New England energy market revenues increased by roughly 150% in the winter of 2024/25 compared to the prior winter, growing from about $1.6 billion to about $4 billion, ISO-NE COO Vamsi Chadalavada told the NEPOOL Participants Committee on March 6.
The increased costs were driven by consistently cold weather, Chadalavada said, adding that this winter was the first with lower-than-normal average temperatures since 2014. Despite that, the system did not experience any capacity deficiency events and maintained adequate oil inventories, he noted.
Natural gas accounted for about 40% of the total energy, followed by nuclear around 23%, imports around 21%, hydropower around 5%, renewables around 4% and oil around 2%.
Chadalavada noted that scheduled LNG injections into the gas system increased to 22.4 Bcf compared to the five-year average of 16.6 Bcf.
Spot payments for the RTO’s Inventoried Energy Program, which compensated thermal resources for maintaining stored fuel on-site, were triggered on five days. The two-year program expired at the end of February.
ISO-NE does not plan to renew the program, which cost about $80 million per winter. The RTO noted in a memo in February that “it has not found that the program provided a notable incremental impact on the regions’ fuel inventories.”
Tariff Uncertainty
ISO-NE also spoke with the committee about the uncertainty surrounding tariffs imposed by President Donald Trump on Canadian imports.
While the RTO has argued that the tariffs should not apply to electricity, it has requested authorization from FERC to collect them in case it is directed to do so by the Trump administration. (See ISO-NE Braces for Tariffs on Canadian Electricity.)
ISO-NE and NYISO have retained an outside counsel to engage with the Department of the Treasury and plan to make the case that electricity should not be covered by the tariffs, and if it is, RTOs should not be tasked with collecting the tariffs, a representative of ISO-NE said.
The RTO’s understanding is, because the secretary of the Treasury has not issued regulations to bring electricity into the scope of the import tariffs, there is no current tariff on electricity imports, the representative noted. Neither the executive order creating the tariffs nor the notice of implementation published in the Federal Register on March 6 explicitly reference electricity.
“I think the biggest thing at this stage is that we continue to seek more clarity,” ISO-NE spokesperson Matt Kakley said.
Committee Votes
The PC voted to support ISO-NE’s compliance proposal for FERC Order 904, which prevents transmission providers from compensating generators for reactive power within the standard power factor range.
The committee also supported changes to ISO-NE’s billing policy to account for a recently accepted change to the RTO’s financial assurance policy allowing an affiliate company to guarantee the payment of Pay-for-Performance charges. (See FERC Approves ISO-NE Capacity Market Collateral Requirements.)
Minnesota regulators voted unanimously Feb. 28 to require that Amazon demonstrate a need for a 250-unit fleet of backup diesel generators at its proposed data center in the central portion of the state.
The Minnesota Public Utilities Commission rejected Amazon’s late December petition to sidestep the state’s certificate of need process for its planned data center campus in Becker (CN-24-435).
During the meeting, Commissioner Joe Sullivan said his mind was “gravitating” toward the plain language of the state statute, which stipulates that any developer of a power plant capable of 50 MW or more must prove the facility is essential over cleaner or more inexpensive alternatives.
Amazon’s planned diesel fleet could generate as much as 600 MW. However, attorneys for Amazon and local labor union representatives argued that the generators should sidestep permitting because they would be strictly for emergency backup, not be connected to the grid and not affect ratepayers.
The topic has also reached the Minnesota Legislature, where Republicans are sponsoring a bill to change state law to exempt Amazon from a certificate of need. If passed, the PUC’s decision to require Amazon’s justification could be moot. The involvement of regulators and legislators demonstrates the uncharted territory of how hundreds of acres of proposed data center should be regulated.
Minnesota Department of Commerce associate counsel AnneMarie Curtin argued that state law is clear in that Amazon’s proposed emergency power fleet meets the definition of a large energy facility that requires a certificate of need.
Commissioner John Tuma said the sheer number of diesel generators proposed by Amazon is a “little shocking.”
“These are not expected to run more than a few times a year and less than 15 hours a year for the regular testing and maintenance that’s required for those systems,” argued Christina Brusven, appearing on behalf of Amazon Web Services. She said similar generators are stationed outside hospitals and government centers, albeit on a smaller scale.
Commissioner Hwikwon Ham pointed out that a “huge load” like Amazon’s that can drop suddenly from the MISO system can trigger an over-frequency event, especially considering the nearby “sensitive” Monticello Nuclear Generating Plant. He said he wondered whether Amazon’s proposed backup would be able to handle such a situation and said he would raise the issue during the certificate of need proceeding.
Tuma said perhaps behind-the-meter generation is not the best way to handle backup power at a site with such large power needs. He urged both Xcel Energy and Amazon to reexamine their ideas about the most appropriate source of emergency power.
