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October 30, 2024

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Emilie Nelson Named NYISO COO, Replacing Rick Gonzales

NYISO on Wednesday announced that EVP Emilie Nelson was named COO, replacing Rick Gonzales, who is retiring at the end of the year.

CEO Rich Dewey told stakeholders at an ISO Management Committee meeting that he recommended Nelson to the Board of Directors, which approved the promotion. Nelson will now be responsible for overseeing both the operations and the market mitigation and analysis (MMA) teams.

“I feel that this really positions us well for the future and is a good leadership expansion for Emilie and sets up both our organization and teams for the challenges of the future,” Dewey said during the meeting.

Nelson joined the ISO in 2004 and has been in the industry for almost 25 years. She previously worked for Mirant New York as a power plant performance engineer. During her tenure at NYISO she has held various roles of increasing responsibility on the market monitoring, energy market design and operations teams.

Nelson holds a bachelor’s degree in mechanical engineering from Tufts University, an MBA from Pace University and is a graduate of Harvard Business School’s Advanced Management Program.

NYISO Board Chair Dan Hill said in a statement that “Emilie has built a strong record of performance-driven results in a number of senior management roles throughout her career at the NYISO.”

Gonzales also congratulated Nelson during the meeting, saying she “will bring some great change to the organization by bridging [the operations and MMA] parts together.”

Gonzales, who has been with NYISO since its inception and previously worked for the New York Power Pool, is scheduled to retire on Dec. 31, 2023.

Draft Budget

NYISO presented the MC its draft budget for next year, saying it will total $194.8 million and that $8 million remaining from this year’s budget will be used to make early repayments on outstanding debt.

The 2024 draft budget is roughly $5 million higher than this year’s budget, with much of the growth attributable to proposed increases in consulting fees and staff salaries, which NYISO says are necessary to accomplish next year’s project portfolio. The ISO will also hire for 19 new positions in both the system and resource planning and operations teams next year.

NYISO’s draft budget for 2024 compared to 2023 | NYISO

NYISO already faced stakeholder scrutiny after presenting its final project budget recommendations of $41.62 million for next year, with many balking at the proposed labor cost increases. (See NYISO Proposes $41.62M Project Budget for 2024.)

Stakeholders can discuss the draft budget again in early October before the board reviews it on Oct. 16. The ISO anticipates bringing the final draft to the MC for a vote on Oct. 25.

Seasonal Demand Curves

The MC also approved NYISO’s proposed revisions related to implementing winter and summer demand curves into the next demand curve reset for the 2025/26 capability year.

The ISO’s proposed changes will be part of the next four-year DCR, which regularly updates the parameters for New York’s capacity market, and seek to better reflect seasonal reliability risks and the value that certain resources provide during the competing seasons.

The revisions were previously approved by the Business Issues Committee and will now go before the board for final approval. (See “Seasonal Demand Curves,” NYISO Business Issues Committee Briefs: Sept. 14, 2023.)

August Market Performance

Gonzales delivered the August market performance report during the MC meeting, saying, “we had pretty mild temperatures that were cooler than average and a little less wet than July.”

He noted that August’s year-to-date energy prices are down 56% compared to last year, decreasing from $93.42/MWh in 2022 to $40.13/MWh this year. August’s gas prices were also down 85% compared with last year, and prices at the Transco Z6 NY pipeline touched a low of $1.18/MMBtu.

As in a monthly operations assessment delivered to an earlier Operating Committee meeting, Gonzales highlighted how an unexpected four-day heatwave in early September saw some of the highest demand during the summer and that the ISO will investigate the hot weather phenomenon. (See “August Operations Report,” NYISO Operating Committee Briefs: Sept. 15, 2023.)

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PJM Board Releases Outline of Capacity Market Changes

The PJM Board of Managers has released an outline of several changes to the RTO’s capacity market to be included in a FERC filing slated to be made next month.

In a Wednesday letter, the board stated it built the filing’s structure off the annual capacity market design PJM formed during the critical issue fast path (CIFP) process. The filing would retain the core design of the Reliability Pricing Model (RPM) but rework the capacity performance (CP) construct, how resource adequacy risk is modeled and resource accreditation. The filing is expected to include parallel changes to the risk modeling and accreditation for fixed resource requirement (FRR) entities with a four-year transition period. (See PJM Members Lobby Board Ahead of Expected CIFP Filing.)

