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October 30, 2024

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PIO Complaint Faults PJM Treatment of Deactivating Generation

Several public interest organizations (PIOs) have filed a complaint with FERC contending PJM’s capacity market inflates consumer prices by not counting generators operating on reliability must-run (RMR) agreements as a form of capacity (EL24-148).

The complaint argues that RMR contracts already require units to be online and available to PJM dispatchers in a capacity emergency, which positions them similarly to committed capacity.

The PIOs said consumers are being asked to pay for capacity twice: once for an RMR unit’s availability and again to procure the capacity the unit would have offered had it participated in the RTO’s Base Residual Auctions (BRAs).

The complaint was submitted by the Sierra Club, Natural Resources Defense Council, Public Citizen, Sustainable FERC Project and Union of Concerned Scientists.

“Failing to account for resource adequacy provided by RMR units produces capacity market price signals that are disconnected from the actual supply and demand balance on the grid,” the complaint says. “This distorted supply-demand balance is economically inefficient because it signals a degree of scarcity that does not exist. The result is artificially elevated prices that harm the markets by encouraging inefficient decisions by both supply and demand side market participants.”

The complaint also argues that PJM’s position on modeling RMR resource capacity is inconsistent because it does not include RMR units’ output when analyzing the amount of generation available within a locational deliverability area (LDA) when analyzing transmission capability during potential capacity emergencies.

The PIOs present two visions for how RMR resources could interact with capacity markets. The most straightforward would be requiring them to offer into the market at $0/MWh as price-takers; however, the complaint acknowledges the change could make generation owners wary of accepting an RMR agreement — which is a voluntary election in PJM. The alternative they propose would be to model RMR units when determining the reliability requirement and reduce the amount of capacity that must be procured through BRAs.

The complaint also requests the commission delay the 2026/27 BRA, currently scheduled for December, to allow the changes to be implemented for that auction.

RMR Impact Set to Increase

The impact of RMR agreements on consumer rates is likely to increase substantially in the 2025/26 delivery year, when agreements take effect between PJM and Talen Energy to keep the 1,273-MW Brandon Shores and 702-MW H.A. Wagner generators online from June 1, 2025, through Dec. 31, 2028.

The complaint cites analysis from Synapse Energy Economics, on behalf of the Maryland Office of People’s Counsel, and a separate report from the Independent Market Monitor, which found that not counting RMR units as capacity could cost PJM ratepayers $4billion to $5 billion in 2025/26. (See Maryland Report Details PJM Cost Increases for Ratepayers.)

The terms of the Talen agreements are being negotiated through settlement judge proceedings the commission ordered in June. The company requested $175 million in annual fixed costs and $29.9 million in project investments for Brandon Shores and $40.3 million in fixed costs and $4.5 million in additional investments for Wagner. (See FERC Orders Settlement Judge Procedures in Two PJM Generator Deactivations.)

Stakeholders also are discussing changes to PJM RMR resources in the Deactivations Enhancement Senior Task Force (DESTF), which is set to open a vote on five proposals during its Oct. 2 meeting. The DESTF packages largely focus on extending the notice generation owners must provide PJM ahead of their desired deactivation dates and how compensation under RMR contracts is determined.

None of the DESTF proposals include a capacity must-offer requirement for RMR units, but a proposal from the Sierra Club would model the expected output of RMR resources that do not participate in the capacity market when determining the reliability requirement.

The parties to the complaint argued that even if a proposal passed that satisfies their concerns, changes are unlikely to be implemented in time for the December auction. The PIOs also noted that the PJM Board of Managers rejected a request from six state consumer advocates in an Aug. 30 letter to launch a Critical Issue Fast Path (CIFP) process to require RMR units to participate in the capacity market. In its Sept. 19 response, the board wrote that doing so would undermine the capacity market’s price signals to replace the outgoing generator or make investments to keep units operational.

In the first of a series of reports on the 2025/26 BRA, the Monitor estimated that not including RMR units in the supply stack as capacity price takers would have increased the cost of capacity procured by more than $4 billion, or 41.2%. The Monitor said this would recognize that RMR resources provide reliability while transmission upgrades to address their deactivation are constructed.

“There are times when a price signal for the entry of generation is not needed or appropriate, e.g. when PJM has committed to the construction of new transmission that will eliminate the price signal when complete,” the Monitor wrote.

Monitor Joe Bowring told RTO Insider that requiring an RMR unit to offer into the capacity market also could lead to costs for consumers, as generation owners would be more wary of entering into RMR agreements and would seek to recover the risk of being subject to capacity performance (CP) underperformance penalties. Instead, he suggested including them in the supply curve as a zero-cost offer.

Bowring said one of the issues with how generation deactivations are treated in PJM is the lacking ability for merchant generation to compete with transmission to address any identified reliability violations. He argued that an expedited interconnection process is needed to give new resources a chance to provide a solution to violations or when reliability issues are identified in general, such as the capacity shortfall PJM has been warning about in the 2029/30 delivery year. He has proposed a similar concept at the Planning Committee for allowing PJM to transfer capacity interconnection rights (CIRs) from a deactivating resource to resources which could resolve associated violations. (See “Voting on CIR Transfer Proposals Deferred to October,” PJM PC/TEAC Briefs: Sept. 12-13, 2024.)

