WASHINGTON, D.C. — The power industry is facing an increasingly delicate balancing act as policies drive some generators to retirement, while major new loads are popping up and making planning for the future more difficult, presenters said during the National Association of Regulatory Utility Commissioners’ (NARUC) Winter Policy Summit.
Historically, PJM has seen its markets drive retirement decisions. Some 90% of the 66,000 MW that have retired in the past couple of decades have come offline when they requested, and most needed no upgrades to accommodate their absence from the grid, said PJM Director of State Policy Solutions Tim Burdis.
“I look out the next 10 years. In 2035 in the PJM footprint, we have 26 GW slated to come off of the system, just based on state and federal policy requirements,” Burdis said. “So that’s not factoring in anything related to the market signal, or the underlying reliability aspects.”
That’s going to lead to more of a division between generators coming off the system and its reliability needs, which means PJM and its members will need to do more to ensure reliability, he added.
“It’s also 26 GW of new load coming onto the system over that same time period in PJM’s latest load forecast,” Burdis said. “So that’s about 52,000 MW or so that are going to have to be accounted for of new supply on the system.”
While historically PJM has balanced the relatively few instances where a retirement leads to reliability issues by expanding the grid, that might not be enough going forward. Both the demand side and new generation being built at retired sites could help ensure the shift happens reliably, Burdis said.
The state of Oregon is facing many of the same issues on load, especially, which is making the PUC’s job of integrated resource planning more difficult, said Chair Megan Decker.
“I’m not going to waste our time with statistics, but suffice it to say that the Pacific Northwest in general and Oregon in particular are seeing significant interest from the data centers that are needed to power, among other things, the AI revolution and, even more exciting for our state’s economy, … high-tech manufacturing,” Decker said. “These can be hundreds or more megawatts at a time and collectively are pushing load growth projections for the region beyond anything we’ve seen or really imagined until very recently.”
Integrated resource plans (IRP) are not accustomed to the uncertainty around big new loads, with data center demand showing up more quickly than load traditionally has, and sometimes in the middle of an IRP process, making them hard to plan for.
“Because of the customer’s competitive sensitivities, they can’t be as transparently scrutinized,” Decker said.
Oregon is the rare state outside of an RTO with retail competition, and to the extent those new loads are served by competitors, Decker questioned how much retailers would contribute to the overall resource adequacy of the system.
One way of handling the situation would be to move away from IRPs and have the PUC look at procurement after the fact, but that would have negative implications for meeting state policies and affordability, she added.
Southern Renewable Energy Association Executive Director Simon Mahan is no stranger to IRPs, representing independent power producers interested in building clean energy around the Southeast. He has intervened on their behalf in many cases.
“The process is not necessarily geared towards ensuring that intervening parties like myself, like our organization, have all the information available,” Mahan said. “The information asymmetry is astronomically high as an intervening party.”
That makes it important for state regulators and their staff to prepare well ahead of time with data collection and ask the right questions, rather than waiting for the contested process to launch that starts a “sprint towards the finish line,” he added.
Typically, the processes might take a year, but utilities work on the filings starting well before that, which means they can be out of date by the time they are filed.
“They will vigorously defend the report, even though there may be news articles or press releases, even from their own corporate headquarters, saying: ‘oh, by the way, we plan to do XYZ,’ which is in total contradiction [to] what the Integrated Resource Plan actually says,” Mahan said.
Mahan quipped that the IRP reports are so full of redactions, including sometimes even publicly available data, that utilities must have a “side hustle in” markers.
The rapid changes make forecasting more difficult, and that means regulators and other intervenors are going to have to “trust but verify” what is being filed.
“How can we verify that what we’re being provided through the lens of the utility is what the customers need the best?” Mahan asked. “And one of the best ways is by letting people like me in the process, so that we can serve as another pair of eyes.”
While the industry and its regulators face hurdles to ensuring reliability on a transitioning grid, University of Chicago Law School assistant professor Joshua Macey said one common misconception of utility is not among them.
“To the extent that regulators are open to trying ambitious new options, there are no legal barriers. Our constraints are political, and they are economic,” Macey said.
The “regulatory compact” was overturned in 1934 by the Supreme Court in Nebbia v. New York, which gave Congress more power to regulate the economy. That overturned the old precedent on regulation, where utilities could be overseen because they had been granted a monopoly over the service territory.
“So, what’s notable about this is we have a set of industries that are the only industries where we have constitutional authority to regulate,” Macey said. “We then have a series of Supreme Court cases that say the question of proper regulation was a legislative determination. And yet we continue to hear arguments that the old model applies only in these industries.”
Cases since then (many dealing with the fallout from Three Mile Island and its impact on the nuclear industry) have made it clear that utilities are entitled to their existing assets, but the next set of assets are open to whatever regulatory determination is correct.
“I think we should be open to experimentation,” Macey said. “The fact that someone has done it in the past may or may not mean they’re in a position to do it most effectively in the future. But it certainly means utilities can take a loss. If they don’t reach their meet their contractual obligation, they can take a real loss.”
ERCOT CEO Pablo Vegas said last week that the “interesting dynamic” of solar energy helped the Texas grid operator meet record demand during its most recent winter storm.
“We continue to see strong solar performance being a very critical part of the resource mix,” he told ERCOT’s Board of Directors during its Feb. 27 bimonthly meeting. “We had very strong solar generation during the days of this winter event.”
ERCOT set a record for solar production at 14.84 GW during the storm’s peak Jan. 16, accounting for about 23% of system demand at the time. That mark has since been extended several times to just shy of 17.20 GW.
As of January, the grid operator had 22.26 GW of solar capacity. According to ERCOT data, another 13.15 GW of capacity is projected to be operational in 2025.
Wind production varied between 1.9 GW and 24.4 GW during the storm. Of course, demand was tightest during calm mornings before the sun rose. Vegas said “incredibly strong performance” from the thermal fleet, storage providing about 1.5% of total energy needs during the storm’s peak periods, and conservation calls helped make up for the missing renewables.
“We were right along the lines of what would be expected [for thermal outages] during that time of year and significantly improved over the performance we saw during Winter Storm Elliott,” Vegas said. “Batteries … are a growing resource on the grid that’s going to continue to be a growing component of the resource mix during those times of need.”
The grid operator set five new winter peaks during the storm, the record peak coming at 78.31 GW early Jan. 16. That was a 5.9% increase over the previous mark of 73.96 GW set during the December 2022 storm, itself a 27.7% increase over the prior record.
“So, a pretty significant increase over that period of time,” Vegas said.
He also applauded the collaboration and preparation across the industry for the grid’s performance during the storm.
“That was different than in prior storms,” Vegas said. “The planning and preparation was far more extensive and much earlier than we’ve experienced in prior storms.”
Ögelman to Retire from ERCOT
Vegas devoted part of his CEO’s report to the board in recognizing his “dear friend and colleague” Kenan Ögelman, who is retiring from ERCOT on March 30.