The board directed PJM to submit the filing to FERC no later than Oct. 13, with the aim of having the changes effective for the 2025/26 Base Residual Auction (BRA). It notes that components could be grouped together or filed individually to “mitigate the risk of a single component of the filing causing the delay or rejection of the entire suite of enhancements.”

The filing completes the CIFP process the board opened in February but acknowledges stakeholders and PJM raised issues that remain unaddressed under the expected filing, such as a seasonal or more granular capacity market design and shortening the period between the auction and corresponding delivery year. The board’s letter states it expects to receive feedback on the filing and next steps during the next Liaison Committee meeting, scheduled for Oct. 2, and through discussions with the Organization of PJM States Inc. (OPSI). (See PJM Stakeholders Vote Against All CIFP Proposals.)

In reworking the CP design, the board stated that it sought to strike a balance between the risks generators see in taking on a capacity commitment and incentives for them to maintain the capability to perform during an emergency.

The filing would leave the penalty rate unchanged but would revise the annual stop-loss limit to be based on the BRA clearing price; currently, both are derived from the net cost of new entry (CONE). Proponents of basing penalties on the value of capacity argued that it would align the risks generators face with the revenues they earn as a market seller, while opponents argued it would reduce the incentive to perform. A proposal to base both values on the BRA clearing price was endorsed by the Members Committee in May but was not approved by the board. (See PJM Board Rejects Lowering Capacity Performance Penalties.)

The filing also directs PJM to revise its calculation of the market seller offer cap (MSOC) to allow generators to include more cost of risk in their offers even when their net avoidable cost rate (ACR) is zero or negative.

“The ability to express risk in offers is integral to ensuring the optimal set of resources are selected to provide capacity and on its own is not an exertion of market power when those quantified risks are rooted in rigorous, reasonable analysis, as is required by the current resource-specific process,” the board said.

The eligibility for receiving CP bonus payments — which are based on the amount of penalties collected and are distributed to generators that overperformed during an emergency — would be tightened under the board’s filing to go only to committed capacity resources, rather than all generators.

The board rejected proposals to excuse long-lead resources from CP penalties, which argued they are not capable of modifying their generators to be more flexible, saying the current rules incentivize them to be ready for emergencies.

“The board does not believe that self-scheduling of such resources in the anticipation of being required to operate presents a reliability concern for PJM, and to the extent a self-schedule request is actively denied by PJM, it represents a dispatch instruction by PJM and therefore an excusal,” the letter said.

The risk modeling changes would increase the amount of weather history data PJM uses to go back 30 years and using hourly granularity and modeling of correlated outages when evaluating resource adequacy. The board did not, however, adopt PJM’s proposal to zero out the capacity benefit of ties, arguing that doing so requires further consideration. It directed PJM to continue engaging in it with the aim of arriving at a new process of considering the value of imported power during emergencies. The new methodology should be targeted for implementation for the calculation of the 2025/26 installed reserve margin, the board said.

“While the board does not support the 0 MW proposal at this time, the board is concerned that the current process to produce CBOT may no longer produce accurate estimates, given the evolving view of resource adequacy risk and resource adequacy dispositions of neighboring regions,” the letter said.

The board also directs changes to modify the winter deliverability assumptions in resource adequacy risk modeling and accreditation for solar resources to consider system conditions and resource output beyond the hours now studied.

The filing adopts PJM’s CIFP proposal to shift to using a marginal effective load carrying capacity for all resource types, which the board said will improve alignment between market structures such as accreditation, compensation and incentives, with system risk.

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Maryland PSC Approves Infinite Net Metering Credit Accumulation

Ratepayers with their own solar generating projects can reap the financial benefits from accumulating net-metered credits indefinitely under rules approved Wednesday by the Maryland Public Service Commission (PSC) that are set to take effect Sunday.

The rules update the existing 12-month accumulation period, under which the utility reimburses each ratepayer annually for any outstanding credits awarded from electricity fed into the grid when a solar system generated more power than the ratepayer needed.

PSC officials, working with the state’s four utilities — Delmarva Power & Light Co., Potomac Electric Power Co., Baltimore Gas and Electric Co. and The Potomac Edison Co. — crafted the rules to meet the requirement of S143, known as the Net Metering Flexibility Act, which Gov. Wes Moore signed in May. It takes effect Oct. 1.