“Maybe we can figure out something that benefits both the grid and the system and keeps it safe because, ‘This is a large load dropping off’ does scare me. These are loads that we are not used to dealing with. … This is something that’s new, and we need to understand what it means for the security of the system,” Tuma said. He urged Xcel to prepare answers on how the load could reliably trip offline and “meaningful alternatives” to the diesel fleet.
“I keep hearing from these Amazons and all these [companies] that they want to do the right thing, and they want clean energy, and that’s why they want to plop their data center right next to that solar facility, so I want to hear that those discussions have happened,” Tuma said.
Commission Chair Katie Sieben asked why Amazon did not simply file a certificate of need with its site permitting materials and then lobby for the bill in the legislature. She said it is “frustrating” that Amazon continues to “squeeze” the commission over ambiguous language in state law. She suggested that Amazon might sue the commission if the law is passed.
Brusven said it’s not Amazon’s goal to put the commission in a “difficult position.”
“It is. You did,” Sieben responded and suggested that Amazon could have been “farther along” in the permitting process at this point had it already opted to explain its need.
Sieben said she expected interested parties in the forthcoming certificate of need process to push Amazon for more environmentally friendly options like biodiesel.
MISO estimates its savings and efficiencies benefited its members to the tune of just over $5 billion in 2024.
It’s the first time MISO’s annual Value Proposition has averaged above $5 billion, though benefits in 2023 came close. (See MISO Estimates 2023 Member Savings Near $5B.) MISO said the 2024 range of cost savings is anywhere from $4.52 billion to $5.75 billion. The RTO subtracts membership dues from overall benefit estimates.
The RTO estimates its membership benefits annually through its Value Proposition study, where it attempts to quantify the benefits of its membership against non-RTO entities. MISO does not track cost savings to individual market participants but said members could expect $15 in savings to every dollar spent on MISO membership in 2024.
Per usual, the bulk of the savings (this time anywhere from $2.9 billion to $3.9 billion) is derived from members’ access to capacity sharing across MISO’s large geographic footprint. Efficiency gains from MISO’s energy and ancillary service markets rank second at anywhere from $881 million to $974 million. MISO’s ability to optimize the use of members’ renewable resources through grid planning again took third place at $403 million to $474 million.
MISO said its reliability category was on average less beneficial in 2024 ($337 million) than it was in 2023 ($346 million) because 2024 held fewer extreme weather conditions.
MISO said the value of its membership is poised to increase over the coming years as the fleet decarbonizes. It estimated cumulative benefits at $50 billion since 2007, when it first began producing the annual approximation.
In a press release, Senior Vice President and Chief Strategy Officer Andre Porter said members benefit from MISO’s “market efficiencies, grid planning and operational enhancements across a large and diverse footprint.”
The House Energy and Commerce Subcommittee on Energy held a hearing March 5 to discuss meeting the growing demand for power, with each party’s members claiming the other side’s policies were hindrances.
Data centers, industrial shoring and other factors are driving up demand now as thermal generation is retiring, subcommittee Chair Bob Latta (R-Ohio) said.
“Meanwhile, subsidized intermittent energy resources and public policy decisions in favor of renewable energy are flooding interconnection queues and making baseload power from coal, natural gas and nuclear near uneconomic,” Latta said. “Generation developers continue experiencing ongoing supply chains constraints for distribution transformers and generation turbines.”
The ranking member of the subcommittee, Rep. Kathy Castor (D-Fla.), pointed to recent disruptions in the federal bureaucracy.
“It’s rather absurd that we’re tackling strengthening our electrical system while Elon Musk and the Trump administration are taking a sledgehammer to the Department of Energy, and especially the initiatives that strengthen and modernize the grid,” Castor said. “The new administration has spent weeks illegally shutting down DOE grants and loans and partnerships that make energy safe, reliable and affordable.”
The administration’s tariffs on the country’s largest trading partners are making key grid and generation components more expensive, in addition to the higher power prices already being felt especially in northern states, she added.
While members took shots at their political opponents, both Latta and Rep. Frank Pallone (D-N.J.), ranking member of the full committee, said the growing demand was an opportunity to seize economic growth and keep the U.S. as the leader in artificial intelligence.
“It means that companies are investing in America,” Pallone said. “The cutting-edge technologies are being developed here, and the families are making investments of decarbonizing their homes and vehicles. These are good things.”
Basin Electric Power Cooperative CEO Todd Brickhouse said the co-op is experiencing some of the same rapid load growth as other parts of the country. It serves 3 million customers living across 12% of the U.S.’ territory in nine states.
