PJM’s Reserve Certainty Senior Task Force (RCSTF) is voting on a PJM proposal to add hourly differentiated notification times to the RTO’s day-ahead (DA) energy market. (See “Hourly Notification Times,” PJM MRC/MC Briefs: Aug. 21, 2024.)
During a Sept. 5 task force meeting, PJM’s Joe Ciabattoni said generation notification times have become an important input for determining reserve eligibility, especially for offline, non-synchronized resources.
The vote is being conducted virtually through Sept. 12, with expedited endorsement sought at the Markets and Reliability Committee and Members Committee on Sept. 25. The tightened schedule would allow for the changes to become effective for the upcoming winter.
Hourly notification times can only be submitted in the real-time (RT) market, creating a discrepancy that Ciabattoni said can lead to units being assigned a DA reserve commitment that they cannot carry with their RT notification times.
Joel Romero Luna, senior analyst with the RTO’s Independent Market Monitor, said the main use case for changing hourly notification times is to allow gas-fired generators to reflect pipeline restrictions that cause them to become less flexible. He said the Monitor has guidelines for how generators should use notification times to reflect gas nomination cycles, so there shouldn’t be much variety in how notification times are used.
The change would require revisions to Manual 11: Energy & Ancillary Services Market Operations and Tariff Attachment K.
Rebecca Stadelmeyer, Gabel Associates’ director of RTO services, suggested that the proposed language allowing hourly notification times used to commit non-synchronized and 30-minute reserves be consistent with references throughout Manual 11 and suggested replacing the 30-minute reserve with secondary reserves. Ciabattoni said PJM will consider the amendment.
Task Force Shifting to Long-term Work Areas
PJM’s Danielle Croop said the RTO is not planning to rework a proposal to replace the 3,000-MW target for 30-minute reserve procurement with a formula that accounts for forecast peak loads and gas contingencies. Following the MRC’s rejection of the package in July, stakeholders told PJM they were uncomfortable with the lack of tariff language to accompany the change. (See “Stakeholders Endorse Reserve Rework, Reject Procurement Flexibility,” PJM MRC Briefs: July 24, 2024.)
Croop said PJM believes the status quo language allows the change by pointing to the manuals to determine the reliability requirement. In the absence of further direction from stakeholders, she said it is not clear how PJM should proceed.
Task Force Chair Lisa Morelli said in future meetings, the working group will pivot to its long-term work, which includes creating reserve product participation requirements and incentivizing resource flexibility.
FERC on Sept. 6 approved a deal in which BlackRock seeks to buy all the limited liability company interests in Global Infrastructure Management for $3 billion in cash and 12 million shares of BlackRock Funding (EC24-58).
Global Infrastructure owns or controls 6,937 MW of generation in CAISO, 606 MW in PJM, 463 MW in ISO-NE, 787 MW in SPP and generation outside RTO/ISO markets. The company also is trying to buy 50% interest in North East Offshore, Revolution Wind and South Fork Wind, which are developing offshore wind off the Northeast, and it has investments in FERC-regulated natural gas infrastructure.
BlackRock is a publicly traded investment management firm that controls gas-fired resources in various parts of the U.S., including 3,374 MW in PJM, 1,042 MW in Arizona and 945 MW in Georgia, as well as other facilities that fall under FERC jurisdiction.
The application drew a joint protest from Public Citizen, and the Private Equity Stakeholder Project and Sierra Club separately protested it.
The two firms’ capacity overlaps in CAISO and PJM, where, after the deal is completed, BlackRock would control 10 and 2.2%, respectively, of generation in those markets. The percentage in California was high enough to require the applicants to run a delivered price test, which showed the combination lacks a material competitive effect on CAISO’s market.
The joint protest argued otherwise, saying BlackRock should have to include any utility in which it holds 10% or more voting shares, which represents more than 20 firms. BlackRock said its shares in those firms are covered by an effective blanket authorization from FERC and it does not control them. (See BlackRock Decision Unearths FERC Wariness of Investor Influence on Utilities.)
FERC agreed with the applicants’ findings that the deal would not impact horizontal market power and agreed that BlackRock does not need to include its investments covered by the blanket authorization in the analysis.
BlackRock does not exercise any control over those utilities, so it does not need to include their generation in the delivered price test, FERC said.
The joint protest argued the application is silent on how BlackRock can manage its passive ownership of voting shares of utilities that compete with its active, direct holdings. They argued FERC should conduct a formal reassessment of the blanket authorization as part of its review of the deal with Global Infrastructure.
FERC said under the blanket authorization, BlackRock agreed it would not exercise control over the day-to-day management of any covered utilities. It would be required to file a separate application if it sought to exercise direct control over the management or operations of a utility outside of that authorization, as it did with the Global Infrastructure deal.
“We decline to reassess BlackRock’s blanket authorization in this proceeding or to hold a hearing on BlackRock’s blanket authorization at this time,” FERC said. “Questions about the conditions applicable to BlackRock’s blanket authorization are beyond the scope of this proceeding.”
