FERC on Oct. 8 granted and denied in part challenges to Pacific Gas and Electric’s 2022 transmission rates, finding that PG&E must remove certain costs from its rate base while also denying a request to pause the utility’s ability to recover costs stemming from two massive fires in California.
The order concerns PG&E’s rate year 2022 information filing, which reflected increased costs in both retail and wholesale base transmission revenue requirements (TRRs) (ER19-13).
The utility reported that its retail base TRR would increase from approximately $2.214 billion to $2.812 billion, while its wholesale base TRR would rise from about $2.202 billion to $2.799 billion.
The California Public Utilities Commission and the California cities of Anaheim, Azusa, Banning, Colton, Pasadena and Riverside challenged the update. FERC handed wins to both sides in its decision while also scheduling some issues for hearing and settlement judge procedures, according to the order.
In siding with the challengers, FERC found that PG&E cannot claim that its vegetation management, such as tree removal, is similar to initial construction activities, which would have allowed PG&E to tack those costs onto its rate base. Instead, FERC ordered PG&E to reclassify such costs as operating and maintenance expenses and remove the costs from its rate base.
“PG&E has not demonstrated that tree removal associated with its [right of way] expansion qualifies as a substantial addition to plant nor a construction of a new asset, and accordingly, PG&E must record such costs in the appropriate O&M expense account,” the order stated.
However, FERC denied CPUC’s request for an order requiring PG&E to remove costs related to the 2019 Kincade Fire and the 2020 Zogg Fire. The devastating fires burned thousands of acres and destroyed hundreds of buildings in Northern California, and CPUC has hit PG&E with severe penalties over the utility’s alleged role in those fires and others. (See CPUC Fines PG&E $45M for 2021 Dixie Fire.)
In its 2022 challenge, CPUC asked FERC to avoid holding ratepayers responsible for the wildfire recovery costs until liability had been determined in various pending investigations and regulatory proceedings, according to the order.
FERC denied the challenge in the Oct. 8 order, finding that it rejected a similar challenge in San Diego Gas & Electric’s formula rate annual update in 2016.
“Consistent with this precedent, we are not persuaded to hold the allowance of costs at issue in this proceeding in abeyance pending resolution of the state criminal, investigatory and regulatory proceedings,” the order stated. “As in the SDG&E proceeding, the ongoing and potential state proceedings CPUC describes could take significant time to resolve, meaning that this proceeding would ‘be held in abeyance for an indefinite period of time.”’
FERC noted that its order “does not limit any party’s right to challenge the justness and reasonableness of the allowance of costs associated with the Kincade and Zogg fires in subsequent PG&E annual informational filings, including by pointing the commission to any relevant information that may emerge from state proceedings regarding the Kincade and Zogg fires.”
Additionally, FERC rejected challenges to PG&E’s accounting of costs related to upgrades to transmission towers, monitoring systems and a boardwalk replacement program.
CPUC also targeted insurance proceeds, wildfire-related costs and costs associated with removing the PG&E-operated Caribou-Palermo transmission line, which failed in 2018, resulting in the Camp Fire, one of the deadliest in California’s history. (See Ancient C Hook, Financial Manipulation Caused Camp Fire.)
Similarly, CPUC argued that ratepayers should not bear the burden of reconnecting the Grizzly Powerhouse, a hydropower project, to the transmission grid, saying that “would not be necessary but for the Camp Fire,” according to the order.
However, FERC declined to take a position on those challenges, finding that the matters “raise issues of material fact that cannot be resolved based on the record before us.” Instead, the commission sent the matters for a trial-type evidentiary hearing but encouraged the parties to reach a settlement before hearing procedures commence.
Representatives for the parties did not return requests for comment.
A Brattle Group study comparing key features of CAISO’s Extended Day-Ahead Market and SPP’s Markets+ contains “several material misstatements of facts” and overlooks evidence “directly contrary to its conclusions,” Powerex contends in an Oct. 7 brief criticizing the study.
The brief from the energy trading arm of Canada-based BC Hydro comes in response to a white paper Brattle published Oct. 1 that sets out a point-by-point comparison of seven design features of the EDAM and Markets+, including transmission optimization, fast-start pricing, real-time unit commitment (RTUC), procurement of imbalance and flexibility reserves, seams optimization, greenhouse gas pricing and congestion revenue allocation. (See Brattle Study Likely to Fuel Debate over EDAM, Markets+.)
All those features have figured prominently in the often-contentious debate between supporters of each market, which increasingly is playing out in various back-and-forth studies and presentations, as well as a series of “issue alerts” published by a core group of Markets+ funders — which includes Powerex.
Fast-start Conflict
In its brief, Powerex contends “the failure of the Brattle paper to provide a credible and fact-based examination of the market design differences is clearly evident in its discussion of fast-start pricing [FSP].”
While Markets+ supporters argue that FSP is an important benefit of the SPP market that’s conspicuously absent from CAISO’s markets, the Brattle paper played down the importance of the mechanism, saying evidence from several RTOs in the East — including SPP — shows FSP has minimal impact on market prices or revenues for fast-start resources.
Brattle questioned the viability of a 2022 study conducted by consulting firm Energy GPS for Powerex and the Portland, Ore.-based Public Power Council (PPC), which analyzed potential impacts on CAISO markets if the ISO were to implement FSP.
In his initial reaction to the Brattle study, Jeff Spires, director of power at Powerex, told RTO Insider that Brattle misrepresented the results of Energy GPS’ analysis and failed to include the most recent data from the Eastern RTOs showing the benefits of FSP.
The Powerex brief builds on Spires’ points, for example asking why Brattle chose to present MISO’s FSP analysis from 2015 and 2016 when more recent data are available online.
“This is a glaring omission, as later reports paint a very different picture,” Powerex wrote. “In 2021, the MISO Independent Market Monitor explained that while the initial effect of fast-start pricing was very small (when fast-start pricing was a new market design feature), MISO subsequently made important changes to how it applies fast-start pricing that ‘have significantly improved real-time price formation in MISO,’” according to the Monitor’s 2021 State of the Market report.
Powerex said MISO data show that, from 2020 to 2023, the overall price impact from FSP was 50 to 100 times the 1- to 3-cents/MWh estimates for 2015 and 2016 cited by Brattle.
