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December 19, 2024

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MISO Records Comparatively Smaller Peak in October Operations

MISO experienced an 84-GW peak load during an unseasonably warm early October; still, the peak was no match for October 2023’s 99-GW peak.

Despite MISO registering a smaller year-over-year monthly peak, its average October 2024 load remained unchanged from last year at 69 GW, according to the RTO’s monthly operations report. Ahead of the fall, MISO predicted a 95-GW peak during the month.

The system appeared unaffected by an 872-MW capacity deficit for the fall season in Missouri’s Zone 5 due to the permanent closure of Ameren’s Rush Island coal plant Oct. 15. MISO wasn’t forced to issue an alert or warning throughout October. (See MISO Predicts Painless Fall Despite Missouri Capacity Shortfall.)

MISO averaged a $26/MWh real-time locational marginal price during October, less than October 2023’s $31/MWh and half of October 2022’s $52/MWh average. Average coal and gas prices stayed static year-over-year, at $2/MMBtu.

MISO said it fell short of its self-imposed standard on price divergence between its day-ahead and real-time markets over the month. System-wide, the average day-ahead price was $26.71/MWh while the average real-time price was $25.80/MWh.

The RTO usually tries to keep its absolute day-ahead to real-time price difference divided by a day-ahead locational marginal price at or below 22.2%. In October, MISO said the deviation reached 27%.

MISO said congestion and real-time ancillary service product scarcity worsened the divergence. It added that “ramp-up continues to be a challenge, particularly in the evening hours as generation is coming offline.”

The grid operator said day-ahead to real-time price deviation this year also has been poor enough to review in January, April, May, June and July, in addition to October.

For October, real-time congestion cost the footprint about $118 million, lower than October 2023’s $186 million.

Daily average generation outages for the typically maintenance-heavy October climbed to 61 GW this year, compared to 53 GW in October 2023.

As it’s been doing on a nearly monthly basis, MISO set an all-time peak solar supply record Oct. 16, when solar briefly served a little more than 8 GW, or 16% of load at the time. Solar contributions were significant enough to register on MISO’s total 49-TWh energy fuel mix for the month, where they supplied 2 TWh.

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Environmental Nonprofits Argue MISO’s New Capacity Accreditation Missing Key Detail

Four environmental nonprofits insist MISO’s recently approved capacity accreditation is incomplete unless the RTO details how it will conduct its loss of load modeling the new approach relies upon. 

The Sierra Club, Natural Resources Defense Council, Sustainable FERC Project and Fresh Energy on Nov. 25 sought rehearing of MISO’s accreditation, saying FERC seemed to miss a key piece of the puzzle when it authorized MISO’s new capacity accreditation method without forcing the RTO to codify and then update its loss of load expectation modeling process in its tariff (ER24-1638). 

FERC in late October approved MISO’s capacity accreditation, which blends the historical performance of individual generators with a probabilistic performance during simulated loss-of-load events. (See FERC Approves New MISO Probabilistic Capacity Accreditation.) The RTO plans to draw on its loss of load expectation (LOLE) analysis to estimate the hours across a year that the system is likely to experience a deficit or dwindling margins and compare those to when its resource classes are expected to be available.  

The four nonprofits contend that FERC failed to appreciate how significant MISO’s LOLE modeling will be to the accreditation.  

“The key inputs and assumptions that MISO uses for the LOLE model have major effects on accreditation outcomes and rates. Neither the commission nor stakeholders can determine whether the RTO’s accreditation scheme will actually produce just and reasonable rates without reviewing those significant modeling choices,” the groups argued.  

They also said the consequences of not vetting LOLE modeling stand to be “severe,” with FERC potentially “abdicating” its responsibility to ensure reasonable rates and MISO wielding “unchecked discretion to alter … key components to change rate outcomes without commission scrutiny.” 

The groups disagreed with FERC that MISO including a description of its LOLE modeling process is merely an “implementation detail.” They said the RTO’s LOLE modeling process contains “several discretionary judgments” and could alter accreditation and significantly affect rates. 

For instance, MISO’s LOLE modeling at present includes a cold weather outage adder, they said, which attempts to capture thermal resources’ outage risks in winter and could dent those resources’ accreditation values. They also said it is working on a new LOLE model for its storage resources, and staff so far in public stakeholder meetings have presented modeling approaches that produce wildly different outcomes.  

The four further argued that the inputs and assumptions to MISO’s LOLE model “are not generally understood in any contractual arrangement such that recitation would be superfluous.” They pointed to the RTO’s existing reference to its LOLE modeling in its tariff and said that “barebones” description “implies nothing about how MISO generates probability distributions for variables such as demand, generator performance, storage availability or external import availability.” They also said MISO doesn’t specify how it assesses “potential load growth or expected changes in the installed resource mix prior to a given delivery year” to influence the modeling.  

“As a direct result of its accreditation choices, MISO has ensured that LOLE modeling choices are specifiable practices that significantly affect rates. Yet MISO’s tariff implies almost nothing about what discretionary modeling methods MISO will adopt within the very complex LOLE analytical space,” the groups summed up. “To facilitate just and reasonable rates, FERC should ensure that stakeholders have full visibility into MISO’s LOLE model as soon as possible so that they can work with MISO to refine the model toward optimized predictive power.”  

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Pennsylvania PUC Examines PJM’s Tightening Reserve Margin

Pennsylvania is a net exporter of electricity, but the narrowing reserve margin in PJM led the state’s Public Utility Commission to hold an all-day technical conference Nov. 25 to discuss resource adequacy.

While this past summer’s capacity auction showed spiking prices amid rising demand and retiring power plants, PUC Vice Chair Kimberly Barrow said she started focusing more on resource adequacy during winter weather events like the polar vortex a decade ago and Winter Storm Elliott in December 2022. (See PJM Capacity Prices Spike 10-fold in 2025/26 Auction.)

“What I’m very worried about now is those challenges occurred at a time when we were not facing the kind of load growth that we’re facing right now,” Barrow said. “The load growth we’re facing is unprecedented, and I do not know if we are bringing resources on quick enough to face that load growth.”

Pennsylvania is a restructured state, so the PUC has limited authority over power generation, but it is still responsible for ensuring reliability and affordability on the distribution system, she added.

Demand growth, driven mostly by large data centers coming online, is working alongside retiring power plants and a slow pace of adding new supplies to cut into what for years was a healthy reserve margin, PJM Executive Vice President Stu Bresler said.

