soft offer cap of $1,000/MWh or a cost-based offer already verified by the market operator, up to a hard cap of $2,000 MWh.
‘Loud and Clear’
The proposal had solid backing from many industry stakeholders, including hydro-heavy WEIM participants Bonneville Power Administration and Seattle City Light, and was endorsed by CAISO’s Market Surveillance Committee (MSC) during its May 15 meeting.
Some stakeholders, such as BPA and the Western Power Trading Forum, expressed concern about a last-minute change to the proposal that limits storage resources to bidding above the $1,000/MWh cap only in the real-time market — and not in the day-ahead market — made in response to the MSC’s opinion that the ISO’s integrated forward market process already solves the opportunity cost issue for storage in the day-ahead.
Opponents included the California Public Utilities Commission and its Public Advocates Office, both of which raised concerns about the potential costs to ratepayers from increasing the cap and the speed with which the plan moved through CAISO’s stakeholder process.
Supporters among stakeholders and the CAISO and WEIM oversight bodies emphasized the measures should be considered only a temporary remedy. Some said the PFE Working Group should come up with a more complete solution before summer 2025, one that would more completely address the bidding requirements for storage and take up the needs of hybrid and demand response resources as well.
After expressing gratitude for the quick efforts by CAISO staff and stakeholders on the proposal, ISO Board Chair Jan Schori acknowledged how much more needs to be done on the matter.
“I am hearing loud and clear, from all the comments that we’ve received, that we simply have to do a lot more work on batteries and storage, and particularly fixing the [bid-cost recovery] rules,” Schori said. “But [batteries] are unique; they are different; and we need to probably come up with a set of rules that really works to match that resource and enable us to both have it be a long-term resource for the industry and for customers, but also to make sure it’s deployed at the time that we need it available to us to address the reliability issues that we may be confronting.”
New Approach to Large Load Addition Capacity Assignments Endorsed
The PJM Markets and Reliability Committee endorsed a proposal to revise how capacity obligations for serving large load additions (LLAs) are calculated to limit capacity assignments to areas where LLAs are forecast to interconnect.
The MRC did not vote on an alternative motion offered by American Municipal Power (AMP) under the committee’s truncated voting structure. (See “Changes to Capacity Assignments for Large Load Additions Contemplated,” PJM MRC Briefs: April 25, 2024.)
When bringing the issue charge in October 2023, American Electric Power (AEP) and Dominion Energy said the current capacity obligation assignments spreads PJM-approved LLAs across transmission zones, meaning an increased load forecast by an electric distribution company (EDC) participating in the reliability pricing model (RPM) could compel a fixed resource requirement (FRR) entity to procure capacity for load it will not serve.
In February, FERC granted AEP a waiver to alter the capacity obligation calculation for four of its vertically integrated utilities to not include forecast LLAs outside their territories. (See FERC Grants AEP Utilities Waiver of Capacity Obligation.)
The tariff and Reliability Assurance Agreement (RAA) revisions would rework how PJM calculates capacity obligation assignments to exclude LLAs included in Table B-9 of the load forecast from base zonal scaling factors and add those LLAs back when determining the obligation peak load input.
The AMP alternative sought to add a definition of large load additions to the Reliability Assurance Agreement (RAA) to clarify how they can result in capacity obligations for LSEs. The proposed redlines also rewrote a section of the “threshold quantity” definition pertaining to the preliminary forecast peak load for FRR entities in a transmission zone alongside RPM participants to remove the phrase “the FRR Entity’s Obligation Peak Load last determined prior to the Base Residual Auction for such Delivery Year, times the Base FRR Scaling Factor.” It will instead point to the relevant RAA section.
DR Availability Issue Charge Approved, Quick Fix Proposal Rejected
Stakeholders endorsed an issue charge to investigate modifying the availability of demand response resources, but they rejected a quick fix proposal to expand the winter availability window by two hours. The issue charge passed with 59% sector-weighted support; however, the proposal failed to carry the two-thirds threshold required at 54% support.
The issue charge and quick fix proposal were sponsored by the Advanced Energy Management Alliance (AEMA), PJM Industrial Customer Coalition (ICC), CPower, Enel and NRG Curtailment Solutions. (See “Demand Response Providers Seek Expanded Availability,” PJM MRC/MC Briefs: Feb. 22, 2024.)