“Basin is currently increasing its generation portfolio by more than 40%, and we are increasing our transmission mileage by more than 20% over the next decade; we will spend $12 billion on these endeavors,” Brickhouse said. “That compares to currently $8.5 billion of assets on our balance sheet today.”
Improvements in federal permitting would help get that work done, with Brickhouse recounting how one transmission project required two different assessments from different bureaus under the Department of the Interior. Basin is also adding 1,500 MW of new renewable resources to help meet that load growth.
“This has required years of planning and development work, and these business decisions were made based on the availability of production tax credits [PTCs],” Brickhouse said. “We understand and we support the need to put our country on a sustainable physical path, but the immediate removal of PTCs will not allow utilities to plan for and avoid increased costs, and this will also immediately harm ratepayers.”
The tariffs will also make that $12 billion of overall expenditure more costly for ratepayers as Basin recovers the funds from ratepayers over the next several decades, Brickhouse added.
PJM is seeing load growth driven by new data centers and manufacturing, said Senior Vice President for Governmental and Member Services Asim Haque.
“PJM expects its summer peak to climb to 220,000 MW over the next 15 years,” Haque said. “To compare, our all-time summer peak, which occurred in 2006, is 165,563 MW.”
For years, PJM had a healthy reserve margin, but the load growth and some retirements are eating into that now, with the tighter supply-and-demand balance leading to higher capacity prices. With interconnection queue and capacity market reforms in recent years, the RTO has almost caught up with its queue backlog and is about to implement its new system, Haque said.
“We want as much supply as we can get in order to meet this growing demand, whether that’s delaying retirements, new supply, that supply in our queue and even additional supply on top of that,” Haque said.
PJM has cleared 50 GW of primarily renewable resources through its queue, which are having challenges related to financing, the supply chain, and state and federal siting processes. Repealing the Inflation Reduction Act and its tax credits for renewables would add financial strains to those projects, Haque said.
One way the customers behind the new demand could help the situation is by ensuring that they can offer some flexibility to the grid, said Tyler Norris, a James B. Duke fellow at Duke University.
The average use rate for the grid is just 53%, meaning that almost half of generation is sitting idle at most times, said Norris, the lead author on a recent study on data center load flexibility. (See US Grid has Flexible Headroom for Data Center Demand Growth.)
“Our analysis finds that with modest flexibility from new large loads, the grid can accommodate significant demand growth without major new infrastructure,” Norris said. “The U.S. power system is already designed to handle extreme peaks and demand, meaning that in most hours, a substantial portion of the power system is unutilized. …
“Flexible load strategies can provide a bridge, while long-lead resources such as new transmission and clean firm generation are developed.”
Noel Black, Southern Co. senior vice president of regulatory affairs, argued his firm’s vertically integrated, traditionally regulated model has prepared the region it serves well for the new load growth, in part by completing the new nuclear reactors at Plant Vogtle.
“Straightforward regulatory models like ours, where the accountability for the grid is clearly understood, are producing results enabling this innovation economy,” Black said. “In short, the Southeast remains open for business. Regions with unusually complex regulatory processes are experiencing slower infrastructure build out. I think this may be why the concept of co-location has become so popular in certain parts of the country.”
The Electric Power Supply Association, which represents independent power producers active in markets and some of which are pursuing co-location deals, released a statement on the hearing arguing that organized markets were poised to meet the growing demand.
“Appropriately structured competitive wholesale markets can drive innovation and competition and ensure that ratepayers are not exposed to any unnecessary or inefficient investment,” EPSA CEO Todd Snitchler said. “Given the uncertainty surrounding how fast demand will grow in the coming decades, it is critical that investment risk be borne by developers and not shouldered by ratepayers.”
A record 49 GW of clean energy generation came online in the U.S. in 2024, nearly 33% more than in 2023, the American Clean Power Association reported March 5.
Clean energy accounted for 93% of the new capacity added nationwide in 2024, ACP said in its new “Snapshot of Clean Power in 2024,” a condensed preview of the annual market report the trade organization will publish for members next month.
ACP paints a picture of momentum and acceleration of the buildout of U.S. clean energy, which for the purposes of the report is defined as wind, solar and storage.
It took more than 20 years for the U.S. to reach 100 GW of utility-scale clean power capacity, five years to reach 200 GW, then just three years to reach 313 GW.
ACP also repeated the all-of-the-above energy message it has been offering since November, when it became clear that a strong fossil fuel supporter would replace a staunch supporter of renewable energy as president of the United States.
“The only way to meet skyrocketing energy demand is to embrace all American energy resources,” ACP CEO Jason Grumet said in the announcement of the Snapshot. “The clean energy sector’s dominant performance in 2024 demonstrates the unique role clean power is playing in bringing electricity online now to support increased manufacturing and data centers.”