“PJM really started in an enviable position, from the standpoint of the reserves that we had available in the system than we do today, but these trends that we are seeing, obviously, are causing that to change and change significantly,” Bresler said. “Overall, we believe that the structure of our wholesale electricity markets remains sound. We believe that those markets will continue to stimulate resource development and resource additions.”

But there is going to be a transitional period with narrow reserve margins, as evidenced by the last capacity auction, he added. PJM’s adoption of effective load-carrying capability (ELCC) to measure resources’ capacity also contributed to the last auction’s outcome, but Bresler said that method should encourage the kind of firmer resources the grid needs going forward.

PJM Independent Market Monitor Joe Bowring said properly designed ELCC rules would help the region maintain reliability, but it and other rules should be changed.

“I don’t think the current design will get us there, but I think that we need to move forward and do a rethink of ELCC and make it more sophisticated at the point where it really will reflect supply and demand,” Bowring said.

ELCC has an “excessive” focus on natural gas plants’ performance during several historical hours in winters when PJM was still learning about gas notification periods, Bowring said. The rule understates the value of thermal resources, especially combined cycle natural gas plants and combustion turbines.

While Pennsylvania has restructured, that does not mean the industry relies entirely on PJM’s wholesale power markets for its revenue, said Travis Kavulla, NRG Energy vice president of regulatory affairs.

NRG owns generation and a competitive retail business that serves about 10% of the demand in the Eastern restructured markets, which means it must hedge the latter with bilateral contracts with generators, he said.

“NRG, when it signs up a retail customer, engages in a policy called back-to-back hedging. On Day 1 of our service under that contract, we estimate a customer’s load, make adjustments for extreme weather and then bilaterally buy energy supply that covers that estimated load on the part of the customer,” Kavulla said. “These bilateral contracts are a major source of revenue to our counterparties, the power plants of PJM.”

Sometimes those bilateral contracts can be more important to generators — though less visible to the public — than income from PJM’s markets, he added.

“These markets were designed with the idea that the bulk of trades would be bilateral transactions and self-supply,” Bresler said. “It was not intended that either suppliers would invest, or consumers would ride the spot market based on spot market prices. The fact of the matter is, though, these markets are unforgiving.”

PJM’s goal is not for prices to be high, but to signal the market that supply is needed, which will encourage suppliers and customers to enter into new long-term contracts, he added.

Kavulla said one thing the PUC could do under its authority would be to encourage longer-term contracts in the retail market. Even residential customers can get prices locked in for five years, at lower rates than default service.

One major recent example of those bilateral deals directly leading to new supply on the grid was the contract Constellation Energy struck with Microsoft to bring Three Mile Island’s recently retired reactor back to service to supply a new data center, said Adrien Ford, Constellation’s director of wholesale market development.

“It’s our partnership with Microsoft that’s bringing the Crane Clean Energy Center back online,” she said, referring to TMI’s new name, “not the PJM one-year print.”

Another way Constellation hedges its generation is by participating in the default service auctions that restructured states run, which secure supply for most small customers that do not shop for competitive supply, she said.

Policy Changes and the Supply Chain

With a new political party taking over the White House and EPA, some of the retirements that PJM has been forecasting could be significantly delayed, said Calpine’s Joe Kerecman.

EPA’s plans to regulate carbon dioxide will certainly change with the new administration, and other rules could also be tossed out, which will mean existing coal plants stay running longer.

That could help because Kerecman and other representatives of independent power producers noted that building new natural gas plants takes longer than it used to.

“I think you can get gas turbine deliveries by 2027 certainly. … You got to write some big checks, which differentiates a company like Calpine, because we have 27,000 MW,” Kerecman said. “We have well established relationships with [original equipment manufacturers] and EPC [engineering, procurement and construction] contractors as well.”

The domestic industry has to compete with growing demand for power plant equipment from the Middle East, along with generally stressed supply chains, he added.

If a developer sent the first milestone payments to an OEM now, they would not get delivery of equipment until mid- to late 2028, and then it would need to spend an additional 12 to 18 months actually building a power plant, Talen Energy Chief Development Officer Darren Olagues said.

“It’s obviously a global queue, but it’s one of the reasons we need to get this right now and inspire the confidence for developers to start to put down the milestone payments,” Olagues said. “You’re talking tens of millions of dollars per turbine.”

It’s also hard to plan for a power plant with continuous discussions about changing PJM’s capacity market, he added.

The industry’s bankers would “love a steadier signal,” LS Power Senior Vice President Marjorie Philips said.

“But I think there’s a couple of things to think about,” Philips said. “One is, the data centers are ignoring the capacity markets. They are paying astronomically more. There’s a reason why we are all looking to supply them. They value the electricity a lot more than we’re valuing it in the capacity market.”

The other factor is that constant regulatory interventions in the market do not help build investor confidence, she added.

“The commodity fluctuations are less troubling than the regulatory interventions,” Philips said. “But I think long term, if we let the market work and understanding that it’s very unpalatable that we’re going to have to deal with high prices, and that, candidly, falls on your shoulders, how to manage the retail rates, and we are not unsympathetic to it, but that is the political reality.”

It takes “two or three” price signals for developers to invest in new supply as they have in the past, she added.

Potential State Responses

While Pennsylvania is a restructured state, Consumer Advocate Patrick Cicero said it was still the PUC’s responsibility to ensure resource adequacy.

“I would just submit that I think that no one should question that is the job of the Public Utility Commission,” Cicero said.

State law requires the PUC to ensure reliable, affordable electricity, and part of that includes the generation issue facing the PJM region, he added.

“The fact that we’re a restructured state means that generation is no longer rate regulated, but it does not mean that the Public Utility Commission does not have the authority and tools necessary to ensure continued reliability,” Cicero said. “I assure you that if something happens, you will be blamed, and so consequently, if you will be blamed, then you should have the tools necessary to fix this problem.”

PJM’s market is not a failure, but it is leading to resource adequacy problems for Pennsylvania right now, PPL Electric Utilities President Christine Martin said.

“I really do think that we need to keep an open mind [and] not let the past dictate the future; not let a law passed almost 30 years ago define our future,” Martin said.

PPL supports changing the law to allow utilities to invest in generation, but Martin said that would not have to completely upturn Pennsylvania’s history with the markets. It is mainly focused on getting new resources online in the commonwealth.

“We are not insulated from Maryland or New Jersey or Delaware or D.C.,” Martin said. “We don’t have that luxury. So, when we think about resource adequacy and economic development and keeping the lights on, the type of generation [and] the location of generation does matter.”