Bruce Campbell, of Campbell Energy Advisors, said the revised risk modeling approach PJM adopted following the critical issues fast path (CIFP) process conducted last year led to the wintertime hours the model has found hold elevated reliability risks being expanded well into the night. However, the DR availability window was not expanded beyond the status quo 6 a.m. to 9 p.m., preventing dispatchers from using DR to address the full risks the RTO has identified. The proposal would extend the window in which DR is dispatchable by two hours to end at 11 p.m. (See FERC Approves 1st PJM Proposal out of CIFP.)
Several demand response providers argued that PJM’s wintertime risk projections, shown on two heat maps, justify expanding the DR availability window. | PJM
Campbell argued the longer availability window would not negatively affect the reliability contribution of DR resources, as most participants are industrial load that consumes power at a steady rate throughout the day irrespective of season.
Independent Market Monitor Joseph Bowring said the change would affect the effective load carrying capability (ELCC) rating for DR resources, a calculation tied into the ELCC ratings of all resources. Making a change to one resource would require recalculating all resource class ELCC values, which he said would be difficult and inappropriate to do with the original targeted implementation for the 2025/26 delivery year.
“PJM calculates the contribution of DR resources to reliability for ELCC purposes using an assumed maximum level of response rather than actual data on DR response during the winter. PJM uses actual data for generation resources. The result is that the ELCC of DR is significantly overstated,” Bowring told RTO Insider in an email. “Actual DR performance/load reduction during Winter Storm Elliott was well below 50% of the stated capacity values. A one-off administrative change to the rules that would arbitrarily increase payments to DR resources and reduce payments to other resources without a comprehensive review of the DR ELCC would be inappropriate.”
During the May 22 meeting, Campbell worked with other package sponsors to revise the issue charge to delay the targeted implementation of the quick fix portion of the issue charge to the 2026/27 Base Residual Auction (BRA). The issue charge was also revised to shift implementation of the third key work activity (KWA) — which seeks to eliminate the window outright or create an additional DR classification that would be available all day — to the 2027/28 delivery year. But this alternate version was rendered moot by endorsement of the original package.
PJM Director of Stakeholder Affairs David Anders said with the vote on the expanded availability window failing, the KWA is now considered complete and future stakeholder discussions will focus on the other work areas.
The proposal would add three intraday resource commitment runs to the day-ahead market, lining up with the North American Energy Standards Board’s (NAESB) gas nomination cycle deadlines. Gas generators would be notified that they are being committed with adequate time for them to nominate for fuel in the subsequent cycle and generators would be asked to voluntarily “use every reasonable effort to notify” PJM if they have procured fuel or expect to do so in time to be scheduled. The manual revisions also say PJM may perform additional resource commitment runs when necessitated by load forecasts, updated resource parameters or changing system conditions.
The proposed revisions to Manual 11 stress that the request for generators to notify PJM if they have or intend to procure fuel is voluntary and does not come with penalties for those who do not provide an update. Gas resources that do not procure fuel necessary to meet their day-ahead or reserve commitments are required to notify dispatchers by adjusting their availability or parameters in Markets Gateway, submitting an eDART ticket and by calling PJM dispatch. The changes include a note stating that keeping dispatchers informed about fuel availability during critical conditions “is essential to providing optimal situational awareness of generator availability to PJM Operations.”
Dominion Energy’s Jim Davis said the proposal is another step building on real-time values to increase operational certainty around the alignment of the electric and gas markets. The package was sponsored at the EGCSTF by PJM, Dominion and Gabel Associates.
First Read of CIFP Manual Revisions
PJM’s Skyler Marzewski presented a set of manual revisions implementing capacity market changes drafted through the CIFP process and approved by FERC in January, including several changes to reflect stakeholder feedback received since it was endorsed by the Market Implementation Committee on May 1.
The manual revisions would phase out Manuals 20, 21 and 21A and replace them with new Manuals 20A and 21B, as well as “cleaning up” Manuals 18 and 14B. (See “Stakeholders Endorse Manual Revisions to Implement CIFP Changes to Capacity Market,” PJM MIC Briefs: May 1, 2024.)
The changes to the Manual 18 language include spelling out a formula that helps determine unforced capacity (UCAP) values for load management resources and clarifying that existing FRR entities may terminate their election to participate in FRR rather than the RPM through “and including” the 2028/29 delivery year without being penalizes.
