The Union of Concerned Scientists released a paper Oct. 15 arguing the electric industry should focus on expanding renewable energy aided with storage rather than keeping natural gas plants running with hydrogen, biomethane or carbon capture and storage (CCS).
“Beyond the Smokestack: Assessing the Impacts of Approaches to Cutting Gas Plant Pollution” noted that gas plants are the largest source of carbon dioxide emissions produced by the electric industry.
“Every path to addressing our nation’s climate commitments and public health priorities calls for a cleaned-up power sector — and that makes reducing CO2 and other harmful emissions from gas plants an urgent priority,” the scientists group said in its paper.
CO2 emissions from power plants are just one way gas plants exacerbate climate change, according to the report, which notes that natural gas itself – methane – is a more potent greenhouse gas, trapping 28 times more heat over 100 years than carbon.
Co-firing hydrogen can cut smokestack emissions, but how the hydrogen is produced has major impacts on the emissions created and can lead to higher emissions than just burning methane, the report said. And because hydrogen is less energy dense than methane, three times as much of it must be burned to produce the same amount of electricity.
“Hydrogen production is energy intensive, making its production method a major factor in determining the overall change in carbon emissions from using hydrogen in gas plants,” the paper said. “Virtually all hydrogen used in the United States today — overwhelmingly for petroleum refining and in the chemicals industry — is produced via steam methane reforming (SMR), the main byproduct of which is CO2.”
That so-called gray hydrogen is not what the industry, or DOE hubs, are trying to promote. They’re pushing so-called blue or green hydrogen, which can be produced via CCS or from water using electrolyzers — though they must be run with zero-carbon power to achieve a carbon-free “green” hydrogen. Even green hydrogen comes with built-in inefficiencies compared to just using renewable electricity directly, according to the report.
“Producing hydrogen by using solar or wind energy to power an electrolyzer with a typical efficiency of 75% and then using that hydrogen in a gas power plant with an efficiency of 45% would result in only one-third as much electricity as that originally supplied by the renewable sources,” the report said. “That is, it would take three times as many wind turbines or solar panels to supply the same amount of electricity via hydrogen blending as from wind or solar directly.”
Hydrogen can be stored but is less efficient than technologies that store electricity outright. It could make sense if other options to capture and store electricity do not work, or in a system that has enough excess renewable electricity to make hydrogen, according to the report, which concluded that direct use of renewable power has a much bigger impact on cutting emissions.
Another option for cleaner gas plants is to keep burning the fuel with a CCS system, an approach the paper claims does not address upstream emissions of methane and introduces other challenges.
“Any CO2 leaking from the pipelines, or the storage would undo the carbon capture effort, at least in part,” the paper said. “Over time, CO2 can slowly leak into the atmosphere if storage reservoirs are not carefully monitored; abandoned oil and gas wells intersecting with CO2 storage sites also increase the risk of leakage.”
CCS technology requires energy to work, and it can take away between 10 to 20% of the electricity produced at the plant, according to the paper, which concluded would exacerbate upstream emissions. The third option cited by the paper is “biomethane” or “renewable natural gas.” It is produced from the anaerobic breakdown of organic matter such as manure, sewage or landfill waste. Smokestack emissions when it is burned are the same, but it avoids emissions in production of the fuel.
The assumption that CO2 produced at the smokestack has a lower climate impact than just venting methane from a farm or dump “is not reasonable in a net-zero framework, where every source of pollution counts; with the United States committed to achieving a net-zero economy by 2050, there is no credibility to a baseline assumption of unmitigated methane venting,” the paper said. “Instead, if biomethane can be captured for use, at minimum, the appropriate baseline climate comparison is flaring, such as is now required at certain regulated landfills.”
It would make more sense, according to the report, to compare biomethane to the best alternative for the climate, which would be to avoid those initial methane emissions through climate-smart farming techniques or avoiding organic waste in landfills.
The West-Wide Governance Pathways Initiative has revised its “regional organization” stakeholder process proposal to expand the size of a key stakeholder committee and boost representation for some groups.
The revision also provides more detail about the makeup and functioning of the Stakeholder Representatives Committee (SRC), among other changes.
“The Launch Committee’s recommendations regarding sectors and sector representatives are intended to promote the goals of the SRC and recognize the uniquely diverse stakeholder community that has a vested interest in the RO,” the committee wrote in the revised proposal. “It is also intended to ensure robust dialogue and guard against changes to the market that would decrease efficiency, result in any market manipulation practices and negatively impact benefits to customers.”
The revised plan would increase the number of seats on the RO’s proposed SRC from 16 to 19. More specifically, it bumps up the number of SRC representatives from the Extended Day-Ahead Market (EDAM) Entities sector (from one to two), the Western Energy Imbalance Market (WEIM) Entities sector (from two to three) and the sector representing non-investor-owned utilities serving load from the EDAM or WEIM (three to four).
The Launch Committee said it proposed to increase the number of seats for the WEIM Entities sector to reflect the size of the WEIM, which has 20 participants.
“The three SRC representatives are intended to provide the flexibility to ensure that both public power and IOUs have representation, as well as enable geographically diverse representation from the Northwest, [the] Desert Southwest and California,” the committee wrote.
The committee’s proposal to increase the number of non-IOU seats on the SRC was intended “to ensure the unique voices of public power, municipal utilities, cooperatives and community choice aggregations are represented. However, if an entity participates collectively through an EDAM entity (e.g. BANC members), they cannot also participate in a different sector as individual entities (i.e., generators or [municipal utilities]).”
The revised proposal also clarifies definitions of the nine SRC sectors set out in the original proposal.
For example, it draws from CAISO’s tariff to clarify the definition of an EDAM entity as being a balancing authority “that represents one or more EDAM Transmission Service Providers and that enters into an EDAM Entity Agreement with the CAISO to enable the operation of the Day-Ahead and Real-Time Markets in its Balancing Authority Area.”