As vice president of commercial operations, Ögelman has overseen market operations, settlement and retail operations, and market design and development. He also led or supported several important initiatives, including various ancillary service products, Lubbock’s integration into the ERCOT market, real-time co-optimization, scarcity pricing reforms, and securitization of credit and financing after the deadly 2021 winter storm.
“Not only were the mechanics of the development and the elegance of the solutions attributable to Kenan’s leadership, but his ability to bring consensus together in these conversations was something that was really remarkable,” Vegas said. “Honestly, the most difficult thing about working with Kenan is pronouncing his name correctly, because there is nothing difficult about working with Kenan.”
For the record, Ögelman’s name is pronounced Keh-naan Oh-gell-mun.
Jupiter Power’s Caitlin Smith, who chairs the Technical Advisory Committee (TAC) where Ögelman represents ERCOT, offered her thoughts during her update to the board.
“I’ve known him, I think, my entire career in this industry,” she said. “He’s a great friend and mentor and I know that the stakeholders will miss him in this role.”
The board and stakeholders present gave Ögelman a round of applause.
He is the most senior executive to leave the ISO after Winter Storm Uri since then-CEO Bill Magness resigned.
Ögelman joined ERCOT in 2015 from CPS Energy, where he was director of energy market policy and chaired TAC from 2011 to 2013. Previously, he was a senior economist for the Texas Office of Public Utility Counsel, which represents residential electric consumers.
IMM Again Critiques ECRS
ERCOT’s Independent Market Monitor told the Reliability & Markets Committee that while the ISO managed the system reliably during the January storm and prices exceeded only $1,200/MWh, “excessively held” ERCOT contingency reserve service (ECRS) inflated prices during the event.
The IMM said prices cracked the $1,200 level even though reserves never fell below 5,000 MW during the storm and the operating reserve demand curve never exceeded $90/MWh.
“What we saw was large amounts of held ECRs likely drove some of that higher real-time pricing, particularly on Jan. 16,” Wen Zhang, the IMM’s deputy director, said, adding efficient prices could have lowered wholesale energy costs by about $90 million.
“This indicates that the concerns we raised about ECRS are still present,” she said.
The IMM has said ECRS, the newest ancillary product added in June, likely cost between $675 million and $750 million for 2023. It says the product created artificial supply shortages that produced “massive” inefficient market costs of about $12.5 billion last year.
The board agreed with the R&M committee’s and staff’s recommendations to approve a nodal protocol revision request (NPRR1186) regulating energy storage resources (ESRs) that was remanded by regulators back to the grid operator in January. (See “NPRR1186 Goes to Board,” ERCOT Technical Advisory Committee Briefs: Feb. 14, 2024.)
As directed by the Public Utility Commission, staff removed language that set penalties for batteries without sufficient state of charge to meet their obligations when deployed.
The directors also withdrew NPRR1209, which was designed to operate in tandem with NPRR1186’s compliance provisions.
Storage developers vigorously opposed NPRR1186 as it went through the stakeholder process last year. SOC requirements will be addressed by existing protocols and revisions still in the pipeline, staff said.
The directors confirmed Smith and Oncor’s Collin Martin as TAC’s chair and vice chair and approved Enerwise Global Technologies as an adjunct member. The ISO gives adjunct membership to entities that don’t meet the definitions or requirements to join as corporate or associate members.
The board also approved several other items that cleared the R&M committee Feb. 26 and previously were endorsed by TAC:
Texas-New Mexico Power’s Pecos County Transmission Improvement Project, a $114.8 million, 138-kV effort addressing reliability needs under maintenance outage conditions near Fort Stockton in the Far West weather zone.
The second phase of the Aggregate Distributed Energy Resources (ADERS) pilot project. ERCOT has cleared seven additional ADERS to go through the qualification and validation process of commercial operations, joining the two that already are participating in the wholesale market. (See “ADERs now up to 9,” ERCOT Technical Advisory Committee Briefs: Jan. 24, 2024.)
Its consent agenda included 11 nodal protocol revision requests (NPRRs), two changes to the settlement metering operating guide (SMOGRRs), a system change request (SCR) and single modifications to the load planning guide (LPGRR), nodal operating guide (NOGRR), planning guide (PGRR), retail management guide (RMGRR) previously endorsed by the Technical Advisory Committee that:
NPRR1170: define when a qualified scheduling entity (QSE) representing a resource that relies on natural gas as its primary fuel source should notify ERCOT about gas supply disruptions.
NPRR1179: ensure that QSEs representing resources with an executed and enforceable transportation contract procure fuel economically and file a settlement dispute to recover their actual fuel costs incurred when instructed to operate because of a reliability unit commitment (RUC). This change also would adjust the RUC guarantee to reflect the cost difference between the actual fuel consumed during the RUC-committed intervals and the fuel burn calculated based on verifiable cost parameters and would clarify that fuel costs also may include penalties for fuel delivery outside of RUC-committed intervals.
NPRR1193: change the ERCOT-polled settlement (EPS) design-proposal form’s referenced location when it moves from the other binding document (OBD) list into the SMOG.
NPRR1195: assign ERCOT-polled settlement metering facilities’ maintenance and repair responsibilities to the facilities’ owner if it is not a transmission and/or distribution service provider (TDSP).
NPRR1199: revise the protocols to add definitions related to the Lone Star Infrastructure Protection Act (LIPA), a 2021 law that prohibits Texas businesses and governments from contracting with entities owned or controlled by individuals from China, Russia, North Korea or Iran if the contracting relates to “critical infrastructure.” The measure also adds language reflecting ERCOT’s statutory authorization to immediately suspend or terminate a market participant’s registration or access if the ISO has a reasonable suspicion that the entity meets any of the LIPA’s criteria, among other revisions.
NPRR1206: clarify the QSEs required to have a hotline and a 24/7 control or operations center and reconcile the deadline by which QSEs representing resource entities that own or control resources must provide notice they are terminating their representation and the deadline that resource entities owning or controlling resources to change QSEs with a 45-day timeline.
NPRR1207: permit the incidental disclosure of protected information and ERCOT critical energy infrastructure information during a tour or overlook viewing of the ERCOT control room provided to eligible persons who have signed nondisclosure agreements and complied with screening and other requirements before accessing the control room.
NPRR1208: create a new daily ERCOT invoice report listing invoices issued for the current day and day prior at a counterparty level.
NPRR1210: change the frequency of the next-start resource and the load-carrying tests from every five years to every four calendar years.
NPRR1211: incorporate the OBD “Methodology for Setting Maximum Shadow Prices for Network and Power Balance Constraints” into the protocols.
NPRR1213: amend requirements for distribution generation resources (DGRs) and distribution energy storage resources (DESRs) seeking qualification to provide ECRS. The NPRR also modifies requirements for ancillary service self-arrangement and ancillary service trades for DGRs and DESRs that provide nonspinning reserve on circuits subject to load shed.