“The influence that large shareholders, BlackRock or otherwise, can potentially exert across the consumer-serving utility industry should not be underestimated,” Christie said. “Such horizontal shareholdings pose the threat of decreased innovation, reduced competition and ultimately higher prices to consumers, as well as the prospect of chilling investment in exactly the new generation resources we need to meet increased demand for power and to enhance the reliability of the grid. So this is an issue that deserves much greater scrutiny, as I have stated before.”
BlackRock already owned passive shares in IPPs in California and is expanding its active control over more of them, but FERC cannot examine the issues cited in the protests due to the blanket authorization.
“You do not need a Ph.D. in economics to see the potential for anticompetitive conduct and outcomes when an investment entity like a huge asset manager seeks to own generation assets that will be — or should be — competitors,” Christie said. “Market power is an ever-present concern, and one rule I taught my law students is that any seller with market power will use it. That’s not a moral judgment, just economic reality.”
The issue of how to allocate transmission plan deliverability (TPD) for projects with long lead-time network and reliability upgrades remained the center of discussion at a Sept. 4 CAISO Interconnection Process Enhancements Working Group meeting.
CAISO allocates TPD to projects separated into four groups. Group A is for customers with executed power purchase agreements and those in the current queue cluster that are load-serving entities serving their own load. Group B includes those actively negotiating a PPA or on a shortlist. Group C is for those that have received commercial operation for the capacity-seeking TPD.
Group D consists of interconnection customers electing to be subject to the Generator Interconnection and Deliverability Allocation Procedures (GIDAP) section (8.9.2.3) in CAISO’s tariff. Being part of that group comes with certain requirements that the ISO and stakeholders considered potentially too restrictive. An interconnection customer in Group D cannot request suspension under the ISO’s Generator Interconnection Agreement (GIA), delay providing its notice to proceed as specified in its GIA or delay its commercial operation date (COD) beyond the date in its interconnection request.
In the Track 3 revised straw proposal, CAISO proposed eliminating Group D.
Bob Emmert, CAISO senior manager of interconnection resources, said cluster 14 of the CAISO interconnection queue included many projects that were unable “to get an allocation through the PPA path or shortlisted path, so they went and chose the allocation group D path.”
“So, a lot of capacity was allocated to those projects, which is actually impacting the [number] of projects that can be studied in cluster 15,” Emmert said. “We didn’t think that was really the best way to go — to, each year, give out some conditional type of allocations through allocation group D and then kind of shortchange the next cluster group on the number of projects that can be studied.”
But some stakeholders were concerned about eliminating the group, given the long timelines for developing transmission.
“The prospect of requiring a short list or PPA to secure deliverability when the resource may not be able to come online and secure deliverability for approximately 10 years is problematic because contracting that far into the future increases risks,” said a presentation given by the American Clean Power Association-California (ACP-CA) during the meeting.
Group D was initially created to give off-takers more assurance for an allocation within the procurement process. Rather than having to wait for the results of the next TPD allocation cycle, some projects will already know they have an allocation, providing increased certainty for LSEs. In light of that benefit, Emmert reversed the ISO’s initial suggestion to get rid of the group and instead suggested removing its restrictions and retaining it.
“The pro in this is … it works well for the process where people are negotiating a PPA and they know whether they have an allocation or not if they follow through with a PPA in time,” Emmert said. “The con is it will impact the next cluster by reducing the number of projects that would be studied.”
‘Conditional Deliverability’
In its presentation, ACP-CA offered a proposal to revise the treatment of Group D, which could be a middle ground between retaining and doing away with the group.
“We share the concerns that have been expressed and the issues CAISO has raised around long development timelines for transmission projects and upgrades and aligning those with reasonable commercial timelines,” said Caitlin Liotiris, a principal at Energy Strategies, who spoke on behalf of ACP-CA. “We also recognize the importance that Group D has played in the commercial process to date, and so are kind of eager to consider an alternative approach to Group D that might continue to provide some of the benefits of the past, perhaps with some additional timeline considerations to help better align the interconnection and TPD allocation timelines with more realistic and achievable commercial milestones.”
ACP-CA’s proposal involves retaining Group D and renaming it “conditional deliverability,” making any deliverability allocated to this group “conditional.”
The conditional deliverability allocated would not reduce the calculation of deliverability available for future clusters under the zonal approach and the 150% zonal limits.
Priorities would be assigned to conditional deliverability allocations, where the first group of projects with this allocation in each TPD allocation cycle would be given first priority, and so on. The priority positions would tell off-takers the likelihood of the project receiving a “standard” group A, B or C deliverability allocation. Rules for determining which projects would be able to convert from conditional deliverability would still need to be established, Liotiris said, such as how to prioritize projects with a PPA over those short-listed or whether to use a scoring methodology.
The ISO said it would need more time to consider whether the proposal could be implemented as part of the interconnection process.
“I think the ISO team needs to come together and discuss this a little bit more,” said Danielle Mills, CAISO principal of infrastructure policy development. “I think there may be some changes to the study process involved in implementing a proposal like this, but it’s probably a little early for us to explain what those would be until we think about it a little further.”
