Constellation Energy turned in another solid quarterly report Aug. 6, boosting its earnings guidance for the year and offering a rosy picture for the future of its nuclear power fleet.
During a conference call with financial analysts, much of the conversation surrounded data centers and the prospect of Constellation helping to meet their immense load demand with long-term behind-the-meter supply agreements.
CEO Joe Dominguez said the company is moving ahead with negotiations for co-located data centers even as the regulatory structure for such agreements is examined.
He presented this as a win-win-win — helping to place the nation at the forefront of the artificial intelligence revolution, reducing the amount of new infrastructure utility ratepayers must fund and locking in a market for Constellation’s zero-emissions generation for decades to come.
“We’re confident that any thorough examination of co-location with nuclear plants will show that it is both the fastest and most cost-effective way to develop critical digital infrastructure without burdening other customers with expensive upgrades,” he said.
Long-term behind-the-meter agreements also give Constellation the economic certainty it needs to seek relicensing of its plants, Dominguez said.
The issue has gained prominence as Talen Energy has proposed a deal to power a growing data center on the site of its nuclear plant in Pennsylvania, drawing protests from Exelon and American Electric Power, which drew rebuttals from Talen and others, including Constellation. (See Talen Energy Deal with Data Center Leads to Cost Shifting Debate at FERC.)
Dominguez said the Aug. 2 actions at FERC “may have slowed things but ultimately will be constructive, in our view. Notably, FERC did not grant requests by a small number of utilities to set the Talen Energy ISA for hearing or in the alternative to reject it outright.”
Co-location is not always the right solution, but neither is it a new or unfamiliar concept, he added.
“As we see it, utility connection will continue to make sense for some applications and in some parts of the grid. But when it’s an option, we will continue to see customer interest in co-location, strong interest, because there are just too many advantages of connecting large load directly to large forms of generation, especially clean generation.”
The protest to FERC about the Talen deal may slow the finalizing of facility co-location agreements or change their details, but it will not block co-location, Dominguez said.
“We really don’t see an outcome here where the FERC is going to say, ‘You can’t do this.’”
Dominguez said it did, just as it has increased the urgency for front-of-meter deals, because the marketplace is tightening.
Another analyst asked whether Constellation expected to get regulatory clarity on the prospect of co-location this year or next.
Dominguez did not offer a prediction but said Constellation is not waiting for absolute clarity in the FERC process.
“I do think the Talen ISA is going to be instructive, and folks are watching that, to make sure it goes through, what conditions might get attached to that, but we independently are working on contractual provisions that allow us to manage whatever outcome comes out of those proceedings.”
He added: “So, at least for the moment, we’re working with our customers [toward] finalizing deals.”
Customers and policymakers have an interest in resolution of the dispute, Dominguez said.
“Talen’s not our deal, but I’ll use it as an illustration: That arrangement is bringing $10-plus billion, maybe more than $20 billion, of economic development to a region that if we’re going to be honest, hasn’t seen a lot of sunshine from an economic development standpoint of this dimension in a long, long time.
“I think it’s fair to say that policymakers around Pennsylvania like to see that for communities like this that need jobs and economic opportunities. And I think it’s fair to extrapolate from that, that they won’t like it very much if people interfere with those things and cause it to come off the rails.”
Constellation reported second-quarter GAAP net income of $814 million ($2.58/share), compared with $833 million ($2.56/share) in the same quarter of 2023.
The company raised its full-year 2024 net earnings guidance from $7.23 to $8.03/share to $7.60 to $8.40/share and maintained its earlier forecast of annual earnings growth greater than 10% on average through 2028.
Constellation’s stock price closed 6.5% higher in heavier-than-average trading Aug. 6.
TULSA, Okla. — SPP is considering a 765-kV solution and several 500-kV proposals in its Permian Basin footprint in Texas and New Mexico, its first dabble with extra high voltage (EHV) transmission lines.
Staff have proposed a 300-mile, 765-kV transmission line in New Mexico that will address “extreme” forecast load growth beyond its next two Integrated Transmission Planning (ITP) portfolios. They say it’s part of a proactive approach to get ahead of the region’s growth.
“It’s kind of the big one we’re going to look at,” SPP planning engineer Nick Parker told stakeholders during the Markets and Operations Policy Committee’s July meeting.
Growing electrification of oil and gas activity fuels much of the region’s load growth, although large industrial and data facilities also are contributors. SPP forecasts the Permian’s drilling load in New Mexico to increase by 5.3 GW in 2032. Southwestern Public Service (SPS), the incumbent utility for the region, says its load projects have grown by more than 2,750 MW since the 2023 ITP.
SPP staff said load growth will continue to aggravate issues in an already stressed area of the system and that solutions must address conditions beyond the 2024 ITP due to expected rate of growth.
The 765-kV solution offers other technological and operational advantages. The line’s capacity is nearly three times that of a double-circuit 345-kV line and its cost per MW-mile is less than one-third the cost per MW-mile of 345 facilities, SPP says. Because 765-kV lines use the highest voltage available in the nation, their load is less than lower-voltage lines and they can carry power over longer distances.
“We expect these loads to continue to grow. They’re still coming, and we know that electrification is still coming,” Parker said. “We think it’s just the more proactive approach to go ahead and move forward with the beginning of a 765-transmission system to ensure we can deliver to this area.”
Staff also are considering about 525 miles of 500-kV projects in the same area. They said with anticipated load growth beyond the 2024 and 2025 ITP studies, “a more robust solution” is required to address voltage and power delivery issues in southern New Mexico.
The growing load in SPP’s Permian Basin footprint | SPP
ERCOT staff has projected the SPS projects will cost about $750 million, or almost as much as the 2022 and 2023 ITP portfolios. The entire portfolio could end up costing between $2 billion and $3.5 billion. The costs are conceptual in that they are more “rough estimates” until SPP receives study-level estimates.
“This portfolio is the largest that we’ve ever had in an annual cycle. It is reflective of load changes,” engineering vice president Casey Cathey said, noting the last ITP cycle’s load forecast exceeding two-year-out models in just one year.