LPGRR074: align specific term language in the profile decision tree “definitions” worksheet with profile segment language that was added to the “segment assignment” worksheet with the Public Utility Commission’s 2022 approval of LPGRR069.
NOGRR261: incorporate the OBD “Procedure for Calculating Responsive Reserve Limits for Individual Resources” into the nodal operating guide.
PGRR109: require interconnecting entities associated with inverter-based resources to undergo a dynamic model review process before the commissioning date and mandate that resource entities owning or controlling operational IBRs undergo a review process before changing settings or equipment that could affect electrical performance and necessitate dynamic model updates.
RMGRR179: add a communication method so TDSPs can use Texas standard electronic transactions to inform retail electric providers of record which electric service identifiers are affected by a TDSP’s mobile generation or temporary emergency electric energy facility deployment.
SCR825: modify ERCOT’s current control room voice communication configurations to give QSEs and their subordinate QSEs greater flexibility when assigning agents, including allowing sub-QSEs to assign agents different from those used by the parent QSE.
SMOGRR027: Move the EPS metering design proposal from the OBD list into the SMOG, standardizing the approval process, and amend the design proposal form to require more information identifying all distribution service providers that have the right to serve a project.
SMOGRR030: Move the EPS metering facility temporary exemption request application form from the OBD list into the SMOG to standardize the approval process.
A dispute around the January cold snap that forced Northwest utilities to sharply increase electricity imports to meet surging demand has become a proxy for the broader contest between CAISO and SPP over their competing Western day-ahead markets.
The debate over exactly what played out on the Western grid during the Jan. 12-16 winter freeze comes amid growing tension in the Western electricity sector as stakeholders await word from the Bonneville Power Administration in April about whether it favors joining CAISO’s Extended Day-Ahead Market (EDAM) or SPP’s Markets+. It centers on whether CAISO and its Western Energy Imbalance Market (WEIM) played a key role in supporting the Northwest during the storm or other factors were more important.
The weather event that drove Northwest temperatures close to historic lows while pushing loads to nearly record highs coincided with a confluence of other developments that stressed the region’s grid. Those included: derates on the Pacific AC and DC interties; an 800-MW forced outage at Montana’s coal-fired Colstrip plant (until Jan. 13); and a fault that caused Washington’s Jackson Prairie natural gas storage facility to sharply reduce its sendout on Jan. 13, prompting pipeline operator Williams to declare a force majeure that cut deliveries to interruptible customers, including some power generators.
Those developments unfolded within the context of unusually low water levels in the region’s hydroelectric system, which has required BPA to operate the Columbia River system at minimum flows to ensure sufficient capacity behind the Grand Coulee Dam for spring fish operations.
A Feb. 8 assessment of the weather event by the Western Power Pool (WPP) showed how dire conditions became on the region’s grid. Reliability coordinator RC West placed four Northwest balancing authority areas into varying levels of energy emergency alerts (EEAs), including one EEA 3, a critical threat level that requires preparations for rolling blackouts to maintain system stability. (See WPP: Cold Snap Showed ‘Tipping Point’ for Northwest Reliability.)
Relying on interchange data reported to the Energy Information Administration (EIA), WPP’s report showed the Northwest was a net importer of 4,900 MW of energy per hour during the five-day freeze.
And while the report showed that CAISO and other California BAs exported an average of 2,833 MW to the Northwest during the event, it also noted that the data indicated the California BAs themselves were net importers, suggesting most of the imports rescuing the Northwest originated from the Rockies and Desert Southwest — not California.
“The same interchange data shows the Desert Southwest/Rockies BAs were net exporters of approximately 5,334 MW on average,” WPP wrote. “Those exports from the Desert Southwest/Rockies region supported CAISO and other California BAs, as well as 2,833 MW of imports to the Northwest on the Pacific AC Intertie.”
Congestion Conflict
The Portland, Ore.-based Public Power Council (PPC) amplified that theme in a Feb. 23 letter to BPA Administrator John Hairston urging the agency to choose Markets+ when it issues its day-ahead market “leaning” in April. (See Northwest Public Power Group Endorses Markets+ over EDAM.)
The PPC told RTO Insider it conducted its own analysis “using data from a variety of sources including … EIA, CAISO OASIS and other publicly available sources.” It also reviewed data from WPP and Energy GPS.
Analysis by the Western Power Pool and Public Power Council indicates that most of the power supporting the Northwest during the cold snap originated in the Rockies and Southwest regions. | Western Power Pool
While the letter’s case against CAISO’s EDAM (and in favor of Markets+) focused largely on governance issues, the PPC highlighted the January cold snap, conveying concerns about how congestion revenue is allocated in the ISO’s WEIM.
“During the recent winter event in the Northwest, Northwest load imported resources largely coming from the Southwest and wheeling through CAISO,” the PPC wrote. It then spotlighted a complaint among some Northwest entities about how the ISO allocated transmission congestion fees generated during the event.
“CAISO’s congestion policies resulted in over $100M of congestion revenues being collected by the CAISO BAA, despite most of the generation serving the Northwest coming from outside California. The policy creating this result is explicitly maintained in the CAISO EDAM,” the PPC said.
CAISO responded to that contention in a Feb. 27 email to RTO Insider, saying the $100 million in congestion rent stemmed from the need for the ISO to hold back some energy flows to avoid damaging the Northwest grid because of the transmission outages in Oregon.
“Despite the assertions in the PPC letter, the ISO does not collect congestion rent for itself,” the ISO said. “It distributes it to holders of congestion revenue rights (CRRs). CRRs are mechanisms that guard against high congestion prices. They are available to a variety of market participants, including load-serving entities in the Pacific Northwest.”
CAISO noted that it is unique among Western grid operators in its technical capability for managing congestion in the day-ahead time frame.
“As a result, CAISO cannot ignore transmission constraints; it must avoid sending energy to areas where it cannot be received,” it wrote.
In a March 1 message to RTO Insider, Lauren Tenney Denison, PPC director of market policy and grid strategy, said her organization recognizes that CAISO distributes the congestion rents it collects to CRR holders within the ISO.
“While entities outside of the CAISO BAA can hold CRRs, it is our understanding that to the extent that Northwest load-serving entities were able to meaningfully hedge against the congestion charged over the California-Northwest Interties during the cold snap, they would need to have purchased CRRs from the CAISO via auction for the portion of the path within CAISO’s BAA,” Tenney Denison said.
The issue, she said, is that Northwest LSEs with ownership or capacity rights on the northern half of the interties will not receive any of the congestion revenue.
“We would like to emphasize that these assets were built based on regional coordination and with the historical mission to create benefits for both the Northwest and Southwest,” Tenney Denison said.
The PPC is asking that the value created by AC and DC interties between California and the Northwest — “as manifested here by congestion rent allocation” — be “shared equitably” by those who have invested in the lines, she said.