HVDC transmission lines can help efficiently connect offshore wind power, meet growing demand onshore and link together the balkanized grid, but before their use can be expanded in the U.S., the OSW industry needs to set some standards, according to a joint company survey.
DNV’s HVDC Standards joint industry project (JIP), which finished its first phase in April, was convened to identify deficiencies in standards for HVDC. DNV worked with Atlantic Shores Offshore Wind, EDF Renewables, Equinor, Invenergy, National Grid Ventures, Ocean Winds, PPL TransLink, WindGrid, RWE, Shell and TotalEnergies.
The firm launches JIPs when a need crops up in the industries it covers for firms to come together and work on a common issue. While HVDC lines have been growing in the U.S., the domestic industry and regulators still lack key standards to deal with how the technology impacts the grid, DNV Principal Consultant Morgan Putnam said in an interview.
“If you look at Europe, there’s a lot of work that’s been done over the last decade to think through the various ways that an HVDC transmission system can operate and the various services that it can provide to the grid,” Putnam said. “And in order to be able to enable those services, you have to define certain aspects of what the system will and will not do, so that you understand how it will impact the rest of the grid. … We really haven’t thought through that for the North American grid.”
The AC backbone of the grid has been in place for over a century, so the country has not had to look at basic standards for it in generations, he added.
Putnam said the JIP’s work is expanding to a “much larger effort” with the Department of Energy, National Renewable Energy Laboratory, RTOs, utilities and others. DOE will be funding a study process that lasts several years to identify gaps in standards, come up with a plan to fill them, and then implement that plan and remove barriers to wider use of HVDC.
High-voltage lines operate much better underground or underwater than AC transmission, and the technology offers efficiencies for long-haul overhead lines. Their power density is also higher than AC, meaning more power can flow over less actual infrastructure, DNV Principal Consultant Cornelis Plet said in the interview.
The JIP has identified 25 different standards that need to be defined, including active power control, reactive power control, power recovery requirements, emergency power control and islanded operation.
The standards include issues at the national, regional and local levels. The developers that DNV worked with on the first phase came up with five areas that they want to see addressed the most: offshore design standards, performance standards, reliability standards, ISO/RTO manuals and utility interconnection manuals.
“As we are looking at substantially more HVDC projects going forward, in order to have a more efficient process, we really do want to standardize these 25 functional requirements,” Putnam said. “And, so, what we’ve looked at is in the U.S., there’s about 10 of them where there’s some partial standardization, and then there’s 15 that there’s not any coverage at all.”
Even the partially completed standards include plenty of work because they often address just one of the three to four likely use cases of HVDC transmission, he added.
Getting all the standards in place in the U.S. will require working with multiple agencies who oversee different aspects of the industry, compared to Europe where one grid code offers some standardization even across different countries, Plet said.
“There are a number of different hierarchical organizations that create rules that transmission providers have to adhere to,” Plet said. FERC sets very high-level technical principles; he noted that last year it mandated HVDC as part of the transmission planning process. NERC sets the minimum technical standards for reliability, but Plet noted that many of their rules for HVDC are designed for overhead lines and need updates for subsea and buried cables.
Regional reliability entities have their role to play, as do ISOs and RTOs, which have to come up with ways to handle the technology in their interconnection and operational requirements.
“This is where developers of HVDC links often run into problems because ISOs often don’t know how to treat an HVDC line,” Plet said. “There’s no specific class for it. Is it a generator? Not really, but it sometimes behaves a little bit like one. Is it a transmission line? Also not really, but it does have some of the transmission line functions. So how [do you] distinguish between that and … create some clear connection requirements for HVDC systems that are not conflicting on both ends of the line? … And this includes not only how should it be studied, but also how can it participate in the different power markets.”
One hot topic has been whether an HVDC line designed to ship power from one region to another can participate in the capacity market on the delivery end, he added.
State regulators also have a role to play in that they are ultimately responsible for ensuring that consumers do not pay too much for energy, Plet said. The New Jersey Board of Public Utilities and New York Public Service Commission have mandated the use of HVDC lines for the offshore wind those states have procured, he noted.
Getting the standardization in place is a key hurdle to making HVDC a normal part of system planners’ toolbox; Plet argued that the technology will be vital to expanding the transmission system.
“You need HVDC,” Plet said. “You will not be able to build out enough new transmission capacity without it.”
RENSSELAER, N.Y. — NYISO last week updated stakeholders on its draft Reliability Needs Assessment, which still shows an expected capacity shortfall by 2034, though it is slightly less than what was initially presented in July.
The ISO told the Transmission Planning Advisory Subcommittee on Sept. 3 that it had increased its assumption of special-case resource elections by about 200 MW. That resulted in a slightly lower loss-of-load expectation of 0.254 — still well above the required 0.1.
The ISO also revised down New York City’s transmission security margin deficit, from 275 MW to 97 MW, by updating its load distribution model.
“We continue to see statewide resource deficiency by 2034,” said Ross Altman, senior reliability manager for NYISO. “That is still driven by increasing demand, continued additions of large loads and unavailability of gas during winter peak conditions.”