GT Power Group President Glen Thomas, a former Pennsylvania PUC chair, cautioned commissioners from turning away from the markets too quickly. Given that generation investments are lumpy, PJM has faced these kinds of debates in the past — including 15 years ago when Maryland and New Jersey tried to get new natural gas built with state-backed contracts, which were ultimately found unconstitutional by the U.S. Supreme Court.

One of the contracts that New Jersey signed would have paid a plant $286 to $432/MW-day, well above the $270/MW-day the last auction capacity auction cleared at, Thomas said. It would have added over $1 billion over the term of the contract, which proved unneeded as the three plants New Jersey tried to support are all still operating today without any subsidies.

“They made a very critical mistake that would have cost their consumers a lot of money, but for the fact it was litigated and determined to be unconstitutional,” Thomas said. “So, it’s great to think about these plans. It’s great to think about the future, but it’s very hard to predict the future with these markets. These markets are cyclical.”

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Report Outlines Scope, Challenges of Clean Energy Siting in New England

A new policy paper from the Acadia Center and the Clean Air Task Force (CATF) emphasizes the importance of community engagement to enabling the wide-scale deployment of clean energy infrastructure over the next two decades. 

“For New England to build out its infrastructure at the speed and scale needed to unlock a local energy transition, it will take buy-in, acceptance and trust from the communities that will host these clean energy resources,” the climate advocacy nonprofits wrote in the report, published Nov. 25. 

The paper includes a quantitative literature review of five recent studies on decarbonization in the region, which, on average, indicate New England’s peak load will grow to 55 GW by 2050, compared with the 2024 peak load of 24,310 MW. This figure is in line with ISO-NE’s projection of a 57-GW winter evening peak in 2050.  

To meet the growing demand, the review found the region will need to add “up to 5 GW of new clean energy capacity per year” for the next 20 years, assuming the region’s existing nuclear plants remain online. The studies estimated on average that 84% of generation in 2050 will come from renewables.  

“The highest order recommendation is that the region must adopt a diverse, clean energy portfolio approach to achieve decarbonization goals while keeping the lights on and heat pumps running,” the  nonprofits said, adding that this portfolio should include a mix of renewables, clean firm generation, interregional transmission, demand flexibility, energy efficiency and storage. 

The organizations emphasized how energy efficiency and demand flexibility could help significantly reduce the peak, with the studies estimating that flexibility could reduce the 2050 peak by about 7%. This peak reduction could save the region billions in transmission costs alone; ISO-NE found in its 2050 Transmission Study that a 10% reduction in peak load could reduce the overall transmission buildout cost by about a third.  

The nonprofits noted that energy efficiency and building retrofits were not modeled in detail in the studies and said more research is needed to quantify the full potential of both efficiency and demand flexibility. 

“Increased modeling focus on the cost-effective potential of building envelope improvements to reduce overall space heating demand could reveal lower levels of generation buildout than currently found by these studies,” the groups wrote.  

“Energy efficiency can and should be deployed as a competitive resource, able to be procured and acquired by the MWh or MW just as states and the region currently procure generation resources,” the groups added, noting that the prices of efficiency procurements likely would be cost-competitive with solicitations of large-scale renewables.  

Community Buy-in Needed

Efficiency, demand flexibility, advanced transmission technologies, repowering existing renewable sites and strategies like agrivoltaics can help reduce the overall infrastructure footprint, but any decarbonization scenario will still require large amounts of new infrastructure, the report said.  

To enable the construction of this infrastructure, developers must do a better job building community buy-in for their projects, incorporating feedback into project design, and providing tangible local benefits, the nonprofits wrote.  

The report features case studies of several high-profile projects from recent years, including the canceled Aroostook Renewable Gateway and Twin States Clean Energy Link projects, along with Eversource Energy’s substation in East Boston — which is expected to come in service in 2025, 11 years after it was initially proposed. 

“Levels of community support or opposition are key factors in a project’s success or failure,” the report said. “High profile project failures and stories of bad actors spread between communities and stoke opposition.” 

The organizations added that community benefit agreements alone are not enough to prevent opposition and said “the process of negotiating and implementing community benefits programs is as important as the benefits themselves.” 

“Development of a community benefit should occur through an early, inclusive, community-led process that not only informs the structure of community benefits program, but also incorporates community input into the design of the project itself,” the report said, adding that benefit plans should include accountability measures to ensure promises are met. 

Community opposition also can be amplified by fossil fuel companies and incumbent power producers, the groups said, referencing the campaign to stop the New England Clean Energy Connect Pipeline and the challenges to the Vineyard Wind project funded by fossil fuel groups. (See Avangrid Sues NextEra over ‘Scorched-earth Scheme’ to Stop NECEC.) 

“Those who have benefited from the region’s widespread reliance on fossil fuel infrastructure are reluctant to accept, and often in opposition to, shifting the resource mix [toward] clean energy generation,” the groups wrote. “Incumbent power generators have interfered in infrastructure development in numerous instances, particularly around transmission that would bring new clean energy supply into the market.” 

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BANC Signs Agreement to Join EDAM

The Balancing Authority of Northern California (BANC) on Nov. 25 became the third entity to formally join CAISO’s Extended Day-Ahead Market (EDAM), following PacifiCorp and Portland General Electric (PGE).  

“BANC is pleased to execute the EDAM implementation agreement with the ISO,” BANC General Manager Jim Shetler said in a press release, adding that CAISO’s Western Energy Imbalance Market (WEIM) “has brought BANC and its members reliability, economic and environmental benefits.” 

“EDAM participation is viewed as the next logical step to expand on those benefits. We look forward to working with the ISO to achieve a spring 2027 go-live date,” Shetler said.  

Shetler has been a key participant on the West-Wide Governance Pathways Initiative’s Launch Committee, which on Nov. 22 passed its “Step 2” proposal to establish an independent “regional organization” to assume governance of the WEIM/EDAM, a move that will require a change in California law. (See Amid Praise for Pathways Step 2 Milestone, Skeptics Remain Unmoved and Pathways Backers Express Confidence on Calif. Legislation.)   

BANC is a joint powers authority consisting of six utilities: Sacramento Municipal Utility District (SMUD), Modesto Irrigation District, Roseville Electric, Redding Electric Utility, Trinity Public Utility District and the City of Shasta Lake. It has been a WEIM member since 2019.   

In 2023, BANC was one of the first entities — along with its largest member, SMUD — to announce its intent to join the EDAM, after PacifiCorp. (See BANC Moving to Join CAISO’s EDAM.) 