Breaking the 2024 total down into its components, some numbers are more impressive than others. The 33 GW of utility-scale solar and 11 GW of storage installed both far surpassed the previous records, but the 4 GW of land-based wind that came online in 2024 was the smallest amount in a decade.
An ACP map shows 175 MW of U.S. clean energy projects in advanced development or construction at the end of 2024. | American Clean Power Association
And while the single offshore wind farm that came online in 2024 did in fact set a record, it was a minor distinction: It offers only 132 MW, and it was competing against a 12-MW pilot project and a 30-MW near-shore facility that constituted the entirety of the U.S. offshore wind portfolio at the start of the year.
Other facts, figures and highlights from the 2024 Snapshot include:
The fourth quarter was the strongest quarter ever for solar installations (nearly 14 GW) and the second largest for clean energy in total (18.8 GW).
Onshore wind remains the largest U.S. renewable sector, but solar is closing in fast: 33.3 GW of utility-scale solar was installed, bringing the total to 129.7 GW, while 3.9 GW of new capacity brought the land-based wind total to 154.6 GW.
New natural gas generation totaled just 2.4 GW.
Nearly 9 GW of generation was retired, with coal- (50%) and gas-fired facilities (43%) accounting for most of the total.
Forty states now have more than 1 GW of installed clean power capacity, up from 37 in 2023; a dozen states saw their clean power portfolios increase by 1 GW or more.
The pipeline of projects in advanced development or under construction reached 175.2 GW by the end of the year; solar accounted for about half at 89.4 GW, but that was 5% less than a year earlier; battery storage accounted for a quarter of the pipeline at 45.1 GW, which was 49% more than a year earlier.
Forty-six clean-energy primary component manufacturing projects came online nationwide, providing $22 billion in direct investment; 85% of those projects were in states that voted for Donald Trump in the 2024 presidential election; and 79 new projects were announced to create or expand production.
Clean power generation is operational in 86% of congressional districts; 79% of the total capacity is within Republican-held congressional districts; and 77% of new capacity added in 2024 was within Republican districts.
FERC has approved two new NERC reliability standards that address the risks from energy sources with inconsistent output by requiring utilities to perform energy reliability assessments (ERAs) and develop plans to minimize the risk of any forecast energy emergencies.
According to the commission’s Feb. 26 letter order (RD25-5), BAL-007-1 (Energy reliability assessments) will take effect on the first day of the first calendar quarter that is 24 calendar months after the effective date of FERC’s order, or April 1, 2027. TOP-003-7 (Transmission operator and balancing authority data and information specification and collection) will become enforceable six months earlier than the other standard. NERC suggested this timeline when it submitted both standards Jan. 6. (See NERC Submits Energy Assurance Standards to FERC.)
FERC noted that Calpine, Ameren and Public Citizen each filed motions to intervene before the deadline of Feb. 5; however, neither these nor any other party has submitted comments or protests so far.
Both BAL-007-1 and TOP-003-7 were developed under Project 2022-03 (Energy assurance with energy-constrained resources), in response to weather-dependent resources like solar and wind generators to replace traditional inertial generation. NERC said in its filing that “traditional capacity-based planning methods and strategies may not identify [the] risks” associated with these resources and their inconsistent output resulting from volatility in weather and load.
BAL-007-1 will require balancing authorities to perform near-term ERAs and create operating plans to identify and minimize the possibility of forecasted energy emergencies. Assessments performed under the standard must review the resources necessary to serve demand while also providing operating reserves for the grid.
Assessment periods will begin no more than two days after the operating day, and cover between five days and six weeks. The standard allows BAs to specify how often they perform ERAs; all time periods must be covered unless the BA can demonstrate that an ERA is not needed for a specific time period because the risk of an energy emergency is low.
BAs can perform the near-term ERA for their work areas alone or jointly with other BAs for multiple areas at a time. Minimum elements that must be in near-term ERAs include:
forecast or assumed demand profiles;
resource capabilities and operational limits (including fuel supply);
energy transfers with other BAs; and
known grid transmission constraints that limit the ability of generation to deliver their output to load.
TOP-003-7 introduces relatively minor updates to TOP-003-6.1 intended to “ensure that [BAs] have the necessary data to perform the [near-term] ERAs” by adding them to the activities for which they “must have documented data specifications to collect data from relevant entities.”
This requirement is the reason for the gap between the two standards’ effective dates. NERC told FERC in January that staggering them would give entities time to collect the data needed for the assessments required under BAL-007-1.
FERC’s order constitutes final agency action, the commission said. Requests for rehearing must be filed within 30 days of the order’s issuance.