In response to a stakeholder question, Altman said NYISO estimates the statewide resource adequacy need to be about 800 MW, but it “could be as high as 1,875 MW” for transmission security. “It’s very hard to put a number on it,” he said.
The TPAS and Electric System Planning Working Group will review the draft RNA later this month. The Operating and Management committees are expected to vote on it next month, with a Board of Directors review and vote in November.
DALLAS — Now that SPP has set planning reserve margins for the 2026 summer and 2026/27 winter seasons, the grid operator has turned its attention to setting up a longer-term PRM.
“We’ve got to get that done so that we can help our members better prepare for what’s coming,” COO Lanny Nickell said during a recent Resource Energy and Adequacy Leadership (REAL) Team meeting.
Referring to comments made by SPP Board Chair John Cupparo after the directors approved the PRMs despite stakeholder pushback, Nickell said he’s received support for a governing structure to advise staff and ensure upcoming resource adequacy work is coordinated. (See SPP Board of Directors/RSC Briefs: Aug. 5-6, 2024.)
During the August board meeting, Cupparo told directors and stakeholders it appeared necessary to establish the longer-term PRM with “defined mechanisms” to assess and adjust the reserve margin at a “reasonable” interval. He also mentioned implementing regional load forecasting capabilities; strengthening SPP’s roles in bringing generation online faster and building transmission; and continuing to develop outward communication “to those who rely on us” and who can help in the infrastructure build.
“All of these items have either been proposed or are in flight,” Cupparo said in August. “The question is whether some or all should be under a single program management structure with a single point of oversight to ensure we get the necessary outcomes in a timely manner. This is a big ask, but we are facing a generational challenge.”
Working with the board, Nickell drew up a senior-level steering committee to perform that task. He said the group will deliver an action plan or project plan to SPP’s board and state commissioners’ committee in October. It then will oversee the work and “make sure it happens,” Nickell said, noting he sees the group as filling an advisory role and not circumventing the stakeholder process.
The committee is composed of REAL Team Chair Kristie Fiegen, who also chairs the South Dakota Public Utilities Commission — “Congratulations, Kristie,” Nickell said as he read off the names — the Markets and Operations Policy Committee chair; ITC Holdings’ Alan Myers and then Omaha Public Power District’s Joe Lang in 2025; Cupparo as the Strategic Planning Committee’s chair; and Nickell as SPP’s executive sponsor.
“How do we make sure all of this stuff happens in a timely manner?” Nickell asked rhetorically. “It kind of boils down to prioritization and actuation. How do we generate the ideas? How do we make sure those ideas are actually executed in a timely fashion? We’ve got to have more generation, we’ve got to have more transmission, and we need it faster.”
He addressed stakeholders nervous about being able to meet future PRM increases, saying it can be challenging to “move the needle in a big way in the stakeholder environment we’re in.”
“That’ll be part of our challenge,” Nickell said. “We’re going to continue to rely on the stakeholder groups. This steering committee is not a solution committee, right? We’re not coming up with the answers. We just need to make sure that answers are being developed in a timely fashion.”
Demand Response RR Paused
The REAL Team had only one voting item during the Aug. 21 meeting, unanimously agreeing to direct the Supply Adequacy Working Group to pause its early work on a tariff change related to demand response. The team said it will determine a path forward to a holistic solution.
Texas Public Utility Commission staffer Shawnee Claiborn-Pinto abstained from the vote.
The SAWG had been working on a revision request (RR618) intended to accurately account for potential increases in demand-response loads claimed by load-responsible entities (LREs) to satisfy their resource adequacy requirement. The change includes a performance mechanism to accurately accredit DR programs based on their performance.
SPP’s Chris Haley said the SAWG had made progress on the policy package but hit a roadblock after it began receiving load projections from LREs as part of a survey of 2029 resource plans.
“This is going to send a (five-year) signal, but there’s a lot of moving pieces here. It was kind of shocking for us, at least when we saw the amount of load growth that’s being projected for 2029 from the ’23 to ’24 submittals,” he said. “Some of that roadblock was around the ability to have market oversight, or ops oversight and insight into these programs. There was some pushback on doing full market registration for demand response that was being submitted for resource adequacy. There is some demand response in the market today, but right now, that demand response is not being submitted for resource advocacy. It is purely a market product today.”
“Regardless of what we do with [DR’s] Phase 1, I think our very next step is to better understand the magnitude of the potential operations issue,” SPP’s Natasha Henderson said. “Resource adequacy is long-term planning. It’s based upon a lot of different information and it’s a good guess, right? In my mind, I think we just shouldn’t lose sight of the fact that we need to keep the lights on in real time, and I think we need some agreement on what that is, what that means for demand response.”
The resource plans indicate a net increase of about 3,000 MW of installed generation by 2029, much of it thermal. That is balanced out by a 3,000-MW increase in forecasted peak demands.
The SAWG expects to bring a recommended long-term PRM to the REAL Team’s November meeting.
