RTO Insider

April 13, 2025

MISO: DR to Face More Stringent Testing by 2026 Capacity Auction

CARMEL, Ind. — MISO said its next capacity auction in spring 2026 will feature more rigorous testing for its demand response that registers to provide capacity.

The grid operator said it will discontinue its practice of allowing its demand resources to provide hypothetical, mock tests as a performance indicator, except where state regulations might allow, for the 2026/27 Planning Resource Auction.

The end of mock testing follows MISO enforcing stricter registration requirements ahead of the 2025/26 capacity auction offer window, which ran from March 26-31. (See Following DR Exploitation, MISO Announces Stiffer Requirements Before Capacity Auction.) Taken together, the more unyielding rules are a response to five recent instances of disciplinary action from FERC regarding companies deceitfully offering demand response in MISO’s capacity auctions. (See Voltus Agrees to $18M Fine to Settle DR Tariff Violations in MISO.)

“There are concerns about the mock test, how it’s being used and the information around it,” MISO Market Design Economist Joshua Schabla said during an April 9 Resource Adequacy Subcommittee. “Frankly, it’s something we’re uncomfortable with.”

Schabla said at times, mocks tests are “little more than a function in an Excel file.”

MISO said all demand resources that plan to provide capacity beginning in June 2026 should be prepared to prove their capabilities via actual demand reductions to at least 50% of their stated seasonal values or down to a firm service level, if they specified one. Tests that show less than a 100% result need to be backed up with documentation explaining why a full reduction wasn’t possible.

MISO said it wasn’t foreclosing the possibility that mock tests won’t ever be allowed among its demand response fleet in the future. So far, the testing requirement would apply only to the 2026/27 capacity auction.

Schabla said MISO plans to require a real test of its load modifying resources (LMRs) once per year. The tests can be completed on the resource owner’s time and would count as one deployment. MISO’s LMRs currently are bound to deploy if necessary five times apiece in the summer and winter and three times apiece in spring and fall.

Erik Hanser, of the Michigan Public Service Commission, said the new testing requirements won’t give resource owners much time because real power tests for the 2026/27 planning year begin in summertime up until LMR registration for the 2026/27 Planning Resource Auction begins Dec. 15.

Schabla said MISO has not called LMRs since December 2022. The three-year downtime provides further justification that it’s time for LMRs to make a demonstration of their abilities, he said.

“We need to see something positive, that this demand resource is real and can perform to requirements. … We need to see that it can do what we’re paying it to do,” Schabla said.

MISO Independent Market Monitor David Patton said terminating the mock test practice is critical because the IMM has noticed mock test results submitted from LMRs with reduction levels that are “difficult to believe.” He said in some cases, LMRs appeared to fail a real power test and then decided to conduct a mock test instead. Patton said at this point, MISO likely is hosting and paying several megawatts of LMRs that either aren’t real or can’t achieve what they say they can.

Patton said it’s “entirely fair” for MISO to provide notice now that it will enact stricter testing requirements, even if it doesn’t yet have FERC approval to end mock testing. He said LMRs should use the time to prepare for actual testing.

Patton said MISO’s proposed 50% benchmark testing is “far too lax.” MISO pays LMRs too much to accept a 50% performance, Patton argued.

“We’re going to continue to talk to MISO and stakeholders about that dimension of this proposal,” he said.

MISO to Allow LMR Capacity Substitutions

MISO also said it will permit load modifying and demand response resources to replace their auction-cleared capacity with other, uncleared capacity in the event they’re unable to deliver promised load reductions. The change would also take effect in the 2026/27 planning year auction.

MISO allows its more traditional resource types to replace zonal resource credits, but that allowance doesn’t extend to demand response resources and LMRs. In MISO, resources’ accredited capacity values are converted to zonal resource credits that are used in auction trading.

MISO said it will allow LMRs to make similar, limited replacements if: the end-use customers it contracted for reductions must terminate contracts; regulations prevent the LMR from performing; or a change in ownership occurs in an end-use facility that the resource was banking on to shrink load. For behind-the-meter generation registered as LMRs, MISO said a planned outage longer than 31 days or a catastrophic outage would present the opportunity for replacements.

MISO said in all cases, it may require documentation or evidence.

Schabla said resources “must have a good reason to replace” and must be prepared to explain their situations to MISO and the IMM.

MISO staff said they intentionally drafted narrow criteria for replacement conditions so auction commitments remain binding, and market participants don’t have a route to avoid obligations.

Some stakeholders have said MISO’s replacement proposal is encouraging and will be helpful if facilities close and zonal resource credits need to be replaced.

April 13, 2025

IMM Praises MISO for Fewer Out-of-market Actions

CARMEL, Ind. — After years of its Independent Market Monitor critiquing MISO for making too many out-of-market actions to tame congestion, the IMM congratulated the RTO for dramatically reducing such actions over this winter’s sustained cold.

Speaking at an April 10 Market Subcommittee, IMM Carrie Milton said MISO operators’ manual actions for congestion management fell dramatically over the winter. She said despite record peak loads over the winter, MISO trusted its markets more and paid minimal uplift payments. (See MISO: Better Preparations Clinched Winter Storm Operations.)

The IMM has long advocated for the MISO control room to allow market-based interventions rather than operators making what it calls inefficient, out-of-market actions to manually redispatch or cap generation output.