“We recognize that there are a number of projects in our queue that probably don’t really need to be in our queue,” he added. “We also recognize there are a number of projects that need to stay, and they need to interconnect.”
ERCOT faces similar challenges addressing the Permian’s explosive growth. In a report filed with Texas regulators, the grid operator said transmission operators expect oil and gas load to peak at 11.96 GW in 2030 and 14.71 GW in 2038. It expects an additional 12 GW of data center and other non-petroleum load by 2030, with the combined total amounting to about a third of the system’s current summer peak (55718).
Based on those forecasts, ERCOT projects a total cost of between $12.95 billion and $15.32 billion for the transmission facilities to meet the coming load. The ISO sees EHV lines as part of the solution, pointing to their “generally known” benefits over 345-kV counterparts: reducing losses for long-distance transportation, increasing short circuit strength and improving voltage stability.
“ERCOT recommends the [Public Utility Commission] give serious consideration to an EHV solution — particularly a 765-kV solution — to meet the forecasted transmission needs,” staff told the PUC.
The commission also is gathering stakeholder input on EHV transmission lines in ERCOT. ERCOT has said in response that incorporating 500-kV and 765-kV lines could reduce or eliminate the need for large underbuilds on the 138-, 115- and 69-kV systems (55249).
“An EHV system would likely remain the backbone of the bulk power system for decades without an increase in voltage,” the grid operator said. It said 500- and 765-kV systems are expected to provide “ample capacity to meet substantial long-term load growth and accommodate large power transfers” and they offer greater flexibility in siting generation resources.
The U.S. Department of Energy on Aug. 6 announced its second round of grants for the Grid Resilience and Innovation Partnerships (GRIP) program, with $2.2 billion going to eight projects that could expand grid capacity, reliability and flexibility across 18 states.
Funded with $10.5 billion from the Infrastructure Investment and Jobs Act, the GRIP program is aimed at supporting “transformative” projects that will “enhance grid flexibility and improve the resilience of the power system against growing threats of extreme weather and climate change,” according to DOE.
Announced in October, the first round of awards totaling $3.46 billion was focused primarily on improving grid resilience against extreme weather events at the distribution level, Energy Secretary Jennifer Granholm said during an Aug. 5 press briefing. (See DOE Announces $3.46B for Grid Resilience, Improvement Projects.)
The second tranche announced Aug. 6 is “specifically focused on transmission lines themselves, building more than 600 miles of new lines and reconductoring more than 400 miles of existing lines,” Granholm said. “Altogether, those upgrades are going to add nearly 13 GW of capacity to the grid … to meet the needs of electrified homes and businesses and new manufacturing facilities and all of these growing data centers that are placing demands on the grid. …
“The first half of 2024 has already broken records for the hottest days in Earth’s history, and as extreme weather continues to hit every part of the country, we must act with urgency to strengthen our aging grid to protect American communities,” Granholm said in a DOE press release.
According to DOE, six of the projects will be using the GRIP grants to deploy grid-enhancing technologies (GETs) to expand capacity on existing lines. For example, California is getting more than $600 million to upgrade 100 miles of transmission with advanced conductors and dynamic line rating technology to increase the amount of renewable energy on the grid.
Similarly, a $57 million GRIP award will go to the North Carolina Department of Environmental Quality, which will partner with Duke Energy to upgrade a key transmission line with advanced conductors that will increase capacity and improve resilience as electricity demand continues to grow in the eastern part of the state.
Advanced conductors have a stronger core that can operate at higher temperatures than traditional grid lines, which allow them to carry more power. Dynamic line rating technologies allow grid operators to determine how much power a line can transmit based on real-time conditions rather than using a preset, static rating.
Of the projects building out new lines, Montana was selected to receive the largest award, $700 million, to support the North Plains Connector (NPC), a 415-mile HVDC line running from Montana to North Dakota. It will be the first transmission project that will connect three regions — MISO, SPP and the Western Interconnection — with bidirectional power flows that could open up 3,000 MW of new capacity, as detailed in DOE’s project description.
The project will also help the Standing Rock Sioux Tribe develop wind power on their land.
That broad regional coverage could provide benefits by connecting meteorologically diverse regions that have demand peaks at different times of the day or in different seasons, according to a recent study by Astrapé Consulting. The difference in generation and load profiles could improve the grid’s reliability on both sides of the project without adding any new capacity, project developer Grid United said. (See Study: Significant Benefits for Merchant Tx Line.)
All GRIP awards are supported by public-private partnerships, with individual states and their commercial partners at least matching or exceeding the federal funds. The $700 million for NPC is being matched with close to $2.9 billion in other funding, according to DOE.
DOE estimates the projects will create about 5,000 jobs, with six of the eight projects partnering with local labor unions.
Getting GRIP Projects Permitted
Other GRIP awards will support initiatives that tackle critical grid challenges, including responding to rapidly growing demand from data centers and connecting offshore wind projects to onshore lines.
Home to the greatest concentration of data centers in the country, Virginia is receiving $85.5 million for a project that will build up distributed energy resources at data centers to provide flexible power to the grid. The funds will go to install battery energy storage systems at the Iron Mountain data center in Manassas, Va., and to deploy solar, storage and a natural gas turbine at the Grace Complex, an industrial innovation hub being developed in Lancaster, S.C.
A $389.3 million grant is going to Power Up New England, a joint project of six new England states, ISO-NE and public utilities that will provide new substations in Southeast Massachusetts and Southeast Connecticut to connect up to 4,800 MW of offshore wind power to the onshore grid. And Northern Maine will get a long-duration energy storage system with multiday capacity to improve grid resilience and the integration of renewable energy.
“With Power Up, we are shifting the way we bring offshore wind into our grid,” said Rebecca Tepper, Massachusetts’ secretary for energy and environmental affairs. “We’ve done the hard work to coordinate with ISO New England and developers to ensure we’re making smart, targeted investments to ready our electric grid.”
