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October 31, 2024

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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. 

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FERC Grants PGE Extra Time to Prepare for EDAM

FERC on Sept. 26 granted CAISO a waiver allowing Portland General Electric to join the ISO’s Extended Day-Ahead Market (EDAM) a few months beyond the deadline set out in the EDAM’s standard participation agreement (ER24-2444). 

The pro forma EDAM Entity Implementation Agreement on file with FERC allows CAISO and a prospective EDAM participant flexibility to work out a specific start date based on the participant’s needs to prepare for market membership, but it also requires that the date be no later than 24 months after the agreement was executed. 

CAISO and Oregon-based PGE signed the agreement July 2, but the utility had asked to join the EDAM in fall 2026, which would put its start time outside the two-year window. 

In requesting the waiver, CAISO argued that PGE would need more than 24 months from the effective date of the agreement to implement the technology needed to start participating in the EDAM, but that PGE’s early signature would allow the utility and the ISO to immediately begin work on implementation issues in parallel with PacifiCorp, which plans to join the market in spring 2026. (See PacifiCorp Fully Commits to CAISO’s EDAM.)   

The ISO said granting the waiver would allow for joint implementation meetings and early engagement with vendors that otherwise would not be possible. PGE then would be able to complete other readiness tasks required for it to be fully equipped to join the EDAM in fall 2026. 

In its comments on the request, PGE said the waiver would be crucial to the success of its entry into the EDAM because of the complexity of integrating its transmission and technology systems with the ISO’s technology, and that the complexity could best be addressed by working in parallel with PacifiCorp. 

In granting the waiver, the commission found  CAISO acted in good faith because it filed the waiver request one business day after the two parties signed the implementation agreement. It also agreed with the ISO that the request was limited in scope because it was a one-time extension of the EDAM entity implementation date for a “discrete” market agreement. 

“Third, we find that granting CAISO’s request addresses a concrete problem; CAISO and Portland General state that more than 24 months from the effective date of the EDAM implementation agreement are needed to complete the work necessary to allow Portland General to start participating in EDAM,” the commission wrote. “Specifically, the parties represent that [the] waiver will allow Portland General to participate in parallel and joint implementation work with PacifiCorp, which will support Portland General’s ability to begin EDAM participation in the fall of 2026.” 

The commission also determined that granting the waiver would not have “undesirable consequences” or harm third parties. 

“Instead, [the] waiver will allow CAISO and Portland General sufficient time to complete their work and coordinate with PacifiCorp,” it wrote. 

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Pathways Initiative Releases ‘Step 2’ Proposal for Western ‘RO’

The West-Wide Governance Pathways Initiative on Sept. 26 released its “Step 2” draft proposal for dividing up functions between CAISO and the new “regional organization” (RO) that initiative backers are seeking to create to oversee the ISO’s Western real-time and day-ahead markets.

The draft proposal calls for the RO to launch in the form of the “Option 2.0” structure discussed in Pathways meetings, one in which the RO would serve primarily as a “policy-setting” body around market rules for the Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM).

The plan stops short of adopting “Option 2.5,” which would have the RO take on more of CAISO’s market functions and legal responsibilities — but also the accompanying financial and legal risks.

But Pathways backers — and the proposal itself — are leaving open the potential for transitioning to the second option once the new entity is established.

“This is really the recommendation for creating a new independent entity that can have sole authority over [CAISO] market services,” Kathleen Staks, co-chair of the Pathways Launch Committee, said during a joint meeting of the CAISO Board of Governors and Western Energy Markets (WEM) Governing Body shortly after release of the proposal.

“It was very important to make sure that we were communicating with the West that we intend for this thing to continue to be able to grow as the West wants it, as utilities demand it and stakeholders demand it. We need this new regional organization to be able to add market services,” said Staks, who is executive director of Western Freedom.

A fact sheet accompanying the proposal notes the plan (emphasis Pathways’) “is not a consensus document but a draft proposal with wide-ranging recommendations to solicit additional stakeholder feedback.”

According to the fact sheet, under Option 2.0, the RO “will have full authority over market rules, sole Federal Power Act Section 205 rights and ultimate authority over associated business practice manual provisions.”

Under CAISO’s existing tariff, the ISO’s board and WEM Governing Body share joint authority over the WEIM and EDAM. In August, both bodies voted to implement the Pathways “Step 1” proposal, which grants the WEM body “primary” authority over the markets, a tariff change still pending approval by FERC. (See CAISO, WEM Boards Approve Pathways ‘Step 1’ Plan.)