By the IMM’s count, MISO operators ordered just 42 manual redispatches and generation caps over winter 2025, compared to 769 in winter 2024 and 1,236 in winter 2023 that the IMM previously cataloged.

“It almost looks like we’re missing data,” Milton said of the IMM’s striking graph comparing the instances of actions in winter 2023, 2024 and 2025. Milton called it a “very impressive result.”

Milton said MISO has worked to make better data available and has congestion management guidelines among control room operators.

Stakeholders asked if the IMM believed that the minimal out-of-market actions could be an enduring trend.

An illustration of the contingency reserve shortage on Feb. 19 | Potomac Economics

Milton said she thought MISO can reduce its extraneous actions in the long run, even if actions outside of the market tick up during spring. She said maintenance outage season combined with volatile spring weather and high wind likely will lend itself to more out-of-market interventions March through May.

“We understand if we don’t see the same result in the spring quarter,” Milton said.

Finally, Milton advised the MISO operations team to put more trust into its look-ahead commitment tool to call up units. If control room operators had followed the tool’s recommendation to procure and committed an additional 905 MW around 7 p.m. ET on Feb. 19, they could have avoided a contingency reserve shortage that day, Milton said. MISO committed only 450 MW, she said.

April 13, 2025

FERC Issues Order 1920-B Upholding States’ Role in Cost Allocation

FERC issued Order 1920-B on April 11, denying rehearing requests on its previous iteration that mostly sought to overturn requirements that transmission planners file cost allocation methods agreed on by state regulators and that they are consulted on future reforms.

Order 1920 gave states in a planning region six months to work on a cost allocation methodology, but it declined to require that they be filed by the ISO/RTO or other planning entity. That changed with Order 1920-A, which did require any agreed-upon cost allocation methods to be filed.

Edison Electric Institute, WIRES, and some regional transmission owner groups argued in separate rehearing requests that forcing transmission owners to file state cost allocation methods, even if they disagree with them, intrudes on their filing rights under the Federal Power Act’s Section 205. That part of the law gives public utilities unilateral and exclusive filing rights to propose rates, terms and conditions of service that essentially places FERC in a reactive role.

But FPA Section 205 is complemented by Section 206, which provides FERC with the authority to modify any existing rates after a finding that they are unjust, unreasonable or unduly discriminatory.

A group of MISO transmission owners argued that the requirement to file state agreements disrupts the balance set by those two sections of the law — “allowing FPA Section 206 to usurp FPA Section 205,” the order said.

“The compliance filings required by Order Nos. 1920 and 1920-A are a tool to implement the commission’s authority under FPA Section 206 and do not implicate public utilities’ rights and obligations under FPA Section 205,” FERC said.

FERC issued Order 1920 and 1920-A under a Section 206 process that it initiated, which included a finding that its existing regional planning and cost allocation rules were unjust and unreasonable. The submission of compliance filings assists in implementing FERC’s authority under Section 206.

“The express text of FPA Section 206 does not provide public utilities with statutory filing rights with respect to the just and reasonable replacement rate following a finding that existing rates are unjust, unreasonable, or unduly discriminatory or preferential,” the order said. “Rather, the authority to ‘determine the just and reasonable rate, charge, classification, rule, regulation, practice or contract to be thereafter observed and in force’ is vested in the commission, and — in commission-initiated proceedings under FPA Section 206 — the commission must find that the replacement rate it determines and fixes meets the statutory criteria.”

The law does not preclude FERC from requiring transmission providers to file state cost allocation methods. And just because a public utility has to file a compliance filing does not transform that into a Section 205 filing.

“A contrary conclusion would fail to recognize and give effect to the distinct and express statutory authority afforded to the commission in FPA Section 206, which arises pursuant to specific statutory findings and which, once triggered, is subject to different requirements than FPA Section 205 filings,” the order said.

While Section 205 does give public utilities exclusive filing rights, when considered in the correct statutory context the arguments that require them to file state cost allocation agreements are not persuasive.

“FPA Section 205 is not implicated by these aspects of Order No. 1920-A, and arguments to the contrary conflate compliance filings to assist the commission in implementing its authority under FPA Section 206 with public utilities’ rate filings under FPA Section 205,” the order said.

Part of the debate goes to a court case from Atlantic City where FERC tried to require public utilities to cede their Section 205 filing rights to an RTO (PJM in the court case). The court found that FERC could not deny utilities statutory rights given to them by Congress.

Order 1920 does not remove those filing rights, because the requirement to file state cost allocation agreements falls under FERC’s authority to set a replacement rate under Section 206.

Transmission owners also made arguments that imposing the state filing requirements goes against the Administrative Procedures Act. FERC responded that given how important state engagement is to getting large, regional transmission lines built, it makes sense to ensure they have meaningful participation in the process.

“The commission found that the additional requirement would allow it to better evaluate whether transmission providers have complied with Order No. 1920’s requirement to provide a forum for negotiations that enables meaningful participation by relevant state entities during the engagement period,” the order said.

A group of PJM transmission owners argued the requirement goes against the First Amendment to the Constitution by compelling speech.

“Order No. 1920-A imposes no actual burden or limitation on transmission providers’ speech but instead requires nothing more than the attachment of one or more files, containing the information provided by relevant state entities, to transmission providers’ compliance proposals under FPA Section 206,” the order said.