The formal commitment comes a month after the Western Area Power Administration (WAPA) said its Sierra Nevada (SN) region would pursue “final negotiations” to join the EDAM, clearing the way for BANC to formally join. (See WAPA Sierra Nevada Region to Advance with EDAM.) 

“We are excited to welcome BANC as the first public power balancing authority to formally commit to join EDAM,” CAISO CEO Elliot Mainzer said. “They have been a valued partner whose voice has been instrumental to the design of EDAM, and we look forward to having them join the market to deliver more benefits to their customers.” 

Along with formal commitments from BANC, PacifiCorp and PGE, three other entities have signaled their interest in joining EDAM: Los Angeles Department of Water and Power, BHE Montana and PNM. An additional two entities, Idaho Power and NV Energy, have indicated they favor EDAM.  

Arizona G&T Cooperatives, consisting of utilities that represent 70% of WAPA Desert Southwest’s load, also recently announced it will conduct a study on the benefits of joining EDAM. (See Arizona G&T Cooperatives Announces Pursuit of EDAM Benefits Study.)

The Pathways Initiative’s “Step 1” plan, which elevates the Western Energy Markets Governing Body to become the “primary” authority over the WEIM/EDAM compared with the “joint” authority it currently shares with the ISO’s Board of Governors, will be triggered once EDAM commitments from non-ISO load reach 70% of ISO load. BANC’s participation means EDAM has achieved commitment from 53% of non-ISO load compared with ISO load.  

BANC’s EDAM implementation agreement is slated to be filed with FERC in December.  

SPP’s competing Markets+ offering on Nov. 25 won its first public commitments from four Arizona utilities, although the RTO is still awaiting FERC approval for the market’s tariff and no implementation agreements have been signed. (See 4 Arizona Utilities Commit to Joining Markets+.)  

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NERC Responds to FERC Cybersecurity NOPRs

Replying to two recent cybersecurity-related Notices of Proposed Rulemaking from FERC, NERC and the regional entities Nov. 22 expressed their support for the proposals while urging the commission to “consider the entirety of” the ERO Enterprise’s standards development process when setting their deadlines. 

The NOPRs propose to expand the ERO’s recently introduced reliability standard requiring registered entities to implement internal network security monitoring (INSM) at some grid-connected cyber systems (RM24-7) and to address perceived gaps in the standards concerning supply chain risk management (RM24-4). The commission issued both NOPRs at its monthly open meeting Sept. 19. (See FERC Proposes Further Cybersecurity Measures.) 

Clarity Requested on INSM Expansion

The INSM proposal builds on CIP-015-1 (Cybersecurity — INSM), which FERC proposed to approve in the same NOPR. The standard requires utilities to implement INSM at all high-impact grid-connected cyber systems, as well as medium-impact systems with external routable connectivity. 

While FERC said the standard would advance grid reliability, in its current form, it is “not … fully responsive to the commission’s directive” to implement INSM. In particular, the commission worried that attackers may be able to compromise systems external to an entity’s electronic security perimeter (ESP) and use that control to establish access within the perimeter as a trusted connection. 

It proposed directing NERC to modify the standard to include electronic access control and monitoring systems (EACMS) and physical access control systems (PACS) in the list of those requiring INSM, which it said would protect “all trust zones of the CIP-networked environment.” 

In its response, NERC first called on the commission to approve CIP-015-1 “as expeditiously as possible,” saying the standard would “improve the probability of detecting anomalous or unauthorized network activity” and help utilities respond to cyberattacks. But, the ERO continued, FERC needs to provide additional clarity on what it means by the term “CIP-networked environment.”  

Although NERC acknowledged that FERC said in the NOPR that the term includes “all assets and systems to which the CIP [critical infrastructure protection] standards apply and [that] may be the targets of attacks,” the ERO pointed out that the term is still not explicitly defined in the proposal. 

“To facilitate an expeditious development process, it would be beneficial if the commission clarifies in a final rule the expected scope of any internal network security monitoring revisions,” NERC said. “For example, in extending the CIP-015-1 protections to EACMS and PACS, would the term ‘CIP-networked environment’ be restricted to east-west communications between EACMS and PACS outside of the ESP? Similarly, would the communications between PACS and controllers and communications to and from EACMS used solely for electronic access monitoring be included?” 

NERC also suggested that FERC give the ERO at least 12 months to complete the proposed revisions, in light of the ERO’s growing standards development workload. NERC pointed out that it is already resolving 82 outstanding FERC directives through the standards development process, and its seven “high priority” projects alone are expected to take more than 10,000 total drafting team hours to complete by the end of 2025. 

Noting that FERC proposed to require that the CIP-015-1 revisions be submitted within 12 months of the final rule, NERC urged the commission to give it enough time to “facilitate additional development options,” including a technical conference, while also allowing the ERO to “balance limited resources between competing high priority projects.” 

ERO Supports Supply Chain Proposal

In the second NOPR issued Sept. 19, FERC indicated its intent to direct NERC to develop new or modified standards regarding evaluation of vendors and equipment to identify supply chain risks, along with processes to validate the accuracy of information received from vendors during procurement and track supply chain risks. 

The commission said it felt moved to act because of “multiple gaps” in NERC’s existing supply chain risk management (SCRM) standards: 

    • CIP-005-7 — Cybersecurity — electronic security perimeter(s);  
    • CIP-010-4 — Cybersecurity — configuration change management and vulnerability assessments; and  
    • CIP-013-2 — Cybersecurity — supply chain risk management. 

FERC said the standards do not specify when and how entities should identify and assess supply chain risks, and do not require entities to respond to supply chain risks through their SCRM plans. 

In their response, NERC and the REs said they appreciate FERC for recognizing the work they have done so far to advance SCRM, including their efforts to revise CIP-013-2 (which were cut short when FERC announced it would be addressing SCRM at the September meeting).  

They said they support the proposed revisions, including adding protected cyber assets (defined by NERC as “cyber assets connected … within or on an [ESP] that is not part of the highest impact … cyber system within the same [ESP]”) as applicable assets within supply chain requirements. However, as with the other NOPR, the ERO Enterprise reminded the commission of its standard development workload and the other deadlines to which it is subject. 

The organizations also asked FERC to consider the relationship between the different standards. Some standards refer to others, and revisions to CIP-005-7, CIP-010-4 and CIP-013-2 could impact other ongoing standards development projects. For example, earlier in 2024, NERC filed a suite of proposed changes to nearly all of the CIP standards, including the three supply chain standards, which might affect the team tasked with carrying out FERC’s order. (See NERC Sends Virtualization Standards to FERC.) 