Similarly, a WEIM entity is described as a BA “that represents one or more WEIM Transmission Service Providers and that enters into an WEIM Entity Agreement.”
According to the proposal, EDAM and WEIM entities can be investor-owned utilities, federal power marketing agencies or publicly owned utilities.
The revised plan also removes the reservation of SRC seats for independent power producers (IPPs) and marketers in the sector shared among IPPs, marketers and independent transmission developers — which continues to hold three seats.
Other Changes
The revised proposal additionally recommends creating the roles of an SRC chair and vice-chair to “serve as the primary point of contact with the RO staff and provide administrative leadership for organizing the SRC” but “not have any decision making or enhanced authority.” The stakeholders filling each role must be from different sectors.
The positions would rotate yearly and be selected by the SRC, with each sector casting a single vote.
The proposal also calls for limiting SRC membership to “market participants” (those with a direct stake in the EDAM or WEIM) but recommends creating another stakeholder category of “other load-serving non-market participants” who would sit outside the SRC. That arrangement would allow “people or organizations who do not participate in the WEIM or EDAM and therefore do not fit within one of the designated sectors” to register with the RO to offer a nonbinding vote on issues before the SRC.
“The votes will not count toward an SRC recommendation [to the RO board] or remand threshold but will be shared with the RO staff and Board for information only. This group of individuals or organizations may participate in the stakeholder process and submit comments that will be included in the package of information that goes to the RO staff and/or board when appropriate,” the proposal said.
The Launch Committee also calls for a reevaluation of the SRC sectors and structure at two points in the future: during implementation of the RO and two years later.
“Reevaluation could include both consolidation of sectors and reorganization of sectors to reflect necessary changes based on meeting the goals. It should also consider whether it successfully prevents sector shopping and astro-turfing, and whether it creates the right balance across sectors for achieving the market goals,” the proposal said.
The revised proposal also recommends removing a provision in the original plan that would trigger an “automatic remand” of an RO initiative back to the stakeholder process if voting on the proposal shows “significant opposition” among stakeholders. That’s defined as a lack of support from a simple majority of sectors or one-third of SRC sectors registering at least 70% of their members voting in opposition.
“We recommend removing the automatic remand but still using the ‘significant opposition’ thresholds to trigger additional discussion at the SRC about whether remanding back to the stakeholders would be beneficial to the process and the initiative,” the Launch Committee wrote.
The committee is seeking comments on the sector proposal until Oct. 25.
ARLINGTON, Va. ― Order 1920 was a “big lift” for FERC, recalled Liz Salerno, who was lead adviser to former FERC Chair Richard Glick when work on the transmission planning order started in 2021.
“You know, this rule went from an [advanced notice of proposed rulemaking], which was just hundreds of pages of hundreds of questions, open-ended questions, of FERC trying to figure this out, to a detailed proposed rule to a final rule in three years,” said Salerno, who now is a principal with industry consultants GQS New Energy Strategies. “That is lightning speed for a regulatory body.”
FERC’s rule on long-term transmission planning was, predictably, a recurring theme at the American Council on Renewable Energy’s (ACORE) Grid Forum on Oct. 10. But while calling the order a big step forward, Salerno and other speakers urged broad and ongoing industry engagement, stressing that compliance and implementation of 1920 likely would take even longer and prove more challenging for the commission, grid operators, utilities and developers.
Industry stakeholders have estimated it may take five to 10 years for the order to have any major effects on transmission planning in the U.S.
Order 1920 is “not a ‘set it and forget it’ type of thing,” Salerno said. “It doesn’t dictate outcomes. It is a framework; it is rules of the road.”
Much work remains, she told the forum. “There are still folks who don’t want transmission to be built,” she said. “They like the status quo. They’re going to be there … voicing their opinion, and so you need to be there, making sure this thing gets implemented.”
Approved in May with a 2-1 vote, Order 1920 requires RTOs and ISOs to undertake long-term transmission planning ― with a 20-year time frame ― taking into account anticipated load growth, state laws and generation retirements, while also looking at seven core benefits of new transmission, such as cost savings and fewer outages. The long-term plans must be updated every five years. (See FERC Issues Transmission Rule Without ROFR Changes, Christie’s Vote.)
The order also calls for grid operators to open a six-month process to allow states to develop new cost allocation methodologies or adopt one or more “ex ante,” or default, methods for cost allocation filed prior to any selection of projects.
The order has triggered dozens of requests for rehearings, which FERC is considering. Eleven legal challenges have been filed across the country but recently were consolidated to the 4th Circuit U.S. Court of Appeals in Richmond. (See FERC Order 1920 Sees Wide-ranging Rehearing Requests) .
Since 1920 was approved, former Commissioner Allison Clements has left FERC, and three new commissioners have come on board, including David Rosner, who also weighed in on the order during an onstage conversation with ACORE CEO Ray Long. Rosner said he will look for ways to “turn down the temperature ― the political temperature that some people think this rule is taking ― in ways that are directionally consistent with what the rule is trying to do, which I firmly believe … is [that] we’ve got to find ways to build needed transmission.”
Drawing on his experience as an energy industry analyst at FERC and as an adviser to the Senate Energy and Natural Resources Committee, Rosner described himself as “an energy nerd.”
“Like I live in the dockets,” he said. “And what that means is, I still read the orders. I read the comments. That helps us to get to good decisions.”
Industry comments are “foundational” in the commission’s decision making, Rosner said.
While providing no details on FERC’s pending decision on a 1920 rehearing, Rosner was “hopeful that there are a number of things in that record that we can do that achieve those goals, and I am also hopeful that we can work with all five commissioners and ideally get a 5-0 [vote].”
Successful implementation, he said, would ensure “that all resources on the grid can provide all the services that they’re technically capable of driving.”