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CAISO Seeks to Dispel CRR ‘Myths’ Around January Cold Snap

CAISO focused on congestion revenue rights when it served up the latest volley in the ongoing dispute over what played out on the Western grid during the January cold snap that forced Northwest utilities to import unusually high volumes of energy to avoid blackouts. 

“Given all the nuances and complexities with all the dynamics at play during that event, it is always useful to step back and have the opportunity to provide some basic facts of how things actually happened,” Guillermo Bautista Alderete, CAISO director of market performance and advanced analytics, said during a Sept. 27 presentation to the Western Energy Imbalance Market’s Regional Issues Forum (RIF).  

“But in order to reach that point in the discussion, it is critical that we first differentiate between the fact and the myth,” Alderete said.  

The cold snap over the Jan. 12-16 Martin Luther King Jr. holiday weekend saw record low temperatures along with historically high peak demand, prompting five different balancing authority areas (BAAs) to declare energy emergency alerts. Stressed grid conditions also produced price separation between the Northwest and California, with extremely high bilateral prices in the Northwest and at the Malin intertie in particular.   

Central to the dispute over the event was CAISO’s role in supporting the Northwest during extreme weather conditions, as the disagreement quickly became a proxy for the broader competition for members between the ISO’s Extended Day-Ahead Market (EDAM) and SPP’s Markets+. (See NW Cold Snap Dispute Reflects Divisions Over Western Markets.) 

A Feb. 8 report by the Western Power Pool found that while CAISO and other California BAs exported nearly 3,000 MW of energy to the Northwest, they also were net importers, suggesting the Desert Southwest and Rockies regions — and not California — were the origin of most of the Northwest’s supporting imports.  

That was followed by a Feb. 23 letter from the Portland, Ore.-based Public Power Council (PPC) to Bonneville Power Administration CEO John Hairston, which critiqued the ISO’s allocation of congestion revenue rents (CRRs) during the event. The PPC wrote that “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.” 

In a March 6 report, Powerex expanded on the CRR complaint and even called on Northwest entities to develop ways to circumvent flowing energy through California, while CAISO that same day issued its own 80-page report defending its actions during the cold snap and explaining the mechanisms used by the WEIM to move power around the grid.    

‘Myth Busting’

Alderete’s Sept. 27 “myth-busting” presentation to the RIF drilled further into the CRR issue, offering a series of seven “facts” and “myths” about what occurred and focusing on the congestion occurring at Malin and on the California-Oregon Intertie (COI) — the main interface between BPA and the ISO. 

The first “myth” Alderete addressed was the assessment that the ISO unilaterally decides on Malin limits to influence congestion. He emphasized that both BPA and the ISO are path operators on the COI and that there is an agreement between the two operators to have a “coordinated operation of the path” and “always enforce the most limiting constraint on the path.”  

According to Alderete, this first “myth” set the stage for the second one: that the ISO directly influenced day-ahead congestion on the Malin intertie. His presentation said the day-ahead congestion occurred “simply because the volume of exports requested for the Northwest exceeded the full Malin capability. Exports at Malin were twice as much as the full Malin capacity, and through the day-ahead market, the ISO positioned internal supply economically to support exports to the Northwest.”  

A third “myth” further perpetuated the belief that CAISO limited COI flows to influence congestion, but Alderete said that COI transfer capability during the MLK weekend was fully available and used in the day-ahead market for the share of the line operated by the ISO.  

“Here is the simple fact for these critical days of the MLK weekend: There were no derates on the Malin intertie. The full capacity of the intertie was used and made available in the day-ahead market,” Alderete said. “I can see how this myth could have been created out of confusion and maybe not appreciating the time frames of the event, and I can clarify that, specific to the MLK weekend, there were indeed weather-related forced outages in the BPA area, and those eventually resulted in derates to the path.”  

But the forced outages and derates affected only the real-time market, Alderete said.  

Delving further into the weeds, Alderete contested the “myth” that CAISO “charged excessive prices to exports flowing to the Northwest, reiterating that congestion prices on Malin were set by export bids, which reflected the price exports were willing to pay to flow.  

Alderete also provided additional color to the process of allocating congestion, saying that while a fifth “myth” holds that parties outside the ISO market have a right to day-ahead congestion revenue, the fact is that it’s sourced “only from re-dispatch of participating resources in the ISO market, including exports.”  

CAISO doesn’t have access to resources outside of its market, such as those north of Malin, to re-dispatch and alleviate congestion on ISO constraints, meaning that the sixth “myth,” that CAISO collected congestion rents on all Malin capability, is incorrect. 

“Congestion on Malin is only collected for the capacity made available to the market, lower than the full capability,” the presentation read. “The ISO operates two-thirds of COI capability; only that portion will be managed in the ISO market with Malin intertie.” 