NERC and the REs requested that FERC “consider no less time than proposed in the NOPR” — 12 months — to both accommodate the busy standards development pipeline and “provide the standards drafting team certainty on the version of CIP reliability standards to revise.” 

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Developers Seek Deadline Extension in NJ Storage Plan

Solar developers are urging the New Jersey Board of Public Utilities to extend the completion timelines in the agency’s proposed storage development plan, saying 550 days to complete a project and secure connection through PJM is too short.

The board’s draft proposal requires grid supply or distributed projects approved under the program to be commercially operating within 550 days of getting the agency award. If they are not, “the capacity they reserved would be returned to the market” and be available for other projects, the proposal says.

The timeline was the most salient concern at a Nov. 20 hearing, in which other speakers — while generally supporting the proposal — called for the BPU to address a range of issues, among them accelerating the start of the program segment focused on distributed storage and strengthening it to make it more attractive to developers.

The proposal, the New Jersey Storage Incentive Program (NJ SIP), sets out the guidelines for two sectors: a program for behind-the-meter, distributed projects that is expected to launch in 2026 and one for in-front-of-the-meter projects, including grid supply projects, that will begin in early 2025.

At least six of the more than two dozen speakers said they believe the project completion deadline — known as a maturity requirement — is too restrictive.

Dan Watson, director of development at Jupiter Power, a large-scale energy storage developer, said construction alone can take three years on a large project.

“It can be a long time with the PJM related upgrades as well,” he said. “So, the 550-day timeline is in obvious need of correction and consideration for larger projects.”

Fred DeSanti, executive director of the New Jersey Solar Energy Coalition, said a grid supply project in front of the meter would “be applying as a wholesale generator in order to do a front-of-the-meter project,” and the current proposed timeline would be tough to meet.

“That’s a process that could take as long as two years or more,” he said. “I know you want to get started on that program in 2025. But it’s unlikely that we can even get approvals until 2027.”

PJM is working through a major backlog of resources and is not accepting any new project requests until 2026.

The proposal says the intent of the requirements “is to eliminate projects that cannot be expected to reach commercial operation within a reasonable time frame.” The proposal explains that a project is considered to have reached commercial operation if “it is fully constructed and has completed the full interconnection process, either at PJM or with a New Jersey jurisdictional [electric delivery company], including construction of any required interconnection upgrades.”

A BPU representative at the meeting said the BPU’s consultant on the project suggested the 550-day timeline. He added that several speakers expressing concern about the requirements “gets our attention,” and the BPU staff would consider the issue.

Launch Date Controversy

The NJ SIP proposal is a revised version of a draft proposal first released in September 2022, with changes made in response to stakeholder input. The state aims to install 2,000 MW of total capacity by 2030, but progress has been slow. A BPU spokesperson said the state currently has 560 MW of installed storage, but that capacity will not be counted toward the 2,000-MW goal.

Several speakers said there is significant interest in developing storage in the state. Diane Cherry, deputy director of the Mid-Atlantic Renewable Energy Coalition, said there are 3,700 MW of storage projects in the PJM queue. Noting the state’s 2,000-MW goal, she urged the BPU to focus on grid-supply project incentives and said, “We can easily meet and exceed this goal with the appropriate regulatory direction.”

Joshua Lewin, president of Helios Solar Energy of Somerville, N.J., encouraged the board to consider launching both the distributed and grid supply segments in 2025, rather than delay the distributed project launch by a year — an opinion also voiced by other speakers.

“This continued delay in the program rollout is unhelpful in gaining customer willingness to enter a new and unfamiliar market,” he said.

The revised NJ SIP includes a competitive solicitation to determine the incentive level for grid supply projects, which was not in the original plan. Also new is an option under which the BPU will accept applications from solar-plus-storage projects, rather than standalone storage projects. That will allow the program to accept projects that are not eligible to receive storage incentives from the Competitive Solar Incentive part of the Successor Solar Incentive program, which encompasses solar-plus-storage projects. (See NJ BPU Updates Proposal for Storage Incentives.)

The revised proposal also makes the bid-participation fee of $1,000/MW refundable to unsuccessful bidders, instead of nonrefundable. BPU said the shift stems from the addition to the plan of a “pre-development security” of up to $100,000/MW, to be paid upon application approval.

The security is designed to ensure the project is carried out as planned, allowing the BPU to impose penalties that will be deducted from the security if the project misses the Planned Commercial Operation Date or the Guaranteed Commercial Operation Date.

The storage proposal also has deferred implementation of a distributed pay-for-performance incentive on projects to give utilities time to develop the mechanism to calculate it.

Prioritizing Segments

Lyle Rawlings, president of the Mid-Atlantic Solar & Storage Industries Association, urged the BPU to focus the program resources on distributed storage rather than grid-scale storage projects. He said the association’s recent member survey showed many already are engaged in the sector.

“There’s a lot of development going on anywhere from less than 10 kWh to tens of megawatt-hours in the behind-the-meter storage field,” he said. One reason, he said, is that “behind-the-meter revenue is substantially more than the grid supply revenue.”

“Behind-the-meter storage is going to be for the foreseeable future more economic, and that means long term a better ability to reduce the incentives from the program and save ratepayers money,” he said. Other speakers said distributed projects, because they are smaller, may get up and running and contribute to the state’s need for storage more quickly.

Addressing the ratepayer impact, Megan Lupo, assistant deputy ratepayer advocate for the New Jersey Division of Rate Counsel, took issue with a new element in the proposal that directs the BPU to pay developers or owners the full project incentive upfront, rather than over 10 to 15 years.

She said the board staff concluded the new system would reduce the level of risk and so bolster program incentives.

“However, it is not clear that any additional incentives are needed for New Jersey to achieve its statewide goals,” she said. “An increase in incentives should be supported by evidence that proves the current incentives are insufficient to meet statewide targets. If not, New Jersey risks over-incentivizing energy storage.”

Lupo also expressed concern about making the fees refundable.

“This change would risk making the bidding process less meaningful and may cause an increase in the number of bids that are speculative in nature,” she said, adding that $1,000/MWh is low compared to other states.

“There is no reason to believe these current nonrefundable fees are overly burdensome to bidders,” she said.

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LPO Announces $4.9B Conditional Loan for Invenergy’s Grain Belt Express

With less than two months until President-elect Donald Trump takes office, the Department of Energy’s Loan Programs Office on Nov. 25 announced three conditional loans totaling more than $11 billion, to be used to build interregional transmission, an electric vehicle factory and virtual power plants.  