If endorsed, the capacity market changes would expand the use ELCC analysis for accrediting all generation types, require that planned resources notify PJM of their intent to participate in a Base Residual Auction (BRA) at least 90 days in advance and change how generation UCAP values are calculated. The MRC manual revisions are set to be voted on by the MRC during its June 27 meeting.
The revisions to Manuals 20, 21 and 21A — which focus on the planning side of the CIFP proposal — would establish a new approach to capacity accreditation, reliability risk modeling and BRA procurement targets. The PC is set to vote on the revisions on June 4 and would be included alongside the Manual 18 revisions at the MRC if approved. (See “First Read on CIFP Manual Revisions,” PJM PC/TEAC Briefs: April 30, 2024.)
Consumer Advocates Intend to Propose Wider DESTF Scope
Maryland and Illinois consumer advocates plan to propose revisions that would widen the scope of the Deactivation Enhancements Senior Task Force (DESTF) to include finding resources that could replace retiring generators and and have PJM consider alternatives to maintaining costly reliability-must-run (RMR) contracts while traditional transmission expansions are constructed to resolve any reliability violations prompted by the deactivation. The current issue charge is focused on how RMR compensation is determined, when generation owners need to notify PJM of their intent to deactivate and improving transparency.
Clara Summers, of the Illinois Citizens Utility Board (CUB), said the intent is to supplement the work of the DESTF, which is discussing proposals from the Monitor and PJM, rather than supplant those efforts.
Phil Sussler, of the Maryland Office of People’s Counsel (OPC), said there are multiple stakeholder discussions looking at generation deactivation siloed between the DESTF and other groups, such as the Interconnection Process Subcommittee’s work on how capacity interconnection rights (CIRs) may be transferred from a deactivating generator to a replacement resource at the same point of interconnection. Harmonizing those efforts raises the odds of a solution that allows the interconnection process to better react to a deactivation request, he said.
Vistra’s Erik Heinle said a balance is needed to ensure discussions do not become so broad that they collapse in on themselves.
“Each of these issues is an important one … but we also want to make sure we don’t get stuck and have the weight of multiple interests preventing us from getting to a solution as expeditiously as possible,” he said.
The call for harmonization mirrored comments at the May 8 Public Interest and Environmental Organization User Group (PIEOUG) meeting, where advocates said siloed processes make it difficult for offices with limited resources to track numerous discussions and limits the solutions on the table. (See “Consumer Advocates Call for More Holistic Thinking at PJM,” Consumer Advocates, Environmentalists Urge Holistic Thinking at PJM.)
AUSTIN, Texas — ERCOT stakeholders plumbed the depths of Robert’s Rules of Order and amended motions before endorsing a rule change May 22 that allows the grid operator to manually release ERCOT contingency reserve service (ECRS) from economically dispatched resources after repeated violations of the system power balance constraint.
Following multiple failed attempts, the Technical Advisory Committee finally met the two-thirds threshold for approval by lowering the nodal protocol revision request’s (NPRR1224) offer floor from the originally proposed $1,000/MWh to $750/MWh. The measure passed 20-10, opposed by the consumer and retail segments over concerns of price increases.
The change introduces a trigger that ERCOT can use to manually release ECRS from security-constrained economic dispatch (SCED)-dispatchable resources when the amount of the power balance violation is at least 40 MW for 10 consecutive minutes. With TAC’s modification, it would also require that energy offer curves for capacity assigned to ECRS be offered at the new floor.
ERCOT staff and the Independent Market Monitor have been collaborating on the issue since late 2023 after ancillary service methodology discussions for this year at TAC and the Board of Directors. The board directed staff to review the processes used to compute the minimum quantities of ECRS and identify potential alternatives by May.
The grid operator has been operating under a conservative posture since the 2022 summer. It has been procuring huge quantities of ancillary services to ensure it has enough operating reserves to account for intermittent solar and wind resources.
However, that has increased costs in ERCOT’s energy-only market. The Monitor says ECRS, the newest ancillary product, created artificial supply shortages that produced “massive” inefficient market costs totaling about $12.5 billion last year through Nov. 27. (See ERCOT Board of Directors Briefs: Dec. 19, 2023.)
