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November 16, 2024

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No Clear Blueprint for Western ‘RO’ Stakeholder Process

One thing has become abundantly clear after three intensive workshops this summer: There’s no blueprint for developing the stakeholder process for the “regional organization” (RO) envisioned by the West-Wide Governance Pathways Initiative. 

“Stakeholder engagement process” is one of six “work streams” the Pathways Initiative launched this summer to lay the foundation for the RO, which would assume the governance of CAISO’s Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM). (See Busy Summer Ahead for Pathways Initiative.) In some ways, its outcome could be the most vital for the RO’s long-term viability.   

That’s because supporters of SPP’s Markets+ day-ahead offering have touted the market’s stakeholder-led approach to governance nearly as much as the independence of that governance from state (that is, California) influence, challenging acceptance of CAISO’s more staff-driven model. 

Scott Miller, executive director of the Western Power Trading Forum, recognized the change in expectations last July, telling RTO Insider that Markets+ had been “charmed” by SPP’s approach to stakeholder engagement. (See In Contest for the West, Markets+ Gathers Momentum — and Skeptics.) 

“Now they’ve been exposed to a stakeholder process that the stakeholders run, and there still hasn’t been a stakeholder process [in CAISO] that is developed much differently, even in the context of the EIM,” Miller said at the time. 

‘Little Bit Outside the Mainstream’

A year later, Pathways backers seek to address those changed expectations, beginning with a series of four workshops to determine how stakeholders want to interact with the future RO. The group’s Launch Committee considered the subject weighty enough to engage an independent facilitator, Gridworks, to manage the workshop discussions. 

Workshop participants are grappling with a broad question of how to create a “hybrid” stakeholder process model that combines the best parts of CAISO’s staff-driven process with the stakeholder-driven — and committee-based — processes of the RTOs in the Eastern Interconnection, which themselves vary in their approaches. 

Several participants have pointed to benefits of CAISO’s approach: its inclusiveness, accessibility and relative informality, despite its top-down nature. They’ve noted that while CAISO’s process does not rely on stakeholder committees, the ISO recently rolled out use of stakeholder “working groups” to hash out market initiatives.  

“The CAISO process is able to organically capture large ideas [and groups of] stakeholders,” Alan Meck, principal market design analyst at Pacific Gas and Electric, said during the Pathways Initiative’s July 24 workshop.  

Meck said he sees benefit in the ISO’s less structured — that is, non-committee — approach to addressing issues because it doesn’t entail a process in which “x percent” of votes from certain stakeholder groups is needed to advance markets changes. 

Oregon Public Utility Commissioner Letha Tawney said that “as a stakeholder who is not resourced to engage in these processes very deeply,” she appreciated the open nature of the CAISO process. 

“I like how it doesn’t ask, ‘What’s your standing? Why do you have a voice here? Do you get to have a say in this? It’s an all-comers [process], and as a decision-maker myself, who tries to run procedurally equitable processes, I really like that,” said Tawney, one of the signatories of the July 2023 letter launching the Pathways Initiative. 

Tony Braun, an attorney who represents publicly owned utilities in California, offered an example of how that openness can benefit stakeholders who sit “a little bit outside the mainstream” on a market issue. 

“When the flexible capacity product was first introduced, the proposal, which was very mature, was to just peanut butter the costs of it on a load-ratio share basis,” Braun said. “We had to fight tooth-and-nail to show … CAISO that our loads and resources did not look like everybody else’s, or at least certain loads and resources.” 

Braun said the public utilities ultimately convinced the ISO to adopt a more cost-causation approach. 

“And I can’t help but think that would have not happened in a voting structure — that we would have just been an extraordinarily small minority and we would just get rolled over,” he said. 

Ryan Millard, West region senior director of regulatory and political affairs at NextEra Energy Resources, said CAISO included elements of “the good, the bad and the ugly.” Among the bad, Millard noted, is that CAISO’s lack of stakeholder process formality can translate into unclear timelines. 

Citing the example of the ISO’s interconnection process enhancements initiative, he said, “I don’t think there were enough attempts in the beginning to kind of structure how the stakeholder process was going to move forward, and there [weren’t] timelines built into the front. In fact, that was my commentary through that process multiple times: ‘Pick a date, you have a lot of conflicting or complicated compliance filings at FERC that are going to make this more complicated.’ And sure enough, it did.” 

Other workshop participants pointed to what they see as advantages in SPP’s more structured stakeholder process, which they experienced in developing the Markets+ tariff. 

Doug Marker, an intergovernmental affairs specialist at the Bonneville Power Administration, said BPA recognizes and supports the fact that Pathways is seeking “to do something different than the older CAISO staff model.”  