Considering GETs
But Abdul Ardate, director of transmission and interconnection for developer EDP Renewables, said 1920 may not provide the kind of certainty that is a top priority for his company and others in the industry.
The requirement for long-term plans to be re-evaluated every five years “is a double-edged sword because some [projects] could potentially get stuck in re-evaluations every five years, [so] that nothing can get built,” Ardate said.
He pointed to projects EDP has seen utilities or RTOs repeatedly re-evaluate and redesign at escalating costs, with one project going from $3 million to $8.5 million to more than $60 million, with nothing yet built. The cost to customers for the resulting grid congestion and “generation that cannot deliver its energy is just tremendous,” he said.
Ardate was also skeptical of 1920’s provisions calling on RTOs to “consider” grid-enhancing technologies ― such as dynamic line ratings or advanced conductors ― that can increase capacity on existing lines to provide short-term upgrades while longer-term transmission projects are planned.
“I don’t think the language is strong enough to require them to include grid-enhancing technology, not just consider, because I think that’s too loose a definition,” he said. “I don’t think this is going to push the needle on anything short-term in terms of implementing any grid-enhancing technologies.”
Karin Herzfeld, senior transmission counsel to FERC Chairman Willie Phillips, countered that 1920 does “include a requirement for the transmission provider to justify its decision and to be transparent about that decision. So, I do think that component will provide some incentive or give stakeholders some confidence that they have actually reviewed and considered to see whether a grid-enhancing technology might be appropriate.”
The catch here is the amount of discretion the rule gives operators to decide what projects or technologies may be appropriate for their systems and to reopen consideration of individual projects every five years, Salerno said. “There is no requirement in this rule to select anything; that is up to the discretion of the transmission provider.
“That cuts both ways,” she said. “That means there’s no guarantee for any of us that transmission is going to get built … which again goes back to why you have to engage and make sure that this is a good process, and there is a likelihood of selection.”
“We can do all the planning; we can look at all the benefits, all the requirements, but then ultimately it’s up to the states to decide which project is going to get selected or built, or how it’s going to be cost-allocated as well,” Ardate said. “We have to get active on the state level, the public utility commission level, the Department of Energy, even on the FERC level to make sure that we get our voices heard.”
Win a Little, Lose a Little
Cost allocation has long been a major challenge ― if not an outright deal killer ― for some interregional transmission, and both Herzfeld and Salerno emphasized the importance of 1920’s requirement that states hold a six-month engagement period to determine whether they will use a grid operator’s default methodology or come up with one of their own.
They can also opt for a state agreement approach, “by which they can punt a project that gets selected to a future cost allocation,” Herzfeld said. “They can punt it to their future selves to decide cost allocation voluntarily.”
Salerno said the default methodology ensures that once a project has been selected as part of a long-term plan, “there’s a cost allocation method waiting for them. There is no additional work to be done.
“This is going to make sure we don’t have a world where great projects get planned and get through the selection process because they have great benefits and then they go nowhere because no one can agree on cost allocation,” she said.
On the other end, the six-month engagement period could help circumvent permitting challenges, she said. “Giving some control back to the states to let them decide how [a project] gets paid for is critical to bringing them to the table and getting them comfortable and happy with the project, so maybe [it] smooths out the process on the back end with permitting.”
Herzfeld agreed the ex-ante provision will “just absolutely make sure that transmission will be built” and prevent a project from stalling should a single state hold out on cost allocation.
“Everyone always wins a little and loses a little” in cost negotiations, she said. But “when there’s nothing to kick in as a default, everyone wants to win a lot and lose nothing.”
Thinking Outside the Box
Rosner’s appearance at the ACORE forum was his second on Oct. 10, following an early morning on-stage conversation with Jason Grumet, CEO of the American Clean Power Association, at an ACP event. (See FERC’s Rosner Talks Priorities at American Clean Power Association.)
Repeating some of the key points from his ACP appearance, Rosner said job one for FERC is managing the U.S. energy transition, which “means a lot of different things. It [means] where we have markets, be smart. Let’s make sure those markets are sending the right signals to get the investments, the technologies or the attributes that the system needs to be reliable.”
Interconnection is another top concern for Rosner, who pointed to FERC’s Order 2023 on interconnection, passed in 2023, and, like 1920, “will take many more years to get compliance with it and get it working,” he said.
At the same time, Rosner said, “I am very open to thinking outside the box about what other things can speed that up,” such as the use of artificial intelligence to cut the time needed for interconnection studies.
“Anything we can do to move those studies faster is going to help us get through those queues faster, and if it’s something we don’t have to write a regulation on … I’m like all in on that. So, I want to learn more.”
ERCOT and the Public Utility Commission of Texas have knocked down recent media reports that a proposed HVDC transmission link between Texas and its Louisiana and Mississippi neighbors will bring the state’s grid under FERC jurisdiction.
Speaking to the ISO’s Board of Directors Oct. 10, ERCOT CEO Pablo Vegas said news coverage of the U.S. Department of Energy’s plan to invest up to $1.5 billion in four transmission projects, including Pattern Energy’s Southern Spirit Transmission 525-kV link eastward, “made it sound like there had been some substantive change in the policy around interconnecting the ERCOT grid to other grids in the United States.” (See DOE Funding 4 Large Tx Projects, Releases National Tx Planning Study.)
“That’s not the case. That is not what has occurred with this recent announcement, nor with the underlying drivers for this project,” Vegas told directors.
Texas has long resisted federal oversight of the ERCOT grid by not mixing its electrons with those of the Eastern and Western Interconnections. It does have four DC ties with neighboring grids, two with SPP and two with the Mexican system, totaling about 1,220 MW of capacity.
One of the links to Mexico is through a variable frequency transformer with a control system that operates like a generator, but it is not a synchronous tie, Vegas said.