Tenney Denison said the PPC also understands CAISO reasons for re-dispatching around system constraints during the event.
“We look forward to additional discussion on where those constraints were observed and whether those constraints were the result of physical flows or CAISO modeling assumptions,” she said.
She added that “it is unclear when CAISO took actions to re-dispatch around these constraints whether those actions were taken as a balancing authority area, or the market operator based on CAISO’s comments.”
‘It Came from Everywhere’
Fred Heutte is a senior policy associate with the Northwest Energy Coalition (NWEC), which has been a vocal advocate for Northwest participation in a single Western market based on EDAM. In an interview, Heutte emphasized caution about reading too much into the EIA interchange data cited by the PPC and WPP, contending the numbers don’t provide sufficient insight into how power actually flowed across the system during the cold snap.
“Because all the interchange data just really does is say, ‘How much generation did you have inside your balancing authority? How much demand did you have? And, therefore, what’s the net difference?’ It doesn’t tell you that much,” Heutte said. “And especially in the Northwest, where things are very complicated. We have lots of different balancing areas.”
Heutte said the WEIM collects a “tremendous amount” of data that will take time to examine to identify exactly how power flowed during the event. But he also downplayed the importance of where the energy originated.
“I think a couple of things are really clear: that the AC intertie brought us a lot of power when we desperately needed it, and the Energy Imbalance Market was really crucial to that,” he said. “Because the market doesn’t just provide power from Point A to Point B, it optimizes the dispatch over a very wide area.”
“To me, personally, the notion of ‘where does the energy come from’ is it came from everywhere,” Heutte said.
Heutte additionally pointed to the “load and resource diversity” benefit of a market as broad as the WEIM is now.
“Because when it’s super cold up here, it’s not as cold in Southern California and Phoenix [and] Las Vegas,” he said. “If it’s really hot there, it might not be so hot here. So, load diversity helps provide some of the additional resources that the transmission in the market can then move around.”
But the PPC has drawn a different conclusion about the role of the WEIM during the freeze.
“Over the week of the cold event, CAISO’s public data shows they were a net importer during the evening peak when electricity demand is the highest,” Tenney Denison said in the March 1 email. “Other public analysis performed by the Western Power Pool and Energy GPS reaches the same conclusion. CAISO also publishes EIM transfer data that shows while the EIM did facilitate transfers to the [Pacific Northwest], comparing to the level of transmission flows published by BPA demonstrates most of the energy flowed outside of the EIM market.”
CAISO told RTO Insider it is close to issuing a “comprehensive” report on the winter event, which should be out as early as this week.
“The report will cover the dynamics of the WEIM and will provide a detailed analysis hour-by-hour of how the WEIM was able to economically re-dispatch resources to find the least-cost solution considering all the physical constraints on the system to move power across the West,” ISO spokesperson Anne Gonzales said. “That will include analysis of power flowing through California from the Desert Southwest to serve the high demand in the Northwest. The report will provide detailed information showing the actual transfers through the WEIM across the region.”
For its part, BPA has only obliquely weighed in publicly on the issues around the cold snap. In a Jan. 31 news release, the agency described how it helped keep the region powered through sophisticated maneuvers that managed to maintain targeted water levels while meeting a level of demand not seen since the time when energy-hungry aluminum smelters dominated the economy of the Columbia River region.
When asked to comment on the ongoing dispute about the winter event, including CAISO’s response, BPA spokesperson Nick Quinata said, “We’re aware of the situation and have no comment.”
Delayed Decision Urged
BPA’s reluctance to weigh in on the debate is understandable, given that its day-ahead market decision is at the heart of the larger conflict around whether the West will end up with one or two organized electricity markets.
Multiple industry sources not authorized to speak for attribution on behalf of their organizations have told RTO Insider that BPA has been favoring Markets+ throughout its public exploration of day-ahead markets, launched last July. During day-ahead market workshops hosted by BPA, agency officials themselves have expressed a preference for SPP’s approach to market governance.
And while BPA has emphasized that it has not yet identified a preferred day-ahead market — or whether it will join one at all — it has been a key participant in the process for developing Markets+. It has also been conspicuously absent as an active contributor to the West-Wide Governance Pathways Initiative, an effort kicked off by state regulators last year to create the framework for a single Western market that builds on the WEIM and EDAM.
Sources also say Northwest utilities Idaho Power, Portland General Electric (PGE) and Seattle City Light — the PPC’s largest member by customer base — are leaning toward commitments to EDAM.
Asked to comment, Idaho Power spokesperson Brad Bowlin said, “We don’t have a schedule for a public announcement. No recommendation has been made to our board of directors yet. Once that happens, depending on the outcome, we will have some work to do communicating with our regulators prior to any formal announcement.”
PGE spokesperson Andrea Platt responded that the utility “recognizes the potential value in a day-ahead market, as well as the barriers to achieving a full RTO for the West.”
“While PGE continues to evaluate participation in both the Extended Day-Ahead Market (EDAM) and Markets+, we are also actively engaged and support the West-Wide Governance Pathway[s] Initiative, which continues to explore ways to build on the benefits of the Western Energy Imbalance Market and realize the potential for a broader footprint in EDAM and enable a path forward for a potential West-wide market,” Platt said. PGE Director of Transmission and Market Services Pam Sporborg is co-chair of the Pathways Initiative’s Launch Committee.
Regarding City Light, utility Regional Affairs Manager Josh Walter also is a member of the Launch Committee. The utility, which manages its own BAA, told RTO Insider Feb. 28 that it backs BPA’s exploration of day-ahead market participation but “does not support endorsing Markets+ at this time” due to “the lack of essential information and the number of unknown variables.”
“City Light urges BPA to give careful consideration prior to making any market leaning. Doing so now would be premature, given undetermined and unresolved critical foundational issues including market footprint, transmission connectivity and governance,” spokesperson Jenn Strang said in an email. “City Light remains committed to creating a pathway to independent governance for the West and urges BPA to include the work of the West-Wide Governance Pathways Initiative in their market determination.”
With six-state utility PacifiCorp already committed to EDAM, a Markets+ consisting of just BPA and British Columbia’s Powerex in the Northwest and possibly a few entities in the Desert Southwest risks isolation and fragmentation. Under those conditions, it would not be as effective as the WEIM is in managing stressed conditions like the January cold snap, according to Heutte, who also recommends that BPA delay its decision.
“If Markets+ succeeds in moving forward with a lot of support across the West, [there will be] a Northwest zone and a Southwest zone with no direct connection from transmission,” he said. “It’ll have to transfer power across the grid of other entities that are not in Markets+, and that dramatically shrinks the load and resource diversity that’s actually available” in the West.
Along with BPA, Arizona Public Service has been a visible participant in developing Markets+ but, Heutte warned, “We have yet to see how enthused the Southwest utilities are really going to be about” the SPP market.