Ratepayers, under the new rules, are by default limited to a 12-month accrual period. But they can opt each March 1 to limit the period for any credit accumulation to one year, or to accumulate credits indefinitely. The rules also apply to subscribers to community solar projects, who accrue virtual credits as a result of their participation in that program.

Eligible ratepayers include any customer who owns and operates, leases and operates, or contracts with a third party who owns a project. In addition to solar generators, the rules cover projects that generate electricity with biomass, micro-combined heat and power, fuel cell, wind or hydro.

Jacob M. Ouslander, assistant counsel at the Office of People’s Counsel, an independent ratepayer advocacy organization, said the rules could be a big benefit to some ratepayers.

“When the NEM (net energy metering) credits are paid out in excess generation, the customer ends up receiving a lower financial benefit from the credit,” he said in an interview with NetZero Insider after the meeting. That’s because ratepayers buy electricity at the “full retail rate,” including distribution charges, but the utilities don’t pay those charges when they buy excess energy credits, he said.

So, ratepayers whose electricity use rises in the future would be better off holding credits and using them in the future, rather than cashing them in.

Fair Valuation of Accrued Credits

Speaking at the meeting, Ouslander expressed concern, however, that it was unclear which method utilities would use to calculate the amount they would pay out for credits accumulated over a long period.

“When you have a situation where a customer could potentially indefinitely bank credits, meaning that they could bank credits for years and years and years, the method that’s spelled out in the tariffs [concerns] us,” he said. “Because there could be a situation where the credits that are eventually cashed out if the customer switches back (to annual accrual) or closes the account end up being much higher than the excess generation that would have been paid out had the customer been receiving the payouts under the 12-month annual accrual cycles.”

That would hurt other ratepayers, who collectively would be paying for the excess amount paid, he said. “Ideally, there would be a method that values the accrued credits at a level close to what the customer would have received under the annual accrual method,” he said.

He added that utilities need to educate ratepayers that they have the option and how to go about it, if they want to switch from the 12-month accrual period to indefinite accrual, or back.

That and other issues related to helping ratepayers understand the impact of such decisions would best be resolved by creating a clear form that would educate ratepayers and allow them to communicate their desired accrual period to their utility company, Ouslander said.

Utility representatives generally agreed. However, PSC officials said a working group tasked with creating the form had yet to complete its work.

Commissioner Bonnie A. Suchman suggested the commission approve the new rules but “suspend” the ability of ratepayers to make a decision until those details had been ironed out.

“If you haven’t nailed down how the indefinite accrual method will work, it’s very hard for a customer to make a choice,” she said.

Joel Michel, assistant general counsel at Baltimore Gas and Electric, said any ratepayer choice would not take effect until March 1. In response, the commissioners agreed to make that the deadline to produce the form and clear up unresolved questions about the process.

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CISA Publishes Hardware BOM Framework

The Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA) put a spotlight on supply chain risk management Monday with the release of its Hardware Bill of Materials (HBOM) Framework, intended to help buyers of electronics equipment identify and mitigate risks in their supply chains.

CISA’s Information and Communications Technology Supply Chain Risk Management (ICT SCRM) Task Force developed the document. The group is managed by CISA with participation from the information technology and communications sectors, both classified as critical infrastructure by the agency.

The impetus behind HBOMs is to provide a list of the names and origins of all physical materials that went into a hardware product. A single modern hardware product may contain components from dozens of separate manufacturers, and an HBOM could provide a major help for purchasers who need to verify that the parts in the items they buy come from trustworthy sources. If something goes wrong with a piece of hardware, the HBOM could more quickly help track down the source of the problem.

Consistency Across HBOMs

But while the potential value of HBOMs is clear, an inconsistent approach may make it difficult for vendors and buyers to get on the same page. CISA’s HBOM framework is meant to provide a common platform to “help organizations illuminate supply chains and support the efficient evaluation and mitigation of” hardware supply chain risks “on a voluntary and flexible basis.”

The body of the framework is organized into three key components. Appendix A sorts HBOMs into potential use cases for risks that they may face. For example, the compliance use case deals with adherence to internal and industry regulations, the security case evaluates exposure to known security vulnerabilities, and the availability case assesses potential impacts from world events and supply chain constraints.

In Appendix B, CISA provides a format that vendors and buyers can use to ensure consistency across products. The appendix also describes a method for addressing components and subcomponents acquired from third parties and tracking their potential vulnerabilities.