Several news stories following the DOE announcement implied that ERCOT soon would be connected to the Eastern Interconnection for the first time. A headline from the EV news site Electrek, “Hell froze over in Texas – the state will connect to the US grid for the first time via a fed grant,” drew most of the attention.
PUC Chair Thomas Gleeson said inquiries from a politician or two prompted him to issue a statement Oct. 4, the day after the DOE announcement.
“While the Southern Spirit Transmission line would cross multiple state lines, the Texas grid will remain independent from the national grid and would not be subject to any federal oversight,” he said.
Gleeson, like Vegas, noted ERCOT already has the four DC ties with its neighbors. “They do not have any impact on the independence of the Texas grid,” he said.
Southern Spirit, a merchant transmission line more than a decade in the making, would provide a 320-mile, HVDC link from Texas capable of carrying 3 GW of power either way. While it was originally designed to move renewable energy to the Southeast, some reports have framed the project as saving Texas should there ever be a repeat of the 2021 winter storm that almost brought down the ERCOT grid.
DC ties approved under Sections 210 and 211 of the Federal Power Act do not pose a risk to ERCOT’s independence, Vegas said. FERC says the Texas grid is not jurisdictional because it is not synchronously connected to the other two interconnections and thus its power sales are not considered interstate commerce and not subject to oversight.
Vegas said the 19 switchable units that can provide about 4 GW of power to either ERCOT or the Eastern Interconnection are “an incredible asset to us,” offering them as an alternative to DC ties.
“DC ties could [solve the reliability problem], but I think they need to be fairly evaluated from all of these factors to really understand what is the best investment for the ERCOT consumers when it comes to investing in reliability and the economic potential of more infrastructure,” he said.
FERC approved the Southern Spirit project, previously named Southern Cross, in 2014. The Texas PUC followed suit in 2017, approving Garland Power & Light’s application for a permit to build a 38-mile, 345-kV line connecting ERCOT to a Pattern Energy DC converter station in the Eastern Interconnection.
The PUC also established 14 tasks, or directives, for ERCOT to complete in accommodating Southern Spirit. The commission closed the project in 2022, saying it agreed with the ISO’s solutions.
The project got a major boost in August when the Louisiana Public Service Commission approved it, 3-2. However, that also opened an appeals window from landowners and lawmakers who have opposed the project. Mississippi regulators have not yet signed off on the project.
If Southern Spirit is fully approved, Pattern Energy says it would begin construction in 2026 and enter commercial operation in 2029. The company plans to invest $2.6 billion in Southern Spirit, which is eligible for up to $360 million in DOE financing support.
Another set of proposed changes to NERC’s Rules of Procedure is before FERC, after the ERO filed them with the commission Oct. 14 (RR25-1).
The revisions are directed at Appendix 4E of the ROP, which governs the procedures for hearings by the ERO’s Compliance and Certification Committee, appeal hearings, and mediation. NERC has been developing these changes for the past two years, after the CCC first approved revising Appendix 4E at a meeting in April 2022. The ERO’s Board of Trustees approved the revisions at its open meeting in August.
According to the CCC’s charter, “the CCC serves as a hearing body in matters when NERC … directly monitors [power grid] owners, operators and users for compliance with reliability standards.” The committee also serves as a mediator for “disagreements and disputes between NERC and the regional entities concerning NERC performance audits of [REs’] compliance programs,” as directed by NERC’s Board of Trustees, and hears appeals from REs challenging NERC noncompliance findings and related penalties.
Regarding the last point, NERC’s proposed revisions would remove references to REs challenging noncompliance findings, on the basis that there are no longer any REs “complying with NERC reliability standards.” This reflects the elimination of the ERO’s “Regional Reliability Organization” function for registered entities, along with the Reliability Coordinator function that some REs possessed, a spokesperson told ERO Insider.
They also would insert a footnote clarifying that hearings involving the CCC “are likely to be extremely limited” because there are no standards applicable to REs, and that NERC probably never will have to directly monitor compliance by registered entities itself due to lack of an RE in their area.
The next category of revisions relates to the CCC’s procedures for hearing appeals of certification matters. NERC said these changes are intended to maintain consistency with the previous category and other hearing procedures in the ROP, and to update language that has remained unchanged since this passage originally was approved in 2010.
Finally, NERC proposed updating the section of Appendix 4E relating to the CCC’s mediation procedures to “clarify which CCC members are eligible to serve as mediators.” The revisions specify that only committee members who “are disinterested parties,” have not worked in the territory of the RE involved in the dispute and have no other conflicts can serve. In addition, potential mediators would be required to attend a training course.
NERC has been active in revising its ROP in recent years, with FERC approving multiple changes in the past 12 months. First, the commission accepted a set of revisions last November intended to streamline the ERO’s standard development process and allow a faster response to emerging issues by granting NERC’s board the authority to direct the development of a new or revised standard when the board feels it is necessary to maintain grid reliability, bypassing the normal stakeholder comment process. (See FERC Approves NERC Standards Process Changes.)
Additional changes followed in June, with FERC accepting NERC’s proposed revisions that would allow the ERO to register owners and operators of inverter-based resources. The commission also dropped its proposal to require NERC to submit performance assessments every three years, rather than every five years as currently required. (See FERC Accepts NERC ROP Changes, Drops Assessment Proposal.)
NERC is seeking comments from industry stakeholders through Nov. 25 on a proposal to expand the categories of information collected in the Transmission Availability Data System (TADS) to improve the ERO’s understanding of load loss.
The comment request was filed under Section 1600 of NERC’s Rules of Procedure, which grants the ERO the power to request data from registered entities “that is necessary to meet its obligations under Section 215 of the Federal Power Act.” Section 1600 data requests must be reviewed by FERC, posted for public comment, and reviewed by NERC’s Board of Trustees before they take effect.