Another item that transmission owners filed for rehearing was the requirement that regional planners consult state regulators before amending long-term cost allocation arrangements, making similar arguments about the FPA.

FERC disagreed again, saying the consultation requirement does not regulate Section 205 filing rights but rather addresses the practices through which cost allocation methods are developed, which is tied to the likelihood such lines actually get built.

“In Order No. 1920-A, the commission determined — and we here sustain — that requiring transmission providers to consult with relevant state entities will provide an opportunity for state input, which ‘has the potential to minimize additional costs and delays in the siting process and to facilitate the development of long-term regional transmission facilities,’” the order said.

One area where FERC did tweak Order 1920 was to clarify that regional transmission plans can consider the needs of non-jurisdictional utilities if they voluntarily agree to pay their fair share under regional cost allocation.

The National Rural Electric Cooperative Association and transmission owners in the WestConnect regional planning area argue the previous language could be interpreted to ban any planning around non-jurisdictional utility needs.

If a non-jurisdictional utility has not voluntarily enrolled in a transmission planning region, its needs cannot be addressed. But if they have signed up for a region, then they can as long as the compliance filing can show FERC there is no free ridership issue.

April 11, 2025

FERC Sustains Order Rejecting Expanded Susquehanna Co-located Load Arrangement

FERC sustained its rejection of amendments to the Susquehanna nuclear plant interconnection service agreement (ISA) to increase the amount of power serving a co-located data center (ER24-2172).

The changes sought by Talen Energy would have increased the scale of the Amazon Web Services data center operating behind the fence of Susquehanna from 300 MW to 480 MW. That was rejected by the commission on Nov. 1 on the grounds PJM had not demonstrated the proposal was “necessary for any interest unique to the interconnection of the Susquehanna customer facility.” (See FERC Rejects Expansion of Co-located Data Center at Susquehanna Nuclear Plant.)

The April 10 rehearing order defended the commission’s earlier finding that the proposed ISA amendments were not based on “specific reliability concerns, novel legal issues and unique factors” as demonstrated by it being based on PJM’s generally applicable guidance document for co-located configurations. While the RTO since has rescinded that document, the commission noted that portions of the proposed amendments to Susquehanna’s ISA mirrored the guidance and comments debating the proposal referred to it repeatedly. The rehearing order argued that allowing a standardized practice to be the basis of ISA language that does not conform to the pro forma interconnection service agreement (ISA) would weaken the commission’s necessary standard.

In its request for rehearing, Susquehanna said the commission’s rejection was not based on the unique configuration Talen sought, but rather that it could create a precedent for other resources that would not be reflected in the pro forma ISA. The company argued that being the first of its kind is not a valid reason for denying the application.

The commission wrote that reliance on the guidance document “raised the question of whether PJM intended to offer certain terms to all similarly situated interconnection customers.”

“Creating a requirement that the commission wait for a pattern to emerge before rejecting a non-conforming provision, as Susquehanna requests, would meaningfully weaken the necessary standard and meaningfully increase the possibility for disparate treatment that the necessary standard is designed to diminish,” the commission wrote.

Susquehanna also argued that reliability concerns “haunt” the rejection order despite PJM stating that necessary studies had not identified any issues with the configuration.

In the rehearing order, the commission wrote the study findings are not relevant to the rejection order, which hinged on a determination that PJM had not shown that the non-conforming language was necessary.

Vistra requested the commission clarify whether its rejection establishes a blanket limit on amending ISAs to co-locate data centers. If the intention was to hold that such amendments are not appropriate, Vistra said the underlying issues should be outlined so Susquehanna could refile without those provisions and others could do so as well. The commission responded that the rejection order does not prejudice any future co-located load configurations.

Phillips Dissents

The rehearing order was approved on the same lines as the original rejection, with Commissioners Mark Christie and Lindsay See in support and Willie Phillips dissenting. Commissioners David Rosner and Judy Chang did not participate.

Phillips wrote that he’s hopeful the commission’s order that PJM show cause investigating whether PJM’s tariff is just and reasonable without language addressing co-located load will allow such configurations to proceed. He repeated arguments he made opposing the original rejection that data centers represent an “era defining technology” that requires regulatory leadership. (See FERC Launches Rulemaking on Thorny Issues Involving Data Center Co-location.)

“Notwithstanding my disagreement with these orders’ rationale and determination, I remain hopeful that the Commission’s recently issued order … will soon result in solutions to address what I regard as unnecessary roadblocks to the continued maturing of an industry that is vital to our economic prosperity and national security,” Phillips’ dissent on the rehearing order said.

PJM’s response to the show cause order said more FERC guidance is needed on how the RTO should allow co-located configurations to proceed and laid out several possible pathways. It also noted challenges that remain unsolved, such as how to account for ancillary services the RTO maintains are consumed by co-located loads and whether protective schemes can be adequate for preventing the load from inappropriately taking energy from the grid. (See PJM Responds to FERC Co-located Load Investigation.)

Proponents of co-location have argued that in some instances the load should be considered separate from the wholesale grid and should not be charged for services such as regulation and black start.

April 10, 2025April 10, 2025

Urgent EDAM Congestion Revenue Issue ‘Will Take Time’ to Address

The complex issue regarding congestion revenue allocation in CAISO’s Extended Day-Ahead Market (EDAM) continues to raise questions and cause some confusion for market participants, with a market expert reviewing possible solutions at an April 8 Western Energy Markets Governing Body meeting.

