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July 30, 2024

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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.

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DOE, FERC Outline Plans for Possible Government Shutdown

The split control of Congress means another possible shutdown of the federal government looms this weekend with a funding deadline of Sept. 30, the end of the fiscal year.

While several days remain before the deadline that could be extended by just a short-term deal, the Department of Energy and FERC already have laid out plans for what would be the first shutdown of the government since 2018. (See FERC to Furlough Most Employees in Govt. Shutdown.)

FERC would run with a skeleton crew of 60 as 1,506 out of 1,566 employees would not work after the agency runs out of funding. The commission said it would be able to keep going for some time using money it has on hand, but once exhausted it would limit activities to the bare minimum for as long as the government is unfunded.

DOE normally has 13,850 full-time employees and some 4,139 of those are financed by a resource other than the annual appropriations Congress is fighting over, while 1,404 employees are “necessary to protect life and property.”

Both agencies said they would be able to wind down standard operations within a half day of finding out the government is not funded.

FERC would keep up its safety reviews of dams and natural gas infrastructure, as well as continuing to monitor the bulk power system for reliability and policing energy markets against manipulation.

As presidential appointees, the commissioners themselves would continue working and issuing any orders that have to come out. For court cases, FERC would ask for stays. If courts deny stays, then staff will have to meet any deadlines in their cases.

DOE headquarters would keep a small staff to help coordinate its actions that must continue, which include maintaining and safeguarding the country’s nuclear arsenal and providing electricity from federal power administrations.

Bonneville Power Administration is self-funded and will continue to operate normally (its employees are covered in the category where their salaries are funded outside of the normal appropriations process). The other power marketing administrations (Southeastern Power Administration, Southwestern Power Administration and Western Area Power Administration) will perform functions related to the safety of human life and the protection of property by engaging in controlling and directing power to utilities, transmission of power and repair of the power transmission system.

“After the exhaustion of available balances, those activities not related to the preservation of life and property, unnecessary to the discharge of the President’s constitutional power, not funded by other than annual appropriations or not otherwise expressly authorized by law will cease,” DOE’s plan said.

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GE Sues Wind Turbine Blade Recycling Company

General Electric is suing a contractor it says failed to recycle GE customers’ old wind turbine blades.

GE alleges it paid Global Fiberglass Solutions of Texas LLC $16.9 million to provide an environmentally sound end-of-life disposal for about 5,000 blades, but GFS instead stockpiled them with other companies’ used blades.

This was “fraud and deception,” GE states in a Sept. 20 filing in federal court in New York City. (Case 1:23-cv-08346)

It also tarnished GE’s reputation when the situation was publicized, the lawsuit states.

The Texas Commission on Environmental Quality measured two GFS stockpiles in Sweetwater, Texas, at a combined 450,000 cubic yards during a 2021-2022 investigation of unauthorized storage of industrial solid waste.

Iowa regulators conducted a similar investigation of three stockpiles in that state in 2020.

Global Fiberglass Solutions is based in Washington state. Its LinkedIn page indicates it also has operations in Sweetwater and in Newton, Iowa. The most recent post on its Facebook page is more than three years old. A top-of-the-page banner indicates its website is under construction.

A person who answered the company’s phone number Tuesday said no one was available to speak to NetZero Insider about the lawsuit.

Allegations

GE’s lawsuit makes the following statements and allegations:

    • GFS hosted GE on-site in Texas to demonstrate the process by which it reduced the massive blades to pellets that could be reused in a variety of products.
    • GE contracted with GFS in 2017 and 2018 to remove roughly 5,000 blades from GE customer sites in Iowa and Texas and recycle them.
    • GFS billed GE for its services within 48 hours of completion of removal from each site.
    • GE paid a premium — $3,525 or $3,600 per blade — to what it thought was an environmentally conscious industry leader.
    • GFS repeatedly assured GE that it was actively recycling them.
    • GE heard reports that GFS instead was stockpiling the blades; it visited Sweetwater in late 2018 and saw the GFS facility did not appear to be in full operation.
    • GE on Dec. 18, 2018, demanded GFS rectify this breach of agreement within 10 days.
    • GFS “all but shut down” its operations; GE cannot be certain that any of the roughly 5,000 blades have been recycled.
    • The Iowa Department of Justice in September 2022 threatened civil action against GFS and GE under the state’s solid waste law; three months later, GE agreed to pay another company $5.5 million to recycle the blades stockpiled in Iowa to avoid litigation and prevent further harm to its reputation.

In its lawsuit, GE is seeking return of the money it paid GFS, plus interest; court costs and legal fees; and declaratory relief on indemnification for the third-party expenses it has incurred.

Background

Onshore wind power is one of the largest businesses of General Electric Renewable Energy. One of its lines is repowering or servicing existing wind farms, which can entail replacing turbine blades. As part of its sustainability pledge, GE actively seeks alternatives to landfilling these extremely large and heavy objects.

Aerial images of the main Sweetwater stockpile are striking — thousands of blade sections and nacelle components gleaming in the sunlight, arranged in piles with aisles between them.

Texas Monthly published a report in August 2023 on local frustration with the situation. Neighbors worry the site is a breeding ground for rattlesnakes and mosquitoes; community leaders fear the company will never remove the blades.

The report quotes the managing director of GFS saying the company is ramping up to shred the blades into pieces the size of coarse sand and has found a buyer for the material. He said the heaps of blades would be gone from Sweetwater by late spring 2024.

He declined to discuss the situation in Iowa.

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As EV Penetration Rises, Utilities Turn to Smart Charging Strategies

A pilot program using smart EV charge management to smooth distribution loads and improve demand response has been so successful a utility is adopting the program permanently before completing the pilot. The interim results of the U.S. Department of Energy-funded pilot were shared at a workshop at RE+ in Las Vegas earlier this month.

“Baltimore Gas and Electric found the initial residential pilot results are impactful and have included a permanent smart charge management program in their multi-year plan,” said Joshua Cadoret, senior project manager at Exelon, which received an award from DOE for a Smart Charge Management (SCM) pilot program with three of its utilities: Baltimore Gas and Electric, Delmarva Power and Light and Potomac Electric Power.

The pilot study, which is ongoing, includes about 3,000 residential EV customers with more than 3,600 vehicles as well as 850 public chargers throughout their territories as of Sept. 7. Commercial EV fleet owners also were targeted, but only one has been recruited successfully to date.

The SCM pilot recruited Tesla owners to enable their cars’ charging to be throttled to reduce peak demand and encourage off-peak charging. WeaveGrid software shares the utilities’ signals with the vehicles. The EV owners received a $10/month electric bill credit, equal to 10% of an average monthly bill, and were able to override the demand response request up to four times each month. The public charging pilot program offered customers two options: the default opt-in where charging is throttled at certain times and charged at a discounted cost/kWh or opt-out to get the full capacity of the charger at the standard rates.

Managed charging aims to solves two problems utilities face: their distribution systems’ ability to cope with an increasing number of EVs and the utilities’ need to respond to renewables, said Shane O’Quinn, senior director of business development at WeaveGrid, a company whose software optimizes EV-grid integration for utilities. “Whenever you have a large number of EVs coming online where 80% of the charging is happening at the residential level, and the residential distribution network is designed to support really relatively modest loads at the household, we’re ultimately going to get to a point to where we have distribution system challenges.”

EV charging incentives can be designed with the goal of spreading the load into times that lower the need for grid upgrades, O’Quinn said: “One of the first things you have to consider is how are people actually going about charging their EVs today and where do you ultimately want them to be in terms of how they charge in the future?”