The brief said Brattle’s study also omitted evidence that, in recent years, FSP in PJM added an average of $4/MWh to $8/MWh to the RTO’s prices during morning and evening demand peaks.
Powerex also said Brattle “briefly acknowledges” that New England system prices increased by 11% when ISO-NE implemented FSP, but at the same time cautions the analysis identifying that increase was “limited to the first eight months after FSP came into effect.”
“Brattle could easily have reviewed the annual reports for [ISO-NE] published since then,” Powerex wrote, citing the ISO-NE Internal Market Monitor’s conclusion in its 2023 Annual Markets Report that “fast-start pricing rules in the real-time energy market continue to have notable impacts on pricing and market costs.”
Powerex also castigates Brattle for saying Energy GPS’ 2022 analysis suggested FSP would have had an average price impact of $15/MWh to $23/MWh on CAISO’s market over 2017-2020 if the ISO had implemented the practice.
“In fact, the [Energy GPS] report clearly states that ‘for the evening peak hour from 6 p.m. and 7 p.m., this price impact averaged nearly $15/MWh in NP15, and nearly $23/MWh in SP15,’” Powerex wrote, referring to trading hubs on the CAISO system. “The Brattle paper takes the price impact of the single-highest hour and presents it as the price impact across all hours, which is simply false.”
John Tsoukalis, a principal at Brattle and the lead author of the study, said his group “will take a close look at and consider the additional evidence [Powerex] put forward on fast-start pricing, but we note that the fast-start pricing section of our white paper is based on the analyses conducted by market monitors in other regions.
“For example, SPP’s [Market Monitoring Unit] stated in May 2022 that ‘there was very little change in the revenues to fast-start units due to the new fast-start pricing. The fast-start pricing appeared to have created [a] 1.5% increase in day-ahead revenues to fast-start resources and a 0.5% increase in real-time revenues. All else equal, the increase in revenue would cause a negligible reduction in make-whole payments,’” Tsoukalis said in an email.
CAISO and FSP
The Powerex brief also calls out CAISO for being the only FERC-jurisdictional organized electricity market without fast-start pricing.
The company explains that in markets with FSP, “special pricing logic” is applied to ensure the cost of starting and operating fast-start units is allowed to set the market’s LMPs when those units are determined to be providing supply at the market’s margin. In markets without FSP, the LMP can remain “well below” the cost of running peakers and “artificially” depress wholesale prices, reducing the amount paid to local generators and imported electricity from neighboring balancing authority areas.
“Avoiding the adoption of fast-start pricing therefore largely benefits utilities (and their ratepayers) in jurisdictions like California that typically import electricity during the hours of the day that gas peaking units are frequently used, while harming suppliers (and their ratepayers) in jurisdictions that typically export electricity during those same hours,” Powerex wrote.
Powerex pointed out that CAISO opposed a 2016 FERC proposal that would have required all organized markets to adopt FSP and that the ISO’s Department of Market Monitoring intervened to oppose adoption of FSP in any market.
“Such opposition aligns with California’s own interests, since the state has historically been a large importer of electricity from both Northwest and Southwest utilities in those hours that gas peakers are running,” Powerex wrote.
Reached for comment on Powerex’s contentions, CAISO pointed out that its Price Formation Enhancements (PFE) Working Group is exploring the potential for implementing FSP in the ISO’s markets.
“We recognize this feature has been adopted in other markets, with each carefully considering integration into its existing design. Different design features of fast-start pricing have tradeoffs that need to be considered by the stakeholders, and in particular, compatibility with existing features of the ISO market design that were specifically developed to compensate flexible and responsive resources with much the same goal as fast-start pricing,” the ISO said in an email.
Still, CAISO said its own analysis, presented to the PFE in April, showed a “minimal $0/MWh impact of fast-start pricing in the Northwest with similar minimal impacts in the Southwest, the exception being very narrow stressed system conditions under which the price impact was small in the CAISO and some specific areas of the Southwest ranging from $2 to $8/MWh depending on the sensitivity.”
Other Features
While the brunt of Powerex’s response dealt with FSP, the company also briefly contested the Brattle paper’s assessment of other market features, including GHG pricing mechanisms, congestion revenue allocation and transmission optimization.
Regarding the last feature, Powerex says the Brattle paper incorrectly asserts that “some stakeholders” — that is, Markets+ supporters — have suggested the market would rely “solely” on flow-based optimization of transmission within its territory, while EDAM would rely on both flow-based and contract path-based optimization.
Powerex said it recognizes that both markets will need to apply contract path limits for rights on transmission located within the boundaries of one market but used in another market.
“But the actual distinction that has been pointed out is that in EDAM, the California ISO will also apply contract-path limits to EDAM transfers between balancing areas participating in the EDAM, just as it applies contract-path limits for [Western Energy Imbalance Market] transfers between entities in the EIM,” it said. “In contrast, Markets+ will limit transfers between balancing areas participating in Markets+ based on physical flow-based limits, enabling more efficient use of the transmission system.”
Cloud computing represents a potential boon for the operators of the North American electric grid, but adapting to the change while remaining compliant with NERC’s reliability standards could be a significant challenge for utilities, a speaker from ReliabilityFirst said at SERC Reliability’s Fall Reliability and Security Seminar.
Lew Folkerth, principal reliability consultant at RF, cast the transition to cloud computing as the latest in a long line of changes. He started his presentation by showing a picture of a slide rule, jokingly asking how many in the room recognized it, before juxtaposing it with a picture of a cloud data center. Both were intended to “help solve problems,” he said, but the data center would “help solve problems just a little bit faster.”
“We [deal with] this stuff all the time. We change daily. But if we don’t manage it, it bites us, right? So, what we’re doing now is all about managing the change in the computing paradigm that we’re seeing coming at us like a freight train,” Folkerth said.
Utilities in the electric industry are moving to adopt cloud services with growing speed, Folkerth said — but the choice sometimes can seem like it is out of operators’ hands. A major driving force is the migration of “essential services that we’re used to having on premise,” such as multifactor authentication and security applications like anomalous traffic detection and end-point detection and response. Folkerth said NERC’s recently approved requirements for internal network security monitoring are an example of a service “that’s probably best done in a cloud environment.”