“One possibility is we’ll end up with something that doesn’t really come close to the performance of a much bigger market, and I think that’s a pretty legitimate issue here,” he said.
WASHINGTON, D.C. — Three senior utility executives told state regulators Feb. 27 that natural gas and nuclear power will be essential to the electric generation mix for decades as the industry decarbonizes.
Speaking at the National Association of Regulatory Utility Commissioners’ (NARUC) Winter Policy Summit, the executives said the industry already has cut carbon pollution in recent decades, while acknowledging the job is far from over.
“Since 1984, carbon emissions have stayed the same out of our sector, but electricity use has grown 73%,” said Edison International CEO Pedro Pizarro. “If the Obama Clean Power Plan had been implemented, the industry would have not only met it and surpassed it, [but done] so earlier than the plan would have called for. We have more than 40% of U.S. generation today coming from clean carbon-free resources like nuclear, wind and solar.”
Pizarro, chair of the Edison Electric Institute, said about 50 of EEI’s members have announced long-term carbon cutting goals and most of them call for net zero by mid-century.
“We’re doing that now in a backdrop where electricity demand is really moving,” he added.
Southern California Edison had seen 15 years of essentially no load growth, but now it is expecting load to grow by 2% each of the next several years, Pizarro said.
Tennessee Valley Authority CEO Jeffrey Lyash said emissions in the agency’s footprint have fallen 60% from 2005. Now electricity is responsible for only 27% of the emissions in the TVA region.
“I think we can get the 80% [reduction from 2005 levels] and keep balanced with that energy security objective,” Lyash said. “The challenge is: And then what? How do you decarbonize the rest of the electricity sector? But more importantly, how do you use electricity, which will be one of the prime ways we decarbonize the rest of the economy?”
Lyash, chair of the Nuclear Energy Institute, said nuclear power will be part of the mix, along with renewables, energy storage, carbon capture and clean hydrogen.
“It’s just such a 24/7, system-stabilizing resource, I’m not sure how you get there without it,” he added.
DTE Energy CEO Jerry Norcia, chair of the American Gas Association, said natural gas is going to have a continued role in a clean energy future.
“When I think about natural gas in our industry, it really has been an enabler of decarbonization,” Norcia said. “About 40% of our power generation in the country now comes from natural gas and that’s a fundamental shift from coal, which was the dominant fuel source for power generation in the past.”
Direct use of natural gas also is popular, with about 189 million Americans using it and 70% supporting its use, he added.
The electric industry is heavily reliant on natural gas and its use is going to be “valuable and critical for a very long time,” Pizarro said. Even in California, SCE’s modeling has the fuel in continued use.
“We see California still having about 40% of the commodity that’s flowing today; it will still be flowing in 2045 economywide,” he said. “For the electric power sector for generation we still see between 4 and 5% of the electrons coming from natural gas-fired resources in 2045.”
Those power plants occasionally burning natural gas in 2045 will have their emissions captured, or at least offset, through “other carbon-negative tools.” Beyond gas, California will need other technologies such as nuclear and eventually offshore wind, which produces power when other renewables do not.
One major issue is whether EPA should complement the Inflation Reduction Act’s incentives with requirements to shut down fossil-fired plants. Pizarro noted that EEI supported the agency when West Virginia and others sued it to stop the Clean Power Plan.
“But we need to make sure that those regulations are fair and reflect reality,” said Pizarro.
Some rules requiring natural gas plants to implement carbon capture or burn clean hydrogen were too stringent based on the development of those technologies, he added. Pizarro was speaking days before EPA announced it would delay regulations impacting existing natural gas plants under its power plant rule, focusing it on coal and new natural gas. (See EPA to Strengthen Emissions Regs for Gas Power Plants.)
EPA Principal Deputy Assistant Administrator for the Office of Air and Radiation Joseph Goffman spoke at NARUC a day before the three trade group chairmen, saying that once the agency issues its final rule on power plants, attention will shift to the states.
“The main driver will be the state plans, that’s where the action is going to be,” Goffman said.
As states issue plans to implement the power plant rules, EPA wants to stay in touch with the economic regulators represented at NARUC along with their environmental regulators, energy offices and legislators, he added.
“That’s where the opportunity will really come to ensure that the rules achieve the urgently needed CO2 reductions from the power sector,” Goffman said. “And at the same time continuing to meet the objectives of a reliable supply of affordable electricity.”
Goffman was speaking alongside a group of state regulators and West Virginia PSC Chair Charlotte Lane. Lane, whose state still is 88% coal-powered without plans to shut anything down until at least 2040, often sparred with him.
“Carbon emissions may be a concern,” Lane said. “But they are not the existential threat to life on this planet that some people would have us believe. I am concerned that the EPA has set its sights on a … target is not going to let up until it shuts down all fossil fuel power plants. However, I believe that the cost of an unreliable power supply will be huge and well in excess of any benefits achieved.”
She asked whether the EPA was considering giving a longer timeline for fossil power plants needed for reliability. Goffman answered yes, saying commenters had made the case for the need to be flexible.
“We sort of see the question of time horizon as part of a larger fabric of flexibility,” Goffman said.
SPP marked the 10th anniversary of its day-ahead, real-time Integrated Marketplace by saying it has provided more than $10.2 billion in savings to members since its launch in 2014.
The grid operator said the market’s value “far surpassed” initial expectations, noting initial studies projected the marketplace would deliver up to $100 million in annual benefits to its 14-state footprint. In its first year, the market delivered $380 million in net savings, and in just four months, it covered its development costs, SPP said.
In 2023 alone, the Integrated Marketplace provided the RTO’s members with $2.25 billion in savings, the grid operator said.
The Integrated Marketplace replaced SPP’s seven-year-old energy imbalance market. It combined SPP’s 16 legacy balancing authorities into a consolidated BA and added congestion-hedging components. The market became financially binding for its initial 103 participants at 12:05 a.m. March 1, 2014.
“The Integrated Marketplace is an important tool in SPP’s toolbelt,” CEO Barbara Sugg said. “It allows us to provide low-cost, reliable generation and additional economic benefits to the region.”
The market also was expected to facilitate the further integration of renewable resources in SPP’s region.
Heading into last summer, the RTO had 32.22 GW of nameplate wind capacity, but only 1.4 GW of solar capacity. However, SPP’s interconnection queue includes 37.51 GW and 24.29 GW of solar and wind projects, respectively, and an additional 20.98 GW of energy storage projects.
WASHINGTON, D.C. ― Sen. Sheldon Whitehouse (D-R.I.) is bullish on CBAM, the European Union and United Kingdom’s adoption of a carbon border adjustment mechanism, which he believes could finally push the U.S. Congress to put a price on carbon.
The CBAM (pronounced “see-bam”) will levy a price on the carbon dioxide emitted in the production of goods imported into the EU and U.K., in essence a tariff, if the carbon has not been accounted for in the country of origin. Adopted in 2023, the EU CBAM is scheduled to go into effect in 2026. The U.K. pledged to adopt its own version by 2027 at the recent UN Climate Change Conference in the United Arab Emirates.