The default for most EV drivers is to plug in their car when they arrive home from work, which usually coincides with peak demand as most housholds turn on HVAC and use appliances at the same time. This is shown in the first scenario in Weavegrid’s  graph, which shows eight cars on a single distribution feeder plugging in when they return from work, although one works late shifts so that car draws on the grid later than the others.

“Many utilities take the next step and think about how they might be able to implement time-of-use rates which can shape behavior so that people are starting to charge after the on-peak times are over,” O’Quinn said. That can help the drivers manage the cost of electricity but may not be optimal for the utility.

The initial stage of the residential pilot tested the ability to use SCM to move charging to off-peak times and resulted in 96% of the more than 40,000 charging sessions being done off-peak. While the drivers may plug in when they get home, the SCM works with vehicle telematics so charging begins when off-peak rates start, the second scenario in the graph.

“There’s another technique that can more actively push the charging into periods that are beneficial for you as a utility. For instance, we can utilize an approach where we’re smoothing out the charge levels on various distribution system assets, making sure that you’re not overloading transformers, for instance,” O’Quinn said, “or you might be able to push the charging into a period where you can soak up renewables on the grid.” The third scenario in the graph shows SCM being used to even out load on distribution grid assets.

Helping utilities use managed charging to absorb renewables on the grid is driven by economic realities, said Russell Vare, who heads automotive OEM partnerships for Kaluza, a vehicle-to-grid software provider. Using data from the UK as an example, he showed how the move from 17% to 35% renewables resulted in a substantial increase in price volatility.

The UK market shows that increased renewables penetration leads to greater wholesale power price volatility. | Kaluza

While regulated markets may not have that degree of price volatility, this data shows the need for utilities to use EVs to absorb peak renewables supply.

The pilot also looked at potential cybersecurity risks and vulnerabilities of EV chargers and vehicle telematics software, according to the Phase 1 Review distributed by the Smart Electric Power Alliance (SEPA).

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Northeast Stakeholders Discuss The Future of Alternative Fuels

New England regulators, policymakers and industry representatives convened in downtown Boston last week to discuss the potential of alternative fuels in the region’s push for decarbonization.

The conference was organized by the Northeast Energy and Commerce Association and featured talks and panels about the future of the natural gas network, along with the potential of fuels like hydrogen, renewable natural gas (RNG), biodiesel and renewable diesel in the energy transition.

The uncertain future of the region’s gas network loomed large over the course of the conference. Massachusetts, New York and Rhode Island all have ongoing state investigations into the future of their natural gas systems, with options ranging from widescale decommissioning to doubling down on the infrastructure.

“It’s so important to consider all options — that includes using the pipes which are in the ground, and potentially expanding pipes — to be able to meet the energy needs of the future,” said Max Bergeron of Enbridge.

From left: Jose Costa, Northeast Gas Association; Donny McCallum, Smartpipe Technologies; Max Bergeron, Enbridge. | © RTO Insider LLC

The company recently announced an open season for a project that would increase its pipeline capacity of natural gas to the northeast. (See Enbridge Announces Project to Increase Northeast Pipeline Capacity.)

“We anticipate we will see a growth in demand for gas utilities of about 6½% over the next five years,” Bergeron said. “We also have to keep in mind that the power grid is very much reliant here in New England on natural gas-fired generation, so we see a strong need for incremental pipeline capacity to alleviate some of those bottlenecks.”

Carleton Simpson, a commissioner on the New Hampshire Public Utilities Commission, said fuel availability “appears to represent a significant challenge moving forward” and added that a “NERC-style entity” may be needed to ensure the reliability of the gas network.

Jessica Waldorf, chief of staff and director of policy implementation at the New York Department of Public Service, said the state faces a tough task of maintaining the functionality of the gas network while keeping up with decarbonization.

“There’s certainly a lot of pressure for us to move quickly away from use of natural gas,” Waldorf said, while noting the state’s gas utilities simultaneously connect “tens of thousands of new customers to the natural gas system.”