GLASSBORO, N.J. — Facing a projected 40% hike in regional electricity demand by 2030, New Jersey needs to rapidly craft a plan on how to boost generation and develop its transmission and distribution system, according to speakers at a Feb. 27 conference on the state’s energy future.
Power demand from data centers and artificial intelligence projects, along with the expected increase in electric vehicle use and building electrification, are driving demand forecasts that project a power shortfall without significant action, industry stakeholders and state officials said at Meeting New Jersey’s Energy Needs, held at and hosted by Rowan University’s Steve Sweeney Center for Public Policy.
The most visible sign of the shortfall was the Basic Generation Service auction held by the New Jersey Board of Public Utilities in February, which will trigger a hike of about 20% in the average residential bill in June.
“It’s a supply-and-demand issue … We need more electrons on the grid,” BPU President Christine Guhl-Sadovy told the conference of about 150 energy executives, government officials and other stakeholders. She added that it is “unrealistic to think that this kind of price shock can be absorbed by ratepayers without impact.”
Yet it is not clear in the current, uncertain political and energy environments where the additional supply to New Jersey, an energy importer, will come from, speakers said. The stalling of the state’s offshore wind projects, and the lack of clarity over the future economics of solar and other forms of renewable energy generation in the face of opposition to subsidies from the Trump administration, could upend the state’s expected reliance on those sources, speakers said. (See NJ Abandons 4th OSW Solicitation.)
“All these trends are evident in New Jersey,” former state Sen. Bob Gordon, a former BPU commissioner, said as he introduced a panel of generation company executives. “And we’re starting to see some real impacts of the supply-demand imbalance.”
The disruptions are unfolding amid ongoing warnings by PJM that aging fossil fuel plants are going offline at a faster rate than replacement plants are arriving, and the RTO is struggling to maintain a generation balance.
“The supply-demand crunch has come to us quickly,” said Asim Haque, senior vice president for PJM, who underscored the urgency of the situation by noting that the RTO saw its highest ever winter peak demand this year on Jan. 20, Martin Luther King Jr. Day.
In assessing how to boost generation, states need to understand that different generators have different “capabilities of how they can contribute to reliability on the system,” he said.
The suddenly oncoming demand suggests the state should move cautiously in its rush toward electrification, said Michael J. Renna, CEO of South Jersey Industries, which owns several natural gas distribution utilities in the state.
New Jersey’s heating-fueled winter peak is three times as high as the air-conditioning-driven summer peak, and “the grid, including all the way down to the utility levels, is built for the summer peak,” Renna said.
“You rush to electrification, you’ve got big problems, because neither the grid nor the utility systems are capable of moving that much electricity, let alone the fact that we have a generation cap,” he said.
He suggested the state instead focus on decarbonization by using gas with lower carbon content that can be used on existing infrastructure, such as “renewable natural gas or green hydrogen that can safely be blended with the geologic natural gas.”
Tim Sullivan, CEO of the New Jersey Economic Development Authority, which funded much of the state’s offshore wind initiatives, said he continues to believe that the economic and employment benefits of wind generation, and the escalating pressure to add supply sources, will return wind to the fore.
“We are not giving up on wind,” he said. “One of the reasons I’m confident in that is that we actually are seeing, outside of Jersey, progress in offshore wind projects. You’ve got electrons that are flowing in Virginia, New York and Massachusetts that are hitting their grids.
“It’s very hard to disabuse me of the notion that the best way forward for New Jersey” is to address the supply-demand imbalance with offshore wind, he said.
Nor is the state going to shy from the energy challenge presented by the demands of AI projects, Sullivan said.
“AI across the country, across the globe, is going to be an energy monster,” he said. He acknowledged that AI projects need “hundreds of megawatts to a gigawatt of power, and they need hundreds of acres of space,” both of which are limited in New Jersey.
Nevertheless, Gov. Phil Murphy is “smartly positioning the state to be a leader, not a follower, in AI,” Sullivan said. He noted that the state recently launched a program that will award $500 million in tax credits to support AI infrastructure and cited the example of a $1.2 billion state-of-the-art data center planned by CoreWeave. The company signed a lease in October on 280,000 square feet of space at the former global headquarters of pharmaceutical giant Merck in North Jersey.
Harnessing Existing Infrastructure
Hanging over any solution that helps boost generation is how to overcome the challenging task of connecting a project to the state’s transmission and distribution system, speakers said. That includes the well known delays with PJM’s generator interconnection queues.
In addition, all of the state’s four utilities, to varying degrees, have areas where projects cannot be connected because the infrastructure cannot accept them, said Lyle Rawlings, president of the Mid-Atlantic Solar & Storage Industries Association (MSSIA).
“That’s the big bad problem that we’re facing. It’s already putting tremendous downward pressure on our ability to deliver solar in this state,” he said.