Speaking at the Aug. 5 press briefing, both Granholm and National Climate Advisor Ali Zaidi said Power Up and other GRIP projects would benefit from DOE’s efforts to streamline and accelerate federal permitting processes, such as the Coordinated Interagency Authorizations and Permits (CITAP) program announced in April.
Under the initiative, DOE will take the lead on permitting transmission projects and coordinate environmental and permitting processes between federal agencies, with a goal of limiting permitting timelines to two years. (See DOE CITAP Initiative Aims to Permit New Transmission in 2 Years.)
Reconductoring projects may be eligible for categorical exclusions, the lightest level of environmental review, under revisions to permitting rules DOE released also in April, providing “a permitting ecosystem that has been vastly improved,” Zaidi said.
Responding to a reporter’s question, a senior DOE official declined to speculate on the potential impact of the bipartisan permitting bill authored by Sens. Joe Manchin (I-W.Va.) and John Barrasso (R-Wyo.), respectively the chair and ranking member of the Senate Energy and Natural Resources Committee.
The Energy Permitting Reform Act of 2024 would increase FERC’s power to authorize new transmission projects and require interregional transmission planning. The bill passed the committee on a 15-4 vote on July 31, days before Congress adjourned for its August recess. The Senate will have three weeks to pass the bill before Congress again goes into recess for the election. (See Manchin-Barrasso Permitting Bill Easily Clears Committee.)
DOE favors removing barriers to permitting and accelerating the ability to do concurrent environmental reviews, the official said, adding that the department is even doing a pilot on using artificial intelligence on permitting.
A third round of GRIP awards will be announced this year or early in 2025 for two other programs under the initiative, DOE said. The Grid Resilience Utility and Industry Grants will target private sector efforts to upgrade the grid, and Smart Grid Grants will support technologies that expand grid capacity.
Hawaiian Electric Co. (HECO) and its parent company Hawaiian Electric Industries have agreed to pay $1.99 billion to settle all claims against them for last year’s wildfires on Maui, the companies announced Aug. 2.
HECO’s payment comprises a bit less than half of a global settlement involving the two companies and six other defendants — the state of Hawaii, Maui County, Kamehameha Schools, West Maui Land Co., Hawaiian Telcom and Spectrum/Charter Communications — totaling $4.037 billion. Maui County said in a statement the settlement was negotiated by mediators “appointed by the court overseeing most of the Maui wildfire lawsuits.”
The agreement also would settle all claims between the defendants, HECO said in its announcement. Maui County, one of the defendants in the global settlement, also is among the plaintiffs that sued HECO following the fires.
“Achieving this resolution will allow all parties to move forward without the added challenges and divisiveness of the litigation process. It will allow all of us to work together more cohesively and effectively to support the people of Lahaina and Maui to create the future they want to see emerge from this tragedy,” HECO CEO Shelee Kimura said. “For the many affected parties to work with such commitment and focus to reach resolution in a uniquely complex case is a powerful demonstration of how Hawaii comes together in times of crisis.”
HECO’s payout includes $75 million that the utility already contributed to the One Ohana Fund, created last year to compensate victims of the wildfires and their families for “deaths and serious physical injuries.” The fund pays $1.5 million to the families of each deceased victim and determines compensation for physical injuries on a case-by-case basis.
Hawaii Gov. Josh Green said in a separate statement that the proposed settlement, described as an agreement in principle, will resolve the claims of about 2,200 affected parties who have filed lawsuits against one or more of the co-defendants. Green said he was grateful the agreement had been worked out after about four months of mediation, as opposed to a lawsuit like those over wildfires in other states that “typically take years to adjudicate.” The agreement has not received final approval from the court.
“My priority as governor was to expedite the agreement and to avoid protracted and painful lawsuits so as many resources as possible would go to those affected by the wildfires as quickly as possible,” Green said. “It will be good that our people don’t have to wait to rebuild their lives as long as others have in many places that have suffered similar tragedies.”
Green added that the state’s contribution to the settlement must be approved by the legislature. Once this has been completed and the court has signed off, the payments are expected to begin by the middle of 2025.
Last year’s wildfires killed 100 people and burned more than 3,000 acres on Maui, including the historic town of Lahaina. HECO faced widespread criticism in the immediate aftermath, with lawsuits filed by multiple plaintiffs alleging that the utility failed to power down electric equipment even amid fire danger warnings from the National Weather Service; did not properly maintain and repair utility poles; and neglected to keep vegetation trimmed and away from power lines. (See Hawaiian Electric Faces Multiple Lawsuits over Wildfires.)
Testifying before Congress last year, Kimura defended her company against allegations of responsibility for the fires, noting that the lines in the area where the Lahaina fire began Aug. 8 were not energized at the time. (See House E&C Members Grill HECO CEO About Maui Fires.) HECO did not have a pre-emptive public safety power shutoff program in place at the time the wildfires began, but Kimura said the utility was considering implementing one; it introduced its first PSPS program last month on Oahu, Hawaii Island and Maui.
In addition, the Hawaii Public Utilities Commission on Feb. 1 approved HECO’s five-year resilience plan to harden the grid against future wildfires and other natural disasters. Steps in the plan include replacing or strengthening more than 2,000 transmission poles on critical circuits, installing cameras and sensors to increase situational awareness in areas with higher wildfire risk, removing trees that are in danger of falling on power lines and undergrounding selected distribution circuits.
Performance-based regulation is a way to align utility incentives with the interests of customers and society, according to a new RMI report that seeks to get more states to adopt the practice over traditional cost-of-service regulation.
Traditional regulation has strong financial incentives for utilities to spend more money than needed on infrastructure, leading to affordability concerns as the industry invests to transition to a modern, cleaner grid, said the report, titled “How to Restructure Utility Incentives: The Four Pillars of Comprehensive Performance-Based Regulation.”
“There’s a number of reasons the traditional model just isn’t really well aligned with the challenges today,” report co-author Kaja Rebane, an RMI senior associate, said in an interview. “Affordability is a very big one of those. Right now, we are facing the need to invest a lot of money in the grid [to] modernize it, to deploy new technologies and to just build more capacity to supply clean power to customers.”