Appendix C lists component attributes that may be appropriate to include in an HBOM, with the goal of creating “consistency across HBOMs by defining a data field associated with each attribute.”

Appendix D suggests potential enhancements that the ICT SCRM Task Force may later add to the document.

Grid security officials have been raising the alarm about hardware supply chains for some time as the operation of the North American power grid becomes increasingly reliant on remote connectivity and electronic devices largely manufactured in China.

In 2020, then-President Donald Trump declared a national emergency regarding foreign threats to the grid and banned federal agencies, citizens and companies from certain transactions involving grid equipment developed or manufactured by entities connected with “foreign adversaries” including China, Russia, Iran and North Korea. President Biden suspended Trump’s order upon taking office but largely reinstated it after a review. (See Biden Reinstates Trump Supply Chain Order.)

CISA Identifies New China Threat

Just days after releasing the HBOM framework, CISA, along with the FBI, National Security Agency, and their counterparts in Japan, issued a joint warning that cyber actors linked to China have demonstrated the capability to modify router firmware and install custom malware in targeted computer systems. The cyber group, dubbed BlackTech by law enforcement, has targeted “a wide range of public organizations and private industries across the U.S. and East Asia,” in sectors including technology, industry, electronics and telecommunication.

BlackTech — also called Palmerworm, Circuit Panda and Temp.Overboard — has been active since 2010, the agencies said in a more detailed advisory. Like Volt Typhoon, another China-linked hacking group that CISA warned about earlier this year, BlackTech uses so-called “living off the land” techniques to hide within a target system by appearing to be legitimately installed software. (See NERC Issues Cybersecurity Data Request.)

The group targets international subsidiaries of Japanese and U.S. companies, first gaining access to the branches and then pivoting to attack the central offices and steal confidential information.

“With our U.S. and international partners, CISA continues to call urgent attention to China’s sophisticated and aggressive global cyber operations to gain persistent access and, in the case of BlackTech actors, steal intellectual property and sensitive data,” said Eric Goldstein, CISA’s executive assistant director for cybersecurity. “We encourage all organizations to review the advisory, take action to mitigate risk, report any evidence of anomalous activity and continue to visit [CISA’s China page] for ongoing updates about the heightened risk posed by PRC cyber actors.”

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New Mexico Contemplates Organized Market Choice

When it comes to choosing one of the two competing Western day-ahead market offerings, who else is participating in the market is a key consideration, a representative of a New Mexico utility said last week.

The New Mexico Public Regulation Commission (PRC) held a workshop on Sept. 21 to discuss the pros and cons of utility participation in a regional day-ahead market or RTO. The discussion came as CAISO prepares to roll out its extended day-ahead market, in competition with SPP and its Markets+ offering.

Kelsey Martinez with the Public Service Company of New Mexico (PNM) said during the workshop that both market operators are “proven,” and PNM believes the two offerings would provide similar benefits.

“Less and less of the decision feels about the market operator and the market design,” said Martinez, who is PNM’s RTO and markets manager. “And more and more of it feels really about who’s in the market with you. So which resources are in the market, which transmission is in the market, what loads are in the market.”

In written comments to the commission, PNM was even more specific, saying “existing market transmission connectivity represents the largest deciding factor in choosing a day-ahead market.”

PNM said it currently has the most market transmission connectivity with Arizona Public Service. PNM expects to select a day-ahead market in 2024.

PNM also worked with consultant Energy and Environmental Economics (E3) to look at the impact of market seams between New Mexico and Arizona. The utility defined seams as areas where entities that share transmission connectivity are in different market footprints.

“For PNM … [the study] showed a large reduction in benefits when seams exist between Arizona and New Mexico,” the utility said in its comments.

PNM noted that it won’t know what transmission connections will be in each footprint until other utilities reveal their day-ahead market choices.

The E3 analysis was a follow-up to a report the consultant prepared for the Western Markets Exploratory Group, looking at the impact of different market footprints on WMEG member benefits.

Moving Renewables to Market

In August, the PRC opened a docket to establish “guiding principles” for participation in a regional day-ahead market or RTO by two investor-owned utilities in the state, PNM and El Paso Electric. (See NM Commission to Set Standards for RTO, Day-ahead Participation.)