FERC reviewed the request in September, according to background information provided on NERC’s website. After the public comment period concludes in November, NERC staff will respond to comments and complete any necessary revisions before submitting the final proposal to NERC’s board at its open meeting in February. The ERO hopes to implement the changes to TADS by Jan. 1, 2026.
Under the proposal, three items would be added to TADS reporting:
load-loss data resulting from transmission system outages.
geographical data for TADS elements.
equipment sub-cause codes to supplement existing cause codes.
NERC said it uses load-loss data “voluntarily collected by the IEEE Distribution Reliability Working Group for its analysis.” However, the organization is concerned about the completeness of this voluntarily provided data and its ability to fully represent an interconnection. In addition, the presence of a third party in the data-collection chain complicates the process of tying load-loss information to events.
The changes should allow the ERO to incorporate more complete load-loss information in the annual State of Reliability (SOR) report and identify transmission system elements involved in specific events through the addition of geographical data, NERC said. Equipment sub-cause codes also will give the ERO better information about the failure rates of specific equipment types, recommend more specific measures to prevent outages and identify trends for the SOR and other studies.
The data request will apply to all registered transmission owners (TO) that own either overhead or underground AC and DC circuits, transformers with a secondary voltage of at least 100 kV and AC/DC back-to-back converters. As with existing TADS data requests, information will be due 45 days after the end of each calendar quarter.
In their comments, NERC is asking applicable TOs to respond to the following:
whether they collect data on load loss, geographical location and equipment sub-cause codes for operation of their transmission systems.
whether the data requested is reasonable and obtainable.
whether the implementation schedule for the request is reasonable.
NERC emphasized that answers to these questions are not required but “would be appreciated.” Respondents also are free to provide any other comments they would like regarding the data request. Stakeholders must email their responses to NERC, using the comment matrix form on the Section 1600 website.
When Arizona utilities file their next integrated resource plans, they’ll be required to include an analysis of cost savings and other benefits they could realize from Western regional market participation.
And starting Nov. 1, utilities must report to regulators at least twice a year on their activities related to joining a day-ahead market.
The Arizona Corporation Commission voted Oct. 8 to approve an order acknowledging IRPs filed last year by Arizona Public Service (APS), Tucson Electric Power (TEP) and UNS Electric (UNSE). But as part of the approval, commissioners adopted a slew of amendments that create new requirements for future IRPs. The utilities’ next IRPs will be due in 2026.
One of the approved amendments, from Commissioner Nick Myers, requires utilities to include in their next IRPs an analysis of cost savings and other benefits resulting from regional market participation. The analysis will show the impact of market participation on utilities’ portfolio development, reserve margin, resource adequacy, reliability during extreme weather events, transmission planning and capacity needs.
APS and TEP are members of CAISO’s Western Energy Imbalance Market (WEIM) and are weighing the choice of two day-ahead markets: CAISO’s Extended Day-Ahead Market (EDAM) and SPP’s Markets+.
“Most of our utilities might even be participating already in those markets by the time the next IRP is due,” Myers said during the meeting. “But I would love to see the analysis of how it’s affecting them at that point in time and, if they’re not in the market, how they think it will.”
Myers said his amendment was in response to stakeholder requests for a market analysis in future IRPs.
Semiannual Reporting
An approved amendment from Commissioner Lea Marquez Peterson also addressed regional market participation.
It directs utilities to include in their future IRPs portfolios that capture the benefits of joining a day-ahead market. For their preferred portfolios, utilities must state their market enrollment assumptions.
Marquez Peterson’s amendment also will require utilities to report on their day-ahead market activities semiannually, including “metrics and other decision-making elements.”
The amendment had the support of stakeholders including Western Resource Advocates (WRA).
“If we are going to decide to go into EDAM or we’re going to decide to go into Markets+, how are we making that evaluation?” Alex Routhier, WRA’s senior policy adviser in Arizona, said during the meeting. “What metrics are we using … and what benefits do we expect to capture?”
APS and TEP have participated in the development of EDAM and Markets+. UNSE joined WEIM in 2022 through participation with TEP, which acts as its balancing authority. UNSE also has worked with TEP on day-ahead market development.
Another Arizona utility, Salt River Project (SRP), has been involved in day-ahead market development but is not regulated by the Arizona Corporation Commission.
Coal Plant Closures
The integrated resource plans show how the utilities plan to meet their customers’ energy needs over the next 15 years. The IRPs are updated every three years.
The utilities forecast growing demand and at the same time are planning for the retirement of coal-fired power plants. APS pledged in its 2023 IRP to exit by 2031 from the coal-fired Four Corners plant, which it operates and partly owns.
TEP owns and operates Units 1 and 2 at the coal-fired Springerville Generating Station and owns 7% of Four Corners Units 4 and 5.
An amendment that commissioners adopted Oct. 8 requires APS to show in future IRPs that it has a “sufficient dependable and dispatchable capacity” to ensure resource adequacy before it exits Four Corners, where the utility has 970 MW of capacity.
The amendment from Myers and Commissioner Kevin Thompson also requires an annual progress report from APS, starting on Aug. 1, 2025, on ensuring resource adequacy in 2031.
The amendment initially said the dependable capacity it calls for should not include battery storage.
But Thompson said during the commission meeting that the battery-storage restriction was dropped. He noted that technology is rapidly advancing and the commission should be consistent in applying its philosophy of being technology- and generation-neutral.
“I don’t want to micromanage APS’ decision as they deploy new generation,” Thompson said.
The suspension of ISO-NE‘s Order 2023 implementation due to FERC‘s inaction has caused uncertainty and stress for some clean energy developers in New England, who worry a significant delay in the rollout of the new interconnection process could slow the rapid deployment of renewables needed to meet state clean energy goals.
When ISO-NE submitted its compliance package for FERC Order 2023 in May, it received significant support from clean energy associations, who praised the RTO for its “extremely robust stakeholder engagement” and willingness to consider and adopt amendments to its proposal. (See Clean Energy Groups Respond to ISO-NE Order 2023 Filing.)