Traditional regulation pays utilities for what they build, while performance-based regulation (PBR) focuses on what they achieve, she added. Utilities will consider a number of factors when they make investments, but regulations guaranteeing them a return on capital are a major influence.
“That’s not … well-aligned with what the challenge is today,” Rebane said. “We do need more capital spending that is important, but we need it to be cost-efficient in order to achieve what we want to achieve in an affordable manner.”
Getting the right regulatory incentives sounds easier than it is because a full suite of performance-based regulations requires multiple changes to the cost-of-service model. The report said regulators can do “incremental PBR” and adopt some specific tools onto traditional regulation, or “comprehensive PBR,” adopting the full suite of reforms to get utilities focused on outcomes in ways cost-of-service regulation cannot.
The report lays out four pillars of performance-based regulation: incentivize cost efficiency, remove the throughput incentive, equalize capital and operational spending incentives, and incentivize targeted outcomes.
Cost efficiency can be supported by an array of changes, such as multiyear rate plans, shared savings mechanisms, fuel-cost sharing mechanisms and metrics focused on spending trends.
Revenue decoupling is the main way to remove the throughput incentive, while equalizing returns for capital and operational returns is self-explanatory. Incentivizing targeted outcomes can be accomplished through metrics, scorecards and performance incentive mechanisms (PIMs).
“Although PBR can be powerful, it is not a silver bullet for every regulatory problem,” the report said. “Even a well-designed comprehensive PBR framework will achieve the best results when it is part of a larger basket of synergistic reforms, such as widening opportunities for stakeholder input, adopting innovation policies, updating planning and procurement processes, and expanding regulatory commission authority and responsibilities.”
PBR in Hawaii
The report highlights Hawaii as a jurisdiction that has adopted comprehensive PBR across the four pillars.
“We highlighted Hawaii, in part, because it really has adopted a framework we would consider comprehensive, meaning that all four pillars that we discussed in the report are supported,” Rebane said. “There’s also been a number of forward-looking reforms in Hawaii that are worth highlighting.”
Hawaii has a five-year multiyear rate plan (MRP) with returns pegged to third-party indexes instead of utility forecasts, she added.
To mitigate excessive earnings or losses, the five-year rate plan comes with an earnings-sharing mechanism with a wide symmetrical deadband to ensure cost efficiency, the report said.
“Because of the deadband, which is centered around an allowed ROE of 9.5%, the MRP’s full cost-containment incentive is preserved (i.e., Hawaiian Electric keeps all additional earnings and bears all deficits) when the realized ROE falls between 6.5 and 12.5%,” the report said. “Outside of the deadband, sharing ramps up in a tiered fashion.”
A shared savings mechanism encourages cost efficiency for operational costs not covered by the annual revenue adjustment in the rate plan, which covers fuel for generators, purchased energy and capacity costs, new projects not funded with the rate plan, and other items. A fuel-cost sharing mechanism trues up just 98% of the difference between expected and actual costs — subject to a $2.5 million annual cap, which gives Hawaiian Electric the incentive to operate its generation more efficiently.
Hawaii regulators have also adopted metrics and scorecards that provide visibility into the utility’s cost trends, which include rate base per customer, operations and maintenance cost per customer, and annual revenue growth.
The term performance-based regulation has been around a while, and RMI hopes its report will help regulators better understand what it means and how it can improve outcomes in their jurisdictions, Rebane said.
“We’re trying to give regulators the tools they need to really reform incentives in their jurisdictions to achieve their policy goals,” Rebane said. “We also, of course, in the report provide kind of a relatively basic overview of a number of the key PBR tools that can support each pillar and so, hopefully, that will provide something of a go-to reference for regulators who are interested in these things.”
Generation owners point to the nearly 10-fold increase in capacity prices seen in the 2025/26 Base Residual Auction (BRA) results announced July 30 as the price signal they need to invest in new development. Meanwhile, consumer advocates say they worry a compressed auction schedule and backlogged interconnection queue will limit the ability for market participants to react.
The clearing price for most of the RTO jumped to $269.92/MW-day and two regions surged to their price caps, reaching $466.35/MW-day in the Baltimore Gas and Electric (BGE) zone and $444.26/MW-day in the Dominion zone. The “rest-of-RTO” price in the previous auction was $28.92/MW-day. (See related story, PJM Capacity Prices Spike 10-fold in 2025/26 Auction.)
PJM said the increase was driven by tightening supply as generation resources retire, increased demand as data center load is expected to come online and a shift in how PJM forecasts reliability risks and determines the capacity contribution for resources.
Nearly half of the capacity that cleared the auction was supplied by gas generation, at 48%, followed by 21% nuclear and 18% coal. Demand response made up 5% of cleared capacity. Hydro fell to 4% and wind and solar were at 1%.
“The significantly higher prices in this auction confirm our concerns that the supply/demand balance is tightening across the RTO. The market is sending a price signal that should incent investment in resources,” PJM CEO Manu Asthana said in a July 30 announcement of the BRA results.
Consumer Advocates, Enviros: Sluggish Planning and Market Design
Illinois Citizens Utility Board Executive Director Sarah Moskowitz said PJM has been slow to adapt and failed to design a capacity market that sparks new generation investments without creating a windfall for developers.
“The power grid operator’s compressed auction schedules mean generators can’t build and come online quickly enough to respond to prices and bring down costs. Just as concerning, PJM has dragged its feet on interconnection and long-term transmission policy reforms that could speed up its approval process and bring needed clean, affordable energy online more quickly. Similarly, we have concerns about the accuracy of PJM’s load forecasting, as detailed in a recent letter from consumer advocates to PJM,” she said.
Susan Bruce, representing the PJM Industrial Customers Coalition (ICC), said the auction results differ significantly from simulated results PJM presented in the stakeholder process and it remains unclear what led to that gap.