The move to the cloud can create unforeseen problems regarding compliance with NERC’s Critical Infrastructure Protection (CIP) standards. For instance, Folkerth pointed out, cyber systems classified as “low impact” under NERC’s standards — meaning they pose a lower risk of disrupting grid operations if compromised — are not required to have physical control centers on-site. However, this requirement changes if a system is reclassified to “medium impact,” which may be as simple as expanding a solar farm to 1500 MW.
“The question is, from the ERO perspective, do we make them backtrack? Build a physical control center with on-site computers so that they can be fully compliant … at significant cost? And how much are we actually adding to the reliability of the [grid] by making them do that?” Folkerth said.
Another challenge with the cloud transition is ensuring compliance when the service providers themselves are not subject to the CIP standards. Cloud operators such as Microsoft and Amazon serve many clients, Folkerth pointed out, and store their data in multiple locations — which may not mesh well with NERC’s security expectations. Expecting them to “let each and every utility audit their systems” is not realistic.
Reliability is another concern. Folkerth said some major cloud providers advertise 99% availability, which sounds “pretty darn good” — except that “99% means 3.65 days per year you don’t have service.” One solution is to have multiple services so that if one fails a utility can switch to another. This approach still could introduce an unpredictable level of latency.
Folkerth encouraged seminar attendees to follow the work of NERC’s standard drafting teams developing the requirements related to cloud services and participate if possible.
Virtual power plants can help the power grid deal with some of its most pressing issues, such as meeting rising demand and helping to integrate more renewables affordably, according to a recent report from RMI and the Virtual Power Plant Partnership (VP3).
The report, “Power Shift: How Virtual Power Plants Unlock Cleaner, More Affordable Electricity Systems,” lays out a path to expand VPPs, in line with the Department of Energy’s VPP Liftoff report from last fall. (See DOE Report Lays out Commercialization Path for VPPs.)
About 500 VPP programs already are in operation, providing between 30 GW and 60 GW of peak-coincident capacity in the country. With hundreds of gigawatts of new distributed energy resources coming online, the report says VPPs could serve much of the emerging need for 160 GW by 2030.
While the technology is being used today, it’s important that it’s part of any planning processes, said the report’s co-author, RMI’s Tyler Fitch.
“The key is going to be changing our operations and planning processes such that VPPs are visible to them and making it such that VPPs can respond to signals in ways that make sense for the grid,” Fitch said.
Current planning practices can silo the distribution system, where VPPs are located, off from the bulk transmission system, so ensuring they can be procured and dispatched like any other is going to be important to fulfilling their potential, Fitch said.
Ben Brown, CEO of VP3 member Renew Home, said VPPs offer the kind of dispatchable, clean resource the grid needs.
“I think there tends to be a lot of focus on newer technology; technology that can go after solving some problems,” Brown said. “And I think for us, it was really important to highlight that, hey, there’s a lot of existing latent resources out there.”
Renew Home was created by the merger of Google Nest Renew and OhmConnect, and it now runs the largest residential VPP in the country. More than 80 million households have installed electric heating and cooling systems, and water heating increasingly is done with electricity, Brown said.
“Those represent … an existing growing resource that, if tapped into correctly, really can provide a meaningful, very low-cost way to support decarbonization and some of the load growth that we’re seeing on the grid,” Brown said.
VPPs offer benefits over the grid-scale resources they compete with in that they are rapidly deployable, meet load where it exists and offer local economic, reliability and resilience benefits, the report says.
“We believe we could bring together about 50 GW of VPP capacity online by 2030 just through kind of the current funnels,” Brown said.
VPPs do not require new technology, and there’s no need to build new infrastructure, with customers installing smart thermostats, distributed solar and storage, and electric vehicles into their existing homes, Brown said.
“Being able to engage directly with households around ways in which their home can add value to the grid and therefore actually them get paid for it, and then being able to reduce their energy costs, is such a huge component of this,” he added.
Getting residential customers signed up in VPPs will be increasingly important to help balance the grid, Brown said. ERCOT, where Renew Home is active as a retail electric provider, already sees its demand peak in the summer, and its winters are driven by residential demand. That will be more common across the country.
“Most of the rest of the country, over the next 10 to 15 years, will probably go through updates with using heat pumps, and that will actually drive more and more heating-related electric peaks versus what’s just happening in certain regions of the country where electric heating is already pretty high,” Brown said.
Heat pumps are efficient, but modeling in the Northeast shows their adoption could greatly increase the peak demands of residential and commercial customers in coming decades.
The adoption of EVs by consumers will add many new DERs to the grid, Fitch said.
“I think we’re sort of at an inflection point here, where a lot of the operational questions are being answered, and lots of the business models are being figured out,” Fitch said. “And … especially with the [Inflation Reduction Act], there’s a whole asset turnover, in terms of internal combustion vehicles to EVs, that will really facilitate a greater role for VPPs.”
Coordinated EV charging so the vehicles on a block are not all charging at once and overloading the local system is part of it, but utilities are realizing that more subtle, minute-by-minute shifts in that demand can help integrate those new loads cost effectively and reliably, Brown said.
“Otherwise, you’re dealing with a problem where you’re just overbuilding infrastructure and passing on that cost to consumers in a way that is not necessarily healthy for where we need to go,” he added.
DERs represent a growing base for VPP, just as the power grid’s need for additional supply as demand grows.
“In the context where interconnecting grid-scale resources is hard, there’s this unique window for VPPs to play this capacity role,” Fitch said.
Some VPPs already are, with Fitch pointing to SunRun’s aggregation of solar-plus-storage systems in California, which provided the grid with an average of 48 MW of dispatchable capacity during a heat wave this July, the company said.
FERC Order 2222, which required RTOs and ISOs to integrate DER aggregations into their markets, also helps integrate DERs into VPPs, Brown said. But some of the rules could be changed to encourage more participation from residential consumers, as the minimum thresholds to participate in some of the markets are too high.
The other big issue facing the industry is access to data, he said.
“It’s not easy for households to be able to get access to and share utility meter data very easily and everywhere, and so that’s an area that we believe there could be continued progress on,” Brown said.
That would help utilities engage with their customers in new ways, such as setting up smart home platforms, apps and other kinds of communications beyond the monthly bill or occasional email, he added.
Texas lawmakers charged with overseeing the state’s $5 billion fund for new gas-fired generation took aim this week at the consulting firm managing the program.
During a public hearing Oct. 8, the Texas Energy Fund (TEF) Advisory Committee roasted Deloitte representatives for missing an apparently fraudulent loan application that accounted for 13.2% and left a nearly 1.3-GW hole in the fund’s portfolio.
