Nearly a decade on, the saga over Dynegy’s manipulation of MISO’s capacity market continues, with FERC denying the company’s asks for procedural changes that might have softened repercussions in the case.
FERC dismissed all four of Dynegy’s rehearing requests related to evidence, intent, a report on remand, and the bounds of FERC’s jurisdiction in an Oct. 4 order (EL15-70).
The latest order is part of FERC’s yearslong inquiry into Dynegy’s apparent manipulation of clearing prices in MISO’s 2015/16 capacity auction. This year, the commission directed hearing and settlement procedures. (See FERC Sets Dynegy’s MISO Market Manipulation Case for Hearing.)
Approximately eight years after the auction, commission staff unwound FERC’s original conclusion that Dynegy — now owned by Vistra — conducted itself appropriately in the auction. That’s due to a D.C. Circuit Court of Appeals 2022 ruling that FERC hadn’t sufficiently supported its decision to accept the $150/MW-day Southern Illinois capacity price produced in the 2015/16 auction. (See FERC Staff Finds Dynegy Manipulated 2015 MISO Capacity Auction.)
This time, FERC rejected Dynegy’s fresh argument that it didn’t know it was manipulating MISO’s capacity market by refusing to sell capacity at a loss ahead of the auction. The commission said Dynegy should have been aware the actions it took to make sure one of its resources set the clearing price for Southern Illinois to raise profits amounted to manipulation.
FERC also said Dynegy’s argument ignores intent.
“Dynegy’s argument that its pre-auction sales strategy was ‘driven by a desire to stop losing money’ misses the point because it ignores the broader question of whether that sales strategy was part of an intentional or reckless effort to set the Zone 4 clearing price in the auction,” FERC said.
Dynegy argued it “could not have known that [FERC’s] market manipulation rules would compel Dynegy to operate a charity — mandating that Dynegy donate its capacity to the market at prices that would not cover its going-forward costs.”
FERC declined to take up Dynegy’s claim that its alleged manipulation scheme might involve non-jurisdictional retail transactions in South Carolina rather than the MISO portion of Kentucky. The commission said it is best to “defer any legal determination as to jurisdiction until after the hearing because certain disputed issues of material fact are likely to bear upon the jurisdictional question.”
Dynegy also proved unsuccessful in persuading FERC to strike from the record its heavily redacted report from June 2022 that concluded that manipulation occurred.
FERC said the report is necessary to the case because the D.C. Circuit Court of Appeals ordered FERC to establish a public record in the case, which was lacking after the nonpublic investigation and a poorly explained decision in 2019 to accept the Zone 4 capacity price.
“[P]arties and participants are free to rely on the remand report in making their cases, and at that point, Dynegy is free to challenge the parties’ or participants’ use of the remand report. … In this way, information would be appropriately considered by the presiding judge in an evidentiary hearing encompassing allegations of market manipulation,” FERC said.
Finally, FERC rejected Dynegy’s claim that FERC didn’t share exculpatory evidence with the company during the nonpublic investigation.
Dynegy contended that it could have used nonpublic, video footage of testimony to help prove its innocence.
FERC countered that the investigation was closed without a show-cause order or sanctions and pointed out that it’s under no obligation to share exculpatory evidence in a Section 206 proceeding. Further, the commission said its staff combed through materials and didn’t find anything that could be deemed exculpatory.
At any rate, FERC said the footage Dynegy singled out is now part of the nonpublic record in the case and can be addressed during hearing proceedings.
Supporting President Joe Biden’s goal of electric vehicles making up 50% of all new light-duty car sales in the U.S. by 2030 will require the country to install more than 1 million publicly available Level 2 and direct current fast chargers in the next 6.5 years, according to a new report from the Alliance for Automotive Innovation.
That pencils out to 451 chargers per day or three chargers every 10 minutes through the end of 2030, AAI says in its Get Connected: Electric Vehicle Quarterly Report for the second quarter of 2024.
While those figures may not be attainable, both the District of Columbia and Maryland have been working on rules to encourage and accelerate the installation of EV chargers, especially at multiunit dwellings and in low-income neighborhoods, as EV sales continue to grow steadily both in the region and across the nation.
The D.C. Council on Oct. 1 voted unanimously to approve a new law (B25-106) that lays out requirements for the installation of charging infrastructure in new construction or major renovations in the nation’s capital. Beginning on Jan. 1, 2027, new single-family construction that includes private, off-street parking will have to be “EV ready” ― that is, include wiring ― for at least a Level 1 charger, which essentially would mean a regular plug in a garage or driveway.
The law also requires a new pilot program to install chargers in low-income, disadvantaged neighborhoods in the city and calls on the District’s Department of Transportation to develop a comprehensive plan for ensuring the city has adequate charging infrastructure, to be updated every three years.
The Oct. 1 order from the Maryland Public Service Commission is more narrowly focused on the rates utilities charge for the electricity used to power chargers installed at multiunit dwellings (MUDs). The PSC order (Order No. 91339) guarantees that charging rates for MUDs will be similar to residential rates, rather than commercial rates that typically include high demand charges.
While they may vary from utility to utility, demand charges tend to be based on specific times of a customer’s highest electricity use, and for some apartment building or condominium owners, the high rates involved could make installation of an EV charger financially unfeasible, local residents told the PSC.
Under the new order, the utilities must offer such customers an EV charging rate equivalent to residential rates — either standard rates based on the volume of power used, or time-of-use (TOU) rates based on whether EVs are charged during on- or off-peak hours.
“One of the major reasons people hesitate to get an electric vehicle is ‘range anxiety,’ or the fear that they can’t envision how they will keep their car charged at home or out and about,” said D.C. Councilmember Charles Allen, who first introduced the D.C. legislation late in 2022 and has shepherded it through committee hearings and final amendments.