The issue is whether certain congestion revenues should be allocated to the balancing area in which the congestion costs accrued, or to the neighboring EDAM balancing authority area where the transmission constraint is located, specifically in cases in which parallel — or loop — flows occur.

In March, CAISO launched an “expedited” initiative to address stakeholder concerns. The ISO plans to release a full proposal on the issue in the coming week. (See Fast-paced Effort will Address EDAM Congestion Revenue Issue.)

Under current EDAM market rules, Open Access Transmission Tariff (OATT) customers in one BAA will end up paying costs for congestion for parallel flows caused by binding transmission constraints in neighboring BAAs, CAISO market expert Susan Pope noted during the meeting. This requirement could make a system and its transmission users carry the costs of unexpected congestion.

OATT point-to-point (PTP) service is awarded without fully accounting for parallel flows, while management of infeasible OATT schedules today requires approaches such as curtailment of non-firm service and out-of-merit redispatch by the impacted BAA to manage congestion, Pope said.

“These congestion charges only occur when there are flows over binding constraints and the amount of the charges reflect the cost of managing the congestion on those constraints,” Pope said. “So, if the cost of managing the congestion isn’t that big, the charges aren’t going to be that big.”

There is strong justification for charging OATT customers for EDAM congestion costs, because the charges are tied to the marginal cost of redispatch to manage congestion on the binding constraints impacted by the OATT schedule, Pope added.

At an April 2 meeting on the subject, Anna McKenna, CAISO vice president of market design and analysis, also disputed the contention that EDAM’s existing congestion revenue framework is inherently flawed. (See EDAM Congestion Debate Builds Even as CAISO Moves to Address Issue.)

However, Pope said the ISO could address stakeholder concerns by redesigning EDAM to include an avenue for OATT customers to more fully hedge or otherwise manage EDAM congestion cost charges.

More specifically, EDAM could adopt use of congestion revenue rights (CRRs), which would provide OATT customers with a hedge against EDAM congestion charges. But the market design does not include CRRs, and CAISO would need to address core issues prior to including them, Pope said. Introducing CRRs would require new rules to establish transmission capability for CRRs while also enabling cost recovery for transmission service providers, she said.

In many RTOs and ISOs, such as NYISO, PJM, MISO and CAISO, OATT transmission reservations were infeasible when modeled, according to Pope’s presentation. Furthermore, RTOs with CRRs have required lengthy stakeholder processes to design the market rules for converting existing OATT service arrangements into CRR allocations, Pope said.

Despite these challenges, introducing CRRs for hedging EDAM congestion costs would “likely enable more efficient scheduling and decrease the cost of serving EDAM load,” Pope said. “But it will take time to design and implement CRRs when agreed upon by EDAM participants.”

In the meantime, a transitional approach is needed to address concerns about OATT transmission customers’ potential undue exposure to charges for parallel flow on binding constraints in other BAAs, Pope said.

One transitional solution is to enable PTP customers to “opt out” of EDAM settlements, which could allow them to avoid congestion charges under all grid conditions, such as by self-scheduling rights before or after EDAM without paying congestion charges, Pope said. But this approach could reduce efficiency and customer cost savings from EDAM and make it more difficult to maintain system reliability during stressed system conditions.

More Work Ahead

WEM Governing Body member John Prescott said the parallel flow congestion issue is “a very thorny problem.”

“But I appreciate the fact that everybody is rolling up their sleeves and, I hope, working in earnest to solve this problem,” Prescott said.

At the meeting, Alan Meck, principal market design analyst at Pacific Gas and Electric, asked if CAISO could break down the pros and cons of each possible solution to the matter.

“I think that I’m following this presentation, but it’s been kind of difficult,” Meck said. “It would be really helpful, I think, if you could add one additional slide synthesizing EDAM design pros and cons and where all of these different issues shake out.”

Pope reminded attendees that a good solution to the issue “is probably one that doesn’t make anybody happy.”

“If everybody’s complaining about something, that might be a good solution,” Pope said. “There’s a lot to gain by solving this problem. I just wanted to encourage everybody to sort of work together, be realistic and try to craft solutions.”

CAISO is on track to publish a full proposal on the topic on April 14, spokesperson Jayme Ackemann said. Whether the CAISO Board of Governors will vote on the proposal at its May meeting is still under consideration, she said.

April 10, 2025

Robb: NERC Working with DOE on Energy Orders

NERC is examining a series of energy-focused executive orders issued by the White House in a “whirlwind week” for their impact on grid reliability, CEO Jim Robb told the ERO’s Member Representatives Committee in a conference call April 10.

President Donald Trump signed the orders April 8, seeking to keep existing coal-fired plants open and strengthen grid reliability and security by requiring the Department of Energy to conduct an assessment identify regions with reserve margins “below acceptable thresholds,” and weaken state and local governments’ ability to regulate energy utilities. (See Trump Seeks to Keep Coal Plants Open, Attacks State Climate Policies.)

The president also released a proclamation that coal plants be exempt from the latest iteration of EPA’s Mercury and Air Toxics Standards to ensure they are not prematurely closed.