But the compliance proposal depended in part on quick approval from FERC, requesting an Aug. 12 effective date.
While the New England grid is dominated by natural gas generation, ISO-NE’s interconnection queue almost entirely consists of solar, wind and storage resources, making reforms to the queue to address backlogs a key component of the clean energy transition.
With Order 2023, FERC aims to streamline and add certainty to the interconnection processes, requiring grid operators to evaluate interconnection requests using group studies with pre-determined timelines.
But in the short term, with ISO-NE’s requested effective date long past, the RTO and project developers remain in the dark regarding when FERC will rule on the filing and whether this ruling will require more work. ISO-NE’s effort to comply with the order has been on pause since early September. (See With FERC Inaction, ISO-NE Delays Order 2023 Implementation.)
“We really need FERC to act on this and issue an order to limit the damage,” said Alex Lawton of Advanced Energy United. “The uncertainty is the biggest killer here.”
The ISO-NE queue has been closed since mid-June and is unlikely to open to new interconnection requests until at least fall 2025. According to the RTO’s proposal, only projects that already have submitted a validated interconnection request would be able to take part in the initial “transitional” cluster study.
Despite the cutoff on new interconnection requests, a large group of projects already are eligible to participate in the transitional cluster. According to ISO-NE, 118 projects are eligible for the cluster, totaling more than 40,000 MW in nameplate capacity.
ISO-NE initially planned to begin the transitional cluster study Oct. 11, but it rescinded the study agreements in September due to FERC’s inaction. As proposed, the transitional cluster study process would take nearly a year from when ISO-NE issues cluster study agreements to the final cluster study report.
Delaying the start of the transitional cluster likely also will delay the start of the subsequent cluster study, which would open after the end of the transitional process. Even if FERC rules relatively soon, the commission could require significant changes to the compliance proposal that further delay the start of the transitional cluster study.
Ada Statler, associate attorney at Earthjustice’s clean energy program, said a short delay is not necessarily a huge deal, but “the cascade effect on the queue is really concerning.”
While imminent FERC action is essential, ISO-NE should conduct a “careful examination” of the work they can do to move interconnection along during the delay, Statler said. She also expressed her hope that ISO-NE will communicate with stakeholders as much as possible to minimize negative impacts of the delay.
Along with the direct delay on the start of the cluster studies, the confusion regarding timelines and what additional work FERC may require is a major challenge, said one battery developer. They added that the delay has caused significant uncertainty for a group of projects that have already signed interconnection agreements but were relying on a supplemental process included in ISO-NE’s filing to qualify for capacity reconfiguration auctions.
An extended delay, however, could help some developers who have projects in the late stages of interconnection under the current rules.
“The ISO is continuing to negotiate interconnection agreements for projects with completed system impact studies and, until such time as the Order No. 2023 rules are in effect, will tender a draft interconnection agreement under the current tariff to any project that receives a final system impact study report and chooses to forgo a facilities study,” said ISO-NE spokesperson Mary Cate Colapietro.
That means some projects could avoid needing to enter the transitional cluster, potentially saving them time and money.
“The suspension will be a problem for many stakeholders, but not all; some projects, both at the transmission scale and distribution scale, will be hoping that a delay allows studies in progress to complete and that the final order respects the studies,” said Aidan Foley of Glenvale Solar.
Whether a project can reach an interconnection agreement prior to the start of the transitional cluster study could have a major impact on its development timeline.
In late August, GDQ, the developer of a 203-MW battery project in Rhode Island, wrote in a petition to FERC that requiring the project to enter the transitional cluster “may cause delays in excess of a year and certainly would delay the execution of an interconnection agreement until no sooner than August 2025 (ER24-2926).”
The delay also has created uncertainty for state-jurisdictional resources looking to connect to the distribution grid. ISO-NE has initiated changes to its planning procedures to coordinate affected system operator (ASO) studies with cluster studies, creating set windows for ASO reviews.
“With the suspension of Order 2023 implementation, DG [distributed generation] interconnecting facilities are left without regulatory certainty of whether ASO studies will commence during the suspension period and, if commenced, whether those studies will be required to restart upon the resumption of the transitional cluster study process,” said Kate Tohme, director of interconnection policy at New Leaf Energy.
“This uncertainty leaves DG interconnecting customers across New England at risk of loss of project viability and is a deterrent to continued DG development within the region,” Tohme added.
ISO-NE has said it “will continue ASO study coordination according to current rules and practices until receiving and evaluating an order from the commission on the compliance proposal.”
VALLEY FORGE, Pa. — The annual winter study conducted by the Operations Assessment Task Force (OATF) found no identified reliability risks for the 2024/25 season, PJM’s Mark Dettrey told the Operating Committee.
The study will be presented in full during the OC’s Nov. 8 meeting and includes a detailed power flow analysis to determine whether conditions such as the largest gas contingency or low/no renewable output could prompt a reliability emergency. While no such issues were found, a preliminary case replicating some of the factors at play in the December 2022 Winter Storm Elliott found the RTO could fall under the reliability requirement if the high forced outage rate were to repeat.
PJM’s Chris Pilong said the case was a “numbers game” looking at available capacity and forced outage rate without getting into the same detail as the power flow analysis.
The power flow analysis was built on the 50/50 non-diversified peak load base case of 141,233 MW and exports of 4,462 MW. It includes a preliminary installed capacity (ICAP) of 179,821 MW and forced outages of 17,955 MW. Pilong said the capacity figures used in the analysis include resources that do not hold a capacity obligation but historically have been available, including generation not obligated to offer into the capacity market.
The gas contingency case held a 7.1-GW reserve margin over the 90/10 diversified load forecast and a 6.4-GW day-ahead scheduling reserve requirement — the low/no renewables scenario had an 8.7-GW margin. The analysis assumed an 18-GW forced outage rate and 5.5 GW of exports.