“We don’t have that fear with gas-powered vehicles because the infrastructure is built out,” Allen said in a statement announcing approval of the bill on its first reading before the Council. “It’s time to do that for electric vehicles. This is an infrastructure bill that sets goals and clears red tape to get more chargers installed where people actually want them.”
The bill must still pass a second vote before the council and be signed into law by Mayor Muriel Bowser.
The push for more chargers comes as the EV markets grow in both D.C. and Maryland. According to the AAI report, both have joined 10 other states across the country where EVs represented more than 10% of new light-duty vehicle registrations in the second quarter of the year.
The U.S. Department of Energy reported that D.C. had 8,066 EVs registered as of the end of 2023, while the federal Joint Office of Energy and Transportation counts a total of 324 publicly available charging locations in the city, with 1,070 charging ports currently in operation.
The federal figures for Maryland are 72,139 EVs registered as of the end of 2023, and 1,844 charging stations with a total of 5,178 charging ports currently in operation.
DC Law in Detail
Both of the new rules are aimed at getting chargers into neighborhoods and locations that have significant populations that live in apartments and would have to rely on public chargers.
Maryland’s rule taking demand charges out of the equation should remove at least one barrier for more installations, while the D.C. law takes a more comprehensive approach.
New apartment houses with more than six off-street parking spaces will be required to make 25% of those spaces EV ready beginning in 2027, and those percentages will go up to 29% in 2031 and 33% in 2034. Chargers in apartment houses are typically Level 2 chargers, which require upgrades to standard residential electrical wiring to support the higher voltage these chargers use.
New commercial buildings with more than six spaces will have to install chargers in 15% of their spaces and have an additional 25% EV ready.
The law also prohibits apartment building owners or condominium associations from prohibiting individual residents from installing EV chargers for their own use ― for example, in a designated parking spot ― subject to some conditions. A resident would have to use licensed electricians or building engineers for the design and installation of a private charger and would be responsible for paying for the electricity used by the charger, as well as for its maintenance.
The law also requires the D.C. Department of Transportation (DDOT) to establish a Neighborhood Electric Vehicle Charging Infrastructure Pilot Program, which by Jan. 1, 2026, will install at least one Level 1 charger in each of four low-income neighborhoods in the city. The chargers will be sited at publicly accessible locations, such as on streetlamps or utility poles, or in public parking lots owned by D.C., and the DDOT will be required to post a list of the locations on its website.
The Department of Energy and Environment (DOEE) is tasked with publishing an Electric Vehicle Infrastructure Deployment and Management Plan on its website, with the first report due also on Jan. 1, 2026, followed by updates in 2029 and 2032.
The reports will include the number of EVs currently registered in D.C., a 10-year forecast of EV adoption and DOEE’s plans to ensure that “the number of electric vehicle charging ports in the District is equal to at least 5% of the number of electric vehicles DOEE forecasts will be registered.”
The DOEE report must also assess the city’s electric grid capacity and whether it will be able to “meet and sustain the demand for electric vehicles.”
Growth of Leasing and Used EV Markets
Despite often downbeat headlines and U.S. automakers’ retreat from their earlier ambitious EV goals, both the AAI report and a third-quarter market update from industry analyst Cox Automotive show that EV sales are rising across the U.S.
AAI reports EVs represented just under 10% of new light-duty vehicle sales in the first half of the year, while Cox Automotive’s Stephanie Valdez Streaty, director of industry insights, similarly pegged EVs with close to 9% of the market.
The sales figures in both reports include full battery EVs and plug-in hybrids, but not traditional hybrids.
EV sales in the third quarter showed “steady demand, a slower pace, yet record sales,” Valdez Streaty said. “We’re on track for another record-breaking quarter, with a forecasted EV sales volume at 338,844, reflecting an 8% year-over-year increase.”
She noted also that both the second and third quarters have seen consecutive months with over 100,000 EV sales. August’s sales of 119,652 EVs were a new record, and a 12.6% year-over-year increase.
But EVs’ upfront cost is still a barrier, with the average EV price, about $56,300, still 15.9% higher than the industry average as of June this year, according to figures from Cox.
Both reports highlighted some key trends.
The AAI report noted that sales of cars with traditional internal combustion engines (ICEs) have peaked. ICE vehicles represented 97% of new vehicle sales in 2016 but only 78% in the year to date in 2024. However, that decline in sales is being filled in large part by traditional hybrid vehicles, not plug-ins. The traditional hybrid market grew from 2% of the new sales in 2016 to 12.3% through the second quarter of 2024.
AAI also counted 117 different electric models sold in the second quarter, including 68 full EVs, 47 plug-in hybrid models and two fuel-cell vehicles. SUV models continue to lead the market, accounting for more than 70% of second-quarter EV sales.
Valdez Streaty pointed to the popularity of leasing as a more affordable pathway for EV adoption as well as a growing source of used EVs for the secondhand market.
“EV leasing remains highly attractive to consumers, offering benefits such as lower upfront costs, reduced financial risk, flexibility to upgrade to new EV models and elimination of residual value concerns,” she said.
Leasing accounted for 39% of new EV sales in June, which is about double the general industry average, she said. Third-quarter sales for used EVs could hit around 78,000, a 69% increase year over year.
With most leases lasting about three years, Valdez Streaty said, “a wider range of vehicles will soon come off lease and enter the market, offering consumers more affordable and diverse options as we move towards an all-electric future.”
The PJM Deactivation Enhancements Senior Task Force (DESTF) has delayed voting on five proposals to rework the RTO’s rules for the advance notification generation owners must provide before deactivating units and the compensation structure for resources offered reliability-must-run (RMR) contracts.
Following several major changes to proposals presented during the group’s Oct. 2 meeting, participants requested additional time to understand where each package stands. An additional DESTF meeting was scheduled for Oct. 17 to open the vote, which will be conducted on the PJM website after the meeting closes. The Independent Market Monitor, Sierra Club and Calpine have each sponsored proposals in the DESTF, while PJM has sponsored two packages, one of which was presented for the first time Oct. 2.