The final and “biggest myth” that caused significant concern among some Western entities was that CAISO kept all $100 million of day-ahead CRRs collected on the Malin intertie. But Alderete emphasized that CRRs are given to their holders and that any surplus is allocated to demand and exports. Because the Malin capacity wasn’t fully exhausted in the CRR release, over $50 million in surplus congestion rents were allocated to measured demand. 

Alderete’s presentation came after a group of Markets+ supporters released a series of “issue alerts” favorably comparing the SPP day-ahead market with the EDAM. The latest alert, focused on market seams, covered the congestion rent subject. (See Markets+ ‘Equitable’ Solution to Seams Issues, Backers Say.)   

Alderete told RTO Insider in an email that the ISO will continue the conversation about the issue at the RIF’s October meeting, for which an exact date has not yet been announced.  

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BOEM Postpones Oregon Offshore Wind Auction

The U.S. Bureau of Ocean Energy Management has postponed its Oct. 15 Oregon offshore wind energy auction due to limited commercial interest. 

The move marks the second scratch out of the four auctions BOEM had scheduled in 2024 — the Gulf of Mexico auction targeted for September also was called off, also due to lack of competitive interest. 

BOEM canceled the Gulf sale outright but held out the possibility that the Oregon sale could go forward in the future. 

Five companies had been qualified to participate in the auction of two lease areas off the Oregon coast, but only one submitted bidding interest. 

The Oregon plan stands out as particularly controversial amid the growing pains and opposition facing the offshore wind industry in the United States as the Biden administration and some states try to build a new emissions-free power sector. 

BOEM’s plans for Oregon met with the familiar concerns voiced by the fishing industry, but it also drew a federal lawsuit from tribal nations trying to block the auction and a plea from the state’s Democratic governor to pause the initiative. 

Gov. Tina Kotek wrote to BOEM Director Elizabeth Klein asking that BOEM halt all leasing activities off the Oregon coast and terminate the auction. 

Kotek in her Sept. 27 letter said Oregon would withdraw from the BOEM Oregon Intergovernmental Renewable Energy Task Force to ensure the state’s interests are protected and to be certain there is adequate time to complete the state’s road map. 

She expressed disappointment in BOEM’s “accelerated process” over the past year and said she remains convinced offshore wind holds exciting promise for the nation’s clean energy future. But if it is built in Oregon, Kotek said, it would have to be done “the Oregon way.” 

BOEM in its Sept. 27 postponement announcement did not allude to the opposition. It emphasized that the auction was the result of engagement with the task force, including coordination with the state government, and said it would continue to collaborate as it determined the prospects of rescheduling the auction. 

Offshore wind power development has been a signature initiative of the Biden administration; all 10 of the BOEM project approvals have come in the past 40 months. 

This initiative has run up against sharp increases in the already-high cost of construction, shortcomings in the infrastructure and ecosystem needed to support the endeavor, project delays and cancellations, and extensive pushback from people who do not want to look at massive wind turbines or who fear their impact on the sea and its ecology. 

The Confederated Tribes of the Coos, Lower Umpqua and Siuslaw Indians sued BOEM in federal court Sept. 16, seeking to halt the auction. They praised BOEM’s Sept. 27 decision, saying they would reconsider their lawsuit and would engage with the state and federal governments to ensure tribal interests were addressed before future lease sales were considered. 

The Midwater Trawlers Cooperative said Oregon’s seafood industry, tribes and coastal communities were breathing a “sigh of relief” over the “welcome news.” 

The BlueGreen Alliance also applauded BOEM’s decision, explaining that offshore wind is a potentially critical tool for the state to meet its 100% clean energy goals by 2040 but that creating the infrastructure needed to support it would take time. 

Oceantic Network supported BOEM’s decision, saying it would allow time for technologies and supply chains to develop and saying it was confident Oregon soon would join other states in the embrace of offshore wind. 

The organizations’ choice of words aligned squarely with their positions: BlueGreen and Oceantic said the auction was “paused” and “delayed,” respectively, while the tribes and fishers said it was “canceled.” 

Any wind farms built in the two Oregon lease areas would need to employ floating turbines, a further complicating factor. While the fixed-bottom towers being installed in shallower waters along the Northeast coast benefit from a 30-year history worldwide, floating towers are only now beginning to be deployed at scale in areas too deep for fixed-bottom technology. 

BOEM had planned four auctions this year: Central Atlantic, Gulf of Maine, Gulf of Mexico and Oregon. 

Only one company expressed in interest in participating in the Gulf of Mexico auction. (See BOEM Cancels Gulf of Mexico Wind Lease Auction.) 

Seventeen entities were deemed legally, technically and financially qualified to bid in the Aug. 14 Central Atlantic Auction; six submitted bids for two leases areas. (See Dominion and Equinor Win OSW Lease Auction.) 

Fourteen entities are deemed qualified to participate in the Gulf of Maine auction, which is scheduled for Oct. 29. (See BOEM Announces Gulf of Maine Offshore Wind Lease Sale.) 