The issue was a major factor in the drop in installed solar capacity in 2024, he said. BPU figures show installations were 40% below the 2023 level even as the state reached a milestone of 5 GW of installed projects.
Still, Rawlings said, the state is “on track” to reach its goal of 17 GW of installed solar power by 2035, and MSSIA modeling shows that by then it could account for 24.5% of New Jersey’s electricity, with nuclear contributing 34%. (See Struggling NJ Solar Sector Evaluates Net-metering Reform.)
Former Commissioner Gordon suggested that part of supply could be swiftly increased by connecting grid-scale battery storage through the infrastructure left behind by now closed generating facilities.
“The task of getting the PJM approval for a battery storage facility located at an old fossil fuel generating plant could take much less time than a brand new project,” he said. “I mean, maybe 90% of the analysis has already been done, and you’re not likely to encounter the political pushback from building something new in an area that might affect the neighbors, because people been living with this generating plant for decades.”
PJM’s Haque said the RTO is awaiting the result of an application to FERC to grant approval in such a situation. He said PJM also has sought permission to grant accelerated approval to projects that pair a generating facility that already has been approved with a battery storage project.
“It’s about trying to expedite resources,” he said. So an approved solar project could be paired with storage, enabling the batteries to “produce during periods where that solar unit can’t produce” and without forcing the storage operator to “go through the queue.”
Leveraging the Footprint
A similar strategy of harnessing “surplus interconnection opportunity” could be adopted by upgrading the state’s existing solar projects, said Lawrence Barth, director of corporate strategy at NJR Clean Energy Ventures, an energy project developer and operator.
“We ought to be thinking about how do we leverage that footprint now that we’ve got panels that produce two to three times that amount than when they were originally installed, at lower cost,” he said.
Several speakers suggested the state consider boosting generation by adding to the nuclear fleet in South Jersey, the Salem 1 and 2 plants and Hope Creek, which are operated by Public Service Enterprise Group and generate about 40% of the state’s electricity. They cited the example of Plant Vogtle — one of the first nuclear reactors built in the U.S. in nearly a decade — that came online in Atlanta in 2024.
But they also noted the extensive permitting bureaucracy, massive investment and lengthy construction timeline needed; Vogtle took 15 years to build. More feasible would be a small nuclear reactor, which could be built in five or six years, said Erick Ford, president of the New Jersey Energy Coalition.
“If they’re going to start the process now, [by] 2030 they should be able to have it online,” he said.
Proponents of SPP’s Markets+ argued in their latest “issue alert” published Feb. 28 that the day-ahead market option provides a robust footprint with “exceptional generation and load diversity” across the region while also claiming recent warnings about its seam with CAISO’s Extended Day-Ahead Market (EDAM) are overblown.
The alert is the seventh and last in a series of notices highlighting the purported advantages of Markets+ over EDAM and the Western Energy Imbalance Market (WEIM). The alerts have covered topics such as governance, reliability, pricing practices, market seams, emissions and market operations.
The contributing parties include Arizona Public Service, Chelan County Public Utility District (PUD), Grant County PUD, Powerex, Public Service Company of Colorado, Salt River Project, Snohomish County PUD, Tacoma Power, Tri-State Generation and Transmission Association, and Tucson Electric Power.
In their seventh alert, the proponents argued Markets+ will “be substantial in size with exceptional generation and load diversity.” For example, the market will have peak demand of over 52 GW and annual demand of over 280 TWh; a significant mix of resource diversity; clean flexible supply; and a “large geographical footprint — encompassing parts of 11 different states — resulting in a reduced probability that heat waves and cold snaps affect the entire Markets+ footprint simultaneously.”
However, the studies do not capture the full economic picture and fail to account for the differences in market design between Markets+ and EDAM, the alert argued. The models assume Markets+ and EDAM will be isolated with limited trade when, in reality, entities in each will continue trading with one another, it said.
“This defies real-world expectations and ultimately promotes an incorrect conclusion that being in the largest possible market footprint should be the only relevant consideration informing an entity’s market choice above all other factors, including fundamental differences in governance and market design that are not evaluated by these studies,” the proponents contended.
John Tsoukalis, a principal at The Brattle Group, contended that the alert “mischaracterizes” assumptions Brattle studies have made regarding market seams.
“Our studies show that there continues to be significant trading across the market seams. In fact, we assume a lower hurdle rate to trade between Markets+ and EDAM than we do to trade bilaterally between two utilities in the WECC,” Tsoukalis told RTO Insider.
“The issue alert does not name our study directly, so perhaps they are referring to the assumptions used in other studies and assuming all production cost studies are the same. That is not the case,” he said.