“Regardless, the auction results will have a serious impact on customers. Given the timing of the auction relative to the 2025/2026 delivery year, customers have little to no opportunity to take action to minimize the cost consequences. And with delays in the interconnection queue, there is real concern about what may happen in the next auction,” she said. “Focused and dedicated efforts must be undertaken — post haste — to ensure that PJM market design can both facilitate new entry and retention of resources, without market power being exercised, better accommodate single point load integration, and properly reflect the value of non-weather sensitive customers’ demand response capability.”
Tom Rutigliano, of the Natural Resources Defense Council, said the price jump is the result of a reliance on fossil fuel generation at the expense of designing a market and grid set up to facilitate the development of clean energy. Gas-fired resources in particular, he said, have failed to live up to the promise of delivering reliability at low cost.
“Make no mistake: This was foreseeable and preventable. This is what happens when regulators sideline a wealth of historically affordable clean energy resources waiting at their doorstep and the transmission needed to bring them online. For years, the largest grid operator in the eastern U.S. has all but refused to diversify its resource mix and bring new energy online, and instead opted to depend excessively on an aging fossil fuel fleet while ignoring its reliability failures. This sticker shock is a direct result of recent regulatory changes made to address those reliability failures.”
He argued the cure to high capacity costs lies in the renewable energy projects pending in PJM’s interconnection queue.
“Diverse power grids are critical for reliability, and now we see just how critical they are for affordability. With wind and solar only making up an abysmal 2% of resources in this auction, but the overwhelming majority of PJM’s project queue, it is clearer than ever that PJM needs to rapidly scale up new energy resources to protect customers and resilience,” he said. “The cost of PJM’s interconnection delays has now reached billions of dollars. Leaders in PJM states must demand accountability and solutions from their grid operator before they have to pay billions more in the next auction just five months from now.”
PJM spokesperson Dan Lockwood said the RTO is in the process of implementing a FERC-approved reworking in how it conducts generation interconnection studies, which uses a cluster-based approach to determining any necessary network upgrades and allocating costs. He said that approach is expected to process 72 GW of resources in 2024 and 2025.
“Today, about 38,000 MW of resources that have already cleared PJM’s interconnection process have not been built due to external challenges that have nothing to do with PJM, including financing, supply chain and siting/permitting issues. PJM remains concerned with this slow pace of new generation construction and is considering ways to accelerate those who can successfully overcome those challenges and build,” Lockwood said.
Transmission Owners See Regulated Generation as Solution
During the utility’s July 31 earnings call, FirstEnergy CEO Brian Tierney said the high capacity prices and sluggish resource development suggest state administered capacity procurements may have a part to play in augmenting PJM’s marketplace, pointing to those run by the New York State Energy Research and Development Authority (NYSERDA) and New York Power Authority (NYPA).
The utility has limited ability to own capacity assets in many states. However, conversations about permitting it to develop dispatchable generation with a regulated return could allow it to respond to price signals when other market participants are not. In states where FirstEnergy does own generation, like West Virginia, he said that could take the shape of new combined cycle gas resources, while in Pennsylvania, that would take legislative changes.
“There are people that get upset and say, ‘You’re going back to regulation.’ I don’t think you have to go back to regulation. I think you can still have energy markets. I think you can still have retail choice where you have it today. But I also think you could have constructs like NYSERDA or NYPA where they could buy on behalf of the state’s residents. And that doesn’t have to be an end to competition,” Tierney said. “And they can even have auctions where all people could participate in that: utilities, independent power producers and others. So, for the people that say it has to be one or the other, I just don’t think that’s a valid premise.”
Part of the difficulty Tierney outlined is the disparity between the amount of time it takes to plan and develop new generation resources, compared to how quickly new loads can come onto the grid. He said new resources built in response to the higher prices could take as long as six years to come online, falling toward the end of the period PJM said it’s concerned about resource adequacy in a February 2023 white paper. (See “PJM White Paper Expounds Reliability Concerns,” PJM Board Initiates Fast-track Process to Address Reliability.)
While he said new resources with a regulated return could be part of the solution, Tierney said developing new competitive generation is off the table.
“The thing we wouldn’t be willing to do would be start competitive generation of our own. That’s something that we’ve recently come out of. We paid a heavy price for that. We’ve rebuilt our balance sheet in the wake of that, and that’s not a place that we’re going to be going back to. But other things, other opportunities that could benefit our customers have the capacity that they need be responsive from a price standpoint are all things that are on the table and are all things we’re talking to our states about,” he said.
PJM capacity prices increased nearly tenfold in the 2025/26 Base Residual Auction, with two regions reaching their zonal caps. | PJM
In a statement, Exelon said the results show a need for new generation and transmission assets, particularly within the constrained BGE zone. In its announcement of the auction results, PJM said the higher zonal prices for BGE and Dominion were the result of insufficient generation within the zones and limited transmission to import from other regions.
“The recent PJM auction results underscore a critical need for strategic investments within the Exelon footprint, particularly in our BGE service territory in Maryland. The elevated price levels in this area, as well as others, reflect both a scarcity of resources and transmission constraints. Even with Exelon’s ongoing investments, including $34.5 billion over the next few years to upgrade the energy grid, additional transmission projects are still needed to ensure the strength and reliability of the energy grid now and in the foreseeable future,” the utility said.
During Exelon’s Aug. 1 earnings call, CEO Calvin Butler said all options are being pursued in response to a question asking whether the utility is looking at authorization for including peaker generation in rates.
“We’re working with our commissions on all types of scenarios. We shouldn’t take anything off the table because we need to address this issue and ensure affordability and equity [are] at the forefront of all discussions,” he said.
Generators Say Auction Delivers Needed Investment Signal
Enel North America Head of Energy and Commodity Management Roberto Rosner said the auction tells generation developers that now is the time to build new capacity resources.
“The signal from the auction is unmistakable: PJM needs more clean generation and more flexible demand-side resources. Power producers like Enel are eager for PJM to implement its interconnection reform so we can add more clean, affordable megawatts to the grid. As load forecasts rise from electrification and data center buildout, the value of demand response for maintaining reliability has never been clearer. It’s also clear that the substantial derate of capacity through ELCC ratings had a meaningful impact on the outcome.”