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NYISO: Large Load Flexibility Eliminates 2034 Shortfall Concern

NYISO made significant updates to its assumptions as part of its final Reliability Needs Assessment, which now shows no concern of a capacity deficiency and a loss-of-load expectation of less than 0.1 in 2034.

The dramatic change came from considering certain large loads as flexible, with the ability to reduce total consumption during summer and winter peaks by about 1,200 MW, the ISO told the Electric System Planning Working Group and Transmission Planning Advisory Subcommittee on Sept. 27.

“Based on recent operating experience and outreach to load developers, cryptocurrency mining and hydrogen-production large loads are considered as flexible during peak load conditions,” NYISO said. “This type of load is assumed to be more price responsive and likely to participate in demand response programs than other loads.”

The change in assumptions reduced the forecasted LOLE in 2034 from the preliminary 0.289 that the ISO expected in July to 0.094. NYISO had warned of a potential shortfall of as much as 1 GW in its preliminary results in July. (See Prelim NYISO Analysis: 1-GW Shortfall by 2034.)

“We feel comfortable in certain large loads, primarily like cryptocurrency and hydrogen-producing large loads, to consider them flexible,” said Ross Altman, senior manager of reliability planning for NYISO. “When you have peak load conditions due to either price responsiveness or participation in demand response programs, they would curtail under peak conditions.”

Altman said semiconductor plants, other data centers and most other large loads were not assumed to be flexible.

Several stakeholders asked whether the flexible loads also were modeled as special-case resources formally enrolled in the DR program. Altman replied they were not, merely that they were assumed to be price responsive in some manner.

One stakeholder asked whether there was anything binding cryptocurrency miners to stay as cryptocurrency miners. He made the point that the servers could be put to other, less flexible uses than arbitraging the cost of energy against the purported value of the currency.

“If one or two of them change their use case, it’ll produce a very different outcome in this study,” they said. “You’ll lose that flexibility.”

“That is true,” Altman said. “Hold on to that thought. I’ll show scenarios that will show what things change on the higher end of the forecast, which includes large loads that are not flexible.”

NYISO stressed that “there is a lot of uncertainty about key assumptions over the next 10 years.” In a high-demand forecast risk scenario, the LOLE would jump to 2.744. The delay of the Champlain Hudson Power Express transmission project also is a concern.

“This still seems to be somewhat gambling,” another stakeholder said. “If these loads aren’t in the SCR [program] or they’re not participating in the emergency demand response program, unless you have a tariff or contract under a dynamic load management program, you don’t have any commitments to them to vary their load.”

The working group will review the full draft Reliability Needs Assessment report on Oct. 4. The Operating Committee and the Management Committee will review and vote on the final report on Oct. 17 and 31, respectively, and the Board of Directors will review and post the final report in November.

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NYISO ICAP Working Group Briefs: Sept. 24, 2024

Demand Curve Reset and Transmission Security 

NYISO’s Market Monitoring Unit, Potomac Economics, presented its recommendations for addressing what it calls inefficient market outcomes caused by setting locational capacity requirements based on the transmission security limit (TSL).  

The MMU told the Installed Capacity Working Group at its meeting Sept. 24 that the current rules overvalue surplus capacity, setting “inefficiently high prices” while also overcompensating resources that don’t help satisfy transmission security requirements.  

“We focused in on the last couple of years here,” said Joe Coscia, a director at Potomac Economics. “It’s possible that the current LCR is quite a bit higher than it would otherwise be as a result of the TSL. … We expect that divergence to grow in the coming years with the entry of [the] Champlain Hudson [transmission project] and other resources like offshore wind as well.” 

The Monitor first made the recommendations in its 2023 State of the Market report, after NYISO had changed how it calculates the TSL floor. 

“Large resources and SCRs [special-case resources] are overcompensated when the LCR of their locality is set at its TSL floor,” it said in the report, released in May. “This is because the presence of these resources causes the TSL floor to increase, so they provide less net supply towards meeting capacity requirements than they are paid for in the capacity market.” 

Thus, the MMU recommended paying resources for capacity based on the requirements they actually contribute to meeting. SCRs should be compensated at the price that would prevail in their locality absent the TSL floor, while large, intermittent and storage resources should be paid the full capacity price for the portion of their capacity that does not cause the TSL floor to increase and the capacity price that would prevail absent a TSL floor for the rest of their capacity. 

Coscia said bulk electrical consumers would save roughly $380 million if the Monitor’s recommendations were implemented. The payments for reliability assurance and transmission security should be paid for and determined with separate curves, he said. Implementing sloped demand curves that reflect the marginal value of capacity for transmission security would avoid excessively high prices. 

Multiple stakeholders representing the generation sector asked whether this suggestion would be compatible with the proposed peaker unit being a storage resource for the upcoming demand curve reset. 

“I’m thinking through a lot of how you would set one, particularly with a two-hour battery, and I’m getting a lot of circular reference errors in my mind while thinking through it,” said Shawn Picard, vice president of engineering for TigerGenCo, which operates in the Bayonne Energy Center in New Jersey.  