Option 2.0 would elevate that “primary” authority to “sole” authority and shift the oversight to the RO, which would effectively assume the role of the Governing Body.

“Sole 205 rights in Step 2 means that the CAISO board does not have any lingering unilateral authority, which exists today and persists in Step 1 in some exigent circumstances, to make a 205 filing at FERC that unilaterally imposes the CAISO board’s policy view regardless of the views of the other body,” the proposal says.

The only area for which CAISO’s board would retain sole 205 authority is for rules “applicable specifically” to the ISO’s balancing authority or grid.

But the proposal has the ISO continuing to perform day-to-day market operations “within the scope of its existing corporate authority, with varying levels of input from the RO.” Under the plan, RO and CAISO rules would also reside within a “single integrated tariff,” and the ISO would remain the counterparty for existing market contracts.

“One premise of the Pathways Initiative is that consumers across the West would be better served by drawing on the existing CAISO software, hardware, facilities and expert operators, rather than designing, building and paying for this infrastructure and expertise from scratch,” the proposal says. “This premise goes hand in hand with the notion that the widest possible integrated footprint, inclusive of California, would be better for consumers than the alternative.”

Because Step 2 grants the RO sole authority over CAISO markets, its implementation will require a change to California law, according to legal analysis performed by law firm Perkins Coie, an adviser to Pathways. The campaign to begin lobbying lawmakers was already in evidence this past summer, but Pathways supporters say the effort will begin in earnest with the next legislative session starting in January 2025. (See California Labor Groups Affirm Support for Pathways Proposal and California Energy Officials Pitch Pathways Plan to State Senators.)

Passage of a bill would put the ball back into CAISO’s court.

“The ultimate tariff changes will have a [CAISO] stakeholder process, but that wouldn’t begin until after a bill passes in California,” Staks told RTO Insider in an email.

Structure

At 133 pages, the Step 2 draft proposal goes well beyond governance functions to detail the proposed structure of the RO, which would be incorporated as a 501(c)(3) nonprofit corporation in Delaware and maintain its principal place of business in Folsom, Calif., near CAISO’s headquarters. It would be overseen by a seven-member board of directors selected to meet FERC’s independence requirements.

The proposal’s fact sheet says the RO’s “articles of incorporation, bylaws and other corporate documents will center on public interest protections and transparency,” while a Public Policy Committee of the board “will engage with states, local power authorities and federal power marketing administrations about potential impacts to state, local or federal policies before final board adoption of a tariff change or an initiative through the stakeholder process.”

The proposal additionally calls for the RO to engage with the WEIM’s existing Body of State Regulators and establish a Consumer Advocate Organization and Office of Public Participation. It would also create a joint structure for CAISO’s Department of Market Monitoring to report to both the ISO and RO boards.

The draft plan also outlines formation of the RO’s sector-based Stakeholder Representatives Committee (SRC), “which will serve as the primary body responsible for overseeing and guiding the development of new initiatives.” The proposal describes the SRC’s three-part process, consisting of issue identification and prioritization, discussion and solution development, and RO board approval. (See Comments on Western RO Stakeholder Plan Show Complexity of Effort.)

“By incorporating sector-based representation, the SRC will ensure that a balanced range of perspectives is considered, promoting collaboration and consensus through sector-specific discussions. This structured approach will enable stakeholders to identify and address key issues collectively, thereby influencing policy development outcomes in a meaningful way,” the proposal says.

The exact constitution of the SRC is still a work in progress, and the Launch Committee has scheduled an additional meeting to discuss the subject on Oct. 7.

Planting a Seed

The proposal additionally calls for the RO to consider transitioning — “over a defined period of several years” — to Option 2.5 after performing more analysis and gathering stakeholder input on making such a move. Under that option, the RO would take on more of CAISO’s market functions and legal responsibilities, and potentially reorganize itself under its own tariff while maintaining a vendor contract with ISO as market operator.

“In Option 2.5, deeper division of liability between two corporations, overall higher cost both to the CAISO and RO, and to stakeholders as a whole, plus the extensive negotiations we anticipate will be involved to rework dozens of pro forma regulatory contracts in Option 2.5, prevent us as a committee from strongly (as opposed to tentatively) recommending Option 2.5 at this stage,” the proposal says.

A financial table in the proposal shows the RO’s estimated annual operating costs under Option 2.5 would be nearly $23.9 million, including $17.7 million for in-house staffing, compared with $13.7 million under Option 2.0, which would incur about $10.6 million for labor.

