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November 1, 2024

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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. 

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FERC Reliability Conference to Highlight Resource Adequacy

FERC’s annual Reliability Technical Conference in October will feature discussions of cyber and physical security threats, resource adequacy, extreme weather and other emerging concerns to grid reliability, according to an agenda posted Sept. 24 (AD24-10).

The commission hosts the technical conference each year to “discuss policy issues related to the reliability and security of the” electric grid, with panelists from across the ERO Enterprise and other industry participants. Panelists at this year’s conference include NERC CEO Jim Robb — who also will deliver an opening presentation on the state of reliability — along with NERC Chief Engineer Mark Lauby and representatives from MISO, ISO-NE, CAISO, Duke Energy and Southern Co.

The 2024 technical conference will be held at the commission’s headquarters in Washington, D.C., on Oct. 16 at 10 a.m. ET. It also will be viewable online.

In the first panel, attendees will discuss a range of challenges facing the electric grid, including the rapid spread of inverter-based resources and distributed energy resources, along with “the increased use and importance of natural gas … for system balancing.” Load growth from severe weather and cyber and physical threats also are on the agenda.

Robb’s co-panelists include Carrie Zalewski, vice president of transmission and electricity markets for the American Clean Power Association; Todd Ramey, senior vice president of markets and digital strategy for MISO; Nelson Peeler, senior vice president of grid strategy, planning and integration for Duke Energy; and Randy Howard, general manager of the Northern California Power Agency.

The second panel will focus on the challenge of maintaining resource adequacy amid “the retirement of existing generation resources, the addition of significant volumes of variable energy resources and rapid anticipated electric load growth” from sources such as data centers. Topics of discussion will include appropriate metrics for capturing resource adequacy risk, the challenges of forecasting the addition of new large loads and whether existing resource adequacy mechanisms can procure enough resources to meet future demand.

Panelists on this session will include Lauby, South Dakota Public Utilities Commission Chair Kristie Fiegen, Data Center Coalition President Josh Levi, Hoosier Energy CEO Donna Walker and CAISO Director of California Regulatory Affairs Cristy Sanada.

At the 2023 event, FERC Chair Willie Phillips and his colleagues focused on cyber and physical security, extreme weather and the power grid’s changing resource mix, with Robb joined by Electricity Information Sharing and Analysis Center CEO Manny Cancel and SERC Reliability CEO Jason Blake, among others. (See FERC Conference Highlights Challenges of Evolving Grid.)

The conference has provided stakeholders with an opportunity for airing frustrations with the ERO’s approach to reliability standards development and enforcement. At the 2021 conference, several participants criticized NERC’s standards process for being inherently conservative and giving significant influence to industry members who will be subject to penalties for noncompliance. (See Cybersecurity, Climate Change Lead FERC Conference.)

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State, Industry Reps Debate Future of Gas at NECA Fuels Conference

BOSTON — In a reflection of broader disagreements across the New England energy landscape, speakers at the Northeast Energy and Commerce Association’s 2024 Fuels Conference presented divergent visions of the role of natural gas in coming decades.  

New England states face significant pipeline constraints limiting the amount of gas that can be transported into the region. That has spurred expensive long-term contracts to secure LNG supply to support the reliability of the gas system during period of peak demand. (See Massachusetts DPU Approves Everett LNG Contracts.) 

Gas demand for electricity generation and for residential, commercial and industrial needs has risen in recent years. That has led the gas industry and some large consumers to call for increased pipeline capacity.  

Matthew Piatek of S&P Global said that though annual gas demand in the Northeast is projected to decline slightly by the end of the decade, peak demand will remain high.  

“The price swings that we see moving forward may be more severe than they have been in the past,” Piatek said. Producers likely will be cautious about increasing supply going forward, and he said to “expect some price repercussions before there’s a supply response.” 

New England’s reliance on LNG likely will continue over the medium term to meet peak demand, Piatek said, but a pipeline expansion could reduce LNG reliance.  

While aggressive deployment of demand-side measures and pilot projects for technologies like networked ground-source heat pumps also could help ease peak demand pressures, “more work needs to be done on the actual commercial viability of different options,” Piatek said. 

Doubling down on natural gas likely would run contrary to state climate mandates. Massachusetts has aggressive sector-specific decarbonization requirements, and natural gas is the main source of emissions from the state’s power and building sectors. Methane leaks — which typically are undercounted in emissions inventories — have a far greater short-term warming effect on the climate than carbon dioxide. 

Conflicts over the future of gas have caused notable tensions among top Massachusetts lawmakers. While the Massachusetts Department of Public Utilities (DPU) has ruled that decarbonization of the state’s gas network likely will be based on electrification, the DPU also has indicated legislative changes are needed to initiate decommissioning of parts of the gas network (DPU 20-80). 