Deloitte principal Rod Kleinhammer, a senior partner overseeing the firm’s Texas business, defended his staff’s work. He said they could have been more intensive in performing due diligence of the 72 applicants for TEF funds. Deloitte conducted what amounted to cursory background checks of the applicants and found no negative results, Kleinhammer said, and added it intended a deeper dive after arriving at its shortlist of 17 projects deserving of loans.
“We should have accelerated some of the additional risk and reputational checks we had planned for due diligence to occur prior to the release of the 17 Texas energy fund loan applications being made public,” he told the committee, reading his short, prepared statement. “We’ve modified our processes and are confident the safeguards we have in place will continue to assure that no entities will be approved for funding before a rigorous and thorough review of the applicants and sponsors has been completed.”
That may not be enough.
Lt. Gov. Dan Patrick (R), one of the state’s most powerful political leaders, posted a statement after the hearing calling Deloitte’s failure to catch the sketchy application a “blunder.” He said the Public Utility Commission should follow through on its demand to claw back at least 10% of Deloitte’s contract and for the legislature to review the state’s other contracts with Deloitte, which average about $250 million annually, according to Kleinhammer.
“Our grid needs more dispatchable power as quickly as possible, and the Texas Energy Fund loan program is the most expeditious way to get more dispatchable megawatts online” he said. “Deloitte has only slowed down this important program. They need to correct their errors now or be gone.”
The application in question was proffered by Aegle Power, which said NextEra Energy was a party to the application, which the Florida company has denied. It also turned out that Aegle’s CEO, Kathleen Smith, had pleaded guilty in 2017 to embezzling a “significant” amount of money from a company that was trying to build a power plant in Corpus Christi, Texas. (See Texas PUC Rejects Possible ‘Fraudulent’ Loan Application.)
“The lack of just basic due diligence is astounding to me,” state Sen. Charles Schwertner (R), who co-chairs the advisory committee, told Kleinhammer. He noted Smith’s name was “all over the application” and received affirmation from the Deloitte rep.
Texas Sen. Charles Schwertner | Texas Senate
“And no one bothered to interview or Google her name?” he asked incredulously. “This is the second-largest, 1.2-GW, second-largest project in the Texas Energy Fund. Is it astounding that it wasn’t a baseline like, ‘Who am I dealing with?’”
Schwertner recalled an earlier conversation with Kleinhammer, in which they discussed Deloitte’s mantra of KYC (Know Your Client).
“You were like, all giddy about it, almost,” Schwertner said. “Do you know Aegle Power?”
“I do now,” Kleinhammer responded. “Now that I know what I’m looking for, it is very easy to find out, sir.”
“What do you mean, what you’re looking for?” Schwertner replied, not hiding his frustration. “’If they’re a convicted felon, I should probably not advance them.’ Is that what you’re looking for? Do we need to spell it out for you?”
Smith had agreed to attend the hearing, but Schwertner said she pulled out Oct. 7 because she said she couldn’t leave Florida because of Hurricane Milton’s approach.
Sitting next to her empty chair, Mitchell Ross, general counsel for NextEra Energy Resources, the competitive business for the giant Florida company with about a $160 billion market cap, said the subsidiary never committed to or applied for any project seeking Texas Energy Fund support.
He said discussions were held with Aegle, but that no equity commitment was ever made. Initial conversations began with Aegle’s investment banker in May, but by July, Ross said, NextEra’s deal team had decided to end the negotiations, partly because of Smith’s criminal history. He said a May letter submitted to the PUC and claiming a $252 million equity commitment from NextEra was fraudulent and has been reported to the U.S. Attorney’s Office.
“We do not support the application, and I agree that false statements and fraud have been committed against the state of Texas,” Ross said.
As if that weren’t enough, Coronado Power Ventures notified the PUC that the air permits Aegle said it had secured from the Texas Commission on Environmental Quality and the U.S. EPA actually were issued to its La Paloma Energy Center in South Texas. The project since has been canceled.
Coronado Power CEO John Upchurch said the application was made without his company’s “knowledge or consent.”
In a strange twist, Upchurch was CEO and Smith president at Chase Power from 2008 to 2012, when the embezzlement occurred. Federal authorities charged both with filing false invoices and using their company credit cards for personal travel, country club memberships and other expenses. Like Smith, Upchurch pleaded guilty to the charges.
“Deloitte’s failure to uncover the falsified application presented by Aegle Power, whose CEO was previously convicted of embezzlement, is outrageous, and the [PUC’s] advancement of this unvetted project is extremely troubling,” Patrick said in his statement.
PUC Chair Thomas Gleeson offered his apologies, saying the commission had “too much of an arm’s length relationship with our contractor.”
“I should have ensured we were more heavily involved in the review,” he told lawmakers. “Ultimately, it is my responsibility to make sure that Deloitte is doing what they need to do.”
The commission said it will strengthen the oversight process to address the issues that led to the Aegle Power application’s acceptance and denial. Executive Director Connie Corona said staff will meet with the 16 remaining applicants and conduct site visits to verify their legitimacy.
The PUC and Deloitte are negotiating over the 10% clawback of the latter’s contract, which is valued at $73 million over four years. An addendum could up the spending to $107 million.
Kleinhammer said the two sides are close, but Gleeson offered a different perspective. He said there will be no negotiation over the 10% number, which amounts to $7.3 million.
“That is $7.3 million, which is 10% of their base contract. That number is non-negotiable. It is not moving down,” Gleeson told the committee. “So, from my view, there is no ongoing negotiation. There is a number that needs to be met, and when it is, we will present you with an agreement of that number.”
Gleeson said the commission also has referred the matter to the Texas attorney general’s office, citing the “lies and false statements” in the application.
WASHINGTON — FERC Commissioner David Rosner told members of the American Clean Power Association that one of his main goals as a regulator is to successfully manage the energy industry’s transition.
“If you look back 20 years, the system is just completely different from what it was,” Rosner said. “And if you look 20 years out forward, it’s going to look different. And, so, one of the things I’m focused on is making sure in regions where there are markets … those markets are equipped to deal with that change.”
Another part of reliably managing the transition FERC oversees is deciding where and when infrastructure investments are needed, he added.
Rosner is not coming new to FERC like most commissioners; he’s moving up to the top floor after working as a staffer since 2017.