Tsoukalis noted also that some stakeholders “have confused long-term bilateral transactions across market seams with short-term day-ahead trading across market seams.” He said Brattle’s model treats the two types of transactions differently, with long-term transactions showing no transaction costs while costs applied to short-term transactions under a two-market scenario are assumed to be lower than costs observed today in the West.
The alert also covered congestion costs. The proponents argued that Markets+ provides enhanced protection from congestion costs by allocating congestion revenue to firm transmission rights holders in proportion to the congestion costs incurred on their specific transmission paths.
In contrast, EDAM participants will miss out on robust congestion cost protections, the proponents claimed.
“EDAM will not return these congestion charges back to the firm [open-access transmission tariff] rightsholders that are exposed to the congestion costs and will instead return the revenue to the [balancing authority area] where the constraint is located, which public data show is most often the CAISO BAA,” the alert argued. “Among the many negative consequences of this design, it is likely to impose large new costs for the transmission customers and ratepayers of EDAM participants outside of California, to the benefit of customers in the CAISO BAA.”
When asked to comment on the issue alert, CAISO’s head of communications, Jayme Ackemann, pointed to another study by the Brattle Group that suggests some EDAM participants “could conservatively save consumers nearly $900 million annually.” (See Updated EDAM Study Shows Doubling of PacifiCorp Benefits.)
Ackemann also pointed to the West-Wide Governance Pathways Initiative, an effort to ensure independent governance of CAISO’s EDAM and WEIM. California state lawmakers recently introduced legislation as part of the initiative. (See Pathways ‘Step 2’ Bill Sets Conditions for EDAM Governance.)
“With FERC’s approval of EDAM’s market design and more than 50% of the load in the West planning to participate, it is clear that maintaining a strong, geographically diverse and interconnected system is crucial to maximizing consumer benefits through widespread participation in WEIM and EDAM,” Ackemann added.
VALLEY FORGE, Pa. — The PJM Planning Committee on March 4 endorsed by acclamation revisions to Manual 14H to conform with changes to the RTO’s surplus interconnection service (SIS) process FERC approved in February (ER25-778).
SIS allows developers to add new resources to an existing point of interconnection that is not fully used; for example, if an existing resource does not operate at all times of day. Injection is capped at the capacity interconnection rights in the original resource’s interconnection service agreement, and surplus interconnection requests do not trigger the need for new network upgrades.
The new manual language would eliminate categorical prohibition on storage eligibility for SIS; change how PJM models proposed resources alongside projects in the generation interconnection queue; expand eligibility to allow SIS applications when the host resource is still in development; and allow projects that consume transmission headroom but do not require network upgrades. It would also allow projects that require additional interconnection facilities for the service while still prohibiting new network upgrades.
PJM’s Ed Franks said SIS applications would be studied using the most recent cluster phase 3 model to be commenced, which he said would strike a balance that allows projects to proceed without being disrupted if others in that cluster drop out. Franks said it is less likely for projects later in the queue to withdraw, reducing the risk of cluster analyses having to be retooled in a manner that impacts the potential for SIS projects to be assigned network upgrades.
“This would only be exponentially more complicated if we were using an earlier model,” he said.
Responding to stakeholder questions on what battery storage configurations would be allowable, Franks said both open- and closed-loop storage would be permitted so long as network upgrades are not triggered.
Ken Foladare, director of RTO and regulatory affairs for Tangibl Group, said the change would allow existing renewable resources to increase their reliability contribution by adding storage, transforming a non-dispatchable resource into semi-dispatchable.
“This is a good opportunity for PJM to be able to add megawatts, especially if you’re adding battery storage to standalone wind, standalone storage and contribute to resource adequacy,” he said.
Stakeholders questioned whether there would be a cure process for cases in which network upgrades are identified and allow for developers to change the scope of their projects to mitigate those violations. PJM Vice President of Planning Jason Connell said the tariff is clear in that if the SIS request causes a need for network upgrades, it would be denied.
PJM Director of Interconnection Planning Donnie Bielak said developers could submit a new application with changes that could avoid triggering the upgrades that led to rejection. He said the RTO wants to avoid taking on the role of a design consultant engaging with a back-and-forth with the developer on what can be done to avoid network upgrades.
Puerto Rican company Pluvia filed a petition with FERC in February asking the commission to find that its proposal to link the territory to the continental U.S. via grid-scale batteries on cargo ships could trigger its jurisdiction over the island (EL25-57).
The batteries being shipped back and forth would be storage-as-transmission-only assets (SATOA), and similar projects have been proposed using railcars. The mobile storage could also ship power the other way. The firm’s filing says the technology could be used for day-to-day shipping and under emergency conditions.