The Monitor suggested the deployment trigger to avoid sequestering large quantities of ECRS out of SCED that it said caused the mechanism to perceive shortages that weren’t real and set energy prices much higher than their true marginal reliability value. It also proposed a re-evaluation of the ECRS procurement quantities and eliminating the $1,000/MWh offer floor.
“Such a provision would retain a significant portion of the artificial shortage pricing that we documented in 2023, mitigating only those prices that exceeded $1,000/MWh,” the Monitor said in its comments. “While this may be in the economic interest of suppliers in the short term, setting prices that are not based on market fundamentals … will undermine the credibility of the ERCOT markets over the longer term.”
Generation owners, led by Michele Richmond, executive director of Texas Competitive Power Advocates, and Lower Colorado River Authority’s Blake Holt and ENGIE’s Bob Helton, disputed the IMM’s valuation of ancillary service reserves.
After first jokingly suggesting that the issue be placed on TAC’s combination ballot, Luminant’s Ned Bonskowski reminded members that ECRS was originally intended to be deployed with real-time co-optimization, which is still two years away.
“It’s a tough problem where we’re trying to bridge two worlds,” he said. “We’ve got a lot of folks that are thinking about the extreme heat and scarcity that we had last summer and reacting to that, whereas I think the joint commenters looked at this and said, ‘Well, while we may not agree that the way ECRS is currently operated is the problem, we recognize that there is a concern, and so as a step towards compromise, let’s try to align whatever it is in NPRR2024.’”
Bonskowski shared data that he said indicated releasing 500 MW of ECRS has a value “well above” the level recommended by the Monitor. He said the Protocol Revision Subcommittee’s (PRS) $1,000/MWh proposal falls “somewhere reasonably” in the middle.
ERCOT’s Jeff Billo, director of operations planning, said the grid operator agrees with the concept of a floor and that it needs to be done correctly “regardless of the quantity.”
“Then we can continue to work on what is the right methodology for determining the quantity,” he said. “We’re coming at this with different viewpoints on the offer floor.”
TAC’s first attempt to endorse NPRR1224, as amended by the Monitor’s comments, fell flat at 10-18 with two abstentions. Its only support came from the consumer and retail segments.
A second motion to endorse the change with the offer floor set at $500/MWh met the same fate by an identical vote. The retail segment was joined by the municipal segment.
A third attempt at passage, this time as originally proposed by the PRS, also failed, at 15-11, with four abstentions. It was opposed by the consumer and retail segments.
Finally, on its fourth attempt, TAC endorsed the measure. It must still be approved by the board and Texas Public Utility Commission, but it has been assigned urgent status so it can be effective this summer.
TAC Endorses $1.2B Project
TAC endorsed the ERCOT Regional Planning Group’s recommended $1.2 billion project to rebuild 345-kV infrastructure in West Texas that will address thermal overloads and petroleum production load-growth issues in the region.
The project easily cleared the $100 million threshold to be classified as a Tier 1 project, necessitating board approval.
Assuming the rebuild is approved, Oncor, the transmission provider, will disconnect existing 345- and 138-kV transmission lines before rebuilding about 245 miles of new transmission lines and switches. It will also build a new substation and upgrade terminal equipment.
The project was first identified in the grid operator’s 2021 Permian Basin Load Interconnection Study. Staff conducted a subsynchronous resonance (SSR) screening for the rebuild. They found no adverse SSR effects to the existing and planned generation resources and also determined the project did not cause new congestion within the area.
The utility plans to complete the work by summer 2028.
Plaque Honors Brad Jones
ERCOT has installed a plaque across from the board room memorializing former interim CEO Brad Jones, who died last year.
Jones took over the grid operator’s reins in the wake of the disastrous and deadly February 2021 winter storm. He worked to raise public confidence in ERCOT and steady the ship before handing the helm to current CEO Pablo Vegas. (See Brad Jones, Former ERCOT, NYISO CEO, Dies at 60.)
The plaque includes a quote from Teddy Roosevelt, Jones’ favorite president. It reads: “‘Far and away the best prize that life has to offer is the chance to work hard at work worth doing.’ I know the work we do here at ERCOT is, indeed, the best prize.”
Staff have also planted a tree in his memory outside ERCOT’s operations center in nearby Taylor.