Voltus President Matthew Plante said the results were predictable given the number of generation retirements and PJM’s load forecasts. However, shifts in resource accreditation also had a large impact on the amount of supply able to offer into the auction. PJM’s shift to marginal effective load carrying capability (ELCC) and reworked risk modeling led to the focus on when resources can perform shifting from summer to winter.
“As the grid changes, we’re no longer in a situation where peaks are always during the summer months. In fact, the last time PJM dispatched the emergency load reduction program was December 2022 … so now it’s equally likely that PJM will need these resources in the winter than in the summer,” he said.
For demand response, that led to a 25% derate in the capacity resources could offer, reducing DR supply by about 3,000 MW. Nonetheless, Plante said the high price point is likely to turn around a yearslong decline in DR participation in PJM’s capacity market. Asset-backed DR resources — such as smart thermostats, batteries or anything requiring a capital investment — are especially likely to be buoyed by the high prices.
“It’s hard to find a customer that doesn’t want to take advantage of the value proposition that now exists,” he said.
Technological barriers have limited DR participation in the past, but most of those have been alleviated in recent years, Plante said. PJM and DR providers are working on addressing remaining regulatory barriers. He called the ELCC derate a “sledgehammer solution” and said the whiplash of frequent rule changes could affect market participation.
“I think regulators need to understand that there’s sometimes we change the rules too frequently and are reactive to things, and yes, a whiplash on rules in particular leads to volatility in the number of megawatts enrolled,” he said.
Staff Implement ECRS Changes, Withdraw Related NPRR
ERCOT staff have withdrawn a protocol change and updated control room procedures following the regulatory commission’s rejection of modifications to the grid operator’s new ERCOT contingency reserve service (ECRS) product.
The Public Utility Commission on June 25 rejected the nodal protocol revision request (NPRR1224) by removing the proposed $750/MWh price floor and directing ERCOT to separately implement the revision’s trigger mechanism for the service. (See Texas Commission Rejects ECRS Rule Change.)
“I think my lawyers would say that they did not direct us to do anything, but that they expressed some support for the concept of releasing ECRS when we hit the triggers that were described, so we’re going to roll with that,” ERCOT’s Jeff Billo, director of operations planning, told the Technical Advisory Committee during its July 31 meeting.
Staff and stakeholders had been working since late last year to reach a compromise on NPRR1224. Stakeholders added the price floor for ECRS’s deployment. The trigger mechanism takes effect when there is a 40-MW power balance violation for at least 10 minutes.
ERCOT introduced ECRS last year. It procures capacity resources that can be brought online within 10 minutes and sustained at a specified level for two consecutive hours. The Independent Market Monitor has opposed the new ancillary service, saying it produced “massive” inefficient market costs totaling more than $12 billion in 2023. (See ERCOT Board of Directors Briefs: Dec. 19, 2023.)
Billo said ERCOT has updated its real-time desk procedures to incorporate the trigger mechanism, which became effective Aug. 1.
The grid operator also withdrew NPRR1232, which staff had begun developing during the NPRR1224 negotiations. Billo said after the PUC’s discussion of NPRR1224’s price floor and stakeholders’ concerns over NPRR1232’s implementation and timeline, staff decided to withdraw the latter and its similar price floor concept.
Staff discussed NPRR1232’s withdrawal with the IMM, Billo said. He said he understood the monitor was “agreeable” with the withdrawal.
$29M in Firm Fuel Service
ERCOT staff told TAC it procured 3,319.9 MW of firm fuel supply service (FFSS) capacity with a projected standby cost of $29.88 million between Nov. 15, 2023, and March 15, 2024.
The grid operator contracted with 32 generation resources at $9,000/MW. Three of those either tripped offline during a watch or had mechanical failures unrelated to fuel or cold weather, leading ERCOT to claw back $976,818 from the resources. The clawback was offset partly by $781,342 in fuel replacement costs, resulting in a total FFSS payment of $29.42 million.
The FFSS ancillary service product is a result of legislative requirements and a PUC order to provide additional grid reliability and resiliency during extreme cold weather and compensate generation resources that meet a higher resiliency standard. Under ERCOT protocols, staff will provide a report to TAC when the product is deployed.
The ISO issued a request for proposal for FFSS during the next obligation period (Nov. 15, 2024-March 15, 2025) on July 31.
In other staff reports:
Matt Mereness told TAC that ERCOT’s highly anticipated real-time co-optimization (RTC) and battery project expects to announce a go-live date by the end of September. The project’s tentative go-live date is 2026. In September, staff will simulate RTC, covering data from June 2023 onward, using their simulator for feedback on price formation.
Bill Blevins, who chairs the Large Flexible Load Task Force, said more than 5 GW of load has been authorized and is waiting to be energized. The task force has discussed going into hibernation; members raised concerns over dissolving the group because they value the interconnection queue updates.
$272.6M Project Endorsed
TAC endorsed a $272.6 million regional project in Central Texas by adding it to the combination ballot. The Tier 1 project, requiring board approval, would address thermal violations in the Temple and Killeen area between Austin and Waco.
ERCOT staff said the Oncor Temple Area Regional Planning Group Project improves long-term load-serving capability, is the least-cost solution and requires the least amount of a certificate of convenience and necessity for the options that meet all ISO and NERC reliability criteria.
The proposed Oncor project in Central Texas | ERCOT
Oncor originally proposed a smaller project, but ERCOT staff’s study found additional thermal and voltage violations and recommended the alternative project after analyzing 11 options. The price tag more than doubles Oncor’s $120.7 million projection.
The project involves converting 69-kV circuits to 138 kV, upgrading more than 65 miles of 138-kV lines, removing existing 138-kV circuits from 345-kV structures, and building a new substation.
Error Forces NPRR’s Withdrawal
ERCOT staff told the committee it has pulled back an NPRR previously approved by TAC over an error in the protocol language that needs to be resolved before it can go to the board.