Speaking at the MRC’s April Informational Session, held in advance of the MRC and Board of Trustees’ May open meetings, Robb said NERC and DOE are “still digesting” the executive actions. He added that NERC staff were meeting with DOE “as we speak” to see how the ERO can assist with the reliability assessment.

DOE must complete the assessment within 30 days of the order’s issuance and release it on the department’s website within 90 days. In addition, Energy Secretary Chris Wright must establish a process to regularly assess the assessment’s methodology, along with any analysis and results produced, and “a protocol to identify which generation resources within a region are critical to system reliability.”

Robb noted that work is underway in Congress on “a fairly similar” bill that would require FERC to use material from NERC’s Long-term Reliability Assessment to “look at how to address the resource adequacy challenges that [NERC has] been flagging for a number of years.”

While Robb acknowledged “there’s more uncertainty than certainty around these” recent events, he told members they indicate “profound changes in direction for energy policy” in the U.S. He emphasized that NERC is “in the mix” with FERC and DOE to determine the best way to meet Trump’s directives.

Robb also told members that NERC has been conducting conversations with the regional entities on enhancing the ERO’s reliability assessments by incorporating additional metrics and other means. He suggested the administration’s moves “may put a little bit more urgency in us moving down the path of renovating those assessments.”

Trustee Ken DeFontes observed that Trump’s executive orders have revealed a public awareness of energy reliability issues that surprised him. He told members about a recent community meeting he attended in Maryland about a proposed transmission line project for the generation planned to replace the Brandon Shores and Wagner plants. The stations, which are fired by coal and oil respectively, were slated for closure until their operator Talen Energy reached an agreement with PJM earlier in 2025 to keep them operating while the transmission was built.

“You can imagine the community was not very happy about [the new transmission]. What’s interesting is, one of the ladies got up and said, ‘Well, I understand President Trump just issued an executive order mandating that coal plants not be shut down. So if we can get that through, then the plants will stay in business, and we don’t need the transmission line,’” DeFontes said. “She was just somebody from the community. I was surprised; the word’s getting out.”

April 10, 2025April 10, 2025

PJM, Alphabet Partnering on AI Tools to Speed Interconnection

PJM and Alphabet on April 10 announced a partnership to develop a suite of new tools using artificial intelligence to speed the RTO’s generation interconnection process.

Amanda Peterson Corio, head of data center energy at Google, said grid planners face an explosion in the number of new service requests they have received, straining their ability to process applications. Google sister company X Development is leading the initiative to build on its Grid Planning Tool and Grid Aware software to create a streamlined work environment PJM can use to more quickly bring new generation onto the grid at a time when the RTO is sounding alarm bells about future resource adequacy.

The planning tool has been deployed in Chile to simulate the grid 20 years into the future with hourly granularity, while Grid Aware uses visual information from sources like Google Maps to facilitate inspections and identify where repairs may be needed.

“This initiative brings together our most advanced technologies to help solve one of the greatest challenges of the AI era: evolving our electricity systems to meet this moment,” Corio said. “We see the opportunity to help secure America’s electricity needs with the many resources seeking to provide energy to the grid and believe this work with PJM is a great catalyst for innovation across the United States.”

The sluggish pace of new entry is one of three contributors to a potential capacity deficiency that PJM has identified in the 2029/30 delivery year, alongside generation deactivations and ballooning load largely fueled by data centers. Executive Vice President of Operations, Planning & Security Aftab Khan said the RTO’s shift to a cluster-based approach to studying interconnection requests is allowing it to more expeditiously work through its backlogged queue, but it still will take about two years for projects to go through the process. Integrating more artificial intelligence into those studies can add more efficiency and quality to studies, he said. (See PJM Reaches Milestone on Clearing Interconnection Queue Backlog.)

“Innovation will be critical to meeting the demands on the future grid, and we’re leveraging some of the world’s best capabilities with these cutting-edge tools to further reduce completion times for new service requests,” Khan said. “PJM is committed to bringing new generation onto the system as quickly and reliably as possible.”

Renewable developers and consumer advocates have pointed to PJM’s interconnection queue as a central obstacle to getting clean energy onto the grid and allowing generation owners to respond to high capacity prices. In a complaint filed at FERC, Pennsylvania Gov. Josh Shapiro (D) argued for a lower maximum capacity price on the grounds the new generation cannot respond to price signals sent by upcoming Base Residual Auctions. PJM has defended the process, saying more projects are clearing the queue but are becoming mired in other issues challenging development, such as supply chain constraints and permitting requirements. (See PJM Presents Capacity Price Cap and Floor to Members Committee.)

Page Crahan, general manager of X’s electric-oriented Tapestry, said a core challenge grid operators face is information being siloed across disparate information streams and tools, an environment she said could be streamlined through using Google’s expertise in data management to create a unified model of the grid, pulling together the output of existing tools to create a “knowledge graph.” She said the name Tapestry was chosen to represent the goal of creating a platform that can stitch together the fragmented elements of the grid.

Speaking during a press conference ahead of the announcement of the partnership, Crahan said one area that could be improved by adding AI is processing PDF applications submitted by generation owners with new projects. Assessing the information in those files creates a bottleneck in the study process, where planners have to consult multiple tools, models and datasets when modeling how a new generator may impact existing equipment. She also gave the example of using AI to aid in validating information provided in interconnection applications; rather than planners having to refer to multiple documents to determine whether the land rights are associated with the correct builder, she said Tapestry software could sift through those files.