Americans for a Clean Energy Grid (ACEG) released a report Sept. 9 highlighting the critical role states can play in modernizing and expanding the grid.
FERC has jurisdiction over interstate transmission, but states play a crucial role in comprehensive and cost-effective transmission planning and development. The report is meant to inform state policymakers and advocates by offering examples of impactful policies, and it emphasizes the importance of interstate collaboration.
The report is based on surveys and a series of interviews with transmission experts, including advocates, utility staff, developers and state legislators.
“As they look to unlock economic development and support affordable energy for their communities, states can play a significant role in supporting transmission and collaborating with their neighbors in order to develop a better grid,” ACEG Executive Director Christina Hayes said in a statement. “The policies highlighted in this report offer a road map for states looking to lead on this critical issue.”
The report, “State Policies to Advance Transmission Modernization and Expansion,” noted that no policy panacea exists for states because of their differences, but it suggests supporting the principles of reliability, resilience and affordability. Coordination among all levels of government is important, including within the state, with other jurisdictions and in the regional planning process, along with other interested parties.
States should promote comprehensive and coordinated regional and interregional grid planning that fully considers transmission modernization technologies and transmission expansion options, with longer time horizons, to pick the most cost-effective solutions, ACEG said.
The report also calls on states to facilitate robust and streamlined processes for siting transmission, with early and meaningful engagement opportunities and support for impacted communities.
Some policies can become barriers for transmission development, with the report saying short-term plans do not work well for transmission infrastructure, which can have a lifespan of at least 50 years.
Some planning can fail to account for the benefits provided by an interconnected network, siloing the state so regulators consider only whether electrons are delivered within it. Or they can seek to protect in-state resources at the expense of reliability and customers.
“Notwithstanding the potential for state policies to erect barriers, experts surveyed for this report were excited about the opportunities for increased state engagement on transmission,” the report said. “They encouraged states to [not only] improve … their own state policies, but [also] to collaborate with neighboring and other electrically interconnected states to adopt similar policies to amplify the impact on regional and interregional planning and development.”
On siting and permitting, the report suggests minimizing duplication between a state’s own process and those of the federal government, the region and its individual neighbors. States should maximize the use of existing rights of way, including siting lines alongside train tracks and highways.
When it comes to costs of transmission, the report encourages states to participate in regional and interregional cost allocation discussions. It also suggested using public funding for some lines to minimize consumer bill impacts.
In addition to simply expanding the grid, modernization and the adoption of grid-enhancing technologies (GETs) also is important. The report suggests directing utilities to study GETs and high-performance conductors and, when legally sustainable, to offer such projects incentives.
States could create environments that favor advanced transmission technologies, with the report suggesting states exempt them from permitting requirements or set operational standards that encourage their use.
The report brings up state right-of-first-refusal laws, but it does not take a firm position on them. It notes that proponents believe ROFRs encourage more collaborative planning by utilities and cut the time to competitively bid transmission, but opponents argue that competition encourages innovation and cost effectiveness.
“This report underscores the critical role that states play in modernizing and expanding our nation’s transmission infrastructure,” AEU Managing Director Jeremy McDiarmid said in a statement. “As the backbone of our electric grid, transmission ensures that electricity remains affordable, reliable and resilient. This means states must work together in collaborative transmission planning.”
SYRACUSE — A summit convened to examine future energy technologies in New York and the economy that will grow around them gave outsized attention to one technology: nuclear power.
As the state’s efforts to site wind turbines and solar panels struggle with project delays, cancellations and cost increases, and as the federal government doubles down on support for next-generation nuclear, advanced reactors are getting a closer look.
The state issued a draft blueprint for considering advanced nuclear during the summit, and it populated panel discussions with nuclear proponents.
Chagrined nuclear opponents moved pre-emptively to sour public opinion on new nuclear power in the days leading up to the summit, accusing Gov. Kathy Hochul (D) of betraying the spirit of the state’s landmark climate plan.
But state officials themselves are not embracing nuclear power, at least not publicly.
Officials have long maintained a neutral tone on the possibility of new nuclear; Hochul and members of her administration kept that streak alive at the summit.
And the blueprint itself is not a road map for expansion; it is a proposal for a plan for considering whether such an expansion would be right for New York. The state is soliciting feedback and hopes to finalize it by the end of the year.
Simultaneously, the state is launching the process to draw up its 2025-2040 energy plan; the first meeting of the Energy Planning Board is set for Sept. 9.
Doreen Harris, one of the architects of the state’s climate plan and one of the leaders of its execution as president of the New York State Energy Research and Development Authority, said NYSERDA is evaluating eight other future technologies besides nuclear.
But with the bipartisan support for next-generation nuclear that has emerged at the federal level and with all the development efforts that are focused on advanced nuclear technology, the state needs to be prepared to consider the technology when it matures, she said.
The potential benefits and drawbacks of nuclear power make the effort both necessary and complicated.
New York expects to as much as triple its present installed generation capacity as it pursues decarbonization of industry, housing and transportation.