“The short answer for that is that you put in a different value for the CAF [capacity accreditation factor] [than] is used in the model, and you would get a different value if you assume that the battery, or any of the other technologies, would have a different CAF for [transmission security] than what it has for [resource adequacy],” Coscia answered. “I just don’t want to speculate on what that value might be.”  

Others brought up that making a separate demand curve for transmission security would probably involve creating additional proxy units and make the whole system more complicated. Howard Fromer, director of regulatory affairs for TigerGenCo, asked how real the savings to consumers were that Potomac had calculated. 

“Did you take into account the potential that what you’re ending up doing is creating this much more complicated system and simply shifting payment dollars from the market to subsidies?” Fromer asked. “How much of this $380 million is real versus just a shift, and we just end up having to pay a higher incentive to attract those resources?” 

“I think our position is that it plays a useful role in sending signals accurately: What are the subsidy values that different resources require?” Coscia said. “It may have an effect on what policy-sponsored projects come in based on how much they can get from the market, or from other sources of payment.” 

Final Demand Curve Reset Recommendations

Both NYISO and its consultants presented their final recommendations for the demand curve reset for a last look before stakeholders make oral arguments to the Board of Directors next month.  

Some changes were made to assumptions in response to stakeholder feedback, including the following: 

    • Peak load window hours for the battery energy storage system (BESS) peaker unit were updated to reflect the seasonal periods for 2024-2025. 
    • Voltages assumptions for the BESS were revised downward for all zones outside Long Island. 
    • Operations and maintenance estimates were revised to include land lease payments for the construction period.  
    • Sales tax was added to O&M expenses.  
    • Costs associated with the mortgage reporting tax were added. 

Fromer asked why the consultants had apparently ignored FERC precedent of discretionary programs not being available for offsets for potential developers. He said that when his company built the last peaker plant in New York City, it could not get an exemption. 

Daniel Stuart, a manager at the Analysis Group, replied that they had tried to come up with a reasonable scenario to model that might fit a potential developer. 

“We do think it’s reasonable and perhaps standard for new developers seeking to build batteries or gas turbines in New York,” Stuart said. “That is the logic we applied for the mortgage reporting tax.” 

Fromer and other stakeholders brought up several other issues they felt had been left out, including investment tax credit eligibility, whether a battery system would need to be removed at the end of a land lease, government incentives and future cost reductions. Analysis Group members said that they had not ignored or dismissed these suggestions but that not all of them were convincing enough to warrant revisions. 

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SPP’s Desselle to Retire After 18 Years at RTO

Michael Desselle, SPP vice president and chief compliance and administrative officer, is retiring after 18 years with the RTO and 40 in the industry. His departure will be effective Jan. 2. 

“We’ll definitely miss Michael,” SPP CEO Barbara Sugg said in a Sept. 30 statement. “His dedication to SPP is clear. He’s respected by his peers, as exemplified by his service as chairman of the Board of Directors and CEO of the North American Energy Standards Board. We wish him the best in his well-deserved retirement.” 

Mike Riley, SPP senior director and deputy general counsel, has been promoted to vice president of corporate services and chief compliance officer to fill Desselle’s position. He begins a transition period Oct. 1. 

Attorneys Tessie Kentner and Chris Nolen have been named associate general counsels with Riley’s promotion.

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Flores, Heeg Named to Lead ERCOT Board

ERCOT’s Board Selection Committee has designated Bill Flores and Peggy Heeg as the Board of Directors’ chair and vice chair. Previously the board’s vice chair, Flores replaces Paul Foster, who announced he was stepping down as chair in June. Flores has been serving as interim chair since then. 

Flores, Heeg and Foster were among the first independent directors named to the board after legislation broke up the previous hybrid structure — a mix of independent members and market participant representatives — in the wake of the disastrous February 2021 winter storm. Board members now are required to be Texas residents with executive-level experience in finance, business, engineering, trading, risk management, law or electric market design. 

Thomas Gleeson, chair of the Public Utility Commission that oversees ERCOT, said in a Sept. 30 statement that Flores and Heeg are “outstanding choices.” 

“Both joined ERCOT at a pivotal time and have worked tirelessly to ensure grid reliability,” he said. “I look forward to continuing our work to strengthen grid reliability.” 

Flores is a corporate governance professional who represented Texas’ 17th congressional district from 2011 to 2021. 

The Selection Committee also announced second three-year terms for five board directors, including Flores and Heeg. Carlos Aguilar, John Swainson and Julie England will begin their terms by Jan. 1. 

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CAISO Passes Initiatives to Address Meter Data Reporting, Expand Trading

CAISO on Sept. 26 passed two separate initiatives: one that removes penalties for certain meter data issues, and another that expands bilateral trading in the Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM).

The first proposal deals with small meter data reporting inaccuracies that the ISO pointed out could be prompting unnecessary penalties. Those inaccuracies, despite being small, trigger full investigations but have minimal impact on settlement outcomes, Becky Robinson, CAISO director of market policy development, told the ISO’s Board of Governors and Western Energy Markets Governing Body at their joint meeting.