“We would like to see a more stakeholder-led issue development process,” he said during the July 24 workshop. In April, BPA staff issued a recommendation that the agency choose Markets+ over EDAM, citing governance and stakeholder processes as two key reasons for its leaning. (See BPA Staff Recommends Markets+ over EDAM.)  

For BPA, it’s important the stakeholder process “get issues defined and developed so that there’s a clear majority and minority perspective, if necessary,” Marker said. 

“The Markets+ process has helped to facilitate developing consensus on some difficult issues. We were really skeptical going into the process about the voting aspect of it, but it served in some instances to really facilitate consensus,” he said. 

Lauren Tenney Denison, director of market policy and grid strategy at the Portland-based Public Power Council, spoke approvingly of the Markets+ system of standing work groups and ad hoc task forces, both of which include representatives from various stakeholder sectors and rely on forms of voting to advance issues through the stakeholder process. 

“While all decisions go to an independent board eventually, they build up through that working group level,” Tenney Denison said. “Then there’s the Markets+ Executive Committee that has representatives from all the participants and stakeholders. That group is also able to direct work back to those workgroups and task forces. So there’s just more structure involved that has stakeholders having an active voice through this voting mechanism on what to prioritize and what needs to be looked at.” 

‘Pleasantly Surprised’

An Aug. 2 Pathways workshop delved into the question of what a “sector-based committee and voting structure” could add to the RO.  

Braun said he thinks sector-based representation is essential and provides an “indicia of inclusiveness” to the stakeholder process, helping to “get the right people at the table” and build consensus. 

“I think I probably get less worked up about the definitions of the sectors than many do,” he said. “I get nervous when sectors get too granular. I think one of the lessons that we’ve learned is that making the sectors broad forces people to work together to come up with plans for populating the sectors and the relative positions in the stakeholder processes,” such as in the WEIM’s stakeholder-led Regional Issues Forum (RIF).  

“I think one of the benefits of having some similarly situated folks within the same group is that it’s helpful to sort of zoom in on areas where there is consensus out of the gate and areas where maybe we’re using different terminology to describe the same thing — or with areas also where there isn’t consensus,” said Ian White, director of regulatory affairs at Shell Trading. 

White said the RIF group representing independent power producers, marketers and independent load-serving entities sector — one in which Shell participates — has become “quite an unruly” sector with its 70 members, many of which operate under different business models and therefore don’t always share the same interests.  

“Regardless of sector size, I think you’re always going to have splinter factions form over issues that are of unique concern to an organization’s individual goals,” NextEra’s Millard said. “And that’s particularly true in diverse sectors, of which NextEra is one. The less formal structure of CAISO’s stakeholder framework sort of allows for that, and you have the ability to collaborate and/or advocate as a subgroup of your sector or even cross-collaborate with other sectors.” 

Allie Mace, manager of market policy and analysis at BPA, said sector-based representation encourages collaboration among stakeholders. 

“In the Markets+ experience, we were pretty pleasantly surprised by the enthusiasm and engagement to dig in on issues and shape compromises and consensus approaches across the sectors,” Mace said. “The sector definitions didn’t seem like they were a barrier to that collaboration. I think defined sectors can help to provide some good helpful parameters for organizing issues and input.” 

Voting with Purpose

On the topic of whether the RO’s stakeholder process should include participant voting, both Braun and Scott Ranzal, director of portfolio management at Pacific Gas and Electric, expressed support for some kind of voting, but raised the question of the purpose of votes.  

As noted throughout the workshop, voting can be characterized as “indicative” (showing a preference during the process), “advisory” (expressing an opinion to a board or other body) or “binding” (advancing a proposal).   

“I think voting is a reflection of desire that actually already happens inside the CAISO,” Ranzal said. “It’s not labeled as a vote, but it is very clear in the CAISO processes where people want to be. So I think if voting is a reflection of desire, and that can help with accountability and visualizing what is happening, adding that to the CAISO process seems like it would have a positive bent to it.” 

“I think voting has the potential to complicate engagement and sometimes discourage engagement altogether, if you’re a minority voice on a specific issue,” Millard said, advocating for “narrowing the application of when and how voting” is used in the stakeholder process. 

Mace said BPA found voting in Markets+ to be a “positive experience” after the agency overcame a “learning curve.” 

“We were pretty impressed with how voting helped to move things along,” Mace said. “Calling for that advisory vote could be a very powerful tool at times in meetings for getting out of a spinning topic and identifying where people stood, so then you can move forward on the compromise and collaboration.” 

Natalie McIntire, a senior advocate at the Natural Resources Defense Council, said she wouldn’t take a position on whether the RO should include voting and whether such voting should be advisory or binding. 