“Frankly, I have an unfair advantage, because there’s — you’ll be shocked to hear this — but there’s a lot of process at a regulatory agency,” Rosner said. “And that’s a really good thing, because we want a lot of eyes on these orders because they affect real people, real companies, real dollars. And, so, I already know to some extent that process, and that’s been a huge advantage.”
He already has seen the regulator go through changes since joining as a staffer. One of the reasons the commission has seemed more partisan in recent years, he said, is a court decision (NRG Power Marketing LLC v. FERC) that ended its flexibility in dealing with Federal Power Act Section 205 filings. (See PJM MOPR Order Reversed; FERC Overstepped, Court Says.)
While focused on long-running debates about PJM’s capacity market, the decision effectively tied FERC’s hands and limited its response to Section 205 filings to an up or down vote.
“Before you would see six, seven, eight — you know — rounds of conditional compliance,” Rosner said. “We can’t do that anymore. It’s yes or no, up or down. It’s always an emergency.”
Rosner also said he’s committed to getting orders out as soon as they are ready, which this summer involved approving new infrastructure. He also noted the commission is working on issuing a rehearing order for Order 1920, the transmission reforms passed this spring before Rosner took office.
PJM’s recent capacity auction and the price spikes caused by a narrowing supply and demand balance also are at the top of mind for the new commissioner, who said he’s been meeting with state regulators from the region concerned with the shift from “abundance to scarcity.” (See PJM Capacity Prices Spike 10-fold in 2025/2026 Auction.)
“The fundamental cure to this disease is adding capacity,” Rosner said. “And so, you know, last year, I think we saw a report just come out of PJM saying they added 2,000 MW of solar. I think they have somewhere between 20,000 and 30,000 MW of signed ISAs [interconnection service agreements], some of those for batteries. And you know, I think what we’re hoping to see is that we get more than 2,000 MW connected next year.”
FERC Order 2023 set a new baseline for interconnection queues around the country, and the commission recently held a two-day workshop looking into other ways, some of which do not require any rule changes, to speed up that process, Rosner said.
Industry Executives Discuss Maintaining Reliability as Grid Transitions
Rosner gave the keynote at an event that featured executives from around the industry describing how they responded to reliability challenges in their territories.
CAISO had to cut power briefly to some customers in 2020 as demand spiked around the West and it was unable to rely on imports, said Chief Operating Officer Mark Rothleder. The short version of what went wrong: California didn’t keep up with the pace of change, represented by higher peaks due to climate change and new types of resources.
At the time, CAISO had just 250 MW of batteries online. That has ramped up to 10,000 MW, which has helped.
“You’re starting to now see things stabilized,” Rothleder said. “We’re seeing these events happen. We’re forecasting the events in the operational time frame. We’re incorporating the changing conditions in the planning horizon, and we’re again developing and moving and building the resources that we need for the future.”
The bad times for SPP came in February 2021, when Winter Storm Uri led to blackouts, said General Counsel Paul Suskie.
Over its first two decades as an RTO, SPP approved $13 billion in transmission. That could grow by more than 50% after a vote set for the end of October, when its board will consider $7.5 billion more. Some $2 billion of that proposed transmission was planned when looking back to Uri and Winter Storm Elliott and determining what would have helped maintain reliability, Suskie said.
The new transmission lines would help connect the north to the south of SPP to better move power in emergencies. SPP also is considering proposals for eight high-voltage direct current lines to connect the Eastern and Western Interconnections as its RTO footprint expands across that seam, Suskie said.
One key policy goal of American Clean Power is getting the Energy Permitting Reform Act of 2024 to pass Congress this year, after clearing the Energy & Natural Resources Committee by a 15-4 vote.
“We are in a joyful position right now having a full consensus,” said ACP President Jason Grumet. “Not a single member of our organization is opposed to the EPRA proposal.”
ITC President Krista Tanner said the permitting bill is needed to avoid situations like the recently completed Cardinal-Hickory Creek Line, which took 13 years to build because it was under constant litigation. The law does not eliminate litigation under the National Environmental Policy Act, but it seeks to minimize “litigation abuse,” Tanner said.
“It puts time frames on statutes, limitations on how soon you have to file; it requires courts take these cases expeditiously, and then it requires the agencies to act within certain time frames,” Tanner said. “So, all of that helps a lot.”
NYISO expects it will be able to operate reliably, according to the Winter 2024 Operating Study presented to the Systems Operations Advisory Subcommittee on Oct. 9.
The ISO forecasts a 23,800 MW peak demand against 41,321 MW of total available capacity this winter, a 73.6% margin. This season’s load forecast is about 1.73% less than last winter’s expected 24,220 MW and about 7.53% lower than the all-time peak of 25,738 MW, set in January 2014.
Peak load was only 22,754 MW last winter, which was very mild. It was one of only three times during that January when load went above 22,000 MW. (See NYISO Recounts Mild Winter.)
The study notes that 935 MW of new generation have come online since last winter, spread across 13 projects. Most of these are solar farms, but they also include two wind farms over 100 MW in upstate New York and one battery facility outside of Buffalo.
Four gas turbine plants, totaling 60 MW, were modeled as deactivated since winter 2023.
COLLEGE PARK, Md. ― Maryland consumes five times more energy than it generates, has limited access to transmission in the central and eastern parts of the state and at present has only six projects totaling 1,245 MW in PJM’s interconnection queue.
“Maryland, as many of you know, has been a state where transmission has come to die,” said Jason Stanek, executive director of governmental services at PJM, in his opening remarks as moderator for a grid reliability roundtable at the Maryland Clean Energy Summit on Oct. 7.
A former chair of the Maryland Public Service Commission, Stanek provided an overview of the state’s dilemma as it seeks to cut its greenhouse gas emissions 60% below 2006 levels by 2031 and decarbonize its power grid by 2035, all while attracting new business, including megawatt-guzzling data centers.
PJM estimates data centers will grow from 4% of Maryland’s power demand in 2024 to 12% in 2029 and 16% in 2039, but Stanek cautioned those numbers could be conservative, and the RTO revises the projections every year. Since 2018, new generation coming online in Maryland has been outpaced by retirements, with 1,600 MW coming online versus 6,000 MW coming off, he said.
“Last year, Maryland held an unenviable position of needing to import [power] every single hour of every single day,” he said.