Invenergy’s Grain Belt Express, an interregional high-voltage direct current line, has received a conditional loan of $4.9 billion to help finance Phase 1 of the project, a 578-mile, 2,500-MW line running from Ford County, Kansas, to Callaway County, Missouri, according to the LPO announcement.  

The second phase of the project, from Missouri to Illinois, eventually will take the HVDC line to 800 miles and connect SPP, Associated Electric Cooperative, MISO and PJM. The LPO announcement notes that DOE’s National Transmission Needs Study has estimated that interregional transfer capabilities between SPP and MISO might need to increase tenfold by 2035 to meet growing power demand. 

EV maker Rivian is slated for up to $6.57 billion for the development and construction of a new plant east of Atlanta. The company plans to build out the facility in two phases, with production of its R2 and R3 SUVs beginning in 2028 and eventually ramping up to 400,000 vehicles per year, according to a Nov. 25 press release.  

If finalized, the Rivian loan would be the first made under LPO’s Advanced Technology Vehicles Manufacturing (ATVM) Loan Program to manufacture EVs in the U.S., as opposed to EV components, LPO said.  

A third conditional loan, for $289.7 million, will go to Sunwealth, a commercial solar developer, which will use the money to install up to 1,000 solar and storage systems across as many as 27 states. The projects will include installations on commercial and multifamily buildings, as well as community solar facilities.  

Partnering with SYSO, a developer of distributed energy resources management systems, Sunwealth intends to aggregate the systems as a virtual power plant. Estimated capacity of the systems could total up to 168 MW of solar and 16.8 MW and 33.6 MWh of battery energy storage, according to LPO. 

The announcements of the conditional loans signal the start of contract negotiations between LPO and the potential recipients to finalize the awards. Companies must “satisfy certain technical, legal, environmental and financial conditions before [LPO] enters into definitive financing documents and funds the loan,” the announcements all say. 

These negotiations often take months, which could mean uncertainty for the awardees. Prior to his election, Trump pledged to claw back any unspent dollars from the Inflation Reduction Act, which added billions to the funds available to LPO. Some analysts have predicted a Day 1 executive order halting any further distribution of IRA funds.  

In response to questions from RTO Insider, an LPO spokesperson did not comment on whether the office would be able to finalize the contracts for these three conditional loans before Trump takes office, focusing instead on the office’s role as a “bridge to bankability” for a broad range of greenhouse gas-reducing technologies.  

Since President Joe Biden took office in 2021, LPO has announced 31 deals totaling approximately $47.72 billion in project investment, including 13 projects with finalized contracts for $13.18 billion in federal support. Contracts for 18 projects totaling $34.54 billion are pending, according to the spokesperson. 

“Utilizing funding provided by Congress, LPO has accomplished tremendous progress in a short amount of time on bipartisan priorities including advanced nuclear, geothermal, advanced fossil energy and critical minerals,” the spokesperson wrote in an email. “As a result, there is steel in the ground and job openings at new or expanded facilities around the country.  

“It would be irresponsible for any government to turn its back on private-sector partners, states and communities that are benefiting from lower energy costs and new economic opportunities spurred by LPO’s investments.” 

Navigating Uncertainty

Both Invenergy and Rivian welcomed the LPO announcements, while still navigating ongoing uncertainties about their respective projects. 

In an emailed statement, Shashank Sane, executive vice president and head of transmission at Invenergy, said, “We are pleased to see LPO’s evaluation validate the findings of the Kansas and Missouri public utility commissions, both of which have long affirmed our project is key to improving grid affordability and reliability across the Heartland.”  

The first phase of the project has earned successive approvals from the Kansas Corporation Commission, originally in 2019 and again in 2023 to increase capacity for power delivery on the line, according to the project website. The Missouri Public Service Commission issued similar approvals in 2019 and 2022. 

However, Invenergy has run up against interconnection delays in MISO, which has given the project a 2030 interconnection date, versus the project’s original target of a 2027 in-service date. In February 2024, FERC approved an interconnection agreement with the 2030 date.  

Invenergy had asked MISO for a limited operation provision in the agreement to allow the Grain Belt Express to begin partial operations in 2027. (See FERC OKs Grain Belt Express Connection Agreement with MISO; Invenergy Displeased with 2030 Target.)

FERC also gave Invenergy only partial approval to charge negotiated rates on the line once in operation. (See Grain Belt Express Gets Partial Approval for Negotiated Rate Authority from FERC.) 

Rivian founder and CEO RJ Scaringe said the LPO’s loan, if finalized, “would enable Rivian to more aggressively scale our U.S. manufacturing footprint. … A robust ecosystem of U.S. companies developing and manufacturing EVs is critical for the U.S. to maintain its long-term leadership in transportation.” 

Rivian suspended work on the new plant in Georgia in March, shifting production of its R2 SUV to its plant in Illinois, a decision saving the company $2.25 billion, according to a press release. 

The company has not specified when it will resume work on the plant, but according to a spokesperson, “Georgia will provide the volume of production essential for us to enter new markets, including international ones. We expect to start construction to meet our stated goal of start of production in 2028.” 

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4 Arizona Utilities Commit to Joining Markets+

Four Arizona utilities announced their plans to join SPP’s Markets+ day-ahead market, a significant win for SPP after a string of victories for CAISO’s competing Extended Day-Ahead Market (EDAM). 

Arizona Public Service (APS), Salt River Project (SRP), Tucson Electric Power (TEP) and UniSource Energy Services made the announcement Nov. 25. 

Markets+ is expected to save the utilities nearly $100 million while enhancing reliability and supporting the addition of renewable resources to the grid, the utilities said in a joint release. 

The utilities said they plan to begin Markets+ participation as soon as 2027. 

“Together with our neighboring utilities, APS plans to join Markets+ to efficiently deliver energy and bolster the resilience of our shared energy grid in Arizona and across the region,” Brian Cole, APS vice president of resource management, said in a statement. 

When asked about the reasons for choosing Markets+ rather than CAISO’s EDAM, an SRP spokesperson said the primary drivers are governance and resource adequacy.   

The Markets+ governance structure promotes independence, transparency, inclusivity and stakeholder-driven decision-making, the spokesperson said.  

And Markets+ will adhere to a single, shared resource adequacy program — the Western Resource Adequacy Program — providing a consistent method to make sure enough resources are available to reliably serve load across the Markets+ footprint. 

“It also ensures that all market participants contribute fairly to the reliability of the market footprint, preventing any participants from systemically leaning on others,” the SRP spokesperson said. 

SRP expects a critical mass of entities joining Markets+ in spring 2027, and SRP will sign an implementation agreement before the market goes live. 