The most significant changes were made to the Monitor’s proposal, with new language added that would model the expected output of RMR units in the capacity supply stack — counting them toward meeting the reliability requirement without mandating that they offer into Base Residual Auctions (BRAs) and take on Capacity Performance (CP) obligations
Monitor Joe Bowring has argued that not including RMR resources in the supply stack is inconsistent with PJM’s practice of modeling their output when calculating the capacity emergency transfer objective (CETO) and limit (CETL) for different delivery areas. Under the Monitor’s proposal, RMR resources would not be included in the day-ahead or real-time energy markets nor ancillary services unless required to maintain transmission reliability or resource adequacy. (See PIO Complaint Faults PJM Treatment of Deactivating Generation.)
Anti-toggling rules were also added to the Monitor’s package, stating that if a RMR unit ultimately decides not to deactivate after the contract term has begun, it would be required to refund capital recovery for improvements and maintenance to the appropriate load-serving entity.
The compensation rate in the Monitor’s package was adjusted to be based on short-run marginal costs (SRMC) rather than megawatt-hours, and an applicable adder of 10% of the deactivation avoidable cost rate was also added. Actual revenues would be the market revenues the RMR resource receives, such as energy and ancillary service payments, minus the SRMC for the unit.
A limit to the duration of RMR contracts was proposed by the Monitor, capping them at five years with a possible three-year extension. Any requests for an extension would have to be presented to the PJM membership at least a year in advance, where practical, so stakeholders can explore alternative solutions to resolving the underlying transmission violations.
PJM’s Package A pointed to the IMM’s language defining the compensation rate and would allow generation owners to choose between the Monitor’s net revenue compensation approach or the status quo cost-of-service option.
All five proposals would require generation owners to provide PJM with at least one year’s notice ahead of their desired deactivation date, while the RTO’s proposals contain exceptions for units that must retire to comply with government policies and catastrophic failures. PJM also added language granting exemptions for the requirement that resources must offer into capacity auctions for years when the unit would be granted deactivation.
The Monitor’s proposal includes exceptions for failures and a “clear regulatory order to retire,” which is mirrored by the Calpine package. The Sierra Club would allow early deactivation, within the one-year notification period, if PJM determines that there would be no reliability issues created by the retirement, along with catastrophic failures and policies that would make the resource uneconomic.
PJM also introduced a new Package D aimed at compromising with some of the changes made to the Monitor’s proposal. It would remove the $2 million limit on project investment costs recoverable through the default compensation rate and rework the default avoidable cost credit (DACC) calculation when it is used for determining compensation. Other components are based on Package A.
David “Scarp” Scarpignato, of Calpine, said it would be inappropriate to move to a vote immediately after major changes were presented to proposals that could change stakeholders’ voting positions. Several changes would also need to be made to the Calpine proposal, which contained references to the original IMM and PJM packages for some components.
Calpine’s proposal would preserve the status quo compensation rate with a 20% applicable adder and adopt the Monitor’s components on actual revenues, RMR term limits and requiring RMR agreements to be public. The company copies PJM’s language on notification timelines. Calpine’s anti-toggling rules would require an RMR unit that reverses its retirement during the RMR term to refund LSEs for payments toward capital improvements. The requirement would also be effective for units that return to serve two years after deactivation.
The Sierra Club proposal largely mirrors the Monitor’s language, but it would subject RMR units to CP penalties for underperformance with an annual stop-loss set at the BRA clearing price per megawatt.
Package sponsors discussed both notifying other parties with proposals of any significant changes ahead of the Oct. 17 meeting and replacing cross-package references with specific language to avoid repeat conflicts. There were also requests for PJM to draft a document or presentation that details the differences between each proposal.
The Rhode Island Energy Facility Siting Board (EFSB) ruled Oct. 3 that it has jurisdiction over large battery storage projects, overruling precedent and giving the board the ability to override local permitting decisions on storage projects if it deems a project has met all the legal requirements (SB-2024-01).
In April, the Quonset Development Corp. (QDC) requested the EFSB declare a proposed 210-MW battery project is outside the board’s jurisdiction, arguing the EFSB has determined “it does not have jurisdiction over battery energy storage systems.”
The prior precedent stems from a 2019 EFSB ruling that a 180-MW storage resource is not under the jurisdiction of the board because the state’s Energy Facility Siting Act does not reference battery storage (SB-2019-02).
QDC also argued the EFSB does not have jurisdiction over a substation, tie line and switchyard needed to connect the battery to the transmission system, writing that the 115-kV tie line “is not a transmission line” and instead is “a line that connects a non-generating battery energy storage system for the purpose of storing and discharging electricity.”
The EFSB wrote in its ruling the question of jurisdiction hinges on “whether the project itself or any component thereof falls within the definition of a ‘major energy facility,’ as defined by the Energy Facility Siting Act.”
The definition includes “facilities for the generation of electricity designed or capable of operating at a gross capacity of forty (40) megawatts or more.”
While QDC argued this definition does not apply to battery storage, the EFSB disagreed, highlighting language from ISO-NE and FERC that categorizes battery storage as a type of generation.
“It would be illogical for the state and federal definitions to collide with each other, especially when the energy industry is inherently interstate in nature and Rhode Island is inextricably dependent upon the regional electric system for continuous reliable service,” the EFSB wrote.
Regarding the precedent set by its 2019 ruling, the EFSB wrote that it “respects the importance of following the reasoning of prior cases and adhering to settled rules,” but added it ultimately is “not bound by its prior decisions and can depart from its own precedents, as long as the agency explains why such a departure is reasonable.”
The EFSB also highlighted the implications the ruling could have on the state’s clean energy goals. This year, Rhode Island set a target of installing 600 MW of storage by the end of 2033; the project at issue in the ruling would meet over a third of this goal. (See RI Sets 600-MW Energy Storage Target.)