Facing each other across tables running along three sides of the meeting room, participants ranged from state lawmakers to offshore wind developers and other industry experts, each with different perspectives on the state’s challenges and possible solutions, both short and long term.
Del. Lorig Charkoudian (D) talked up a bill she hopes to introduce in Maryland’s General Assembly in January, aimed at accelerating the permitting process for energy storage and other distributed energy resources coming onto Maryland’s distribution system, outside of PJM’s jurisdiction.
“I think that PJM doesn’t do the job it needs to be doing on transmission planning, and I think that our hands are tied, and so … I have finally just given up and put [planning provisions] into this bill,” Charkoudian said.
An outline of the bill is being circulated for input from stakeholders but has been informally dubbed “Build Stuff in Maryland,” she said. “The idea is, what can we do fastest? And the thing we can do fastest is distribution utilities can put storage on the distribution grid; so, medium size … 1,2,3 MW at substations, and that can be done at a pretty quick scale to respond to some of the immediate [reliability] problems, assuming storage is treated fairly in capacity markets.”
While not on the bulk transmission system, these projects could “address our resource adequacy problems fairly quickly,” she said.
Stanek and others pointed to FERC’s recently passed Order 1920, which aims to provide a new, more comprehensive framework for RTO and ISO transmission planning, for example, calling on the grid operators to consider grid-enhancing technologies, such as advanced conductors, that can increase capacity on existing lines.
David Townley, public policy director at CTC Global, an advanced conductor manufacturer, argued that waiting for much-needed transmission to be built can take years, triggering additional risks as new generation comes online. “By the time you get the line built, you may be in a congestion point; it may not be the solution anymore,” Townley said. “Take steps you can take now to open up those capacities … because the lines are loading up and changing.”
Abe Silverman, assistant research scholar at the Ralph O’Connor Sustainable Energy Institute at Johns Hopkins University, cautioned that full implementation of 1920 is still five years away but that states now should be codifying their goals and policies for clean energy and grid planning.
“That will help a lot,” said Silverman, who previously was general counsel and executive policy counsel for the New Jersey Board of Public Utilities (BPU). “So, the more you can put on paper and hand to PJM [and] say, ‘These are our goals,’ the stronger that 1920 planning process will be.”
States like Maryland should encourage their neighbors in the PJM service territory to “codify their rules in a comparable manner.” Then they present PJM with a “comprehensive action plan” as part of the 1920 process, he said.
State of the Grid
Stanek was quizzed on PJM’s request to FERC for a rehearing of 1920, one of many the commission has received and is considering.
PJM found the 1,363-page ruling “overly restrictive for a footprint as diverse and wide, serving 65 million customers,” he said. “So, the purpose of the request for rehearing was to preserve our right to inform FERC that we think there should be more flexibility in how PJM complies” with the rule.
“Otherwise, this final rule is effectively one-size-fits-all,” Stanek said. At the same time, PJM is moving ahead to comply with the timelines set out in the rule, he said.
Stanek’s opening presentation zeroed in on the key challenges for transmission planning in Maryland.
The state’s generation mix is 42.8% natural gas and 42.9% nuclear, with coal and hydro providing about 5% each, and wind and “other” accounting for a final 4.3%.
But what’s in PJM’s interconnection queue for the state is 54% energy storage, 44% solar, 1% wind and less than 1% natural gas and hydro.
The state is one of a handful that does not have an overarching, holistic plan for infrastructure development to help guide the transition to clean energy ― as opposed to the GHG emission reduction plan the Maryland Department of the Environment issued at the end of 2023 ― Stanek said.
Further, Maryland’s offshore wind projects are not included in the state’s interconnection queue because they will be coming onshore in Delaware before connecting to the PJM grid, Stanek said.
The U.S. Bureau of Ocean Energy Management recently approved the Maryland Offshore Wind Project, which includes two separate sites totaling up to 2 GW of power. Maryland’s other major offshore wind project, Ørsted’s Skipjack 1 and 2, has been on hold since the company backed out of its offtake agreement with the state in January. The company has said it would “reposition” the project for future offtake agreements.
For PJM, Stanek said, the short-term solution for Maryland is, first, to ensure no shutdowns of existing baseload generation ― coal, natural gas or nuclear ― until the necessary transmission is in place to handle the new carbon-free generation in the queue.
The RTO intervened in the planned closure of the Brandon Shores coal-fired power plant in 2025, citing a potential for up to 600 reliability violations in Maryland, Delaware, Pennsylvania and Virginia to keep the 1,283-MW plant online via a reliability-must-run agreement with its owner, Talen Energy.
Stanek said Maryland also should accelerate permitting and siting of new generation, but cautioned getting new projects online could be complicated by Maryland’s profile as a high-risk state for utility investors in rankings from S&P Commodity Insights. In S&P’s most recent evaluation, the state was placed in the bottom of nine possible rankings, meaning it has the highest regulatory risk for investors, said Lillian Frederico, the company’s energy research director.
Frederico stressed that the rankings are not intended to evaluate whether state utility regulators are doing a good job, how they are implementing state policies or if those policies are “good, bad or indifferent.” Rather, S&P looks at regulatory decisions in rate cases and other actions, based on “the comparative level of risk for investors” and for the returns on the money they invest in utilities, she said.
Maryland’s ranking has been affected by the new commissioners on the PSC, in particular, Gov. Wes Moore’s appointment of former consumer advocate Frederick H. Hoover as commission chair. Moore (D) also named Bonnie Suchman and former state Del. Kumar P. Barve (D) to the commission.
“Just the fact that these are different people appointed by a different governor with a different political agenda, there’s some concern that there could be shifts in policy that may or may not be favorable,” she said. “When you have uncertainty, uncertainty equals risk.”
Transmission as Common Ground
While it may not be a direct result of rankings like S&P’s, Maryland has significantly fewer projects in PJM’s interconnection queue than its neighbors, including Pennsylvania (91), Virginia (107) and even West Virginia (14).
Beyond the six projects awaiting interconnection agreements, Maryland also has 35 projects totaling 1,338 MW that have agreements but have yet to be built.
Adding to investor perceptions of uncertainty, Stanek said the state has a spotty track record on permitting new transmission projects. The latest, the proposed Piedmont Reliability Project, a new 500-kV line stretching 70 miles over three counties, already is stirring the kind of local reaction ― “quick and largely fierce” ― that has stalled past projects, he said.