Theme of the Month
The meeting got off to a rocky start when ENGIE’s Helton attempted to submit a friendly amendment to the phrase of the month brought forward by American Electric Power’s Richard Ross.
Ross, who provides a monthly theme for both ERCOT and SPP stakeholder meetings, called in to say May’s was “words matter.”
“It’s been used quite well this week at SPP meetings,” Ross said. “I’m quite confident you guys can pull it off.”
He resisted Helton’s suggestion to add “innovation” as a nod to the ERCOT Innovation Summit the day before.
“I hate to be difficult, but it’s my phrase of the month,” Ross said as members erupted in laughter.
2 Combo Ballots Pass
TAC members approved a separate combined ballot containing NPRR1198 and related changes to the Planning Guide (PGRR113) and Nodal Operating Guide (NOGRR258) that adds an extended action plan as a constraint-management plan suitable to managing congestion resolvable by SCED.
Calpine, CenterPoint Energy, Jupiter Power and South Texas Electric Cooperative abstained from the unanimous vote, with Calpine’s Bryan Sams saying his company prefers SCED solutions.
EDF Renewables’ Alexandra Miller, the NPRR’s sponsor, said her group included all input and requests to ensure transparency was consistent throughout the changes.
“This is not something that is done outside of SCED, and it is a change to the system configuration. … Scalability is allowing transmission owners to operate and choose what to respond with,” she said.
TAC unanimously endorsed its combo ballot and the withdrawal of a Planning Guide revision request (PGRR105) that would have added DC ties to the list of resources that must meet minimum deliverability conditions. ERCOT staff said the PGRR was contrary to a recent PUC decision and that it raises a policy issue that is best suited for the commission.
The ballot also included the Real-time Co-optimization Battery Task Force’s recommended mitigated offer cap for all hydro resources and five NPRRs that, if approved by the ERCOT board, would:
NPRR1218: update the state’s renewable energy credit trading program to clarify that it only applies to solar renewable energy.
NPRR1220: modify the market’s restart process to require board and TAC approval and provide an alternative mechanism to board approval under certain circumstances.
FERC on May 23 upheld the contract termination payment (CTP) rules for Tri-State Generation and Transmission Association it approved last year, though it modified some of its original order in response to requests for clarification (ER21-2818-002, et al.).
Tri-State is a wholesale generation and transmission cooperative that serves members in Colorado, Nebraska, New Mexico and Wyoming with long-term, full-requirement wholesale electric service contracts.
FERC’s preferred balanced approach was initially proposed by one of Tri-State’s members. The co-op argued for its preferred accounting methods on rehearing, but FERC declined to overhaul its December order.
“We continue to find that the adopted BSA is consistent with principles of cost causation and with the purpose of an exit fee,” FERC said. “The presiding judge correctly explained that the BSA appropriately aligns costs and benefits to Tri-State members by declining to assign generation-related debt to Tri-State’s members located in the Eastern Interconnection, whose loads are supplied entirely through power purchase agreements.”
FERC also continued to find the BSA’s treatment of PPAs is just and reasonable because it requires that members pay their pro rata share of those that are actually used to serve load.
Tri-State argued that assigning the costs of dozens of PPAs to departing members would be unworkable, which did not persuade FERC. The commission said the co-op does not need to provide members with their exact share of PPA costs before they make a final decision on departure.
FERC granted requests for clarification from Tri-State and Mountain Parks Electric on the amortization term for the transmission credit. It should be amortized over the remaining term for the depreciation rates in effect for the assets to which the debt payment relates, the commission said.
It also clarified that the amortization term for the credit is determined based on the average remaining life of depreciable transmission plant base as determined by Tri-State’s most recent Form No. 1 filing at the time a member withdraws.
The commission sustained the overall transmission crediting approach, finding the prepayment and back-crediting of transmission-related debt in the adopted BSA strikes a reasonable balance between ensuring the debt-related costs of Tri-State’s transmission assets are recovered through the CTP and ensuring the withdrawing member reaps the full benefit of these costs while minimizing cost shifts.
“The payment of transmission-related debt as part of the CTP is intended to compensate Tri-State for the transmission-related debt it incurred to serve withdrawing members,” FERC said. “To prevent shifting costs onto remaining members, the withdrawing member must compensate Tri-State for this debt whether it uses Tri-State’s system or not.”