As it does this, the state climate law mandates 70% renewables by 2030 and 100% zero-emissions electricity by 2040. Progress is lagging badly enough that the 2030 goal appears out of reach. (See NY Expects to Miss 2030 Renewable Energy Target.)
So would New York benefit from new reactors to supplement or supplant some of the oldest nuclear facilities in the nation?
Speakers at the summit — those not employed by the state — largely were positive on the idea, and shared thoughts on how to make it happen.
Rich Powell, CEO of the Clean Energy Buyers Association, said his 400-plus members share a common goal but not a common definition of what constitutes carbon-free energy. He urged a similar flexibility in New York, and suggested that preferring one technology does not necessarily mean opposing others.
“Our members will continue to buy wind and solar like crazy everywhere around the country. Let me start by saying that,” he said. “We do need additional tools in the toolkit, in addition to wind, solar, if we’re going to responsibly meet all of this new load.
“You need to accept ALL technologies if you’re really serious about a clean energy future.”
Amber Bieg, lead senior program manager for global sustainability at Micron, said the chip fabrication complex the company plans to build near Syracuse eventually would need a constant 2-GW feed — which equals nearly 6% of the highest peak load the New York grid has ever recorded.
“Right now,” she said, “with the existing technology, the existing market availability, I see two options: I see natural gas, and hopefully renewable natural gas, and then I also see nuclear. And it’s not a one or the other, and it’s not nuclear vs. renewable, it’s nuclear plus renewable plus all the … clean energy that is available right now.”
New York Public Service Commission Chair Rory Christian, serving as a panel moderator, asked what builds a consensus in host communities in favor of nuclear power amid the strong feelings on both sides of the issue.
Nicolle Butcher, chief operating officer at Ontario Power Generation, said “We’re very good at being able to explain to our employees why nuclear is important, the energy transition. We do a lot of education within our company, because we know that they become ambassadors out in the communities.”
Christian asked about safety concerns the public may have about nuclear power.
University at Buffalo Professor Andrew Whittaker said no one died in the Three Mile Island accident and while 20,000 people died in the Fukushima tsunami, radiation from the resulting nuclear disaster did not kill anyone. Chernobyl was deadly, but that reactor lacked key safety infrastructure.
“I think we need to understand the operating reactors are safe enough, or more than safe, they are safer than any other significant infrastructure.”
Christian alluded to the cost overruns seen at Plant Vogtle in Georgia, where construction of two new large-scale reactors cost much more and took much longer than originally advertised.
“I’m curious to hear thoughts on financial mechanisms, procurement measures, anything else that can be done to de-risk development of these advanced nuclear plants,” he said.
The consensus: Follow up with more Vogtles in a timely manner.
Steve Chengelis, senior director of future nuclear at Electric Power Research Institute, said there were cost reductions and schedule accelerations seen in Vogtle 4 over Vogtle 3.
“I think it’s kind of a shame we’re not building Vogtle [5] right now.”
With a timely follow-up project, the construction workforce and supply chain would not disperse and the knowledge gained at cost of time and money would not become obsolete.
“We can get there, it’s been proven. We just have to start that process and keep it moving.”
Butcher said OPG is building its first small modular reactor east of Toronto. And then it is building three more, so it can assess what economies of scale develop after incurring the one-time expenses associated with first-of-its-kind construction.
She urged New York: “Don’t start from zero. Catch up with all of the lessons learned in Canada. OPG in particular and [New York Power Authority] have been great partners since the 1950s, when we first built hydro plants together.”
She also flagged the importance of looking beyond policy, finance and technology to areas such as workforce development.
“We’ve hired 400 engineers in the last 12 to 18 months, just to reinforce our ranks. The trades workforce is the one we worry about most. It’s your traditional welders, boilermakers, all of those, it’s the sheer number of them.”
John Parsons, deputy director for research at the MIT Center for Energy and Environmental Policy Research, said more projects are needed, along with more discussion on paying for them.
“I really think we ought to be challenging ourselves to see some more Vogtles. Those large light water reactors are the best basis for low-cost baseload energy. But I do think it’s a challenge to be able to do it. It’s not something that can be done easily, and it’s not something that you can put onto the shoulders of this or that community.”
Armond Cohen, executive director of the Clean Air Task Force, said the public sector must step up if a nuclear renaissance is to happen.
“I think we should not underestimate how huge this lift is. We’ve not built nuclear in this country for 25, 30 years at scale,” he said.
“Every major nuclear scale-up in the world that has been successful, whether you’re talking about Canada, France or South Korea, has been either the state itself, a government building or a state-owned company building, and I believe that we’re going to need a much more aggressive policy from the state of New York, plus better government partnership. I just don’t see the private sector coming to the table with the kind of incentives that are in federal legislation right now.”
Judi Greenwald, executive director of the Nuclear Innovation Alliance, said a public entity might be able to create a pipeline of projects that could sustain a nuclear industry in New York. (The state-owned New York Power Authority was in the nuclear business but sold its two reactors to private-sector operators decades ago.)
“There’s also a lot of potential for risk sharing, and it’s interesting to me that you guys have played such an important leadership role in offshore wind.”