The proposal also aims to address the concern that scheduling coordinators (SCs) may lack sufficient incentive to submit demand response baseline data, as well as identify certain requirements that pose an unnecessary administrative burden to SCs and the ISO.

Kathy Anderson, senior manager of transmission and markets at Idaho Power, presented an example of a meter data error the utility experienced to help demonstrate the issue to the board and Governing Body.

When Idaho Power joined the WEIM in 2018, the metering for a 19.5-MW resource inadvertently was set up incorrectly in the system, Anderson explained.

“At the time, we didn’t realize that the generator meter was actually already compensated for line losses, so we programmed the line losses into our energy accounting system,” Anderson said. “This resulted in subtracting more losses than we should have for the actual generator value.”

The magnitude of the issue was relatively small, calculating out to an hourly average error of about 0.37 MW, and was fixed after Idaho Power discovered it. However, because of the tariff violation, the utility was fined $639,000.

“We felt this was excessive, given the magnitude of the inadvertent error, so we filed at FERC to have the penalty waived, and FERC did approve that penalty waiver request,” Anderson said (EL23-94). (See FERC Waives Nearly $2M in CAISO Data Reporting Penalties.)

Following the incident, Idaho Power expressed to CAISO that it felt the tariff had a “disproportionate penalty design.” To address the issue, the utility proposed establishing a materiality threshold for incorrect meter data penalties, where inaccuracies less than 3% or 3 MWh won’t be penalized.

“We feel comfortable with this change, because we feel that small meter data corrections really don’t rise to the level of warranting a penalty or the need for a costly investigation, which is a time-consuming process for both staff and the market participant,” Robinson said.

The proposal also recommends establishing due dates and new penalties to incentivize timely DR monitoring data submittal.

“The Department of Market Monitoring has observed some significant and ongoing problems with timely monitoring data submittal, given the lack of well-defined deadlines,” Robinson said.

Finally, to ease administrative burden, the proposal introduces a 30-day period where the ISO waits to assess penalties and streamlines the investigation process.

Robinson indicated that there was broad stakeholder support for the proposal, and the board and Governing Body voted to pass it unanimously.

Inter-SC Trades

The board and Governing Body also unanimously passed a proposal to streamline and expand inter-scheduling coordinator trading to the WEIM and EDAM.

The initiative was first introduced in August and moved through the stakeholder process expeditiously. (See CAISO Kicks Off New Initiative to Streamline Bilateral Trading.)

Inter-SC trading is an optional market feature that facilitates settlement of bilateral contracts between SCs. It was already used in the ISO’s balancing authority area, but not in the WEIM or EDAM.

WEIM and potential EDAM participants indicated to the ISO that expanding inter-SC trading “would be a beneficial service to their participation in the regional markets,” Robinson said, and that establishing it would not impose any costly barriers to EDAM implementation in 2026. Stakeholders also expressed that extension of inter-SC trading could support diverse business needs and market participation structures, and help further integrate bilateral markets in the West.

“It provides additional optionality and value to those market participants in the EIM and the EDAM and … it’s something we can implement and integrate with the EDAM implementation efforts,” said Milos Bosanac, CAISO regional markets sector manager.

The proposal also passed unanimously, with broad stakeholder support.

A ‘Distinct Disadvantage’

Members for the West-Wide Governance Pathways Initiative’s Launch Committee also presented the “Step 2” proposal, which was released Sept. 26. (See related story, Pathways Initiative Releases ‘Step 2’ Proposal for Western ‘RO’.)

Step 2, part of the “stepwise” approach to regionalization in the West, would transfer governance authority over existing energy markets from CAISO to a new regional organization (RO).

The proposal seeks to implement “Option 2.0,” which would give the RO full governance authority over the WEIM and EDAM under a single integrated tariff, though an “Option 2.5” also was considered, which would separate the RO tariff from the ISO’s.

While the proposal received general support, some board members felt the presentation was premature.

“We are at a distinct disadvantage that the 128 pages that you released today, we have not been able to read,” board member Mary Leslie said. (The document actually is 133 pages.) “I wish that this were reverse order — that we would have been allowed to read this and then have you here.

“We are very pro creating a Western energy market, but you can understand our situation as board members, that we have a fiduciary responsibility in California and to the CAISO.”

Launch Committee co-Chair Pam Sporborg, of Portland General Electric, reiterated that the process still is underway.

“I think you guys are used to seeing final proposals that are up for a vote, and this is not a final proposal,” Sporborg said. “We are here to offer an overview of our 133-page document and hopefully give you enough grounding to be able to parse through that and bring us your feedback.”

The final proposal is expected in mid-November.

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Nvidia CEO Huang Explains What’s Behind AI’s Energy Demand

As new data centers built for artificial intelligence continually increase the demand for electricity in the U.S., one of the leaders in the field, Nvidia, is touting AI’s ability to increase the efficiency of the grid, as CEO Jensen Huang discussed at the Bipartisan Policy Center on Sept. 27.