The proposal calls for the RO board to perform “a deeper feasibility analysis, with stakeholder input, to assess the costs, benefits, possible expanded market functions, implementation details of how to achieve the additional corporate independence and responsibility, and to determine whether a departure from Option 2.5 is warranted.”

The analysis should be one of the board’s “initial priority tasks,” to be started within nine months of the RO’s formation, the draft adds.

“The idea here is that we will plant a seed. … We’re working with stakeholders and with you to plant the seed into fertile soil and to help water it and help it grow,” Launch Committee Co-Chair Pam Sporborg, of Portland General Electric, said during the CAISO board meeting. “But we do envision that as this organization takes root, that it will grow into what we call Option 2.5, [which] will have expanded authority and take on the actual responsibility, including a lot of the liability and compliance obligations associated with running the market.”

The Launch Committee will hold a stakeholder meeting to discuss the draft proposal on Oct. 4 and is accepting written comments on the plan until Oct. 25. It expects to release a final recommendation the week of Nov. 15.

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California GETs Bill Gets Newsom’s Signature

California Gov. Gavin Newsom (D) has signed a bill that proponents say will speed the deployment of grid-enhancing technologies — techniques that can rapidly boost grid capacity and increase the use of renewable resources. 

Senate Bill 1006 was signed into law Sept. 25. It will require utilities to study the feasibility of using advanced reconductoring and other grid-enhancing technologies (GETs) and submit reports to CAISO, which will review the findings as part of its annual transmission planning.  

A second bill related to GETs is awaiting the governor’s signature. Assembly Bill 2779, by Assemblymember Cottie Petrie-Norris (D), would require CAISO to report any new use of GETs that it deems reasonable, along with the cost savings and efficiency of that technology, when it approves a transmission plan. 

The report would go to the California Public Utilities Commission (CPUC) and committees in the state Assembly and Senate. 

Newsom’s deadline to sign or veto bills is Sept. 30. If the governor takes no action on a bill passed by the legislature, it becomes law without his signature. 

SB 1006, by Sen. Steve Padilla (D), notes that California must “rapidly and cost-effectively” increase transmission capacity to meet its decarbonization goals. 

While new transmission lines “will absolutely be necessary,” GETs are a way to increase capacity at a fraction of the cost of new lines, Padilla said in a release when he introduced the bill. 

“Grid-enhancing technologies can be installed in months and often pay for themselves within a year based on access to lower-cost generation alone,” Julia Selker, executive director of the WATT Coalition, said in a letter urging Newsom to sign the bill. 

GETs listed in SB 1006 include dynamic line ratings, advanced power flow control and topology optimization, as well as advanced reconductoring. 

Under SB 1006, transmission utilities will have two reports due Jan. 1, 2026. The first will look at the feasibility of using GETs to achieve one or more of the following goals: 

    • Increase transmission capacity. 
    • Reduce transmission system congestion. 
    • Reduce curtailment of renewable and zero-carbon resources. 
    • Increase reliability. 
    • Reduce the risk of igniting wildfire. 
    • Increase capacity to connect new renewable energy and zero-carbon resources. 
    • Increase flexibility to reduce risks surrounding technology and permitting uncertainties in statewide electrical system planning and improve optionality for load-serving entities. 

The second study will evaluate which of a utility’s transmission lines could be reconductored to achieve goals similar to those outlined for the first study, with two additions: reducing line losses and increasing the ability to quickly energize new customers or serve increased customer load. 

Utilities will repeat the first study every two years and the second study every four years. 

Supporters of SB 1006 and AB 2779 include Advanced Energy United. 

The bills “will unlock the potential of these revolutionary grid technologies, enabling us to meet rising power demands while minimizing rate impacts so we can keep the lights on without spending an arm and a leg,” Edson Perez, Advanced Energy United’s California policy lead, said in a statement in August. 

Another bill related to GETs, AB 3246 by Assemblymember Eduardo Garcia (D), died in committee last month. The bill would have streamlined the approval process for advanced reconductoring of existing power lines. 

GETs also are called out in a $10 billion climate-resilience bond measure that California voters will decide in November. (See Calif. Lawmakers Send $10B Climate Bond Measure to Nov. Ballot.) 

SB 867, which sent the bond measure to voters, includes $325 million for clean-energy transmission projects, with preference potentially given to projects that provide multiple benefits, such as reconductoring and other GETs.