“That means the American products being exported into the EU or the U.K. will pay a tariff for the relevant carbon inefficiency of their manufacturing,” Whitehouse said in a keynote speech at the American Council on Renewable Energy’s Policy Forum on Feb. 29. “Which gives a very, very strong motivation to those industries to come to Congress and say, ‘Hey, lift this tariff. … I don’t want to have this collar around my neck when I’m trying to compete in the EU and the U.K.’ And the only way to get that collar lifted is with a domestic carbon price.
“So, there’s finally, finally, finally going to be some industry counterpressure against the fossil fuel industry in Congress, and that could be the tipping point that will help us move toward carbon pricing.”
One of the Senate’s strong liberal voices on climate change, Whitehouse repeatedly slammed the fossil fuel industry for its campaign of “climate denial and propaganda … run through multiple dozens of phony friends groups.”
“The more [we} can find a way to call that out, the easier it is for the public to understand that, no, actually the wind turbines off Rhode Island are not killing the right whales, and that information comes from a source they should not trust.”
Having clear information “can help change public opinion in these localized debates,” he said, referring to the rise in local opposition to renewable energy projects.
But Whitehouse also criticized President Joe Biden for not making better use of his “bulliest of pulpits” to counter industry misinformation, for example, pointing to the Securities and Exchange Commission’s proposed rule on corporate disclosure of climate-related risk.
As reported by Reuters, pushback from corporate interests and state officials may have resulted in the SEC dropping a key provision of the proposed rule, requiring U.S. corporations to report the greenhouse gas emissions from their supply chains, called Scope 3 emissions.
“Some significant financial companies have retrenched … on their [environmental, social and governance efforts], Whitehouse said. “Their complaint about ESG … is never the S; it’s never the G. It’s always the E, and the E it always is is fossil fuel.”
The fossil fuel “roadshow” against the disclosure rule and the lack of more outspoken support from the White House has caused agencies such as the SEC “to pull their ambitions in a little bit,” he said.
The commission is set to vote on the rule at its March 6 meeting. Responding to a query from NetZero Insider, an SEC spokesperson declined to comment on the Reuters report, framing it as “speculation about what may be in or out of a rulemaking.”
The IRA Tipping Point
The upcoming election and defending the Inflation Reduction Act against former President Donald Trump’s potential return to the White House have become increasing concerns at industry events like the ACORE forum.
In an on-stage conversation with Lesley Hunter, ACORE’s senior vice president for policy, finance and ESG, Whitehouse likened Republican calls to repeal the IRA to their previous attempts to repeal the Affordable Care Act passed in 2010, the massive health care law widely referred to as “Obamacare.”
Republicans made several attempts to repeal the law while Trump was in power, Whitehouse recalled, “until a certain tipping point of constituents were enjoying the benefits of Obamacare … and you kind of had to live with it.” Now, with projects funded by the IRA spreading across blue and red congressional districts, “it would be hard for a member to go back and vote against the IRA after they attended the ribbon cutting for a significant project.”
The best defense for the IRA is to go on announcing and building projects, he said. “Have ceremonies and invite public officials and let them know it came through the IRA.”
At the same time, Whitehouse gave the IRA and Biden’s executive actions on climate change mixed reviews. The law has been a “terrific success,” he said, but details of implementation, and the law’s durability, may depend on moving rules through a federal bureaucracy where speed still can be slowed by one recalcitrant official or agency.
The Biden administration’s rule requiring federal agencies to include the social cost of carbon in project cost estimates is another step toward carbon pricing, as is the IRA’s fee on excess methane emissions, Whitehouse said. Their impact, however, may depend on how rigorously individual agencies implement both measures.
Looking at the social cost of carbon, “you need to be making sure agency by agency that they are following [administration] guidance and actually setting up the decision making in their power purchase contracts and agreements,” he said.
EPA issued a proposed rule in January on methane charges ― to be imposed on oil and gas facilities emitting more than 25,000 metric tons of carbon dioxide per year ― with a comment period ending March 26.
The proposed rule does contain provisions that would allow exemptions for some oil and gas companies. Echoing concerns of environmental and clean energy advocates, Whitehouse urged EPA to avoid any loopholes, “responding like firefighters to smoke coming out of a building, and getting the damn thing shut down, and not with fire hoses but with lawyers.”
Permitting Update
Whitehouse also gave an update on bills he has introduced aimed at streamlining the siting and permitting of interstate transmission and offshore wind.
Both bills would give FERC expanded authority for permitting interstate transmission lines. While chances for a general permitting bill are low, Whitehouse remains hopeful that “if circumstances are right, [a transmission permitting bill] could move fairly quickly; so, we want to be ready for that.”
His offshore wind bill ― the tortuously named Create Offshore Leadership and Livelihood Alignment By Operating Responsibly And Together for the Environment (COLLABORATE) Act ― was released in draft form in January for comment. The bill aims to streamline permitting by frontloading “disputation,” Whitehouse said.
The goal is to “bring in the real people who are going to be affected by [an offshore project], so you can get off to a much faster start and not find your opponents lurking in the weeds through the long administrative process,” he said.
“We’re pretty close to landing the final text, but we’re wide open to further amendments,” Whitehouse said. “Then the question is what’s the vehicle?” The best chance could be attaching COLLABORATE to either a must-pass bill or some kind of bipartisan consensus package, he said.
EPA is holding off on new emissions restrictions for existing natural gas-fired power plants.
The agency in May 2023 proposed stronger greenhouse gas pollution standards for new and existing fossil-burning generation facilities and received more than 1.3 million comments in response. (See EPA Proposes New Emissions Standards for Power Plants.)
The process had been nearing its conclusion but will now continue.
EPA will soon send a finalized version of its proposal to the Office of Management and Budget, but the rules will not cover existing gas facilities — EPA said Feb. 29 it wants to strengthen provisions that pertain to existing gas.
EPA Administrator Michael Regan said in a news release:
“As EPA works towards final standards to cut climate pollution from existing coal and new gas-fired power plants later this spring, the agency is taking a new, comprehensive approach to cover the entire fleet of natural gas-fired turbines, as well as cover more pollutants including climate, toxic and criteria air pollution.”
Gas-burning plants are cleaner than coal-burners, but they do produce emissions and are more numerous. The Energy Information Administration tallied 2,073 gas-burning plants rated at least 1 MW nationwide in 2022 and only 242 coal-burning plants.
In contrast, some environmental advocates criticized the original emissions proposal as too lenient, saying it would have applied to only a small percentage of existing gas-fired plants.
This sentiment was captured in a celebratory quote EPA provided Feb. 29 from Washington Gov. Jay Inslee (D):
“This is excellent news from Administrator Regan, and I commend him for his continued leadership. We cannot mitigate emissions and pollution from power plants by ignoring our country’s largest source of electricity generation: existing gas plants. Washington state is eager to support EPA in undertaking this rulemaking as quickly as possible.”