PNM has been participating in CAISO’s Western Energy Imbalance Market (WEIM) since 2021 and El Paso Electric joined the WEIM this year.

Last week’s workshop was scheduled as part of PRC’s guiding principle development. In addition, PNM, El Paso Electric and other stakeholders filed lengthy written comments answering questions posed in the commission’s initial order opening the docket.

Some stakeholders used the workshop as an opportunity to make a pitch for a Western RTO.

“Moving forward in the stepladder of market opportunities before us is good, but stopping short of a full RTO leaves real opportunity on the table,” said Rikki Seguin, executive director of the Interwest Energy Alliance.

Interwest is an advocacy group that represents utility-scale renewable energy developers in six Western states. For the renewable industry, “getting to the benefits of centralized transmission planning and cost allocation is key,” Seguin said.

To meet state policy goals, the West will need to add 9 GW of renewable energy each year starting in 2026, Seguin said, citing data from Energy Strategies’ Western Flexibility Assessment.

New Mexico is well-positioned to help satisfy that demand, she said, with its “world class” solar and wind resources.

But “absent the transmission planning … it’s going to be really hard to move those renewables to market,” Seguin said.

Bifurcation Challenges

Public interest group Western Resource Advocates (WRA) also weighed in on the regional market issue in written comments and with a presentation during the PRC workshop.

WRA said a single, large-footprint market would provide the most economic, environmental and reliability benefits to New Mexico. In terms of challenges arising from regional markets, WRA said one of the largest would be a bifurcation of day-ahead energy markets and their impact on efficient clean energy dispatch and economic gains from the WEIM.

In addition, WRA is concerned about New Mexico utilities’ decision-making process for joining a market.

“The choice to join a regional market … should not be based on grounds of expediency to satisfy an adjoining utility that it relies on for transmission access and dispatch,” WRA said in written comments.

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MISO Somewhat Open to COD Allowances in Interconnection Queue Rules

MISO has signaled it is receptive — but only to an extent— to stakeholder ideas on loosening its commercial operation date deadlines in its generation interconnection queue.

MISO will collect stakeholder suggestions through Oct. 17 on how it might stretch deadlines around commercial operation date rules in its interconnection queue. The RTO is experiencing a growing number of generation projects that are approved to connect to the system but aren’t finished.

However, MISO said the potential commercial operation dates generation developers are using in negotiations for upcoming generator interconnect agreements (GIAs) so far don’t exceed the existing extensions MISO’s tariff allows.

“It appears at least on the surface that commercial operation date extensions are adequate,” MISO’s Brady Mann said at a Sept. 26 Interconnection Process Working Group teleconference.

Mann pointed out that MISO allows a three-year deferral when transmission owners cannot bring equipment necessary to connect new generation into service on time.

MISO policy requires GIAs struck among interconnection customers, transmission owners and MISO to contain a commercial operation date that’s within three years of the date originally requested in their queue applications. The grid operator additionally allows up to a three-year extension of the commercial operation date in the initial GIA. When developers can’t meet either extension, MISO can remove the project from its queue or developers can seek a waiver of the queue tariff deadlines with FERC.

Mann added that MISO is open to hearing potential remedies from stakeholders.

“It is a new world we’re living in, so having that collaboration and conversation will be helpful,” Mann said. “Our intent here is to understand the issues you’re facing and additional remedies that may be required.”

EDP Renewables last month requested that MISO consider extending its grace period or letting developers amend commercial operation dates to be more realistic in GIAs. The developer said study delays and supply chain setbacks mean interconnection customers can’t realistically meet the commercial operation dates set forth in the first drafts of their GIAs. (See MISO to Assess Extending Queue’s COD Grace Period.)

Multiple renewable energy developers told MISO that behind-schedule commercial operation dates will be common.

“We’re in a different world than in 2018. There are supply chain and delivery issues on both the interconnection customer and transmission side. … The problem is not likely to go away, in our view, and will extend into several future queue cycles,” EDP Renewables’ David Mindham said. “We believe it’s better to deal with this problem holistically than file a bunch of one-off waivers at FERC.”

Mann said MISO expects both interconnection customers and transmission owners to simultaneously gather supplies, conduct engineering analysis and construct facilities after a GIA is negotiated. He said one shouldn’t be waiting on the other to move ahead.