The extreme winter storm scenario increased the forced outage rate to 46 GW to simulate the impact of a storm similar to Elliott. Exports were cut to the 3-GW firm interchange and 7.1 GW of load management added to the modeling, resulting in the reserve margin falling 13.8 GW below target.
PJM Seeking More Prompt Data Request Responses from Generators
PJM’s Eli Ramsay encouraged generation owners to self-schedule units for cold weather preparation exercises ahead of the winter and presented an overview of the data request process, which could result in members being found in breach of the Operating Agreement if they do not respond.
PJM will open a data request for generation owners Nov. 1 with a checklist of cold weather preparation steps and asking for any improvements that have been made to resources since Winter Storm Elliott. The request will be open through Dec. 15, with a reminder one week before the deadline.
Generation owners who do not respond to data requests will be notified they may be in breach of the OA, with 48 hours to supply the information through a remediation data request. Pilong said the response rates for the Cold Weather Preparation Checklist and Fuel and Emissions annual survey historically have been around 80%, which has trended in the mid- to high-90% range in recent years. Pilong said the increase followed outreach to generation owners, which PJM is trying to step back from, instead relying on members to report that information when requested.
PJM’s Kevin Hatch said operators rely on generators to update their parameters in eDART when cold weather advisories are issued, which provides dispatchers with visibility into unit availability. Self-scheduled drills ensure those parameters can be relied on if a generator is needed.
Monitor Presents Results of Synchronized Reserve Performance Inquiry
Joel Romero Luna, senior analyst with PJM’s Independent Market Monitor, presented the findings of outreach to synchronized reserve resources that failed to perform during a July 8 event, finding that a majority of the shortfall was due to communication failures or delays.
Synchronized reserve performance has lagged in recent years, leading PJM to increase the reserve requirement by 30% last year after backtracking on an earlier doubling of the target. (See “Stakeholders Reject PJM Synch Reserve Manual Change; RTO Overrides,” PJM MRC/MC Briefs: May 31, 2023.)
The Monitor spoke with 146 resources, representing about 93% of the total 1,755-MW shortfall during the July 8 synchronized reserve event, in an effort to better understand what led to the underperformance. More than 800 MW of shortfall could be attributed to communication issues, with most of those units following signals in PJM’s Automatic Generator Control (AGC) system. (See “Stakeholders Endorse Reserve Rework, Reject Procurement Flexibility,” PJM MRC Briefs: July 24, 2024.)
Luna noted that stakeholders have approved a PJM proposal to send synchronized reserve deployment signals through AGC, which he said could address some of the underperformance seen in July. If all units following their basepoints through AGC had responded to the synchronized reserve deployment, Luna said the performance rate would have been 76%, rather than the 46% seen July 8. While that would be an improvement, he said that would remain inadequate.
Inaccurate parameters, delayed action by plant workers, lacking knowledge of business rules and modeling issues all contributed to underperformance as well. In some cases, changes in ownership caused knowledge gaps about how to respond or resources were assigned reserve commitments for the first time and did not know how to respond.
“We saw a lot of that: units that were not aware that they were being assigned reserves and were required to respond,” he said.
The use of phone calls within companies to relay reserve deployment information contributed to the delays, Luna said. PJM Director of Operations Planning Dave Souder responded that the RTO’s All-Call signal results in a call to committed reserves within seconds of a deployment and the issue lies in how companies receive and process that information.
Quick Fix Proposal on Day Ahead Schedule Reserve Calculation
Hatch presented revisions to Manual 13: Emergency Operations seeking to clarify how PJM calculates the annual Day Ahead Scheduling Reserve (DASR) and uses the figure to determine when the 30-minute reserve target is insufficient. PJM proposed the change through the quick fix process, which allows a solution to be brought concurrent with an issue charge. Approval may be sought at the Nov. 8 OC meeting.
Hatch said the reserve target does not account for the varying risks and needs PJM can experience day to day, which can result in additional reserves being needed in some circumstances. The 30-minute target is set at the greater of the primary reserve requirement, the largest active gas contingency or 3,000 MW, whereas the DASR is based on underforecast load error and generation forced outage rates.
“We need to look for a percentage-based approach,” he said.
Souder said the revisions would codify existing practice around the reserve adequacy run and no changes would be made to market-based reserve procurement.
Stakeholders rejected an earlier PJM proposal to allow it to replace the 30-minute target with a formula that would select the greater of the load forecast error and forced outage rate together multiplied by the forecast peak load, the primary reserve requirement or the largest active gas contingency. (See “Stakeholders Endorse Reserve Rework, Reject Procurement Flexibility,” PJM MRC Briefs: July 24, 2024.)
First Read on Several Changes to Generator Operational Requirements
PJM’s Madalin How presented a package of revisions to Manual 14D: Generator Operational Requirements drafted through the documents’ periodic review.
New language was added requiring generation owners to provide PJM with information about changes to wind resources that may impact their characteristics without modifying the resource’s output to the extent to require going through the interconnection queue. PJM’s Joe Mulhern said information about changes in turbine technology could affect forecasting.
The revisions also include reformatting the Cold Weather Preparation Guideline and Checklist for readability, clarifying how generation owners should proceed if they lose remote control of MW or MVAR output and clarifying the requirement that all generators must provide PJM with reactive capability curves before entering operation and complete reactive testing within 90 days after coming online.
Several stakeholders questioned whether the changes were too substantive to be appropriate for the periodic review process and requested more time to review the language before moving to a vote next month.
September Operating Statistics
PJM experienced a 1.23% hourly forecast error in September, with a peak error of 1.74%, according to the RTO’s monthly operating report. PJM’s Marcus Smith, lead engineer for load forecasting, said Sept. 19 saw an approximately 6% underforecast due to weather forecast error, while Hurricane Helene contributed to overforecasting Sept. 27 and 28.