NPRR1215 clarifies that the day-ahead market energy-only offer credit exposure calculation zeros out negative values. However, ERCOT’s Austin Rosel said an error introduced an unintended change in the E2 credit formula by adding a price variable that wasn’t part of the original system design. Comments will be filed to address the error.
“We think this is the best way to get it back to get it corrected,” Rosel said.
TAC approved the change in June. It originally was scheduled to go before the board in August but will now have to wait until October.
Changes to CDR’s Methodology
Members approved two NPRRs in separate votes. NPRR1219 passed 21-2 with four abstentions; TAC’s consumer segment provided both dissenting votes and both abstentions. It proposes changing the methodologies for the capacity, demand and reserves (CDR) report’s preparation and incorporates a report release schedule. The NPRR also includes new definitions to support the methodology changes and revisions to address outdated terms and add clarity to the methodology descriptions.
Members raised concerns about using effective load-carrying capability (ELCC) for renewable resources and a rushed process and potential implications of changing the reporting methodology. They warned of confusion over differences in the CDR’s reliability metrics and ERCOT’s new reliability standard being developed.
TAC endorsed NPRR1230 23-2, with four abstentions. The four-person cooperative segment cast a dissenting vote and three abstentions over the proposal to establish a shadow price cap for congestion affecting interconnection reliability operating limits.
Members supported the measure because of its market-based approach and operational efficiency. It proposes to manage transmission flows with market mechanisms, rather than manual control room interventions. Cooperatives raised concerns about increased cost to load.
The combo ballot included three other NPRRs, another binding document request and a change to the Verifiable Cost Manual that, if approved by ERCOT’s Board of Directors as required, would:
NPRR1217: Remove the requirement for load resources and emergency response service resources to be deployed with a verbal dispatch instruction (VDI) from ERCOT.
NPRR1231: Provide more clarifications and improvements to the firm fuel supply service.
NPRR1233: Add a flat fee for federally owned generation units and adjust the weatherization inspection fee for transmission service providers.
OBDRR051: Align the methodology for implementing operating reserve demand curve to calculate real-time reserve price adder with system changes required for the emergency pricing program.
VCMRR040: Remove the need for ERCOT to buy an annual coal price index subscription for use in calculating the quarterly coal fuel adder. The VCMRR describes a methodology for a qualified scheduling entity to submit “actual coal fuel adders” similar to the current process for natural gas resources.
New York will convene a summit to address its two-pronged climate goal — accelerating renewable energy buildout while strengthening its economy.
The Future Energy Economy Summit will look at the role next-generation technologies could play in providing solutions to challenges such as deployment of dispatchable emissions-free resources, which are expected to be critical to grid stability as the state relies more heavily on intermittent wind and solar power.
The event also will look at ways new clean energy technologies could support the establishment and expansion of new commercial and industrial enterprises in New York.
State agencies and authorities working to advance the clean energy transition will host the summit Sept. 4-5 in Syracuse. Power producers, technical experts, and labor, environmental and business groups are expected to attend.
New York has some of the most ambitious clean energy goals of any state.
An important focus of the summit will be looking beyond the wind, solar and hydropower generation that constitutes almost all the renewables now being operated or built in New York.
Organizers are looking for input on other technologies, such as next-generation geothermal, advanced nuclear, clean hydrogen and long-duration storage. This will help inform state strategies on using these new resources and using them in a way that fosters economic development.
New York’s clean energy transition has slowed amid soaring costs and lengthy permitting and interconnection processes, and the agencies leading the initiative say the state is on track to miss its first clean energy milepost in 2030, possibly by a wide margin.
The state has responded by allowing developers to rebid projects at higher prices and by attempting to streamline the yearslong review processes facing projects.
Technology development is perhaps a more complicated challenge to solve, but one the state has been tackling for years, including by supporting pilot projects and research.
The state Public Service Commission in mid-2023 began the fraught process of determining what constitutes zero-emissions energy (Case 15-E-0302) for the purposes of complying with the landmark Climate Leadership and Community Protection Act of 2019.
The Future Energy Economy Summit is expected to provide further context for this effort by the PSC.
In her Aug. 5 announcement of the summit, Gov. Kathy Hochul (D) said: “Supporting our historic investments in renewable energy, this summit will bring together the brightest minds to explore how we can accelerate our progress, what potential roles next-generation technologies can play in stimulating economic growth and jobs throughout our state, and how New York’s innovation ecosystem can support these future industries.”
An unusually broad array of stakeholders contributed comments for the news release, reflecting the wide range of industry sectors and advocacy groups affected by the issues at the heart of the summit.
Xcel Energy says it relies on industry best practices and its own experience in beefing up wildfire mitigation plans for its operating companies.
In Colorado, where its affiliate faces nearly 300 lawsuits after the 2021 Marshall fire destroyed more than 1,000 homes, killed two people and caused more than $2 billion in property damage, Xcel recently filed a $1.9 billion wildfire mitigation plan that updates the previous one. It will serve as a template for wildfire mitigation plans in Texas and New Mexico and the company’s other states.
“I’m really proud of what we’re going to accomplish on the operational side to provide the real-time risk reduction that we need today to give us the time to make the necessary enhancements and system resiliency and hardening for our system over time,” Xcel CEO Bob Frenzel told financial analysts during the company’s second-quarter earnings call Aug. 1.
The Colorado plan integrates industry experience, incorporates evolving risk assessment methodologies, adds new technology and expands the scope, pace and scale of programs reducing wildfire risk, Frenzel said. It also benefited from the “hard work of the people that have come in front of us in California,” he said.
“We expect to dramatically reduce our wildfire risk based on their experiences and doing some of the lessons learned from all of those organizations. But that shouldn’t be taken as anything other than a huge focus that we also have in Texas and in [New] Mexico around our plans there,” Frenzel said.
Xcel has been linked to February’s Smokehouse Creek fire in the Texas Panhandle, the largest in state history. It has acknowledged its infrastructure likely started the fire. The company plans to file a resiliency plan in Texas for its Southwestern Public Service subsidiary later this year.