“But if there is voting, I think it’s really important that you spend a fair amount of time thinking about the balance of those votes,” McIntire said. “I think different regions across the country have different ways that they weight voting based on sectors, and you want to really make sure that that voting is reasonably balanced so that no one sector has control over the outcome of those votes.” 

Kerinia Cusick, president of the Center for Renewables Integration, said any “effective” stakeholder process she’s been involved with has included some form of voting. 

“I’m trying to sort of think of examples where there has been no voting, and those have been somewhat frustrating processes,” Cusick said. “They’ve been sort of long, very engaged, and then nothing comes out of it. So there’s a ton of value of voting to drive accountability.” 

Michele Beck, director of Utah Office of Consumer Services, said she agreed with workshop participants who want to find a “middle ground” between the more “prescriptive” voting structure of the Eastern RTOs and the CAISO process, “something that might be more limited, more indicative.” 

Ranzal said Pathways likely will draw on parts of multiple RTOs to serve the RO’s stakeholder process.   

“We’re going to create our own thing, as we often do in the West, and I think that suits and fits the needs of the West and that’s a good thing. That’s part of the reason why we’re all out here,” he said. 

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4th Circuit Remands Duke Energy Market Power Lawsuit Filed by NTE

The 4th U.S. Circuit Court of Appeals on Aug. 5 sent back to lower courts a lawsuit alleging Duke Energy abused its market power to prevent a power plant developer from serving a municipal utility in North Carolina.

NTE Energy had pursued a deal where it would build a natural gas plant in part to serve Fayetteville, N.C., as the municipality’s contract with Duke was about to expire. But the utility came back with a cheaper contract and kept the business. A lower court found Duke was just competing for its business, but the appeals panel of three judges has open questions on whether market power was abused.

“While we recognize that much of Duke’s conduct can be understood to be legitimate competitive conduct, as well explained by very able counsel, we also have found much from which a jury could conclude that Duke’s actions were illegitimate anticompetitive conduct that violated Section 2 of the Sherman Act, also as well explained by very able counsel,” the 4th Circuit said. “Because genuine disputes of material fact exist, we vacate the district court’s summary judgment and remand for further proceedings.”

On remand, a different district judge will have to be assigned to the case because in the first round U.S. District Judge Kenneth Bell had recused himself due to a former law partner working for the utility. He was reassigned the case years later and denied a motion from NTE to recuse himself again.

“We conclude, as most courts have, that once a judge recuses himself from a case, he should remain recused from that case, even though his recusal may not have originally been required,” the order said.

As an independent power producer, NTE builds power plants and has to rely on utility-owned transmission to transport its power to customers that typically are municipalities. It started construction in 2016 on a new combined cycle natural gas plant in Kings Mountain, N.C., which required access to Duke’s system because it controlled more than 90% of the wholesale market in the region.

Duke and NTE signed a standard interconnection agreement for the Kings Mountain plant and at first were not worried about the constitution. But the IPP started attracting customers as its new combined cycle plant provided power at cheaper rates than Duke could offer, and nine customers signed deals for power from the plant.

NTE had cheaper power, but Duke had 20-year contracts with many customers that required several years of advance notice before they could be terminated, which limited the opportunities for customers. Fayetteville and its 500 MW of load had an expiring contract after being served by Duke for a century.

“NTE did indeed then have plans to build additional power plants in the Carolinas,” the court said. “But key to its plans for expansion was the rare opportunity — because of the terms of Fayetteville’s agreement with Duke — to compete for Fayetteville’s business.”

The Reidsville Energy Center was planned to be a 475-MW combined cycle plant, but it needed a large anchor customer to get built, and Fayetteville was the most attractive one available. Duke entered into an interconnection agreement with the plant that FERC approved, which had NTE pay it $58.9 million for the interconnection lines plus ongoing charges to use them.

After that deal, NTE poached an additional three Duke wholesale customers, and as of 2017, its costs to supply them still were 30% above the IPP’s. Duke identified holding onto Fayetteville as its “biggest upcoming battle” with an opt-out for its contract opening up in 2024, the court said.

Duke reworked its contract with Fayetteville, and executives exchanged emails saying they hoped to get a deal worked out and “ruin NTE’s plans” for the Reidsville plant, as any other remaining opportunities to get a municipal customer were more than a decade away, the court said.

“Despite its relative inefficiency, Duke made a highly attractive, multi-faceted offer to Fayetteville, which amounted in the aggregate to a discount of $325 million for Fayetteville and which was unprecedented,” the court said.

The discount came on the deal the city already had with Duke, but the terms moved those rates higher starting this year to a price more than NTE would have charged. Duke also agreed to quadruple the price it paid for excess power from a fossil plant Fayetteville owned.