Growing Share of Approved And Unbuilt Generation

In a separate presentation, Mann said volumes of executed generator interconnection agreements are on the rise, with the 35 GW in GIAs expected to be executed by year’s end more than doubling 2022’s 16 GW.

MISO acknowledged the lion’s share of gigawatts from recently executed GIAs isn’t yet in commercial operation. Mann said MISO predicts a “large increase” in commercial operations in 2028, when developers exhaust their three-year grace periods.

MISO has said it has about 49 GW worth of generation projects that are approved to connect to the system under completed GIAs but remain unbuilt, which raises its near-term reliability risks. (See MISO: Reliability Risk Upped by 49 GW in Approved but Unbuilt Generation.)

By year’s end, MISO expects that value to grow to 66 GW in executed GIAs for generation projects that have yet to reach commercial operation.

Meanwhile, MISO’s interconnection generation queue studies continue to slip on their intended timelines. Most interconnection queue cycles for MISO’s four planning regions are delayed.

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DOE Looks to Build Clean Energy Park at Hanford Site

The U.S. Department of Energy wants to convert 30 square miles of the state of Washington’s heavily contaminated Hanford Site into a clean technology park.

But the agency doesn’t yet know what type of clean tech it wants there.

Led by Deputy Energy Secretary David Turk, DOE officials talked about the concept Friday with about 75 people, including developers, in Richland.

The Hanford Site consists of 586 square miles of land set aside for nuclear research and development, of which the central portion and much of the Columbia River shoreline are highly contaminated. Southeastern Hanford borders Richland with a 30-square-mile portion that is mostly uncontaminated.

That 30 square miles includes the fenced-off Columbia Generating Station nuclear plan and a long-defunct research reactor. A handful of small, mildly contaminated waste burial sites are also in the area, which DOE says would be easy to clean up. The area is adjacent to the Pacific Northwest Laboratory’s complex in northern Richland.

DOE wants to combine its cleanup and energy missions by turning this area into a clean tech park, Turk said. However, it does not plan to pin down what it wants to put in that park for a while.

The agency is seeking public comments on how it should proceed by Oct. 12. It then expects to issue a request for proposals in late November. Decisions to narrow down those proposals should occur by early 2024.

“We’re not going into this with, ‘It has to be this technology, it has to be that technology.’ … We’re soliciting creative options,” Turk said. He declined to say if solar farms would be considered for the site.

Brian Harkins, DOE Hanford Site assistant manager for mission support, said wind farms would face hurdles in the area because of their vibrations. Just west of the 30 square miles is a Nobel-prize-winning observatory that captures gravitational waves from black holes and colliding stars. Its instruments are ultra-sensitive to outside vibrations.

The site could conceivably hold several projects simultaneously. The requirement is that any specific project must generate at least 200 MW of electricity. “We’re thinking big, really big,” said Ingrid Kolb, director of DOE’s Office of Management.

The area has been already heavily surveyed on environmental and cultural matters. DOE officials estimated that the appropriate environmental impact studies would take two to four years to complete. One advantage is that the studies would tackle the entire 30 square miles at once, instead of being divided into separate studies for individual projects, DOE officials said.

In a separate development, southeast Washington economic development organization Tri-City Development Council earlier this month said it planned to set up a nonprofit subsidiary to help develop clean energy businesses in the region. The group’s leader told NetZero Insider that it has not yet set a timetable for getting the venture up and running or identifying goals. (See Southeast Wash. Looks to Become Clean Tech Hub.)

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Wash. Judge Rejects Cap-and-trade Lawsuit

A Washington judge on Friday rejected a lawsuit that sought to suspend the state’s cap-and-trade program.

Thurston County Superior Court Judge Mary Sue Wilson ruled that the 2022 transportation bill that included a clause giving Washington’s Department of Ecology rulemaking authority to implement a 2021 cap-and-invest law did not violate the state’s constitution by having more than one subject in it.

The conservative Citizen Action Defense Fund sued the state in January, alleging that the Legislature invalidated its 2022 transportation bill by cramming multiple subjects into it.

The lawsuit had two intentions, said Jackson Maynard, executive director for the Citizen Action Defense Fund. One was to hold the line on the state constitutional rule that limits a bill to one subject. The second was to at least temporarily halt the state’s new cap-and trade program by eliminating Ecology’s rulemaking authority.