In explaining why AI demands so much power, Huang recounted the history of Nvidia and how its approach to computer processing can be applied to the grid.

The company makes the chips, systems and software that have led to the AI boom, but before that became mainstream, it was best known in the video game industry for manufacturing one of the two leading lines of graphics processing units (GPUs) — the GeForce — large chips that can be added to a computer to help it process the now extremely detailed models and 3D images in games.

The standard design for most computers dates back to 1964, called the “IBM system,” which uses a central processing unit (CPU), multitasking, and the separation of hardware and software by an operating system. That basic “general purpose computing” design still is used today, though with massive improvements, Huang said. Around 1993, as video game developers began transitioning from 2D to 3D graphics, Huang and his colleagues realized some problems are so specialized a general-purpose approach does not work well.

“Physics simulations and data processing and computer graphics … image processing — these problems have algorithms inside that are very computationally intensive,” Huang said. “And if we could take that and run it on a specialized processor, on a specialized computer, we could add a chip to the computer that makes it go 100 times faster.”

GPUs focus on those specialized tasks, while the main CPU is reserved for more general tasks. That opened up efficiencies in computing, which let the technology tackle new and more difficult tasks as video game graphics and physics became more advanced. The GeForce still is going strong for gaming PCs and also is used by Nintendo’s Switch console, Huang noted.

“Then one day, artificial intelligence found us, and so accelerated computing … was an observation about the future of computing that turned out to be right,” Huang said.

Queries of artificial intelligence use more energy than traditional internet searches, and it takes significant energy for an AI network to “learn.”

“The reason why it consumes a lot of energy is that the artificial intelligence network, through trial and error, is trying to figure out how to predict something, and it’s recognizing patterns and relationships among tons and tons of information,” Huang said.

Eventually, AI networks comb the datasets they are trained on enough so they understand them and can make predictions based on them. “These data centers could consume, today, maybe 100 MW,” Huang said. “And in the future, it’ll probably be … 10 times, 20 times more than that.”

Those massive loads do not have to be built in one place, Huang said. Data centers can be built where energy supplies are plentiful. (See Industry Considers Building its Own Generation to Decarbonize.)

“There are places in the world where we have excess energy,” Huang said. “It’s not necessarily connected to the grid. It’s hard to transport that energy to population, but we can build a data center near where there’s excess energy and use the energy there.”

Siting new data centers in energy-rich areas is one way of getting around the issue of interconnecting resources to the grid and transmitting energy to population centers, Huang said.

But the promise of AI could lead to more efficient use of energy in other applications, with Huang pointing to work Nvidia is doing around weather forecasting that will make that process much more efficient compared to the super computers used now.

Making the grid smarter is another application for AI that could help save significant energy, he said. AI could help integrate sustainable energy, operate two-way vehicle charging and find faults on the grid so they can be fixed before they lead to a reliability lapse.

The growth in data centers has given a shot in the arm to nuclear power, with Constellation Energy recently announcing a deal with Microsoft that will reopen the recently retired reactor at Three Mile Island. (See Constellation to Reopen, Rename Three Mile Island Unit 1.)

“Nuclear is going to be a vital, integral part of this,” Huang said. “No one energy source will be sufficient for the world, and so we’ll have to find that balance.”

Efficiency has fueled Nvidia’s success, with its approach using far less energy for complex tasks than standard, general-purpose computing, he added. Efficiency is going to be key to meeting all the new demand going forward too.

“I would really love to see our power grid be smart today,” Huang said. “Our nation’s power grid was built a long time ago because we’re one of the earliest countries to become prosperous, and that power grid could benefit from the insertion of artificial intelligence and smart technology into it. And that smart grid would … help us properly provision technology to the right places.”

A Constellation executive asked Huang whether he agreed with some who have argued that new data centers should add clean power to the grid, as opposed to using what already is available for their purposes. The largest nuclear plant owner, in addition to reopening Three Mile Island, is interested in co-locating data centers with plants that still are in operation, which FERC and other regulators are examining. (See Talen Energy Deal with Data Center Leads to Cost Shifting Debate at FERC.)

Huang answered that, having met with the Biden administration multiple times, the current policy is to allow U.S. companies to build as many data centers domestically as they can, and the administration is interested in helping the sector with permitting and connecting to the grid to make that possible.

“Building the AI infrastructure of our country is a vital national interest,” Huang said. “And although it consumes energy to train the models, the models that are created will do the work much more energy efficiently. And so, when you think about the longitudinal lifespan of an AI, the energy efficiency and the productivity gains that we’ll get from it, from an industry, from our society is going to be incredible.”

AI is one source of demand that does not require 24/7 reliable power, he added. The processes can be shut down for 5% of the year when demand is peaking elsewhere on the grid and then come back to what was being worked on as other users drop off the grid.

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RTOs Continue Glacial Pace at Replacing ‘Freeze Date’

MISO, PJM and SPP have been failing for years to find a suitable replacement for a 20-year-old system reference they use to portion out flow rights on their system — and they don’t appear to be any closer to a solution. 