Tapestry already has partnered with system operators across the globe, including developing “near real-time grid virtualization” software to simulate AES’ distribution grids in Ohio and Indiana, as well as advanced inverter technology working with Australia’s Commonwealth Scientific and Industrial Research Organization.

Crahan said Chile’s National Electric Coordinator (CEN) has deployed the Grid Planning Tool to allow planners to simulate its grid 86% faster, allowing 30 times the number of scenarios to be run. Google’s DeepMind software also has improved CEN’s weather forecasting for wind.

Unlike those other projects, Crahan said the work with PJM will be the “first of its kind” to integrate AI into the modeling interconnection study process of a large grid coordinator. X is aiming to deliver the first tools to PJM in 2025, she said.

In response to questions on how the effort to speed interconnections may interact with President Donald Trump’s executive order April 8 seeking to ease regulations on coal generation, Khan said PJM is fuel agnostic and will welcome any resource that can improve reliability. He added there are many factors that can impact the viability of coal, including the growth of gas generation. (See related story, Trump Seeks to Keep Coal Plants Open, Attacks State Climate Policies.)

Corio said Google remains dedicated to its climate goals and will continue to seek clean energy sources that can provide firm capacity. She specified that coal is not a clean technology under that framework.

April 10, 2025April 11, 2025

ACP Road Map Suggests Market Changes to Increase Storage Participation

The American Clean Power Association on April 8 released a report produced by The Brattle Group laying out how organized markets can replicate the success CAISO and ERCOT have had in deploying energy storage resources.

The “Energy Storage Market Reform Roadmap” includes detailed changes for the energy, capacity and ancillary services markets, with individual “road maps” for MISO, NYISO and PJM guiding how to grow storage in their territories.

The report and road maps focus on those grid operators because they have “opportunities for market reform,” their states are pursuing decarbonization, and they have a mix of central planning and market-based investment.

CAISO and ERCOT have shown that with updated market rules, energy storage delivers substantial value and complements both thermal and renewable generation to help meet reliability needs.

“Energy storage technologies add a new dimension of flexibility and efficiency to our electric grid,” ACP Vice President of Energy Storage Noah Roberts said in a statement. “Energy storage has proven to boost reliability and lower energy costs. In Texas, the state added 5 GW of energy storage in one year, eliminating calls for customers to reduce electricity use during historic summer heat, stabilizing the grid through volatile winter storms, all the while delivering more than a billion dollars in energy cost savings. This road map outlines actionable steps to better utilize energy storage to deliver reliable and affordable power across the United States.” 

Before FERC issued Order 841 in December 2020 to open up the RTOs to energy storage, the resource faced barriers to participation in the markets, which were designed around the attributes of other generators. Where the organized markets have encouraged deployment and removed barriers, storage has helped prevent blackouts and reduced pressure on customers during tight operating conditions on the grid, while delivering cost savings, ACP said.

One of the areas the report and road maps focus on is the need to replace retiring generation while maintaining reliability and meeting growing demand in many parts of the country. Storage can help replace the reliability services retiring generation provided while keeping a lid on high capacity prices, ACP said.

Many generators were planned to support local transmission needs, especially when they were built in load pockets. Retirements will continue to trigger transmission violations, and some of those are too localized for capacity markets to solve.

The industry’s historic answer for those situations is to build transmission, and sometimes to keep power plants running with out-of-market, reliability-must-run contracts while that is built. But storage, or non-wires alternatives, can contribute to solving those issues at lower costs to consumers, the paper says. “RTOs should identify solution(s) that lead to the lowest costs for ratepayers when procuring reliability solutions out of market.”

Some RTOs, including PJM, do not consider non-wires alternatives for retiring generators. Others do, but they are rarely picked because of a lack of comprehensive benefit-cost analysis, which is exacerbated by the short notice period between the solicitation date and required online date, the report says.

On average in PJM, RMRs have cost $300/MW-day, which is well above the market clearing prices in the long term of $100/MW-day, according to the paper. Studies have shown the benefits of competitive solicitations both in transmission infrastructure procurement and generator procurement, it says.

Energy storage — especially long-duration and multiday — may be able to resolve both transmission security constraints and provide flexibility value to the grid, the report argues.

The report highlights how CAISO oversaw a process to replace the 165-MW Oakland gas plant that announced its retirement in 2016. The ISO picked Pacific Gas and Electric’s Oakland Clean Energy Initiative, which included some transmission upgrades, storage and demand response that met the need at a lower cost than transmission or generation solutions alone.

It also pointed to NYISO’s efforts to replace the dual-fuel Narrows and Gowanus plants that were slated for retirement this year. The plants are to be replaced by the Champlain Hudson Express Line to bring hydropower down from Quebec. That line is on track for an operation date of May 2026 but potentially could be delayed until 2027.

NYISO identified a short-term reliability need and issued a competitive solicitation for a solution, but none of the responses could solve it in time. Recently, NYISO said the peaker plants will still be needed for the next couple of years. (See related story, NYISO Reaffirms Need for NYC Peakers in Summer.)

“As electricity grids struggle to keep pace with the feverish growth in energy demand across the country, every electron of power counts,” Eolian COO Stephanie Smith said in a statement. “Battery energy storage helps both thermal and renewable energy technologies optimize their participation and increase reliability and resilience by providing power when and where it is needed quickly. By updating existing rules to account for new technologies, regional electricity markets can enhance grid performance and lower costs for consumers.”