Disagreement over potential legislative changes helped derail negotiations on a wide-ranging climate bill this summer. (See Mass. Lawmakers Fail to Pass Permitting, Gas Utility Reform.) The debate also has played out in other states across the region; both Maine and Rhode Island have ongoing studies into the future of natural gas. 

Marc Brown of the Consumer Energy Alliance, which represents a wide range of industrial energy consumers including major fossil fuel companies, argued that natural gas “is going to play a very important role in balancing out this energy transition.” 

“I don’t see gas as a transitional fuel, I see it as here for the long term,” Brown added. 

Regarding concerns that new investments in natural gas infrastructure could lead to burdensome stranded costs, Brown said “nobody likes stranded costs, but we should also be concerned about upfront costs” associated with widescale electrification.  

From left: Rich Kassel, AJW; Robin Vercruse, Low Carbon Fuels Coalition; Stephen Dodge, moderator, Clean Fuels Alliance America; Floyd Vergara, Clean Fuels Alliance America | © RTO Insider LLC 

Anastasia Daou, of commercial real estate association NAIOP, echoed Brown’s concerns about upfront costs and said Massachusetts building energy codes finalized in 2023 will increase the cost of new building development.  

“The building sector is feeling a little targeted recently,” Daou said, noting that adding costs to new building projects “is simply going to stop development.” 

Government representatives from Maine and Massachusetts pushed back on the narrative that the states are moving too quickly away from gas.  

“We’re clearly headed toward a future where we are less reliant on natural gas,” said Melissa Lavinson, executive director of Massachusetts’ newly created Office of Energy Transformation. Lavinson emphasized that the state has legislatively mandated emissions limits and that the DPU has directed the state’s electric distribution utilities to pursue “basically an electrification pathway” for decarbonization. 

Maine Public Advocate William Harwood said, “the public expects us to meet those greenhouse gas emission goals,” and it’s the job of lawmakers to cut emissions while keeping energy costs as low as possible, protecting low-income customers and keeping businesses afloat.  

“You don’t have to be paying particularly close attention to understand that there are very serious environmental consequences — along with public health consequences — associated with burning gas within homes,” Harwood said. 

Harwood said states must look ahead when considering new gas investments to minimize stranded costs and must be honest about who will pay for stranded costs when they occur.  

“When we get to that point, there is going to be a huge fight over whether those costs are the responsibility of ratepayers or shareholders,” Harwood said. “I don’t know that there’s a good solution for who pays for stranded costs.” 

Low Carbon Fuel Standards

Also at the conference, several speakers made the case for low carbon fuel standard (LCFS) programs to cut transportation emissions. LCFS policies typically incentivize low-carbon fuels through charges imposed on carbon-intensive fuels.  

LCFS programs targeting transportation emissions have been rolled out in California, Washington and Oregon but have yet to gain significant traction on the East Coast.  

Rich Kassel, a partner at consulting firm AJW, said an LCFS is “the only program in the transportation sector on the large scale that addresses emissions from existing vehicles.” 

LCFS programs in the West have reduced emissions of local pollutants and particulates due to the cleaner-burning properties of renewable diesel and biodiesel, Kassel said.  

Kassel added that the greatest pollution reductions have occurred in environmental justice neighborhoods and that the equity benefits could be even greater if a small percentage of revenue generated by the program were required to be spent in environmental justice communities. 

“It’s the way you get Exxon to buy electric school buses in West Harlem,” Kassel said.  

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With Final Class Year Approval, NYISO Marks End of an Era

NYISO‘s Operating Committee on Sept. 26 approved the system upgrade facilities (SUF) and system deliverability upgrade (SDU) studies for Class Year 2023 — the last using the ISO’s current interconnection process as it transitions to a new cluster-based approach. 

“Next week marks my 20th year with … NYISO, and in my 20 years, we have worked through all kinds of challenges with the class year interconnection process,” said Zach Smith, vice president of system and resource planning. “The team has been fantastic through all of this, but it really has been tremendous with what we expect to be our final class year as we transition to the new cluster process.” 

The SUF study identifies which interconnection facilities and developer attachment facilities would be required to reliably interconnect a group of projects to the grid under the minimum interconnection standard. The SDU study determines whether each project is deliverable at its requested capacity resource interconnection service level.  

CY23 includes 67 projects. If all are interconnected, the generators would add about 14,000 MW to the grid, while the HVDC projects would inject 1,300 MW. The total cost for developers would be about $2.398 billion. 

Developers have until Oct. 28 to accept their cost allocations. The studies would have to be updated if there are any rejections. 

The first transitional cluster study began Aug. 1.