The three RTOs establish market flows and firm entitlements on jointly managed flowgates using a snapshot of the neighboring systems in 2004 before their seams existed; they refer to it as their “freeze date.” So far, the three grid operators haven’t found a substitute for using a static list of generation resources and transmission service requests that remains unchanged from when Usher’s “Yeah!” topped music charts. 

MISO Independent Market Monitor David Patton has expressed frustration with the three not being able to land on a more suitable system representation. 

“The problem is we’re so far beyond the freeze date that it’s untenable,” Patton told the MISO Board of Directors’ Markets Committee on Sept. 17. 

Instead of adhering to their tariffs and joint operating agreements, the RTOs have resorted to patchwork processes to oversee flow entitlements, he said. The “impossibly stale” depiction of the systems is leading the grid operators to violate their rules, he argued. 

Patton indicated to the committee that talks between the three RTOs to find a substitute for the freeze date recently broke down.

“MISO’s put the most reasonable negotiations on the table. MISO is not the problem here,” Patton said, avoiding naming any party who might have been difficult in negotiations. “I want to alert you that something needs to be done about this. … They’ve been negotiating for a decade.” 

Patton implied that if MISO had agreed to some terms contained in the proposed agreement, it would have resulted in unreasonable outcomes for its members. 

WEC Energy Group’s Chris Plante characterized RTOs’ inability to replace the freeze date as one of the seams issues that “seems like low-hanging fruit that refuses to fall off the tree.” 

“We’ve been trying to resolve that issue for more than a decade,” Plante said during a meeting of MISO’s Advisory Committee on Sept. 18. He said the issue is emblematic of how elusive solutions to seams issues can be. 

SPP Manager of Interregional Strategy and Engagement Clint Savoy confirmed before the RTO’s Seams Advisory Group on Sept. 11 that a comprehensive freeze date solution was voted down. He said the initiative is now being reworked among the RTOs for future evaluation. 

PJM also said the RTOs’ Congestion Management Process Working Group is actively working on an alternative solution. The RTO said it believes an “updated model” is needed to “better align current congestion patterns with planning processes while accounting for centralized dispatch.” The current freeze date takes into account “generation dispatch in the historic control areas rather than the current centralized dispatch approaches in the participating markets,” spokesperson Jeffrey Shields said in a statement. 

PJM did not respond to RTO Insider’s request for comment on where solution discussions currently stand and if it viewed any party as making unreasonable demands. 

MISO acknowledged that using the April 1, 2004, date to determine firm rights on flowgates based on pre-market flows is suboptimal. 

“RTO systems have changed considerably over the last 20 years, making it more of a challenge for MISO to balance the needs of our system as well as our neighboring grid operators. MISO recognizes the inherent errors that occur with mapping a 2024 market system back to the historic 2004 framework,” spokesperson Brandon Morris said in a statement. 

MISO said it has proposed a solution “based on approved industry standards,” which is being discussed, though there is no timeline on when it could be implemented. 

Savoy said SPP “remains committed to developing a solution that will facilitate equity, transparency and mutually beneficial outcomes for all involved, including the customers and facilities that we represent as the RTO.” 

However, Savoy added that replacing the freeze date is a complex endeavor “involving numerous parties with diverse interests.” 

“We’re grateful for our partnerships with MISO, PJM and the rest of the Congestion Management Process operating entities, and for the engagement of many of our stakeholders through our Seams Advisory Group. We look forward to sharing more about our approach to this matter in the upcoming joint SPP-MISO Common Seams Initiative meeting in November,” Savoy said in a statement. 

For years, the RTOs kicked around a proposed solution that would have divided flowgate rights by age, with priority given to network resources from 2004 and earlier, followed by network resources after 2004, then transfers between local balancing authorities to make up shortages on a pro rata basis, and finally RTO load served by RTO dispatch. The solution would have increased transfer rights for markets over nonmarket entities, and the seams might have experienced a reduction in nonfirm transfer availability and increased curtailments of nonfirm transfers. 

MISO and PJM had hoped to implement this flowgate merit order by mid-2022. MISO in 2021 said the sticking point was the firm flow limits calculations with nonmarket entities, who said a large increase of firm rights for market entities could increase the need for transmission loading relief. At the time, MISO reported that nonmarket entities party to the RTOs’ Congestion Management Process were still resistant to changes that would affect firm flows in the region. (See MISO, PJM Eye Nov. Freeze Date Defrost.) The nonmarket neighbors remain concerned that an increase in firm limits for post-2004 network resources could lead to more curtailments for those outside the markets. 

From MISO and PJM’s Joint and Common Market meetings in the last few years, the RTOs appeared to be ready to use a new model in their respective Energy Management Systems. Last year, the two said they were readying a mock analysis tool to test scenarios. 

The RTOs also completed a white paper on the freeze date in 2021; at the time, it was a diplomatic turnaround from late 2019, when staff said they were mulling filing a proposed solution that would all but certainly be opposed by nonmarket parties and leave it up to FERC’s discretion.