The Minneapolis-based company reported second-quarter earnings of $302 million ($0.54/share), as compared to the same period a year ago of $288 million ($0.52/share). Xcel’s ongoing earnings reflected the recovery of increased infrastructure investments and warmer than normal weather, partially offset by increased depreciation, interest charges and operations and maintenance expenses.
The company reaffirmed its year-end guidance of $3.50-3.60/share. It has met year-end expectations 19 straight years.
Xcel’s share price closed at $59.75, up 2.5% after the earnings release.
CAISO’s own systems may have contributed to a set of “operational surprises” that forced it to declare a series of energy emergency alerts in July 2023, a member of the ISO’s Market Surveillance Committee (MSC) said July 30.
“It is our understanding that CAISO/Western EIM operators were surprised by near-real-time changes in the CAISO/Western EIM supply demand balance on July 20 and July 25, 2023,” MSC member Scott Harvey, a consultant at FTI Consulting, said during a presentation at the MSC’s monthly meeting. “There are also indications that CAISO systems and operator actions may have contributed to operational surprises for Western EIM balancing area operators.”
High levels of self-scheduled exports out of CAISO’s balancing area to support stressed conditions in other parts of the West prompted the ISO to issue an EEA 1 on July 20 and EEA watches on July 25 and 26. (See CAISO DMM: High Exports to Southwest Led to July EEAs.)
On July 20, CAISO was close to being unable to deliver exports that had received hour-ahead awards, though no load was ultimately curtailed. But on July 25, the ISO was unable to award several thousand megawatts of self-scheduled exports.
As a result, CAISO imposed import limits from the WEIM into the CAISO balancing authority area between July 25 and Nov. 16, leading to increased transmission congestion in the 15-minute market and lower prices in the five-minute market, the ISO’s Department of Market Monitoring said in March. (See DMM: CAISO Transfer Limitations During Q3 Heatwaves Led to Price Disparities.)
Although the DMM previously said it was unclear why CAISO chose to implement transfer limits through November, Guillermo Bautista Alderete, CAISO’s director of market performance and advanced analytics, provided additional color by identifying two key market issues. The first, he said, was an inaccurate display of dispatchable capability in the market, where information presented to operators showed an imprecise calculation of storage resources, impacting operators’ ability to take proactive action.
“One of the purposes of that display and that information is to project how the ramp capabilities position for the near future,” Alderete said. “If they see that the ramp capability is getting thinner and thinner, they may start taking action rather than applying load conformance.”
The second was related to scheduling and tagging processes. When clearing transactions in the WEIM between Oregon and California, a change in practice led to double counting, which exacerbated congestion and kept flexible ramping product (FRP) “stranded in the north.”
Additionally, export reductions projected in the hour-ahead scheduling process (HASP) led to uncertainties in the real-time market due to exports not materializing.
“We had about 2,400 megawatts of additional demand that HASP was not projected as having to meet, and now the [real-time dispatch] has to meet that extra obligation in real-time,” Alderete said.
The issues weren’t fully addressed until Nov. 16, when the ISO stopped imposing transfer limits.
MSC Questions Flexiramp, HASP Structure
The “operational surprises” associated with July’s events also included problems identified with HASP and CAISO’s flexible ramping product (flexiramp).
While the role of HASP has “evolved dramatically” since it was implemented in 2014, the structure has not, Harvey said.
The HASP originated as a tool to schedule interchange transactions between CAISO and adjacent balancing areas in conjunction with the scheduling of CAISO balancing area resources. While HASP still serves that role, it “has developed into an hourly spot market for the purchase of capacity to meet the [WEIM’s] resource sufficiency evaluation,” Harvey said.
In 2014, almost all imports and exports scheduled in HASP were with balancing areas that didn’t belong to the WEIM. As of July 2023, nearly all imports and exports scheduled in HASP sourced or sank within the EIM.
As a result, stakeholders questioned the implications of the resource sufficiency evaluation of HASP transactions included in WEIM base schedules but not clear in HASP.
“A core issue is that when CAISO clears HASP to schedule hourly interchange between … CAISO and other Western EIM balancing areas, day-ahead market exports that do not clear in HASP improve the CAISO resource balance relative to the day-ahead market, appearing to increase supply in both … CAISO and the Western EIM,” Harvey’s presentation said.
“However, market exports that do not clear in HASP may be included in the base schedules of EIM entities,” it said. “The current HASP structure models the improvement in CAISO supply when day-ahead exports do not clear but does not model the potential reduction in Western EIM supply. Hence, HASP can appear to show a supply demand balance in the Western EIM when there actually is a large supply gap.”
If WEIM entities find out only after HASP posts that exports included in their base schedules will not flow in real time, they will have less time to take remedial action, as was the case in July.
“It seems that this HASP structure is creating an information problem, that it isn’t set up to tell us the truth for the Western EIM,” Harvey said. “It’s going to tell the truth for what the CAISO needs to do to avoid load shedding in terms of having supply that it can point to, but it isn’t looking necessarily at … the big picture.”
Harvey also questioned the effectiveness of flexiramp and pointed to its potential to create more “operational surprises.” In the case of July’s events, flexiramp product couldn’t reach CAISO’s balancing area due to congestion.
“If we’re going to reduce the load conformance, we have to make sure that the flexiramp is deliverable, and it looks to me like part of the problem on the 20th was that it wasn’t,” Harvey said.
Additionally, flexiramp is designed only to cover net load uncertainty and does not procure capacity in real time to cover all types of supply changes, such as those that occurred in July.
To avoid another emergency event, Alderete highlighted a few ways CAISO could improve.
“We have realized there needs to be better awareness for operators to get a sense of the wider picture, how many transfers they have and potentially give them more confidence of how much of those could be realized,” Alderete said.
Staff also took steps to increase transparency, including using market messages to communicate information on transfer limits.
“We realized that we could have communicated better, and I think we can do better for whenever the next time is going to be,” Alderete said.