Tariff Decision Pending

The announcement comes as SPP awaits FERC’s decision on the Markets+ tariff, which initially was filed in March. FERC issued a deficiency letter in July identifying 16 problems in the tariff. (See FERC Finds SPP Markets+ Tariff ‘Deficient’ in Several Areas.) 

SPP filed a response to the letter in September, addressing each issue and asking FERC to issue an order by Nov. 20.  

But FERC isn’t required to abide by that request and will take “as much time as they need,” an SPP spokesperson told RTO Insider. SPP said previously it’s confident it can address concerns the deficiency letter raised. 

In contrast, CAISO’s EDAM already has received FERC approval. 

A TEP spokesperson said the company fully expects FERC to approve the Markets+ tariff, while acknowledging the approval can be an “iterative process,” a comment echoed by SRP. 

“We will continue to work with FERC and SPP throughout the process in demonstrating the value this direction will bring to our customers,” the TEP spokesperson said. 

FERC approval of the tariff will mark the start of a second phase of Markets+ development. 

“SPP thanks all Markets+ stakeholders for their engagement and collaboration in phase one development and looks forward to their continued involvement,” Antoine Lucas, SPP vice president of markets, said in a statement provided to RTO Insider. “We eagerly anticipate receiving signed phase two commitments by the end of the year so we can continue to work together to build a market that provides benefits for all western entities.” 

Footprints Taking Shape

The Arizona utilities’ announcement of their Markets+ decision is the latest step in the evolution of two day-ahead market footprints in the West. In addition to the Arizona announcement, Bonneville Power Administration has expressed a “leaning” toward Markets+ over CAISO’s EDAM. BPA is waiting for FERC’s ruling on the Markets+ tariff before deciding. (See BPA Execs Lay out Markets+ Benefits, Risks, Reasons.) 

Although Powerex has not yet made a formal commitment to a day-ahead market, it has clearly signaled an intention to join Markets+ and to not join EDAM. 

The Arizona announcement “is a clear indication of the value that many utilities are seeing in the Markets+ day-ahead market option,” Lauren Tenney Denison, director of market policy and grid strategy at the Public Power Council (PPC), said in an email to RTO Insider. 

The Portland-based PPC, a trade group representing the extensive network of Northwest publicly owned utilities that buy low-cost power from the Bonneville Power Administration, has been a consistent advocate of BPA choosing Markets+ over CAISO’s EDAM. (See Northwest Public Power Group Endorses Markets+ over EDAM.) 

“As a participant in the development of Markets+, PPC has appreciated the collaboration we have had with these Arizona utilities and the shared goals we have for a well-designed, well-governed day ahead market option,” Tenney Denison said. 

Meanwhile, EDAM scored its latest win this month with Public Service Company of New Mexico’s announcement of its plans to join the CAISO market. (See PNM Picks CAISO’s EDAM.) 

PacifiCorp, Portland General Electric and Balancing Authority of Northern California have signed EDAM implementation agreements with CAISO and the list of entities expected to join EDAM has grown to include NV Energy, Idaho Power and Los Angeles Department of Water and Power.  

In October, the Western Area Power Administration’s Desert Southwest (DSW) Region said it would cooperate with Arizona G&T Cooperatives on a study examining the potential benefits of DSW joining EDAM. DSW this year withdrew from the second phase of developing Markets+ after determining it would realize few benefits from participating in that market. (See Arizona G&T Cooperatives Announces Pursuit of EDAM Benefits Study.)    

After NV Energy announced its intent in May to join EDAM, Advanced Energy United issued a statement encouraging other entities, especially those in the Southwest, to join EDAM. The industry association said EDAM was becoming “the most viable day-ahead market.” 

Brian Turner, who leads Advanced Energy United’s regulatory engagement in the West, said AEU is pleased that Arizona utilities are “embracing broader energy markets,” which have the potential to bring customer benefits including greater reliability and affordability. 

But Turner said the Arizona announcement is “bittersweet,” as having two Western day-ahead markets will create seams and market inefficiencies.  

As the market footprints are now developing, Markets+ could end up with a “big fat seam” in Northwest-Southwest trade caused by NV Energy and California entities joining EDAM, Turner said in an interview. 

And the Arizona utilities are giving up known benefits of their participation in CAISO’s Western Energy Imbalance Market (WEIM) in exchange for unknown potential benefits of Markets+, he added. 

But how the Western day-ahead markets ultimately take shape remains to be seen. 

“Things are still very dynamic,” Turner said. 

Robert Mullin contributed to this article. 

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ERCOT Technical Advisory Committee Briefs: Nov. 20, 2024

Members Endorse 2 Changes to Transmission Planning

ERCOT stakeholders approved a pair of protocol changes related to transmission planning as the Texas grid operator continues to grapple with connecting incoming load to its system.

During the Technical Advisory Committee’s Nov. 20 meeting, members approved NPRR1247, which uses a consumer energy cost reduction test to measure congestion cost savings when evaluating economic transmission projects. They also approved NPRR1180 and a related change to the Planning Guide (PGRR107) that incorporates a 2022 state law requiring any ERCOT reliability transmission project review to include the historical load, forecasted load growth and additional load seeking interconnection.

Several generators and retailers opposed the first protocol change, noting that congestion costs can be hedged but transmission costs can’t.

“We think basing decisions on that is probably discounting a significant value that accrues to loads,” Luminant’s Ned Bonskowski said.

The NPRR was brought forward by ERCOT staff after collaborating with the Public Utility Commission. The ISO retained Energy and Environmental Economics (E3) to identify a set of viable options and provide recommendations for the most suitable congestion cost savings test. E3 presented its work in a March 2024 analysis, recommending a system-wide energy cost reduction test as the most suitable for ERCOT.

While staff approved E3’s recommendations, Luminant said the proposed congestion cost savings test could increase costs for ratepayers when competitive market solutions could serve load less expensively. The generator suggested applying a .25 multiplier factor to the calculated system-wide consumer energy cost reduction before using it to determine a project’s economic benefits.

“We think this may be a good compromise,” Bonskowski said. “If there’s a need to move forward on something today, we certainly would also support tabling” to give stakeholders more time to “make sure that we get this right before sending it up to the board.”

The vote to table NPRR1247 fell short, 11-17, with one abstention.

Mark Bruce, speaking for Pattern Energy, said his client is concerned about an overall lack of transparency and the need for further vetting. He said Luminant lacked backing data in its comments and urged stakeholders to revisit the matter with a change to the Planning Guide to further prevent downstream effects.