While no local permits would be required for this project, which would be in an industrial park, local permitting could pose “an insurmountable obstacle” for future battery projects in the absence of EFSB jurisdiction, the board wrote. The EFSB can overrule local permitting decisions for projects under its authority.
The EFSB similarly found that it has jurisdiction over the infrastructure needed to connect the battery facility to the transmission grid.
“Given the numerous FERC cases unambiguously illustrating that generator tie lines are jurisdictional transmission facilities, the claim made by petitioner that the 115-kV Generator Tie Line is not serving a transmission purpose is contradicted by FERC precedent and, therefore, is unsustainable,” the EFSB found.
It added that a lack of EFSB jurisdiction over interconnection infrastructure “could have been devastating to the ability of an offshore wind developer in the future to interconnect its project to the transmission system within or through Rhode Island, given the potential for local opposition.”
The EFSB said the project developer must submit an application for the battery facility and its associated electric infrastructure.
CAISO on Oct. 7 described to stakeholders how it will apply the Extended Day-Ahead Market (EDAM) transmission revenue recovery mechanism to its own balancing authority area.
The mechanism, referred to as the EDAM access charge, will allow transmission owners (TOs) to recover transmission revenue shortfalls attributed to transitioning their assets into the day-ahead market.
The access charge was the only provision of CAISO’s initial EDAM tariff proposal that FERC rejected last December, finding the ISO failed to justify the reasons behind the three components constituting the charge. CAISO revised the plan and it was accepted by the commission in June. (See FERC Approves EDAM Tx Revenue Recovery Plan.)
During the Oct. 7 meeting, CAISO staff gave an overview of how the access charge could be applied within the ISO through an explanation of the plan’s three components for calculating and recovering lost revenue after launch of the EDAM.
The first component allows TOs to recover historical transmission revenues associated with wheeling access charge (WAC) revenues.
“When an EDAM entity joins the EDAM, the intertie point becomes a transfer point between the ISO and that EDAM entity, and there may be an impact on wheeling access charge [WAC] revenues that were historically recovered across that intertie,” Milos Bosanac, CAISO regional markets sector manager, said at the meeting. “This component 1 allows for the recovery of those historical WAC revenues at that particular intertie to the extent that there’s an impact.”
The WAC revenues eligible for recovery under the mechanism will be based on a three-year average of revenues prior to that transfer point becoming an EDAM point, Bosanac explained. The draft tariff revision states that each TO will be responsible for calculating the first component.
Heather Curlee, senior counsel at CAISO, dove into the draft tariff language to implement the access charge in the ISO and provided additional details on the plan’s components.
The second component seeks to compensate TOs for costs “associated with forgone transmission sales on eligible existing contracts or [transmission] upgrades” that potentially increase the transfer capability between EDAM areas. Recovery of those costs would again require analyzing the three-year historical average of recovered revenues on a particular EDAM transfer point and comparing it to the overall ratio of the total transmission revenue requirement within the BA.
According to the tariff, a participating TO with existing contracts will calculate the second component, to include revenue shortfalls associated with the release of transmission capacity resulting from expiring existing rights not included in the first component.
The third component centers on compensating CAISO TOs for EDAM wheel-through transfers that provide benefits for other parts of the market footprint.
The draft tariff revisions say that in periods when the total volume of EDAM wheel-through transactions exceeds the total net transfers of the CAISO BA, the ISO will calculate by multiplying its share of the excess volume based on its individual share of transmission revenue requirements in relation to total transmission revenue requirements for the CAISO BA.
CAISO will distribute to gross load in the ISO BA each EDAM access charge allocated to its BA, according to the proposed tariff revision.
The ISO plans to file the draft tariff language with FERC in November.
ERCOT CEO, State Rep Preview 2025 Texas Legislative Session
AUSTIN, Texas — The Gulf Coast Power Association again reported a record attendance — just over 800 — for its annual Fall Conference held Sept. 30 to Oct. 2, with discussions on the industry’s future, emerging grid technologies and Texas’ 2025 legislative session.
ERCOT CEO Pablo Vegas and state Rep. Todd Hunter (R) — chair of the House State Affairs Committee, which oversees the Texas grid — kicked off the conference with a fireside chat that included their expectations on the 89th Texas Legislature, which convenes Jan. 14.
“Here’s the bottom line for all the questions I get every place I go: labor, water, power. I bet I get contacted every two to three weeks by new groups coming to look at Texas,” said Hunter, often referred to as “The Man in Black” around the Texas Capitol for his wardrobe choice. “So what’s on the legislative agenda? One, I think you will see a push by the legislature to do what we can to increase power resources. Texas, I think, is the fastest growing state. The demands are huge. And what does that mean? Water, labor and power.
“The message from me: What’s on the plate is to do everything we can meet the needs.”
Vegas said ERCOT works “incredibly closely” with Hunter’s committee and that there isn’t a “big gap” operationally between what the grid operator has and what it will need for the next few years. The sessions that followed Winter Storm Uri of February 2021, he said, “have set us up for the growth trajectory that’s in front of us.”
“One thing that maybe we’ll spend a little bit of time on is talking about how to best manage the influx of different types of large loads that are coming to Texas,” Vegas said. “That’s something that is an evolving and changing dynamic. … Whether it’s data centers; whether it’s hydrogen developers; whether it’s the electrification that we’re seeing out in the Permian [Basin], there’s going to be a wide variety of opportunities to work with these customer groups to find ways to help them grow reliably and rapidly, because Texas does have one of the most fertile environments for economic growth. I think we’re going to be really well positioned for a constructive legislative session.”
Moderator Barbara Clemenhagen, GCPA executive director, asked whether ERCOT will continue its post-Uri conservative operations posture in which it sets aside several thousand megawatts each day to respond to tight situations. Vegas responded that as an “energy island,” the grid operator can’t lean on its neighbors to protect a “flagship competitive market that is studied and looked at very closely around the world.”