While not confined to Maryland, “NIMBYism is clear,” Stanek said. “Nobody wants a transmission project in their backyard.”
PJM awarded the Public Service Enterprise Group the contract for the line as part of its Regional Transmission Expansion Plan (RTEP) portfolio of projects costing about $5 billion, in a process the Maryland Office of People’s Counsel has criticized as not providing enough time for local review and input.
Charkoudian also argued that PJM’s planning process for the RTEP has not considered offshore wind development on the Atlantic Coast.
“We’re bringing massive amounts of generation onto the Eastern Shore, high-capacity offshore wind, which has the same capacity as some of the gas plants that are being defended and supported and we’re being begged to keep online,” she said. “And there’s not a planning mechanism. It is essentially … a problem for the developers or the states who want to subsidize that offshore wind to figure out how to get [it] onshore.”
Both Charkoudian and state Sen. Brian Feldman (D), chair of the Senate Education, Energy and Environment Committee, promised new initiatives on siting and permitting in the upcoming legislative session. For solar projects that have stalled out while in the PJM queue, Charkoudian’s bill could include new incentives and could push for better planning of offshore transmission so that it will “solve Maryland load issues,” she said.
Another possibility could be for Maryland to consider a state agreement approach (SAA) with PJM, similar to New Jersey’s, to provide the kind of long-term, integrated transmission planning the state needs for offshore wind, Charkoudian said.
Silverman, who was at the New Jersey BPU during the SAA negotiations, said it took four years and extensive coordination between regulators and the legislature to come up with the mix of laws and regulatory actions needed to move the initiative forward.
He again stressed the importance of regional collaboration and how the need for expanded transmission could provide common ground for states with differing policies on clean energy and grid decarbonization.
“One of the things I spend a lot of time doing is talking to states across the political spectrum,” Silverman said. “We may not agree on the benefits of offshore wind, but I think what we can agree on is, if there’s a transmission facility that reduces consumer costs in your state, you should be for it. If it’s going to improve reliability, you should be for it, and most transmission lines meet those criteria.”
The National Association of Regulatory Utility Commissioners (NARUC) in a new report laid out many of the potential use cases for advanced nuclear technology and some of the policy considerations that surround them.
Carbon capture, district heating, desalination, mining and synthetic fuel production are all possibilities, along with gigawatts of emissions-free electricity.
Numerous technical, financial and political hurdles must be cleared before any large-scale deployment of next generation nuclear reactors can occur, along with innumerable regulatory and policy deliberations.
But efforts to clear those hurdles are underway, and advanced nuclear is gaining momentum as part of federal, state and corporate energy strategies.
NARUC and the National Association of State Energy Officials offered “Energy and Industrial Use Cases for Advanced Nuclear Reactors” as an overview of the considerations and questions facing state regulators and policymakers as the new technology advances.
“This new report is a timely resource as we explore how these reactors can be utilized not only for generating electricity but also for various industrial applications,” Nick Myers, vice chair of the NARUC Subcommittee on Nuclear Issues-Waste Disposal, said in a news release.
“By providing a detailed analysis of potential use cases, the report equips state officials with the knowledge needed to support and guide the integration of advanced nuclear energy into our broader energy strategies.”
The report defines advanced nuclear as improved versions of third generation light-water reactors (dubbed Generation III+) and new designs that may be cooled by gas, liquid metal or molten salt, and may be extremely small compared with traditional commercial reactors (Generation IV).
All have an improved safety profile and a high capacity factor, NARUC writes, and depending on their design, they may also offer modular construction and configurability, tailored size, black start capability, and flexible ramping and output.
Also, Generation IV gas, metal and salt reactors would generate process heat so great as to be useful for hard-to-decarbonize industrial applications, the report notes.
Some of the other use cases, however, could entail Generation II and III reactors expanding beyond their role as central power generation for the grid.
These include:
Distributed electric generation for nearby or co-located large users: This recently has become a goal for some data center developers, but drilling and mining operations also could benefit from portable micro reactors, and the Department of Defense has interest in mobile generation in the 1 to 5 MW range.
District heating: Light water reactors, with their lower operating temperatures, could use their waste heat to warm groups of buildings up to 100 miles away. Advanced reactors could fill the same function as part of a cogeneration system. The concept is not new — the first such system went online in Bulgaria in 1988.
Desalination: Removing salt and solids from water is energy intensive. India and Kazakhstan began using nuclear power for this purpose in the 1970s.
Direct air capture: Removing carbon dioxide from the atmosphere requires heat and electricity; burning fossil fuels to generate either might tend to defeat the purpose.
High-temperature applications: Chemical and steel production require temperatures as high as 900 degrees Celsius, which is at the top end of the range high-temperature gas reactors are expected to reach.
Hydrogen: Light-water reactors can power hydrogen production through electrolysis processes. Thermochemical water splitting processes still in development would require very high temperatures that Generation IV reactors could provide.
The report concludes:
“Public utility commissions and state energy offices will play a vital role in supporting the development of advanced nuclear projects slated to begin in the next decade, so understanding potential use cases, identifying opportunities to connect the dots between larger state goals and initiatives, and considering potential challenges which might arise as advanced reactors begin construction phases will be critical in supporting these developments.”
The Bonneville Power Administration would earn $65 million in annual benefits from joining CAISO’s Extended Day-Ahead Market but face $83 million in increased yearly costs from participating in SPP’s Markets+, according to a new Brattle Group study that is sure to further inflame the ongoing debate over day-ahead markets in the West.
“We find that if most of the Pacific Northwest, including BPA, joined EDAM, customers in the region would see a cost reduction of $430 million per year,” Brattle Principal John Tsoukalis, lead author of the study, said in an Oct. 9 press release accompanying the study.
By contrast, PNW net system costs would collectively increase by $18 million under a situation in which most of the region’s entities participate in Markets+, Brattle found.
In the study, the PNW system includes BPA, Avista, PacifiCorp’s West balancing authority area, Portland General Electric (PGE), Puget Sound Energy, Seattle City Light and the numerous public utility districts that largely rely on BPA for low-cost power to serve electricity customers in mostly rural areas of Oregon and Washington.