Marc Nichol, executive director of new nuclear at the Nuclear Energy Institute, said more than 30 nuclear projects are being planned or considered in North America but only the Ontario plan has gone to contract.
The risks attached to first-mover projects are just too great at this point, he said. End users willing to pay a premium for clean electricity are important. But even that is not enough to greenlight a project, he said, and without a final investment decision, the other challenges are academic.
“We’re trying to convince the federal and state governments to share this risk with us so that these projects are going to be able to get to go.”
David Crane, undersecretary for infrastructure at the U.S. Department of Energy, said that is the intention.
“So one of the areas where we have worked with the states and the private sector is to try and line up a clear line of sight to units two through five or two through 10. So I think you’re going to see a lot of developments in the nuclear world over the next year.”
J. Ryan McMahon II, the Syracuse-area county executive, alluded to the deliberative pace at which state government often proceeds.
“I think this is a really good document. I think it’s a really good way for us to start the conversation. But time’s not our friend here. We need to move.”
But there still is strong opposition, even if it is not as widespread as it once was. Opponents cite the high costs and perceived risks of nuclear, as well as the waste stream that will remain highly radioactive for centuries.
New nuclear could be a ticklish matter in a state where Democrats hold all statewide elective offices and both chambers of the Legislature and where hundreds of local governments wield control over development.
Small anti- and pro-nuclear demonstrations were staged outside the summit as state officials launched the study process for advanced nuclear inside.
As it is written, the “Draft Blueprint for Consideration of Advanced Nuclear Technologies” is just that: a collection of questions to guide consideration of the technology, not a plan for construction.
Many speakers at the summit clearly favored building new nuclear generation, but state officials kept any opinions or intentions to themselves.
Gov. Hochul gave the 600-plus attendees and viewers a rousing speech about New York’s leadership stance on clean energy and its place in the industrial heritage of the nation.
“All of you are here because you have something to contribute,” she said. “I’m expecting that contribution to lead us to solutions that other states are too intimidated to tackle. Because this is big, this is hard, but it’s so worthwhile.”
Hochul made only the briefest mention of nuclear power, and not until the end of her speech: “I’m so excited about this all-of-the-above approach — except for fracking and coal, like I mentioned — from wind and solar to geothermal, hydrogen or even splitting an atom.”
Even such a tentative endorsement does not sit well with some environmental advocates. The entire process of nuclear generation — paying for reactors, mining uranium, keeping the surrounding community safe, managing spent fuel — is fraught with risk, they say.
In a Sept. 4 piece, the New York Public Interest Research Group accused the Hochul administration of focusing attention on an unsafe, expensive and unproven technology to divert attention from its failure to meet the climate law’s 2030 goals.
Sustainable Finger Lakes organized the anti-nuclear protest outside the summit, saying, “Decades of experience have demonstrated that nuclear energy is too toxic, too dangerous, too expensive and too slow to build to be a climate solution.”
Food & Water Watch New York State Director Laura Shindell said: “Gov. Hochul must fight for the climate law she flouts, starting with an absolute refusal to bring more dangerous nuclear reactors to New York.”
Robert Howarth, a Cornell University professor and member of the New York State Climate Action Council, said, “Nuclear power is simply too expensive and too slow to deploy, and the state’s needs are far better met by renewable energy and battery storage.”
At the summit, NYSERDA President Harris maintained an agnostic tone on potential zero-emissions resources that could get the state closer to its climate goals even as she highlighted nuclear.
But she acknowledged the issues surrounding nuclear and said the draft blueprint begins the process of addressing them.
“It is critical for us to understand the diversity of perspectives that come with a resource like advanced nuclear,” Harris said. “So we remain open to a comprehensive assessment of all of these resources, but really do want to focus your attention on this particular technology.”
After the summit, Harris told NetZero Insider the overriding objective is to have dispatchable emissions-free resources at the ready — in mass quantity — when the wind does not blow and the sun does not shine.
No technology can fill this role now, but advanced nuclear might be one of the future options that could, she said.
Advanced nuclear also could serve as baseload, even if — especially if — the present emphasis on wind and solar power yields a large intermittent renewable portfolio. There always will be a need for baseload, Harris said.
New York’s reactors have a fairly steady capacity factor in the mid-90% range while its front-of-meter solar farms ranged seasonally from 6% to 26% and its onshore wind farms ranged from 12% to 34% in 2023.
Further illustrating the split, the nameplate capacity of the reactors was only 23% greater than the wind and solar farms in 2023, but the electrical output of the reactors was 437% greater.
There is value and there are costs to each technology beyond the construction price tag. Drilling down to establish the cost and value is central to the work NYSERDA and its partners are doing, Harris said.
“These are very different asset classes, both with respect to the cost profile and the value that they may ultimately provide, such that I feel strongly that we have to think about the very unique value proposition,” she said.
The U.S. Department of Agriculture on Sept. 5 announced more than $7.3 billion in financing for 16 cooperatives as part of its largest investment in rural electrification since 1936.