“This competitive market works, and I believe that it can work in the changing environment that’s coming our way,” Vegas said. “We have one of the most dynamic set of resources that are providing energy; that can come and go and fluctuate their intermittency on the wind and solar side. We need to have a lot of these reserve resources to be able to manage that because we can’t lean on anyone else. This is what we have to do in order to ensure we can be reliable on a regular basis. I don’t believe consumers or stakeholders are comfortable with living on the edge of a grid that could be an emergency condition on a regular basis.”
ERCOT Deals with Uncertainty
ERCOT’s Dan Woodfin, vice president of system operations, said the pace of change in generator types has been so “tremendous” that the ISO’s operators are having to learn a new system every six months.
“Operators like to have rules of thumb about how they operate,” he said. “A couple of years ago, we had a lot of wind and a little bit of solar. Last summer, we had more solar and a few batteries. And this year we have more solar and more batteries. And next year, we’re going to have twice as much solar, potentially, and a lot more batteries. That means every six months or so, we throw away all our rules of thumb and we’re operating a new system.”
Woodfin said four issues must be considered in adapting the grid to new technologies: adequacy, uncertainty, variability and stability.
“If you’re involved in the ERCOT stakeholder process, you will recognize those things as being the underlying factors behind most of the major debates that have gone on in the last year or so,” he said. “Managing the sunrise and sunset ramps is going to become increasingly critical. Now, the increasing number of batteries help manage other resources’ variability, but then we have to make sure we’re not overly depending on them beyond their inherent limited duration.
“There’s also the managing of the uncertainty because some of that we can predict. I’m pretty good at predicting when the sun’s going to come up and when the sun’s going to go down every day,” Woodfin continued. “But as we get more wind and solar, even if we’re driving down the percentage error in terms of our forecast, the errors continue to grow with the additional installed capacity. So there’s just a lot of variability and uncertainty growing.”
PUC Exes Praise SPP
A panel of former Texas regulatory commissioners shared their perspectives on recent shifts in energy policy and offered their thoughts on improving the stakeholder process and communications between ERCOT’s Technical Advisory Committee and the Board of Directors.
“What’s the right way to kind of think about efficient, inclusive and successful [relationships]?” asked Pat Wood III (1995-2001). He noted recent comments by Public Utility Commission Chair Thomas Gleeson that the interaction between the board and TAC “did not work” for him. (See “Members Discuss Stakeholder Process,” ERCOT Technical Advisory Committee Briefs: Sept. 19, 2024.)
“There’s a disconnect, seemingly, between all these arguments that are happening at TAC and what the board eventually deliberates on,” said Will McAdams (2021-2023). “But I believe we don’t need to reinvent the wheel. Other ISOs have crossed this Rubicon before.”
McAdams offered SPP’s Members Committee as an example. The 23-person committee, comprising several different stakeholder segments, debates issues and provides an advisory vote for the board before the directors cast their ballots.
“The Members Committee is a great tool … and none of this requires statutes, by the way,” McAdams said. “I think it could be self-adopted, but … some type of equivalent organization that may not be empowered to have a binding vote … where the board will see the arguments from the industrial segment; the industry segment; the utility segment. They’ll know exactly what they’re getting into with their vote.”
“I 100% agree with that,” Pedernales Electric Cooperative CEO Julie Parsley (2002-2008) said as Brandy Marty Marquez (2013-2018) nodded her head in agreement.
“SPP has been great because they sit at the table; they argue,” Parsley said. “They vote, right? But they’re not the controlling vote. They just vote, and then the independent board members vote. [The members are] in front of them. They’re not off in some committee room at TAC, so they hear it all, and it’s really great.”
Marquez, McAdams and Parsley all represented Texas on SPP’s Regional State Committee.
DOE’s Biddle Spotlights Clean Energy
Bearing what she called “the longest title in the world,” Leslie Biddle — the U.S. Department of Energy’s deputy under secretary for commercialization and finance — issued a call to action for utilities, regulators and the rest of the industry to “rethink our go-to solutions” for adding new generation.
“So how do we do that in a way that addresses the baseload needs?” she asked her audience. “I’m so excited to be here because we do also need to change the culture; we need to use things differently than we have in the last couple decades. For a few decades now, we’ve been using the same labor to build centralized generation and associated transmission and distribution to meet those long-term human needs. It worked … but we haven’t really had to innovate, and we haven’t had to adopt new ways of working, and we will.”
Case in point: DOE’s latest in a series of liftoffs reports, Pathways to Commercial Liftoff. Thanks to the Infrastructure Investment and Jobs Act and the Inflation Reduction Act, the department is positioned to invest billions of dollars in large-scale demonstration and deployment of clean energy technologies it says will be needed to meet rising demand.
Biddle pointed to a slide that listed more than $6 billion in investment for two dozen awards for projects in Texas and Louisiana. They included $1.2 billion to X-energy to develop gas-cooled reactors and another $1.2 billion for a hydrogen hub involving Chevron, ExxonMobil and Air Liquide, among others.
“We expect this all to be built in the next four years,” she said. “Our capital goes in currently for the development stage.”
DOE says it expects 15 to 20% growth in demand over the next decade and for it to double by 2050, driven by economic development and electrification.
“It’d be hard to say that we aren’t surprised about the electricity demand growth over the next decade, when you’re telling everyone that they should electrify. That’s what happens,” Biddle said. “From our perspective, growth is good. It means that we’re bringing in more manufacturing jobs, and we’re expanding our leadership and innovation and expanding artificial intelligence and expanding access to more efficient clean growth in America. It will require a change in the way we invest and manage our system. Fortunately, we have the technologies and the solutions we need to meet the growing demand.”
AI as Savior for Clean Energy?