Waldorf said if utilities continue to add customers at current levels, the state will be required to ensure the system can “safely and reliably meet the demand of those customers.” She added this will result in “really hard infrastructure decisions.”

“It also is increasingly challenging because we’re balancing those decisions against the requirements of the Climate Act, in addition to all of our other statutory responsibilities,” Waldorf said. “And that means additional review processes and additional analysis is needed to really justify the need for these projects on the basis of reliability.”

Jamie Van Nostrand, chair of the Massachusetts Department of Public Utilities (DPU), echoed the concerns about gas availability while questioning whether utilities should continue their pace of new gas hookups.

“To some extent, it seems to be business as usual in the natural gas industry with respect to new residential hookups and continuing levels of load growth,” Van Nostrand said. “Is that consistent with the statutory emissions limits that we need to achieve?”

Van Nostrand called the dynamic “a disconnect,” adding, “things seem to be that bad that [the gas utilities] are worried about the need to keep the Everett Marine Terminal open to address reliability concerns, but it doesn’t seem to have any impact on policies with respect to accommodating new connections.”

The DPU chair also called for a greater focus on reducing the energy burden on residents as the state transitions away from fossil fuels.

“We want to start a proceeding to focus on the energy burden, to figure out if there are rate designs … that would allow us to move rapidly forward on a clean energy agenda, while still recognizing that people have a hard time paying their bills,” Van Nostrand said. “That’s a very high priority for this commission.”

Hydrogen And RNG

State policy concerning the future of the gas networks frequently has pitted climate organizations against the gas industry, with climate groups pushing to rapidly decommission gas networks and the industry advocating for a continued reliance on the gas system and the blending of alternative fuels like RNG and hydrogen.

Bergeron said RNG and hydrogen could be blended into the gas network to lower its carbon intensity, while acknowledging fossil fuels like natural gas will have an “ongoing role.”

“We see RNG as an opportunity to leverage our existing network,” Bergeron said.

Jose Costa of the Northeast Gas Association echoed Bergeron’s support for fuel blending and added that legislative and regulatory help is needed to bring RNG into the region’s gas network.

“Electrification of everything is not the sole answer,” Costa said. “The natural gas distribution network, it’s going to be there, it’s going be needed, and I’m not sure if fully renewable energy will be the energy source of the future — it’s going to be a mixture.”

alternative fuels

Massachusetts Rep. Jeff Roy, co-chair of the Joint Committee on Telecommunications, Utilities, and Energy. | © RTO Insider LLC

Massachusetts Rep. Jeff Roy, (D) co-chair of the Legislature’s Joint Committee on Telecommunications, Utilities and Energy, told the conference Massachusetts “must use all the tools at its disposal to remain both a national leader in climate mitigation efforts and a prosperous, affordable home to residents.”

Roy highlighted a bill he introduced this legislative session (H.2938) that would promote the use of alternative fuels including RNG and hydrogen in the state’s gas network, calling the bill “a starting point for our conversation on the role of fuels in the Commonwealth’s future.”

Lobbyists for gas industry groups including Enbridge, National Grid and the Propane Gas Association of New England have supported Roy’s bill, arguing it would make efficient use of the existing gas network.

Meanwhile, members of climate organizations including the Green Energy Consumers Alliance, Mothers Out Front and Gas Transition Allies have opposed the bill, arguing that using the fuels in the gas network simply would perpetuate fossil fuel reliance and would lead to high costs to ratepayers due to the mounting expenses of maintaining the state’s aging gas network, combined with the high costs of hydrogen and RNG.

“The Commonwealth’s clean energy and climate plans indicate that the best pathway to clean heat is through electrification, not renewable natural gas and hydrogen, which this bill subsidizes,” Carrie Katan of the Green Energy Consumers Alliance told a legislative committee in June, adding the fuels are better suited for hard-to-decarbonize sectors like air travel.