The program went into effect Jan. 1 and has so far this year raised $1.462 billion in three quarterly auctions and one special auction. (See Wash. Allowance Prices Surge Again in 3rd Cap-and-trade Auction.)

The money is earmarked for many programs that combat climate change, which has been linked to health, agriculture, fish and wildfire issues. A large portion of cap-and-trade revenue is used to address transportation concerns.

Plaintiff’s attorney Callie Castillo argued Friday that the Legislature overreached by loading too many subjects into the transportation bill.

“We don’t know if this is a transportation bill or a climate action bill. Those two don’t go together. … [The bill] is simply a tax increase,” Castillo said.

Assistant Attorney General Alicia Young argued that the disputed bill provided resources to tackle transportation programs with several sub-sections to address a bigger issue.

“This is an omnibus bill to address a broad issue in multiple ways. … This is a resources bill,” Young said.

Judge Wilson agreed with Young. “In this legislation, subjects come together or hang together on one topic,” Wilson said.

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State Ratepayer Advocates Discuss Role in Energy Transition

BURLINGTON, Vt. — ISO-NE, states and stakeholders must work together to prevent transmission costs from skyrocketing amid the energy transition, consumer advocates told the ISO-NE Consumer Liaison Group (CLG) last week.

Consumer advocates from all six New England states convened at the CLG fall meeting Thursday to discuss their role in the transition off fossil fuels.

The advocates stressed the importance of keeping energy affordable for consumers, while highlighting the dual climate and cost benefits of limiting the peak demand on the grid as electrification of transportation and heating increases.

“We’re trying to broaden the definition of what a consumer interest is,” said Bill Dornbos, legal director for Connecticut’s Office of Consumer Counsel, making the case that consumer needs include both low rates and a healthy climate and environment.

Dornbos added that it is time to “rebalance the power dynamic between ratepayers and utilities” to spur innovation and adapt to the climate crisis.

Andrew Landry, Maine’s deputy public advocate, agreed on the importance of keeping electric rates low in the clean energy transition.

“I believe, and our office believes, that we can achieve our climate policy goals in a way that is affordable,” Landry said.

Jacob Powser of the CLG Coordinating Committee | Rebecca Beaulieu

ISO-NE has projected a 2050 winter peak of up to 57 GW due to the electrification of heating and transportation as part of its 2050 Transmission Study. (See ISO-NE Planners Outline Potential Solutions for 2050 Tx Overloads.) Landry said more planning and focus is needed to limit the growth of the peak, including increased investment in demand response programs, energy efficiency and storage.

“I think we have underinvested in efficiency and demand response,” Landry said, noting that ISO-NE indicated in the initial transmission study findings that a 10% reduction in the 2050 winter peak would be associated with a one-half to one-third reduction in transmission costs. (See ISO-NE Projects Decrease in Gas, Increase in Coal and Oil for 2032.) Landry added the region should “do everything we can to lower that peak.”

Landry said ISO-NE has a key role in keeping transmission costs low as demand from electrification increases.

“I think market rules can be designed to support demand response and support energy storage,” Landry said, adding that “we also need to think about demand response and storage in the transmission planning process,” along with non-transmission alternatives.

Don Kreis, New Hampshire’s consumer advocate, agreed on the need to keep peak loads low and prevent runaway transmission costs.

“I am absolutely rabid about energy efficiency,” Kreis said, adding that there is an overlap in climate and ratepayer interests. Kreis also called for more scrutiny on asset condition projects, which represent the largest source of new transmission investments in the region. Asset condition projects are transmission upgrades for infrastructure that is old, obsolete or in need of wide-scale repair.

This month, Kreis co-signed a letter with representatives from Connecticut, Maine, Massachusetts and Rhode Island calling for a pause on all nonemergency asset condition projects not yet under construction until the asset condition approval process is reformed. The current process requires relatively minimal scrutiny for the multimillion-dollar projects, the costs for which are spread among ratepayers across New England. (See States Press New England TOs on Asset Condition Projects.)

The consumer advocates wrote there is about $5 billion in proposed, planned or under-construction asset condition projects and that this cost has increased by approximately 50% in the past six months.

“All stakeholders … need the opportunity to assess the reasonableness of each [transmission owner’s] planned spending,” the consumer advocates wrote. “Ultimately, the NETOs must be held accountable for the prudency of this spending.”