DOE could find help in reaching its net-zero-emissions goals from an unlikely source, according to several panelists discussing artificial intelligence.
“I’m going to say something slightly controversial, but I feel that AI and the computing power and all of that, even though in some ways it’s consuming more … we need AI to get us to net zero because of the sort of second-by-second optimality that we need,” said Erin Boyd, chief digital commercial transformation officer for AES. “All of the data goes into getting more out of our assets and finding better locations and managing demand and supply just down to that sort of microsecond.
“Even though everybody says, ‘Oh, AI is driving up energy demand,’ it’s an interesting problem where I’m not so convinced yet that that’s the case. I believe that AI is actually what’s going to get us to net zero and a situation where we’re actually consuming less, but also consuming energy that’s uncertain; that’s fickle, that you know can’t be managed.”
“I’m also very upbeat about the potential for AI,” said Venkat Tirupati, ERCOT’s vice president of DevOps and grid transformation. “I look at it from two different angles. The first angle is just on grid operations and market operations. There are definitely things that will help us to be more efficient to run markets very well. But if I look at ERCOT as an enterprise, there are a lot of productivity gains that we could get by just embracing AI into the everyday.”
PUC’s Roth Gets Award
The GCPA honored the PUC’s Werner Roth with its emPOWERing Young Professional Award, presented annually to individuals under the age of 40 who have demonstrated excellence in the electric power industry, made unique contributions to the power market’s success, and served as a role model and leader for others.
Roth, a senior market economist in the market analysis division, has worked at the commission for more than 10 years. He holds bachelor’s and master’s degrees in economics and another bachelor’s degree in chemical engineering.
“I have often wondered how a young graduate without experience in the electric markets could develop such deep and wide skills for power markets,” said Harika Basaran, the division’s director. “Then I realized that he did most of it on his own initiative.”
Roth thanked the commission’s leadership for allowing him to “lean in on a lot of the projects that have focused on a lot of issues in the ERCOT process and, more importantly, have enabled staff to [provide] perspective on those
The proposed reliability standard to require ride-through protection for inverter-based resources (IBR) cleared a major hurdle last week by passing a formal ballot round after multiple previous attempts to get it over the finish line ended unsuccessfully.
Now the way is clear for NERC’s Board of Trustees to vote on it and four other standards whose passage is required to meet FERC’s deadline of Nov. 4 to submit the first of three tranches of IBR-focused standards. Those votes are set to take place at a special board meeting scheduled for Oct. 8.
The formal ballot for PRC-029-1 (Frequency and voltage ride-through requirements for IBRs) concluded Oct. 4 with 158 votes cast in favor of passage and 50 votes against (with comment); 59 ballot pool members either abstained or did not vote. After applying NERC’s segment weighting, which lowers the impact from segments with fewer voters, the final result is a 77.88% weighted segment value supporting passage, comfortably above the two-thirds majority needed for passage.
Failing to meet the two-thirds threshold would not necessarily have prevented PRC-029-1 from passage. Under Section 321 of the ERO’s Rules of Procedure — invoked for the first time by NERC’s board at its August meeting — the standard could have been considered approved with a 60% segment-weighted majority. (See “Board Invokes Standards Authority to Meet IBR Deadline,” NERC Board of Trustees/MRC Briefs: Aug. 15, 2024.)
In that case, the board would have had to solicit written public comment on the proposed standard. If satisfied the standard was just, reasonable, not unduly discriminatory or preferential, and in the public interest, it then could file it with FERC.
The Section 321 authority also required NERC’s Standards Committee to conduct a technical conference to solicit input from industry stakeholders. At the technical conference, held Sept. 4-5 in Washington, D.C., representatives from a range of industry segments — including original equipment manufacturers and utilities — discussed their objections to the proposed standard. (See NERC, Industry Discuss IBR Issues in Technical Conference.)
Following the conference, NERC revised the standard to address attendees’ concerns, including the clarity of the definition of “ride-through,” criteria for frequency ride-through performance and exemptions to ride-through criteria for equipment with hardware limits. Most stakeholders commenting on the revised draft felt the changes reflected opinions expressed at the conference, though many also felt more could have been done to accommodate concerns.
In a long comment, Jens Boemer of the Electric Power Research Institute said the new draft standard “appears to be improved” and expressed appreciation for the standard drafting team for taking the comments of EPRI and others on board. However, he also indicated “further improvements” would be welcome, including:
further clarification of the definitions of IBRs and the term “ride-through,” and specific grid conditions for which the ride-through requirements apply.
guidance for determining the maximum capability of an IBR.
exemptions for legacy equipment that may be challenging to update because of lack of manufacturer support.
At its meeting Oct. 8, NERC’s board will vote on submitting PRC-029-1 to FERC for approval, along with the other IBR standards approved in previous ballot rounds:
PRC-024-4 — Frequency and voltage protection settings for synchronous generators, Type 1 and Type 2 wind resources, and synchronous condensers.
PRC-028-1 — Disturbance monitoring and reporting requirements for inverter-based resources.
PRC-002-5 — Disturbance monitoring and reporting requirements.
The board also will consider accepting revisions to the charter of NERC’s Reliability and Security Technical Committee (RSTC) that are intended to improve the balance of industry representation at meetings. The new rules will allow a sector to seek a special election to fill an open seat representing it, rather than have that seat convert to an at-large member as the current charter provides.
In addition, they will remove the numerical cap on the number of representatives from a sector that can serve as at-large members and will direct the RSTC Nominating Subcommittee to prioritize balanced sector representation.
FERC has issued a deficiency letter over SPP’s proposed revisions to its tariff, bylaws and membership agreements intended to facilitate nine western entities’ RTO membership as transmission owners.
In an Oct. 3 letter, the commission said SPP’s filings are deficient and that it needs more information to process them. It asked the grid operator to submit its responses by Nov. 4 (ER24-2184, ER24-2185).