The report is the latest in the series of Western day-ahead market studies performed by Brattle, the most recent being a white paper comparing key features of the EDAM and Markets+. (See Brattle Study Likely to Fuel Debate over EDAM, Markets+.) It was not commissioned by BPA, but rather by a group of Northwest-based EDAM proponents, including the Northwest & Intermountain Power Producers Coalition (NIPPC), NW Energy Coalition (NWEC), PNGC Power and Renewable Northwest, as well as GridLab.
Those organizations have been firmly in the camp of electricity sector stakeholders who have argued that the West must create a market with the largest possible footprint — and that pointedly includes CAISO — to allow participants to fully tap the “diversity benefit” of resources and loads that would become available from such an arrangement. The Brattle BPA study throws its weight behind that argument.
“The key benefit differentiator in customer cost savings between the two markets is the diversity of the generation resource mix available in an EDAM footprint, which includes the Pacific Northwest as well as parts of the Southwest,” Brattle said in its press release.
Study Structure
The BPA study participants included the Balancing Authority of Northern California, El Paso Electric, Idaho Power, Los Angeles Department of Water and Power, NV Energy, PGE, PacifiCorp, Public Service Company of New Mexico, Sacramento Municipal Utility District and other utilities, transmission owners and independent power producers.
Those participants “helped refine our model by performing full reviews of relevant modeling assumptions including transmission rights, transmission costs, load forecasts, fuel prices, generation mix and costs, etc.,” Brattle said, calling out PacifiCorp and PGE among the “several” reviewers that “were able to provide details relevant to BPA’s system.”
Brattle worked with the Northwest Power and Conservation Council to fine-tune its flexibility modeling of BPA’s hydroelectric system, assuming the federal power agency’s ability to dispatch its fleet would be the same across all market scenarios.
The BPA study was conducted “using a nodal production cost model of the [Western Interconnection] with added markets, transmission rights and contract-path trading functionality.” It chose 2032 as the study year “to reflect the first decade of markets operations, representing an intermediate year that captures known changes in resource mix and transmission infrastructure.”
The study models a “business as usual” (BAU) case that reflects current utility participation in markets and the known decisions on day-ahead markets (all for EDAM at this point), as well as two “market participation” cases. In the Markets+ case, BPA and almost all utilities presently uncommitted to a day-ahead market join the SPP market, while an EDAM case shows all existing Western Energy Imbalance Market (WEIM) participants either remaining in that market or joining EDAM.
The study also models two extreme weather events, each based on a historic cold snap and heat wave.
“These events are modeled as single weeks in which we increase modeled loads (peak and energy) and gas prices, including gas price volatility beyond typical weather-normalized values to reflect the increased strain on the system and the ability of markets for addressing such strain,” the study said.
The study’s transmission assumptions include a “detailed view of the physical transmission system and long-term (contractual) transmission rights”; multiple trade type options between BAAs; and “GHG unit-type-specific trading structure which closely mimics the unit-specific GHG import tracking and charge structures in the EDAM and Markets+ designs.” It also assumes participants will make all their transmission available to the market, except where study participants have called out specific carveouts.
‘Key Differentiators’
BPA’s $65 million estimated benefit from participating in EDAM came down to two key factors, Brattle said.
The first is the expectation that BPA will reduce its adjusted production costs (APC) by $43 million in the CAISO market because of increased sales revenues stemming from higher prices in EDAM during the hours when the agency usually sells power.
The second factor is a projected increase in BPA’s congestion revenue from zero in the BAU case to $166 million in EDAM, a product of “the amount of transmission BPA brings to the market, its advantageous position in the EDAM footprint, and price deltas between” California and the Pacific Northwest.
While the study found that BPA’s congestion would average about $4/MWh in both markets, the agency’s congestion revenues in EDAM would be double those of Markets+ because of its higher trading volumes in the CAISO-run market.
On the downside, Brattle found BPA’s EDAM benefits would be partially offset by a $114 million loss in bilateral trading revenues and $37 million loss (to $2 million) in short-term wheeling revenues — the outcome of declining bilateral activity.
“Bilateral trading revenue falls more in [the] EDAM [case] as almost all of BPA’s trading partners are in the EDAM,” the study found.
In the Markets+ case, BPA’s increased costs stem in part from a projected $87 million drop in bilateral trading revenues, the result of many — although not all — BPA trading partners joining the agency in the market.
But the key difference between the two cases relates to production costs. In Markets+, BPA’s APC is projected to increase by $72 million because of slightly lower prices in that market during some intervals when the agency sells its power.
“The impact on prices is mostly in overnight hours, driven by the higher opportunity for increased thermal resource dispatch efficiency during these hours in the Markets+ footprint relative to the EDAM or BAU cases, which is driven by higher gas prices in the Pacific Northwest compared to the Southwest and Rocky Mountain regions,” the study said, adding that the opportunity for that kind of dispatch efficiency isn’t available under BAU because of “trading hurdles” between the Northwest, Southwest and Rockies region.
“The increased thermal dispatch efficiency and lower prices in the Markets+ footprint benefit net buyers in the PNW through reduced purchase costs but reduces sale revenues to the detriment of net sellers in the PNW such as BPA.”
On the plus side, Markets+ would increase BPA’s congestion revenues by $88 million, while short-term wheeling revenues would remain nearly flat, at an estimated $38.9 million.
“Market congestion, bilateral trading revenues, short-term wheeling revenues, and APC savings are the key differentiators of BPA’s net benefits between EDAM and Markets+,” the study said.
PNW Findings
The Brattle finding that EDAM’s benefits for the full PNW system would far outpace those of Markets+ could be the most significant point of the study for many in the region. It could also stir the most controversy in the debate over the two markets.
The study found that the $430 million in savings in EDAM derive from a $171 million reduction in APC, “driven mainly by higher sales revenues in EDAM for the region” and $651 million in EDAM congestion revenues. Those benefits would be offset by a $283 million decline in bilateral trading revenues and a $66 million loss in short-term wheeling revenues.
The cost increase for the Northwest under the Markets+ case was largely attributed to lower sales revenues, which left the region’s APC net of revenues $18 million higher than in the BAU case.
Reached for comment, BPA spokesperson Doug Johnson said, “BPA did not participate in and has not yet reviewed the study. We will attend the Oct. 17 webinar hosted by the study’s authors and will comment on the results after we better understand the study’s methodology, inputs and findings.”
SPP spokesperson Meghan Sever said the RTO was preparing a statement on the Brattle study.