Two shortage cases were approved Sept. 4 due to high load and a reduction in dispatchable generation.
LS Power Seeks Issue Charge to Align CETL Calculation with Winter Risk
VALLEY FORGE, Pa. — Tom Hoatson, of LS Power, presented to the Planning Committee the third in a “trilogy” of issue charges seeking changes to PJM’s effective load carrying capability (ELCC) accreditation paradigm, focusing on aligning the capacity emergency transfer limit (CETL) with PJM’s winter-skewed risk modeling.
LS Power presented two issue charges at the September Markets and Reliability Committee meeting addressing the transparency of ELCC and how it is applied to individual units. (See “LS Power Issue Charges on Accreditation Transparency, Unit-specific Performance,” PJM MRC Briefs: Sept. 25, 2024.)
The issue charge states that PJM models transfer limits for locational deliverability areas (LDAs) looking at their summer peaks, which is incongruent with a risk modeling approach that has shifted the bulk of risk into the winter. The issue charge is set to be voted on at the PC’s Nov. 6 meeting. (See FERC Approves 1st PJM Proposal out of CIFP.)
“Having switched now to a model that assesses risk throughout the year, using a summer peak-based CETL calculation without reference to the EUE [expected unserved energy] distribution creates a misalignment between the periods when capacity is most valuable and the transfer limits for LDAs during those periods,” the issue charge reads.
Hoatson said that during the December 2022 Winter Storm Elliott, it appeared there was insufficient west-to-east transfer capability despite no such transmission constraints being modeled in the CETL analysis. The winter power flow issues were not modeled in CETL for that LDA.
Stakeholders Endorse Dual Fuel Manual Definitions
The PC endorsed by acclamation a proposal to revise the definition of dual-fuel combustion turbines and combined cycle resources to reflect the Reliability Assurance Agreement (RAA) definitions accepted by FERC in July (ER24-1988). (See “First Read on Manual 21B Revisions,” PJM PC/TEAC Briefs: Sept. 12-13, 2024.)
The change would allow dual-fuel resources that are capable of starting on their primary fuel before shifting to their secondary to qualify as dual-fuel. During the earlier stakeholder process, Calpine’s David “Scarp” Scarpignato said some gas units can start on a small amount of fuel already purchased and packed into the portion of the gas pipeline on generator property, even if the regional pipeline is offline. (See “Quick Fix for Dual-fuel Classification Endorsed,” PJM MRC Briefs: April 25, 2024.)
Transmission Expansion Advisory Committee
2024 RTEP Window 1 Projects Include Expansion of 765-kV Network
PJM has closed the solicitation period for transmission developers to propose projects in its 2024 Regional Transmission Expansion Plan (RTEP) Window 1, which focuses on addressing heavy power flows from west to east driven by load growth in Dominion being served by power in the western half of the footprint.
Senior Manager of Transmission Planning Sami Abdulsalam said past RTEP windows have resolved much of the need to import power from the east and are performing well in the analysis. But load growth is continuing to accelerate and driving more transfer needs.
“Data centers are a strong influencer toward the increasing load forecast,” he said, as well as electrification and electric vehicles.
PJM received 88 project components, with an additional six packages of components, all of which include expanding the RTO’s 765-kV network either toward the area of the Joshua Falls and Acton-Morrisville substations or into northern Virginia near the John Amos substation. The proposals include 48 upgrades of existing facilities, 40 of which are mostly new greenfield infrastructure.
Staff will begin shifting toward building the components into a package they believe meets the regional needs most effectively, with an eye toward future expandability. Once that has been completed, Abdulsalam said Board of Managers approval of a recommended package is being targeted for the first quarter of 2025, with first reads at the TEAC expected in December and January.
Several residents in the northern Virginia region spoke out against the proposed expansions, saying that constructability will be inhibited by the impacts to residents already being affected by several projects and asking whether new generation could be an alternative.
Status of Supplemental Projects
FirstEnergy has reduced the scope of a project to upgrade equipment at its Beaver substation in the ATSI zone to replace a 345/138/13.2-kV transformer with a higher-rated unit. The original scope included replacing two existing transformers and installing two more 138/13.2-kV units. The change reduces the project cost estimate from $12.7 million to $10 million with an in-service date of March 23, 2029.
American Electric Power (AEP) presented a $185 million project to build two new 345-kV substations to accommodate 1,100 MW of new load in the New Carlisle, Ind., region expected to come online by Dec. 15, 2026. Both of the new substations would cut into the Elderberry-Dumont and Dumont-Olive Bypass 345-kV lines.
Toward Elderberry, the new Larrison Drive facility would be configured as a breaker and a half, with 16 345-kV breakers and six bus ties to the new customer for $70.4 million. The New Prairie substation would be similarly configured and cost $79.5 million.
Five overtaxed 345-kV breakers would be replaced at the Olive substation and three new breakers would be added for $29.3 million. End work also would be required at the Sorenson, Elderberry and Dumont substations for $1.72 million for each facility. A sag study and mitigation for the Kenzie Creek-Thomson 345-kV line would cost $620,000 more.
AEP also presented a need to serve a 1,000-MW data center near Granger, Ind., which aims to come online initially with 300 MW of load in December 2027 and ramp up to its full consumption in January 2029.
PPL presented an $81 million project to build a new 230-kV switchyard to serve a 1,000-MW customer near Hazleton, Pa. The load is expected to come online in 2027 with 250 MW, growing to 1,000 MW in 2030.
The new Tresckow switchyard would be cut into the Harwood-Siegfried and Harwood-East Palmerton 230-kV lines for $8 million. The facility itself would cost $45 million and be configured as a breaker and a half with four bays and a 125-MVAr capacitor bank. Three 230-kV lead lines would stretch four miles to the customer for $28 million.