The firm filed its petition in early February, and FERC noticed it a couple of weeks later. It has largely flown under the radar, with only Public Citizen filing a “doc-less” motion to intervene before the comment period closed March 3.
Pluvia describes itself only as “a domestic limited liability company wholly owned by citizens of the United States and organized under the laws of the commonwealth of Puerto Rico, inter alia, to produce, transmit and sell electric energy at wholesale.” Exactly who is behind the firm is unclear: Its petition was filed by one lawyer, and its incorporation documents with Puerto Rican authorities only list another lawyer.
The state-owned Puerto Rico Electric Power Authority (PREPA) entered into contracts with Luma Energy (a subsidiary of Canadian utility Atco and Quantas Services) to run its grid in 2021, and with Genera PR (a subsidiary of the LNG firm New Fortress Energy) to run its generation in 2023. Pluvia told FERC that those deals have kept a monopoly in place, which is overall detrimental to the island’s population.
“Public electricity monopolies have been effectively managed by other states, which have cooperated to lower costs and improve service to customers by implementing federal electric competition policy under the” Federal Power Act, Pluvia said. “The government of Puerto Rico’s administration, however, has been unsuccessful. The damage Puerto Rico’s electricity monopoly has caused is considered a human-made disaster with appalling humanitarian and economic impacts in Puerto Rico that also impact United States taxpayers.”
The island was infamously impacted by Hurricane Maria, which in 2017 destroyed the island’s power grid and kept some of its residents without power for four weeks.
“It’s really not done well since the hurricanes; the reliability of the system is probably about 10 times worse in terms of safety and safety metrics than the U.S. average,” Cathy Kunkel, energy consultant for the Institute for Energy Economics and Financial Analysis, said in an interview. “And the reliability has actually declined over the last year or so.”
PREPA’s system was contracted to Luma and Genera after the hurricane, with Kunkel saying it was not sold outright because that would have put at risk federal disaster relief funds being used to shore up the grid.
High costs and an unreliable power system have been impairments to economic growth on the island and its ability to stop people from moving to the mainland, Pluvia said in its petition.
On top of still running a creaky grid before and after Maria ravaged PREPA’s system, the public utility has been bankrupt, which has hampered its ability to attract needed investment, Pluvia said
“PREPA’s lack of credit creates a barrier to normal project financing for energy projects, as financing sources hesitate to bet on PREPA’s performance of its long-term contractual obligations to buy electricity in quantities and at prices stated in” power purchase agreements, Pluvia said.
The combination of public monopoly and insolvency leads consumers and investors to a dead end, while creating the misleading appearance of an energy transition through multiple phases of bids and awards that produce contracts needing affordable financing, it added.
While Pluvia and its backers might have run into trouble with securing contacts, Kunkel noted that major deals have been struck recently.
“There’s definitely been long-term contracts that have been signed in the last several years,” Kunkel said. “There’s been a number of new renewable energy contracts and some battery storage contracts and a new natural gas plant contract that was signed in December.”
Another trend since Maria has been end-use consumers’ increasing adoption of distributed solar and storage, which Kunkel said makes up about 9% of Puerto Rico’s electricity consumption.
The issue of FERC jurisdiction over Puerto Rico’s grid has come up before, such as when Alternative Transmission filed a petition in 2023 seeking a finding from the commission that its proposed undersea cable would not trigger commission jurisdiction (EL23-14). The project and its details were a little too vague for FERC to give a firm answer, but it did discuss the jurisdictional issues and said it could forswear oversight of Puerto Rico’s grid as it has in similar cases involving ERCOT. (See FERC Weighs in on Jurisdictional Questions over Puerto Rico Project.)
The Alternative Transmission case came up in Pluvia’s petition as it seeks to clarify that its proposal of shipping batteries back and forth by sea could trigger FERC jurisdiction over the island’s power system, which the commission said could happen with an undersea cable.
The petition does not ask FERC to claim jurisdiction immediately, but Pluvia said it may request that in future proceedings, and it expressly reserved the right to do so.
Puerto Rico has a version of a state regulator already called the Energy Bureau, which was set up about a decade ago to oversee PREPA. IEFFA’s Kunkel said it has helped bring some normalcy to the island’s regulatory structure.
“One of the problems with PREPA … was that it really had just kind of become a very politically driven entity and was not making decisions based on best-practice, sound utility planning,” Kunkel said. “For example, it had not had a base rate case since the 1980s. One of the first things that the Energy [Bureau] did was to have a base rate case.”
As for bringing RTO-style markets to the island, it is unclear how much benefit they would bring: Puerto Rico’s system is far smaller than any of the continental organized markets, meaning it would lack the benefits that come from centrally dispatching large amounts of generation across a wide footprint, Kunkel said.