Some environmental advocates offered messages that were more wait-and-see than celebratory.
NRDC President Manish Bapna said in a prepared statement:
“We can’t tackle climate change and clean up air pollution without slashing emissions from the existing gas-fired power plants already pumping huge amounts of carbon and other dangerous pollutants into the air. EPA needs to finish the job without delay.”
Peggy Shepard, executive director of WE ACT for Environmental Justice, said:
“We are wholly appreciative of EPA’s leadership in demonstrating the need for further review, and at the same time request a clear and transparent process as we look forward to collaborating for its improved realization. Only when this rule is finalized can we truly know we are on a path to resilience and justice.”
Regan touched on these concerns in EPA’s news release:
“This stronger, more durable approach will achieve greater emissions reductions than the current proposal. EPA proposals on criteria pollutants and air toxics also will help address local air quality impacts to better protect vulnerable frontline communities.
“This comprehensive approach to reducing climate and air pollution will also consider flexibilities to support grid operators and will recognize that ongoing technological innovation offers a wide range of decarbonization options. EPA will immediately begin a robust stakeholder engagement process, working with workers, communities with environmental justice concerns and all interested parties to help create a more durable, flexible and affordable proposal that protects public health and the environment.”
After a fresh FERC review, Invenergy has walked away with half the authorizations necessary to charge negotiated rates for transmission service on its $7 billion, 5-GW Grain Belt Express transmission project.
Late last year, Invenergy sought FERC permission to amend its negotiated rate authority for Grain Belt Express because the merchant transmission project’s design had changed substantially since FERC originally granted authority in 2014 (ER24-59).
FERC scrutinized the project using its four-factor test. The commission said while Grain Belt satisfied its requirements for just and reasonable rates and regional reliability, it lacked information on whether Grain Belt would parcel out capacity on its line fairly.
“We reserve judgment on whether Grain Belt’s capacity allocation process satisfies the commission requirements for undue discrimination and undue preference (factors two and three). We will make a determination regarding those factors at such time as Grain Belt submits a filing providing sufficient detail to evaluate whether its capacity allocation process satisfies the commission’s requirements, either in advance of its open solicitation or post-open solicitation,” FERC wrote in a Feb. 29 order.
FERC said while Invenergy requested “flexibility” for its upcoming capacity allocation process, it provided only “limited detail on the selection process or selection criteria for the commission to evaluate.” The commission said it couldn’t be confident Invenergy would not bestow undue preference on generation affiliates when selling the line’s capacity.
Invenergy said last year it intends to launch an open solicitation for takers of capacity on the first, 2.5-GW phase of the line, which runs from Kansas to Missouri. In its filing, it said it has hired the Brattle Group to serve as an independent consultant and oversee the open solicitation for a “portion of capacity for Phase 1.” Invenergy said the Brattle Group will develop selection criteria and ensure the solicitation is conducted in a transparent and non-discriminatory manner. Invenergy also promised a post-solicitation compliance filing to FERC.
The Missouri Joint Municipal Electric Utility Commission already has agreed to buy up to 225 MW of capacity on Grain Belt.
The Missouri Landowners Alliance protested Invenergy’s request to amend its negotiated rate authority and said the commission should require Invenergy to reapply for permission to offer capacity on Grain Belt at negotiated rates. The landowners argued that project ownership, capacity and interconnection points have changed too drastically since FERC originally granted Grain Belt’s negotiated rate authority.
Invenergy acquired development assets for Grain Belt from Clean Line Energy Partners in 2018. The Missouri Landowners Association argued Invenergy didn’t notify FERC of the handover and the expansion of the project. (See Invenergy Announces Grain Belt Express Expansion.)
The association also voiced concern that Invenergy “controls a large inventory of energy facilities,” including generation, and suggested it could give its affiliate customers preferential treatment or have an incentive to withhold capacity. It cautioned FERC that Grain Belt’s “use of an independent evaluator should not take the place of regulatory scrutiny and guidance.”
Invenergy rebutted that FERC rules don’t allow it to unduly discriminate or show undue preference in the open solicitation process.
The association also accused Invenergy of beginning negotiating capacity sales ahead of its future open solicitation. Invenergy said the Missouri landowners’ allegation was incorrect and based on the association conflating sales of transmission service with a sale or lease of an undivided interest in Grain Belt.
FERC didn’t address the debate because it left those sections of the four-factor test undecided.
The Sierra Club in late October wrote to support negotiated rate authority for Invenergy.
“The Grain Belt Express Project will lower electricity costs for consumers, markedly improve the economic operation of these regional electric grids, offer significant resilience value — especially during storms and other high-demand events — and improve resource adequacy for customers and utilities,” the environmental group said.
Invenergy plans to begin construction on Grain Belt in early 2025 and has said it already secured 95% of the land necessary for Phase 1 of the project. The Kansas-to-Illinois line will connect SPP, Associated Electric Cooperative, MISO and PJM. Invenergy has selected Siemens Energy to provide the HVDC technology for the first phase of the 800-mile line.
Invenergy said it expects to put separate filings for approval before FERC to transfer Phase 1 capacity to buyers and/or lessees via sales and/or leases of undivided interests in the transmission line. Those require individual approvals.
CARMEL, Ind. — MISO last week said its extensive analysis shows that its current $3,500/MWh value of lost load (VOLL) should be raised to $10,000/MWh.
The grid operator has made a renewed push in recent months to re-estimate its value of lost load after saying that its existing VOLL is dated, having been established in the 2008-2009 time frame. MISO’s current VOLL reflects the willingness of the lowest-income residential customers in the RTO’s footprint to pay for uninterrupted service.
During a Feb. 29 Market Subcommittee meeting, MISO’s Chuck Hansen said the $3,500/MWh limit “can currently curtail valid market prices.”
“When the system is in a more vulnerable state, prices should reflect the risk of diminishing reserves,” Hansen said.
Three years ago, MISO’s Independent Market Monitor recommended the RTO adopt a $10,000/MWh VOLL.
Hansen likened a well-thought-out VOLL to the “jolt” delivered from farmers’ electric fences, which aren’t meant to injure livestock.
“The goal isn’t to shock the cows; the goal is to just keep them in the field,” he explained.
Hansen said a raised value would almost counterintuitively moderate market volatility because market participants would take more actions to dodge the highest prices.
“With higher prices, we expect lower volatility and more preparation to avoid those kinds of real-time energy deficiencies,” he said.
Hansen said MISO’s current VOLL is “outdated and below industry willingness to respond to demand.” He said a reasonable VOLL would properly discourage market participants from “these ‘touching the electric fence’ situations” and “potentially make them more rare than they already are.”