FERC asked for more information on:
Any existing tariff provisions that will facilitate the transition of the new members’ transmission service request queues into SPP’s current service-study processes.
The proposed tariff’s provision that the Western Area Power Administration-Colorado River Storage Project’s replacement energy is “necessitated by WAPA-CRSP’s inability to deliver sufficient energy from reservoir projects under the control of the U.S. Bureau of Reclamation in the marketing area of WAPA-CRSP for reasons such as persistent drought or environmental constraints.”
New metered boundaries and the need to establish a second balancing area authority that will be incorporated into SPP’s markets.
How separate reference buses in the market’s two balancing authority areas will accurately model the marginal cost of serving load in each BAA, including the cost of congestion.
How LMPs on both sides of the West DC ties will inform how SPP optimizes the interties’ usage.
Which rate(s) under the tariff revisions would apply to point-to-point transmission service where the load is located within a BAA external to the SPP Region but not interconnected to SPP’s eastern or western market.
SPP filed the tariff for its western RTO expansion in June as it seeks to become the first grid operator with markets in both the Western and Eastern Interconnections. It says its RTO West will provide more than $200 million in annual benefits to its members. (See SPP Files to Incorporate Western Entities into RTO.)
RTO West is scheduled to go live in April 2026.
FERC also filed a deficiency letter for SPP’s Markets+ tariff, another of the RTO’s western services. Saying deficiency letters are part of a “routine process, SPP staff responded to the letter in September and asked for an order by Nov. 20. (See SPP Dispels Concerns over Markets+ Deficiency Letter.)
NYISO on Oct. 4 released the first draft of its 2024 Reliability Needs Assessment (RNA) showing a capacity deficiency in New York City beginning in 2033 and proposing to declare a reliability need for its zone.
The deficit is driven by a combination of forecast increases in peak demand and the looming retirement of small gas plants in the city, NYISO said. The analysis found that on a peak summer day with expected weather conditions (95 degrees Fahrenheit), the city would be deficient by 17 MW for one hour in 2033, rising to 97 MW for three hours in 2034.
“This is based on the transmission security analysis and the feeding into the transmission security margin,” Ross Altman, senior manager of reliability planning for NYISO, told the Electric System Planning Working Group. “This is an actionable reliability need.”
The declaration of a reliability need triggers a process in which NYISO solicits solutions, including transmission-based from the local transmission owners, and generation and demand response from market participants. The ISO declared a short-term reliability need for the city last year, finding a potential 446-MW shortfall by 2025. It later decided to keep two natural gas peaker plants, collectively 565 MW, in Brooklyn operational beyond their state-mandated retirement as a solution. (See NYISO to Keep Gas Peakers Online to Solve NYC Reliability Need.)
The assessment assumes those units to no longer be available beginning in 2026. The state also recently enacted legislation to retire seven small New York Power Authority gas-fired plants in the city and Long Island worth 517 MW by the end of 2030.
“The reliability need could be met by combinations of solutions, including new generation, retention of planned generation retirements, transmission, energy efficiency, demand response measures or changes in operating protocols,” the draft says. “Specifically, scenarios performed in the RNA indicate that the New York City transmission security deficiency could be resolved by resources currently under development but not yet in the base case.”
NYISO had reported the possibility of such a deficiency for the city, but it had been overshadowed in meetings by a preliminary finding of a statewide shortfall of as much as 1 GW by 2034. The ISO, however, updated its assumptions about the flexibility of large loads — specifically, cryptocurrency mining and hydrogen-producing facilities — which reduced its loss-of-load expectation to less than 0.1.
Still, the ISO warned in its draft that the LOLE is “extremely close” to the maximum: 0.094. “The tightening margins are a significant concern that … NYISO will closely monitor and re-evaluate in future [Short-Term Assessments of Reliability] and the next cycle of the Reliability Planning Process.”
“We are just under a violation, and a big factor of that is the treatment of large loads,” Altman said.
Large Load Flexibility
Several stakeholders questioned how NYISO determined how certain large loads would be flexible and criticized the lack of any data on the topic.
“In your evaluations, did the cryptocurrency load representatives — whatever they are called — give you any idea about how much notice they would need to curtail their load?” asked Mark Younger, of Hudson Energy Economics.
Altman said he did not know and that he did not want to get too detailed on what NYISO discussed with the cryptocurrency companies because such information was “proprietary.”
“They provided enough information that [made NYISO] feel they would be flexible, either sensitive to prices or demand response,” Altman said. NYISO did not forecast the price of Bitcoin or other cryptocurrencies, he said.
“For other resources, whether it’s SCRs [special-case resources] or generators, … NYISO has tariff provisions and other goals that require submission of information so you guys can track what’s going on,” said Kevin Lang of Couch White. “This is the only place I can think of where there’s absolutely nothing — no reporting requirements, no obligations — … and yet from the tables you’re showing us, if these loads continue to operate during peak periods, we have a very significant problem.”
“We are engaged in bilateral discussions and surveying with these large loads in terms of the nature of these large loads and their intention to operate,” said Tim Duffy of NYISO, explaining that operating procedures and interconnection studies were also sources of information. “NYISO is really reliant upon transmission owners to gather that data.”
“I appreciate the explanation, but I just think, given how critical this is to your assumptions, that there should be something more formalized with these loads,” Lang replied.
Tight Deadlines, Annoyed Stakeholders
Stakeholders expressed numerous criticisms of the draft’s publications, including the lack of an executive summary: The opening section simply says “Reserved for future drafts.”
They were also annoyed that NYISO released the draft on a Friday, with multiple stakeholder meetings scheduled that day, with a deadline for comment the following Monday (Oct. 7).
“I am going to bust your chops,” Younger said. “The ISO needs to be rethinking the timeline that they hope that market participants can provide useful feedback on this, given how late it came out and also given that it came out at the same time that many of them are dealing with a critical step in the Demand Curve Reset, a timeline that was well known in advance.”