Community Members Call for Clean Energy, Transparency

Several local climate and environmental justice advocates who spoke at the meeting called on ISO-NE to take bolder steps to spur the transition away from fossil fuels.

Julie Macuga, a researcher for Global Energy Monitor, said it’s difficult for states to implement decarbonization policies when ISO-NE policies like the Minimum Offer Price Rule and forward capacity auctions ensure ratepayer dollars go directly to fossil fuels.

“ISO New England has the power to support actual grid reliability in the face of climate change,” Macuga said, adding that “you can end coal, gas, biomass and more.”

Jacob Powsner, a member of the CLG Coordinating Committee, climate activist and maple farmer, told RTO Insider he would like to see more transparency and democratic engagement from ISO-NE, as well as a larger voice for ratepayers at NEPOOL.

“If a member of the public wants to join [NEPOOL], it costs $500,” said Powsner, who added that even as an active member of the CLG Coordinating Committee, he still personally would have to bear the costs of NEPOOL membership.

“That would just come out of the farm budget,” Powsner said.

Energy transition

Burlington activists Leif Taranta and Julie Macuga | Rebecca Beaulieu

Leif Taranta, a Burlington-based community organizer, emphasized the impacts of climate-fueled flooding that hit Vermont this summer, displacing hundreds of residents.

“What is reliable energy when business as usual means that folks don’t even have a light switch?” Taranta asked.

Taranta called for increased focus on community resilience solutions and said there is “widespread desire” for programs including community solar, net metering and demand response.

“We can change our ways to take care of each other, and that should be the first priority,” Taranta said.

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Massachusetts Announces Permitting And Siting Reform Commission

To increase the pace of development for clean energy resources, Massachusetts Gov. Maura Healey (D) signed an executive order Tuesday creating a state Commission on Clean Energy Infrastructure Siting and Permitting.

The goal of the commission, the administration said in a press release, is to identify and reduce barriers for clean energy infrastructure and cut permitting timelines. The commission will work with state agencies within the Executive Office of Energy and Environmental Affairs (EEA) and make recommendations to government officials and legislators.

“This commission represents our administration’s efforts to bring people together and build consensus to tackle one of the most complex issues of our time,” Healey said, adding that “the clean energy transition can’t wait.”

The announced commission members, who were sworn in on Tuesday, represent a variety of interests, including labor, environmental justice and climate groups, electric utilities and the clean energy industry.

“With these members leading this effort, we are confident that the recommendations will be smart, balanced and ready for action,” said EEA Secretary Rebecca Tepper.

The commission also will make recommendations about how best to engage with communities in expedited permitting processes and ensure the benefits of the energy transition extend to all state residents.

“We’re going to need a lot of new infrastructure, and we’re going to need it fast,” said Lt. Gov. Kim Driscoll. “With these stakeholders at the table, we’re going to build serious consensus on how to tackle this challenge in a way that ensures environmental justice communities don’t bear a disproportionate burden, greenspace and other development priorities are protected, and we can all share in the benefits of clean energy.”

The executive order also tasked the commission with convening a “Siting Practitioner Advisory Group” to advise the commission on technical issues. That group will be chaired by Mary Beth Gentleman, a former assistant secretary for policy at the EEA and partner at Foaley Hoag.

The co-chairs of the legislature’s Joint Committee on Telecommunications, Utilities and Energy (TUE), Rep. Jeff Roy (D) and Sen. Mike Barrett (D), both have listed permitting and siting reform as top priorities of the current legislative session and are on the commission. (See Checking in on Clean Energy at The Mass. Legislature.)

Rep. Roy introduced a bill (H.3215) this session that would create an electric infrastructure permitting office to issue consolidated permits covering all necessary state and local approvals for clean energy infrastructure, which the office would need to issue within seven months of an application.

“What we’re trying to do,” Roy told NetZero Insider this year, “is move the community input back to the beginning of the process, give folks an idea of what they’re trying to do and how it’s going to help them and then streamline the permitting process so it runs parallel.”

The TUE committee played a large role in the omnibus climate bills passed in the legislature’s two prior sessions, and the committee’s leaders have said they intend to construct another climate bill in the current session, which ends Nov. 15.

Healey’s executive order also creates an Interagency Siting and Permitting Task Force to inform the commission, with experts from the EEA, Economic Development, Housing and Livable Communities, and Transportation Executive Offices.

A final report from the commission is due at the end of March 2024.