The department released the grants under its Empowering Rural America (New ERA) program. The $9.7 billion program is part of the Inflation Reduction Act and designed for cooperatives interested in buying or building new energy systems.
National Rural Electric Cooperative Association CEO Jim Matheson welcomed the news, calling it a “transformative opportunity” for cooperatives.
“The New ERA program showcases what is possible when the government prioritizes voluntary, flexible decision-making and allows electric co-ops to take a tailored approach to respond to local needs,” he said in a statement.
All but one of the 16 cooperatives have completed the New ERA’s competitive stage and are in the underwriting process to receive an award. They include three co-ops from Colorado: Tri-State Generation and Transmission Association ($679 million), United Power ($261 million) and CORE Electric Cooperative ($225 million).
Tri-State, which provides wholesale power to its 41 members, plans to use the funds to build or buy 1,480 MW of solar, wind and battery storage and to support the retirement of 1,100 MW of coal-fired generation. It said that will eliminate nearly 5.8 million tons of greenhouse gas emissions annually.
Texas’ San Miguel Electric Cooperative said that if it is awarded New ERA funds, they will be used to convert the co-op’s lignite operations to 400 MW of solar generation and build a 200-MW battery storage facility. It also could use the funding to refinance debt from its stranded lignite infrastructure, a significant obstacle for the transition to solar generation, it said. San Miguel’s 410-MW coal plant is among the top 30 facilities in emitting mercury.
USDA received more than 160 requests for more than $44 billion in funding. Its first New ERA award ($573 million) went to Wisconsin’s Dairyland Power Cooperative, which plans to procure 1,080 MW of renewable energy through four solar installations and four wind farms across Wisconsin, Iowa, Minnesota and Illinois.
The NEPOOL Participants Committee voted Sept. 5 to update the Generation Information System (GIS) to enable the transfer of hourly certificates, opening the door for the sale of hourly renewable energy credits.
Constellation Energy, which developed the proposal, had argued that hourly tracking is the logical next step in the evolution of RECs and would help incentivize carbon-free resources.
“Customers are looking beyond annual procurement of clean energy and unbundled clean energy attributes [toward] supply options that match generation with hourly consumption,” Constellation’s Gretchen Fuhr told the Markets Committee this year. “ISO-NE is already a leader in tracking all generation sources. Tracking hourly attributes is the next step.”
The GIS system is administered by APX, which will develop the changes needed through 2025. The update is expected to cost an additional $75,000.
Financial Assurance Policy Changes
The PC did not reach a consensus to support proposed changes to the Pay-for-Performance (PFP) financial assurance policy, which ISO-NE has said are important to reduce the risks of generators defaulting on their payments.
In a memo prior to the meeting, ISO-NE wrote that it “has identified a fundamental gap in its credit risk management approach regarding the mitigation of PFP penalty payment defaults. The ISO’s proposal to assess capacity sellers’ liquidity and require more collateral from higher-risk entities on an ongoing basis addresses this risk.”
The PFP rate is set to increase from $5,455/kWh in the current capacity commitment period to $9,377/kWh in 2025/2026.
The RTO has proposed to introduce “a corporate liquidity assessment to evaluate PFP penalty default risk that could result in additional financial assurance requirements for higher-risk market participants.”
Following the liquidity assessment, ISO-NE would assign market participants a risk category, which would determine its financial assurance requirement. Some generators have expressed concerns about added costs associated with the additional financial assurance requirements.
ISO-NE’s proposal failed to pass the two-thirds approval threshold with 62.5% in favor, while NEPGA’s revisions also failed with 47% and 53% in favor, respectively.
Despite that, a spokesperson for ISO-NE said the RTO plans to file its proposed changes with FERC.
COO Report and Aug. 1 Scarcity Event
About 1,150 MW of generator outages and reductions, higher-than-expected temperatures, a pair of constrained interfaces and about 350 MW of out-of-service fast-start resources combined to cause ISO-NE’s capacity scarcity condition on Aug. 1, COO Vamsi Chadalavada told the committee.
Chadalavada noted that the RTO entered the day with a limited capacity surplus and experienced about 750 MW in outages prior to the scarcity event. An additional 400 MW in outages occurred as the grid approached peak load, he added.
The Aug. 1 peak load was the highest of the month, at 23,758 MW. Oil generation on the system increased drastically for the peak, while hydro resources also ramped up significantly.
PFP charges for underperforming resources totaled about $50 million during the event. The average systemwide LMP reached $2,113/MWh during the peak hour.
For the month, the real-time hub LMP averaged about $39/MWh, Chadalavada said. The overall monthly energy market value was $403 million through Aug. 27, compared to $674 million in July and $310 million in August 2023. The Forward Capacity Market value was $120 million.
Chadalavada’s monthly report indicated the New England grid’s carbon emissions for the year continue to outpace those of 2023, largely because of increased natural gas emissions.
Order 2222
Also on Sept. 5, FERC accepted by delegated order a compliance filing by ISO-NE for Order 2222 that specifies the deadline for meter data submission (ER22-983-008). The proposal was not protested by any parties.