New VOLL Means New ORDC
MISO said it also will seek to change how VOLL ties into its operating reserve demand curve (ORDC). MISO’s ORDC is linked to VOLL, and the current curve mostly sits at $1,100/MWh and $2,100/MWh across two large steps before it tops out at $3,500/MWh.
Despite proposing a $10,000/MWh VOLL, MISO wants its ORDC to peak at $6,000/MWh and stay there until about 50% of cleared operating reserves materialize. From there, the curve would slope downward until MISO can confirm more than 80% of its cleared operating reserves, at which point the curve would become two steps: $1,100/MWh until 88% of reserves show up and $600/MWh until 100% of reserves turn up.
If MISO already had the new curve in place, Hansen said more than 90% of MISO’s past shortages would have resulted in lower penalty prices. Most of the RTO’s operating reserve shortages occur at 88% of reserves or higher. Historically, MISO has never experienced an operating reserve shortage below 50%.
“This is not just about raising VOLL and making prices higher. On the right side of the curve, we thought it was appropriate to lower prices,” Hansen said.
Hansen said MISO would like to introduce an ORDC that is lower for small reserve shortages and results in higher prices for greater shortages.
“As reserves go away, we want prices to approach VOLL, but we don’t want prices to be so high that they reach VOLL well before load shedding is initiated,” Hansen said. Conversely, he added that the lower bound of the ORDC shouldn’t be so low that it’s cheaper for market participants to violate marketwide operating reserve requirement.
Hansen said MISO wants to continue to use an updated VOLL as a price cap for locational marginal prices, market clearing prices and during load shed events.
But he said MISO would like to sever the connection between VOLL and MISO’s emergency demand response offer cap. MISO has called on its emergency demand response only once, more than 15 years ago. Today, MISO’s emergency demand response averages less than 500 MW and is managed on a separate system from the RTO’s markets. The product was introduced before MISO debuted its ancillary service market, and owners are under no obligation to be available. Hansen said MISO has debated retiring its emergency demand response product and urges market participants to move their offerings under the RTO’s existing load-modifying resource and demand response programs.
MISO’s proposed ORDC. The ‘SOM’ curve refers to the Independent Market Monitor’s past recommendation for a new curve. | MISO
Justification for $10K
Hansen said the current VOLL was established alongside the launch of MISO’s ancillary services market and “that number has not changed in 15 years.”
He said MISO has made hundreds of calculations to freshen its VOLL, including crunching numbers for different lengths of outages; nonsummer versus summertime periods; afternoon, evening or off-peak periods; and using different customer load classes, including small commercial, industrial, residential and manufacturing segments.
MISO found that for a one-hour outage occurring off-peak in summer, VOLL will run $4,337/MW for residential customers and up to nearly $81,000/MW for small commercial and industrial customers. For an eight-hour outage occurring off-peak in summer, a residential VOLL will run about $8,107/MW, while small commercial and industrial customers’ value runs more than $266,000/MW.
“We’ve been studying a range of numbers, many numbers,” Hansen said.
MISO found that its highest VOLL occurs during off-peak periods with small commercial and industrial customers the most exposed to risks of lost revenue. Larger commercial and industrial customers often have access to more capital to prepare to bounce back more quickly from an outage, staff said.
When MISO made its 2007 FERC filing to create VOLL, it used the average of the $1,470/MWh median value of its residential class and the $15,250/MWh lowest median value of the small commercial and industrial class. The resulting VOLL was weighted 85% toward residential customers.
Using that same 2007 calculation, Hansen said the 2023 VOLL for a summertime, one-hour outage occurring off peak should be $13,640/MWh.
“What we’re proposing is actually on the conservative side,” Hansen said.
Hansen reminded stakeholders that MISO isn’t in charge of which customers are affected by outages when it orders load shedding. The RTO simply tells local balancing authorities how many megawatts it needs off the system. MISO said a recent survey of its local balancing authorities shows that when instituting rolling blackouts, customers dropped on average are 48% residential, 30% large commercial and industrial, and 22% small commercial and industrial.
Hansen said a $10K VOLL reflects that industrial customer load is also shed alongside residential load during dire circumstances.
CARMEL, Ind. — MISO is determined to file with FERC by the end of March to introduce a probabilistic capacity accreditation that’s controversial among stakeholders.
MISO stakeholders continued to lobby for a deferral during a Feb. 28 Resource Adequacy Subcommittee meeting, again telling the RTO it hasn’t shared enough information on its loss of load-oriented accreditation style. (See MISO Set on March Accreditation Filing, Stakeholders Push for Slowdown.) A filing in March seems destined to gather several protests.
But Senior Manager of Market Design Neil Shah said MISO has now shared enough data from its analyses to give stakeholders a “broad indication” of their future capacity credits to adjust generation plans accordingly.
“The filing needs to happen now for stakeholders to make those adjustments,” Shah said.
MISO doesn’t intend the accreditation to take effect until the 2028/29 planning year.
Shah said “the beauty of” MISO’s method is that it measures the reliability contribution of all resources across “hundreds and hundreds” of simulated risky hours.
Under the new method, generators’ capacity credits would be determined by a combination of individual past performance and resource-class average performance during hours with tight conditions and modeled loss-of-load hours for different types of generation. Most resources’ credits would shrink under the new accreditation. Resources would be divided by fuel type: gas, coal, hydro, nuclear, energy storage, pumped storage, wind and solar. MISO at first didn’t commit to listing resource types in its tariff filing with FERC.
Shah likened MISO’s accreditation change to his homeowner’s insurance policy recently increasing by a few hundred dollars based not on him, but on his neighbors filing more claims recently. He said his insurer took the growing claims as proof of rising risk in his neighborhood and reassessed. MISO, Shah said, is no different with this new accreditation direction.
Many MISO stakeholders have argued the loss-of-load accreditation would inject too much uncertainty into the MISO market, disrupting integrated resource plans and investment decisions. At the RASC meeting, some said they don’t have adequate insight into how capacity credits would differ by resource type and questioned whether MISO’s proposed resource classes would sufficiently represent all types of resources in MISO.
Shah said MISO is prepared to make a future filing if new technology necessitates the RTO add new resource classes but said MISO has landed on a “good representation of resources classes” in the footprint today.
Shah also noted that during the three-year transition period, MISO wouldn’t apply the accreditation but would publish indicative accreditation results for resource classes, as well as anticipated local reliability requirements and planning resource margin requirements based on the direct loss-of-load accreditation method. MISO wouldn’t share unit-level capacity values publicly; market participants would need to request those from the grid operator.
MISO has said the new accreditation would better ensure seasonal reserve requirements are met, shape long-term investment and retirement decisions “by accurately representing the capacity value of a resource in the prompt year,” and incentivize resources to show up during times of the greatest system need. It has characterized the new accreditation style as a “consistent accreditation methodology for all resources, capturing the reliability contribution during times of highest risk.”
MISO’s Zak Joundi has said MISO members would “have plenty of time to adjust” to the new rules.