Duke expected to lose $100 million on the reworked deal, but in a white paper, company officials argued they could offset the loss through higher charges to other customers.

NTE tried to exercise a suspension of its interconnection agreement, which it thought would have kept its place in Duke’s queue, but the utility said it had breached the deal and tried to terminate it outright.

On Sept. 6, 2019, Duke unilaterally terminated the deal with NTE without notifying FERC as the interconnection agreement required. Days later it approved the reworked deal with Fayetteville and signed it while the plant’s interconnection was listed as canceled.

FERC approved the reworked Fayetteville deal in early 2020, and NTE’s efforts on the Reidsville plant lost momentum. The commission also found a few months later that Duke had improperly terminated the NTE interconnection deal.

NTE argued that Duke’s actions destroyed the value of the new plant and left its customers with no choice but to pay the utility higher rates, which led to the lawsuit.

The district court entered a summary judgment dismissing NTE’s lawsuit, which NTE appealed to the 4th Circuit.

“NTE alleges that Duke engaged in several, simultaneous courses of conduct that combined to thwart NTE from bringing a more efficient power plant online and ultimately from competing with Duke in the Carolinas wholesale power market,” the court said. “It argues that the district court erroneously ‘compartmentalized’ the various aspects of Duke’s anticompetitive conduct and asked whether each one, independently, was unlawful.”

Duke argued the appeals court should reject the holistic approach NTE favors, saying the Supreme Court has set up tests to determine whether conduct abuses market power and the IPP flunked them all. All the activities Duke undertook were legal under those tests.

“In the context of the allegations in this case, we agree with NTE,” the court said. “It is foundational that alleged anticompetitive conduct must be considered as a whole.”

Anticompetitive conduct comes in different forms and can’t always be categorized easily as in the Supreme Court’s tests, which can be too rigid for a “complex or atypical exclusionary campaign.” Such cases are more challenging than when individual practices are each independently unlawful, but they are not categorical impossibilities under the law, the court said.

While the court agreed with NTE that the lower court should look at Duke’s activity (canceling the interconnection deal and offering a discount to Fayetteville) altogether, material disputed facts in the case prevented summary judgment.

“Upon resolution of those disputed facts, a jury might well conclude that Duke’s conduct was simply good, old-fashioned competition, which, in the end, favors the consumers of electric power in the relevant market,” the court said. “On the other hand, the factfinder might just as well conclude that Duke saw a more efficient competitor in NTE and acted, through a broad range of anticompetitive conduct in various contexts, to eliminate that competition, to the detriment of consumers.”

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New England States Delay OSW Solicitation to Account for DOE Funding

Connecticut, Massachusetts and Rhode Island have delayed their much-anticipated coordinated offshore wind solicitation by 30 days to account for the effects of the U.S. Department of Energy’s recent award of Grid Resilience and Innovation Partnerships funding to help interconnect offshore wind projects. 

The states were set to announce the results of the procurement Aug. 7. The day before, DOE announced its award of $389.3 million for substations in Southern New England to help interconnect up to 4,800 MW of offshore wind, as well as to spur the development of multiday energy storage in Maine. (See DOE Announces $2.2B in Grid Resilience, Innovation Awards.) 

The coordinated solicitation is intended to lower overall costs by using regional supply chains and the three states’ collective buying power. It drew 5,454 MW of bids from four developers, staying within the solicitation’s 6,000-MW cap. (See New England States’ OSW Procurement Receives 5,454 MW in Bids.) 

This marks the second time the solicitation has been delayed; the states previously pushed the project selection date from June to August to buy time for clarity on federal tax credits from the Inflation Reduction Act. (See New England States Delay Offshore Wind Solicitations.) 

Under the new schedule, project selection is scheduled for Sept. 6, while the long-term contracts are set to be executed in November and submitted for approval in December. 

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Constellation Raises Earnings Guidance amid Rising Demand

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.) 

On Aug. 2, FERC said it would hold a commissioner-led technical conference this year on co-location of large loads at generating facilities (AD24-11). 

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.’” 

An analyst asked if the recent PJM auction increased a sense of urgency among potential customers to lock down these co-location agreements. (See PJM Capacity Prices Spike 10-fold in 2025/26 Auction.) 

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. 

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SPP Considering 765-kV Solution for Permian Basin

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.

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DOE Announces $2.2B in Grid Resilience, Innovation Awards

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.  

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HECO Joins $4B Settlement over Maui Wildfires

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.

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RMI Report Urges States to Adopt Performance-based Regulation

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.” 

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PJM Market Participants React to Spike in Capacity Prices

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.

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ERCOT Technical Advisory Committee Briefs: July 31, 2024

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.