April 10, 2025

NY Energy Summit: Patience Trumps Angst

ALBANY, N.Y. — Energy and transmission development in New York can be an exercise in patience and persistence, with supportive policy messages counterbalanced by complex regulations, high costs and long timelines.

The annual New York Energy Summit often is a showcase of this dichotomy, a chance to catch up on the latest developments in the Empire State and share thoughts on how to build on those changes or get around them.

The 2025 edition of the event could have been more of this, given the important policy decisions being hashed out a block away in the state Capitol. But they often seemed overshadowed by national developments — a brewing global trade war, trillion-dollar hourly swings in the financial markets and murmurs of a recession or stagflation bearing down on the U.S. economy.

Clearly the need to expand and modernize New York’s grid persists regardless of who is in the White House, and the timelines will extend beyond the term of any one president, or any three.

But as recent weeks have shown, a president can change the landscape markedly in much less than a single term — or even worse, shroud the landscape in a fog of uncertainty.

As New York Public Service Chair Rory Christian noted in a keynote address: “Difficult times lie ahead.”

“Inaction is not an option,” he said. “I encourage you to lean into this moment, not despite the uncertainty, but because of it.”

New York’s grid is like most others — it needs extensive and expensive modernization and expansion as it faces potentially huge load growth. The state also has some of the most ambitious plans in the nation to decarbonize the power portfolio feeding that grid, as well as some of the highest costs and most rigorous processes for carrying all these plans out.

Rapid-fire directives coming from the White House since Jan. 20 have made the prospect more daunting.

Inflation and interest rate fluctuations have created new financial risks, as have President Donald Trump’s repeated tariff threats. Previously committed grants and tax incentives remain under threat.

An executive order issued on Day 2 of the New York Energy Summit targets key policy decisions in climate-focused states and calls out New York by name.

State officials speaking at the Infocast event acknowledged the uncertainty facing everyone in the room but said it has not changed New York’s vision.

“If there’s one message to take away today it is that the state of New York is fully committed to our clean energy goals,” said Georges Sassine, vice president of large-scale renewables for the New York State Energy Research and Development Authority, which is leading the efforts to decarbonize the state, particularly its generation portfolio.

Christian heads the Department of Public Service, which leads regulatory efforts to put the infrastructure in place to accomplish these policy goals.

“[The goals] require, above all, a modernized grid,” Christian said. “We’re entering an era where our history of flat demand and flat load growth is no longer the norm. We’re in an era where need for interconnecting multiple resources in a short period of time is no longer a luxury but a necessity.”

Christian laid out some of the steps being taken toward this Grid of the Future, as the proceeding is named, and toward the flexibility needed to make it meet the needs at an affordable cost.

Like any long-running process with thousands of stakeholders, there is not unanimous agreement on the details, nor universal satisfaction with the pace.

The state has seen slow buildout of renewables in the nearly six years since passage of its landmark climate law mandated the transition, and multiple panelists said state regulators need to adjust their approach accordingly — fossil fuels will be needed longer than the state hoped.

Matt Schwall, director of regulatory affairs for Alpha Generation, said all six of his company’s plants in New York are operating with Title Five state air permits that are expired and awaiting renewal.

“And that’s not just unique to us; that’s every generator in the state. It’s tough to convince an investor to put money in the state when you don’t know if you can even get a permit.”

Independent Power Producers of New York President Gavin Donohue, whose members produce much of the state’s electricity, said reliability concerns are growing.

“The state needs to be realistic about what it takes to keep the lights on, on a day-to-day basis, and there needs to be a recognition that permits need to be issued in an effort to maintain that reliability,” he said.

NYISO Vice President of Market Structures Shaun Johnson said: “Particularly in some areas of the state, we have razor-thin margins. We, at the moment, don’t have a lot of flexibility to be able to ramp up new generation quickly and meet those future demand needs.”

The solution, he added, is not simple; it is a mix of load demand, market signals and state policy that will attract investors. “Because at the end of the day, they can choose — am I going to come to New York? Am I going to go to Virginia? Am I going to go to Texas? Where am I deploying my capital? And in some ways, we’re all competing against each other for that capital.”

New York has had some very visible problems adding generation — 88 renewable projects canceled their offtake contracts after cost escalations swept the industry in 2023. Those projects would have provided sizable progress toward the state’s clean energy goals and toward meeting the need for more gigawatts of capacity. The contracts are gone but the projects themselves are not necessarily dead, and the state will try to draw them and others back into its portfolio.

Sassine said more requests for proposals (RFPs) are in the works, along with requests for information (RFI) to shape those RFPs.

“We very much look forward in these RFI processes to get feedback from all stakeholders on how we should be thinking about risk-sharing, going forward in light of all this federal uncertainty,” he said.

The state-owned New York Power Authority has begun working in its new role as a renewables developer, and the vice president leading the effort, Vennela Yadhati, said renewables have a key advantage over the fossil fuel generation that suddenly is in favor in Washington: speed of deployment.

Multiple speakers at the summit noted the yearslong wait for a newly built gas turbine. Yadhati contrasted the relative speed with which solar and onshore wind generation are being built and cited the resilience those industries have developed.