“I know there’s been some pressure from above to deliver something to the board on this at their next meeting,” Bruce said. “My client’s been engaged from the get-go, from its first showing as a draft before it was even filed. We’ve been trying to understand and perfect this very important revision request.”

TAC eventually approved the measure 25-3, with one abstention. Luminant, Calpine and Shell North America all opposed the motion.

The committee approved NPRR1180 25-0, with four abstentions, two from consumer interests.

The Office of Public Utility Counsel’s Nabaraj Pokharel said he supported the rule’s legislative intent but stressed the importance of ensuring load projections used for planning “are as accurate as possible.”

“There is a risk of unintended consequences, particularly if load studies are not thorough or accurate,” he said. “While building transmission to meet actual load is necessary, [it] could result in unnecessary cost that would ultimately be borne by residential consumers.”

To remedy that concern, Mark Dreyfus, speaking for a coalition of cities, suggested approving the protocol change and filing a follow-up revision request that drills down into the load-projection’s validation process.

“There’s a lot of projects waiting to have this process in place and we need to get moving on those projects,” he said.

Texas Competitive Power Advocates Executive Director Michele Richmond said several meetings with Oncor and other wires companies have resulted in a draft proposal for another NPRR that would address the process’ transparency and standardization.

“I think we are very comfortable with moving this forward, given that commitment and the really good discussions that we have been having,” Richmond said.

Large Loads Need a Segment Home

TAC discussed with staff potential changes to the committee’s segment makeup, driven by the growing influence of data centers and cryptocurrency miners that don’t fit neatly into either the industrial consumer or large commercial segments.

ERCOT membership has risen from 257 members in 2021 to 356 this year, mostly because of large flexible loads. Staff has asked entities with large loads to register in the industrial segment when making their membership applications for 2025.

The grid operator’s seven segments are used to fill out the 30-person TAC. Any changes to the representation would require an amendment to the bylaws and PUC approval.

“Things have changed a lot,” Engie’s Bob Helton said, alluding to a TAC segmentation that has been static since 2014. “Every time we talk about this, we have to be careful of balance. Anything we do is going to be a long, drawn-out deal to make sure that that balance remains in place and that no segment or group has a heavier weight than any other one in trying to approve things.”

Staff said ERCOT now has just over 62 GW of large loads in its interconnection queue. It has added another gig of new standalone and co-located projects since October.

West Texas Project Endorsed

TAC members endorsed ERCOT’s recommended $202.2 million Oncor project that addresses reliability issues in West Texas, placing it on the combination ballot.

The project stems from the 2019 Delaware Basin Load Integration Study. The region has significant oil and natural gas load and ERCOT’s highest peak demand growth rate percentage in recent years.

The Regional Planning Group approved Oncor plans to upgrade an existing capacitor station, build 22 miles of double-circuit 345-kV lines, convert 41 miles of 138-kV lines to 345-kV, build 41 miles of new 138-kV lines, and install six 5000-A, 345-kV circuit breakers. The project is expected to be completed in 2027.

Because the project cost more than $100 million, making it a Tier 1 project, it must be approved by ERCOT’s Board of Directors.

Co-chair Martin to Step Away

The meeting was the last as TAC’s co-chair for Collin Martin, Oncor vice president of grid operations. Martin told his fellow members he is stepping away “partially” to focus on potential transmission projects in the Permian Basin.

“I appreciate everybody’s confidence in being able to be seated to this on the table,” he said. “It’s been a great year. I learned a lot.”

“I learned a lot from Collin,” said TAC Chair Caitlin Smith, with Jupiter Power. “He brought a wide range of knowledge to TAC leadership, and not just the engineering side. He knows a lot about the market side and the systems and everything. I think having him here to add his perspective has been very valuable.”

Fellow Oncor employee Martha Henson has been proposed as Martin’s replacement. Smith will continue as chair.

HDL Override Change Tabled

TAC again tabled a protocol change (NPRR1190) that would recover demonstrable financial loss arising from a manual high dispatch limit (HDL) override to reduce real power output, should the output be used to meet qualified scheduling entity load obligations. Members directed their Wholesale Market Subcommittee to provide remarks on the change back to the Protocol Revision Subcommittee before they take it up again in January.

The change was approved by TAC in June. However, the board remanded it back to TAC in October over the consumer segment’s concerns that the NPRR would reward overscheduling of power that cannot be delivered. Members of that segment say that will force consumers to subsidize insufficient hedging by other market participants in the face of changing grid conditions. (See “2025 AS Methodology OK’d,” ERCOT Board of Directors Briefs: Oct. 9-10, 2024.)

Reliant Energy Retail Services’ Bill Barnes said he has discussed this with Eric Goff, who represents residential consumers but was unable to attend the meeting, and floated a concept from their conversation. He said it acknowledges consumer concerns about a situation where HDL overrides become a “dominant component” of the market.

“We would be more dependent on these out-of-market payments. That’s not the goal of 1190. That’s not the goal for any of us,” he said.

Barnes said an annual settlement trigger, should ERCOT find itself in a situation where it hits a threshold amount of HDL payments, would lead to a review of the protocol’s language. That would tighten the contracts eligible for some participants, he said.

Members unanimously endorsed a combo ballot that included four NPRRs and related changes to the Planning Guide (PGRR) and Nodal Operating Guide (NOGRR) and an Other Binding Document request that will do the following if approved by ERCOT’s board:

    • NPRR1239, NOGRR266: move reports that don’t contain ERCOT critical energy infrastructure information (ECEII) from the market information system secure area to the public ERCOT website.
    • NPRR1240, NOGRR267, PGRR116: move reports that don’t contain ERCOT ECEII information from the market information system secure area to the public ERCOT website. The change also conforms rules with current posting practices, including those for maintaining ECEII lists of equipment in the outage scheduler; for making the annual planning model data submittal schedule available in the model-on-demand (MOD) application; and for posting weekly demand forecasts, demand analyses for 36 months and beyond, metrics of forecast error, and assessments of chronic congestion on the website.
    • NPRR1246, NOGRR268, OBDRR052, PGRR118: insert terminology associated with energy storage resources (ESRs) into the protocols, aligning the ESRs’ provisions and requirements with those for generation resources and controllable load resources. The change applies to ESRs in the future single-model era and should be implemented simultaneously with NPRR1014 (BESTF-4 Energy Storage Resource Single Model).
    • NPRR1254: require resource entities to submit the initial resource registration data for a generator interconnection or modification (GIM) project four months prior to target inclusion in the ERCOT network operations model. This gives ERCOT and the entities one month to address errors or deficiencies.