Several sections, including those detailing the New York City reliability need and the narrowly avoided statewide need, were worded confusingly, stakeholders said.
“My personal opinion is that NYISO has bungled some of the communication efforts around recent reliability reports,” said Chris Casey, utility regulatory director for the Natural Resources Defense Council. “I think it’s important for us to have time to be able to not only understand what the data and findings are, but make sure the narrative matches reality. I don’t think we were given time to do that here.”
Doreen Saia of Greenberg Traurig requested that NYISO allow more time for discussion at the working group’s meeting Oct. 9.
“We are going way too fast on an area that is completely charting new ground,” Saia said.
Lang pointed out that NYISO had provided executive summaries on previous RNA reports for 2018, 2020 and 2022.
“You are going way too fast, and you aren’t giving market participants sufficient time to understand what’s really going on here,” Lang said.
Dramatic spikes in New Jersey electricity bills over the summer stemmed from the combined effects of an unprecedented heat wave and recent rate increases, utility executives said at a state Assembly hearing.
Electricity use in June and July shot up by 15 to 20% in some areas over the same period in 2023 in what the New Jersey Board of Public Utilities (BPU) said was the hottest June on record.
The Oct. 2 Assembly hearing also spotlighted the need to better cope with the state’s growing need for electricity and how to bring new generation sources online to replace retired fossil fuel sources.
The hearing came as Gov. Phil Murphy (D) pursues an aggressive energy policy centered on electricity and the development of 11 GW of offshore wind capacity. Republican lawmakers argue the state is moving too fast and should embrace a broader energy portfolio.
The Assembly Telecommunications and Utilities Committee convened the hearing in response to widespread customer complaints about the sudden increase in the size of their bills.
“I received countless calls from my constituents because they are seeing what I have been seeing — skyrocketing electric bills,” Assemblywoman Andrea Katz said in testimony to the committee. “I heard it from my neighbors, and I saw it on my own electric bill. Utilities like Exelon have seen their stocks up 10% over the last year, while at the same time, families in New Jersey are paying hundreds of dollars more a month for their electric bills. … And we all need answers.”
BPU President Christine Guhl-Sadovy said the “main driver of the increases over the summer was an increase in usage.”
Customer use across the four utilities that serve the state — PSEG, Jersey Central Power & Light, Atlantic City Electric (ACE) and Rockland Electric Co. — increased by 12 to 16% over the previous year, which was relatively cool with unusually low use, she said.
In addition, she said, the BPU certified a rate hike that would increase the average customer bill by 5 to 8% due to electricity rates set in the Basic Generation Service (BGS) auction held by the four utility companies.
Multiple Rate Hikes
Brian O. Lipman, director of the New Jersey Division of Rate Counsel, said the rate hike was one of several implemented by utilities that affected customers for whom, given the elevated temperatures, “air conditioning is no longer a luxury, it is life saving.”
In testimony, and in a supporting letter to the committee, he said ACE had increased rates nine times since July 2023, and reduced rates four times, for a net overall increase. These included increases for transmission rates, infrastructure improvements, and prices set by the BGS results, which increased electricity supply rates by about $7.56 per month, he said.
Even before the use increase, the average ACE ratepayer was paying about $23.64 more in June 2024 than a year earlier, Lipman said.
Add during the heat wave and “the result is significantly higher bills for ACE customers in the summer of 2024 as compared to the summer of 2023,” he said in the letter. “This analysis does not only apply to ACE. I could go through the same analysis for PSE&G, JCP&L and Rockland Electric Co.”
Speaking at the hearing, Phil Vavala, ACE’s regional president, said the average customer bill increased by 20%, part of which was due to the “pass-through” cost of electricity rates, which are set at the BGS auction.
He said the company works to “empower customers to better manage their energy use.” That includes providing customers with programs that “help those who are struggling to meet their energy needs” and to deploy smart meters that enable customers to better monitor their energy use, he said.
Electricity Demand Surge
Several speakers said the spike in customer bills showed the state has to address far larger systemic issues.
“One of the main takeaways that we probably will all share today is that we do need more generation,” Guhl-Sadovy said. “We, over the last couple of decades, have not seen a significant demand increase in energy use, in part because we’ve done a really good job in energy efficiency. And so we’ve helped to keep that demand flatter. But we have seen energy demand go up, and so we do need more generation.”
BPU officials said at an Oct. 1 hearing into the agency’s offshore wind infrastructure solicitation that they expect demand for electricity in the state to increase by 15,000 GWh to 93,000 GWh by 2025. (See related story, NJ Offshore Infrastructure Plans Spark Electromagnetic Fears.)
Jason Stanek, executive director of PJM Interconnection, which serves 13 states, said the region is in the midst of a transition.
“We’re seeing a tightening of supply and an increase in demand,” he said. “And they’re going in opposite directions relatively quickly.”
He said the RTO’s load forecast released earlier in the year showed trend lines that were “head and shoulders above all prior years.” That increase stems in part from the rise in electric vehicle use and the emergence of commercial high-energy users such as data centers and artificial intelligence facilities, he said.
An example of the challenge facing PJM, he said, is that in the 12 months prior to the summer of 2024, the RTO experienced 4,000 MW of generating source retirements, while peak demand rose by 4,000 MW.
“So that’s an 8,000-MW difference in just a short period of 12 months,” said Stanek, adding that such a sudden increase in demand is difficult for PJM to handle. A shortfall in supply compared to demand can increase the price of electricity. That was demonstrated in the results released in July of the organization’s recent capacity market auction, which set electricity prices nearly 10 times higher than a year ago, he said.
Stanek urged lawmakers to help PJM, and the region, better handle the ongoing demand surge by avoiding policies that are “designed to push resources off the system before we have an equal and equivalent amount of replacement resources.”
At the same time, PJM is working through a backlog of customers waiting to connect new sources to the system, he said.