“The renewables industry has been through administration changes in the past,” she said. “We have been through uncertainty in the past, but we continue to strive and thrive, actually, in this market.”

Marguerite Wells, executive director of Alliance for Clean Energy New York, placed some of the onus for moving ahead on the renewable energy developers themselves.

Some developers, she said, have submitted “tire kicker” proposals they were not fully committed to, contributing to the sluggish nature of the NYISO interconnection queue, and others have cut corners on their community outreach efforts — a potentially serious mistake in a home-rule state where local opinion can slow or block a proposal.

As the level of public opposition and concern around projects and politicization of renewables grows, it is more and more incumbent on developers “to do a better and better job with community relations and stakeholder work,” Wells said. “I think that often gets short shrift.”

New York’s infamously slow timelines, she added, are getting better, through the state’s streamlined regulatory processes and through NYISO’s newly revamped interconnection process.

“I think we can see that the new process is doing what it’s supposed to do,” Wells said. “It’s painful to go through it now. It’s much more expensive and it’s faster, and it’s more technically challenging to get all that work done in a shorter period of time. But the end goal is to have an interconnection process that more similarly mimics what Texas has done, which is get a project through in a year or two. Used to be five to seven in New York, and that’s not necessary.”

U.S. Rep. Daniel Goldman (D) conceded that his opinions hold no sway with Trump and that he is worried about the fate of renewable projects both present and future.

But he said the country’s need for electricity and the benefits renewables have provided for red congressional districts will be more influential than the opinions of a congressman representing a deep-blue New York City district.

Goldman urged listeners to stick with the approach that most of the renewable energy community seems to have adopted the day after Election Day, emphasizing the good of the nation rather than the good of the planet.

“Let’s set aside the climate benefits as we are making this case right now, because the economic and national security case for clean energy is stronger than ever.”

He added: “We absolutely cannot give up with this administration — even if those wind turbines are unattractive.”

Sergio Garcia, executive director of project finance at Rabobank, counseled patience and a longer view. Financial planning is difficult until budget and policy negotiations produce a firm picture of the tax incentives that grew from the Inflation Reduction Act.

“Right now, we’re all distracted with the IRA,” he said. “It’ll change — in what form, I have no clue. Until we have visibility in there, it makes your jobs a lot harder, because you need to deploy capital.”

Garcia added: “It’s a reality check, right? It did work before the IRA, and it’ll work again in one form or another, and renewables will continue to strive because it is the lowest levelized cost of energy. So I think there’s plenty to do. I think that banks are all active, and we’re all like looking for projects to finance.”

April 10, 2025April 10, 2025

Texas Loan Program Loses 2 More Gas Projects

Texas’ loan program for gas generation has lost two more projects, marking the third and fourth companies to withdraw projects from the due diligence review process.

Constellation and WattBridge became the latest to pull projects from the Public Utility Commission’s In-ERCOT Generation Loan Program, part of its Texas Energy Program. The companies took out four projects totaling 1,410 MW.

The 16 remaining applications total 8,346 MW of capacity and $4.46 billion in requested loan amounts. The TEF is a $5 billion, low-interest program designed by lawmakers to quickly add new natural gas plants.

PUC spokesperson Ellie Breed said staff intend to advance additional applications to the due diligence phase at a future open meeting.

Constellation was seeking financing for 300 MW of gas-fired generation at its Wolf Hollow III facility. It told the PUC in March it was unable to determine “with certainty” the project’s overall costs because of the “uncertain timing” in receiving an air permit from the Texas Commission on Environmental Quality. That would prevent Constellation from signing a binding loan document.

Wattbridge withdrew three projects totaling 1,110 MW of capacity. It said the TEF’s financing terms “introduce risk and costs that result in lower than anticipated returns with elevated risks.”

The company also said it was withdrawing a 510-MW project in the Houston region from the pool of remaining applicants.

Two other companies pulled their projects from the TEF earlier in 2025. They cited supply chain issues as delaying the projects and keeping them from meeting a December 2025 deadline for initial loan disbursements. (See 2 Companies Withdraw Texas Energy Fund Projects from Consideration.)

More than 4,650 MW of capacity has been withdrawn or denied from the original submitted applications. Nearly a third (3,903 MW of 12,249 MW) of the projects that advanced to due diligence now have been withdrawn or denied.

“Texas will get new gas resources … but gas plants take time,” noted Stoic Energy principal Doug Lewin in his newsletter. “They can’t be developed fast enough to ensure reliability or allow for economic growth in the next three or four years, and possibly longer than that.”

Kristi Hobbs, ERCOT’s vice president of system planning and weatherization, told board members April 7 that all 16 Texas Energy Fund projects recommended for due diligence by the PUC have submitted full interconnection study (FIS) applications with the ISO and are in various phases of the generation-interconnection process. Seven applicants have completed the full study processes.

“Moving forward, a lot of progress on those,” Hobbs told the board.

The TEF was created by the Texas Legislature in 2023 to add more dispatchable generation to the grid and was approved by voters later that year. Managed by the PUC, it is designed to provide grants and loans to finance construction, maintenance, modernization and operation of electric facilities in the state.

The fund is composed of four programs: In-ERCOT Generation Loans, In-ERCOT Completion Bonus Grants, Outside-ERCOT Grants and Texas Backup Power Package.