Katan said biofuels like RNG are “fundamentally inefficient fuel sources” constrained by the feedstocks used to produce them, adding “no amount of state subsidies will overcome these problems for RNG, just as no amount of federal support could make ethanol the future of transportation.”

The environmental groups also argued that blending in alternative fuels would perpetuate the health effects and safety issues from the natural gas network. A 2022 study from Boston College’s Global Observatory on Planetary Health found that air pollution contributed to nearly 3,000 excess deaths in Massachusetts in 2019, largely attributed to burning fossil fuels.

Boston College biology professor Philip Landrigan, a co-author of the study, told NetZero Insider that blending hydrogen or RNG into the natural gas supply would have little effect on the local air pollution associated with the gas system, including the release of air pollutants like NOx gases, benzene, and other toxic chemicals.

Landrigan added that while the local air pollution impacts of natural gas are not as bad as coal or oil, natural gas is “every bit as powerful a greenhouse gas.” The professor added that he considers the effort to mix hydrogen into the gas network to be “a desperate attempt by the fossil fuel industry” to maintain a market for gas and protect their investments in gas infrastructure.

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Stakeholders: Pathway Initiative Offers ‘Fresh Look’ at Western Market

Stakeholders from across the Western electricity sector say they see renewed potential for developing a more organized regional market through the open-ended process offered by the West-Wide Governance Pathway Initiative.

But many of them also caution the initiative must become more transparent, both in its processes and its sources of funding.

Those were two of the key takeaways from stakeholder comments filed in response to questions in an Aug. 29 letter circulated by the backers of the initiative, who are seeking to quickly work through “Phase 1” of the effort to define a governance framework and seat a founding board of directors by next January. (See Backers of Independent Western RTO Seek to Move Quickly.)

Utilities regulators from Arizona, California, Oregon, Washington and New Mexico established the initiative in July to improve the prospects for developing a single, West-wide electricity market that pointedly includes California — a response to the competition for members between CAISO’s Extended Day-Ahead Market (EDAM) and SPP’s Markets+.

The comments were posted on the website of the Western Interstate Energy Board. The solicitation received 36 individual comments and five sets of joint comments — a few of which also included contributions from some of the individual commenters.

‘Fresh Look’

The Aug. 29 letter asked stakeholders to address questions related to the initiative, including the pros and cons of it being facilitated outside of any existing organization and the preferred structure, process and scope for Phase 1. It also asked for opinions on the best stakeholder engagement model for enabling broad stakeholder involvement and ensuring efficiency.

Multiple parties pointed to potential benefits of conducting Phase 1 of the Pathway Initiative outside the auspices of any existing organization or process.

A group calling itself “Joint Commenters” — which includes RTO advocacy group Western Freedom; American Clean Power Association; multiple utilities in California, Oregon and Washington; and other industry groups — said the approach offered the advantage of separating “the discussion from existing market institutions and can enable a fresh look at certain structural and governance issues that have been examined in other contexts.”

The Bonneville Power Administration, which some Northwest stakeholders say is leaning toward joining Markets+, said the initiative “offers the opportunity for a different approach to create a multistate entity for market development than other entities have taken.”

“It has the opportunity to be a new, intentionally designed entity, separate from existing organizations. As a new entity, it could develop appropriate practices about how a multistate entity can operate and engage,” BPA wrote.

But one downside, BPA said, is that “[t]he new entity and its structure will need to be created rather than being able to rely on an existing structure,” which could hinder “the ability to move quickly.”

BPA has said it will issue a decision on which day-ahead market to join in March 2024, a timeline some Northwest stakeholders consider to be too aggressive given the importance of the agency’s transmission and generation for the wider West and all the variables currently in play. (See NW Stakeholders Divided on BPA Timeline for Day-ahead Decision.)

In its individual comments, Portland General Electric, one of the Joint Commenters, said the open-ended nature of Phase 1 could bring “renewed enthusiasm” to the effort to develop a Western market. But the Oregon utility also said “it is crucial to demonstrate continued support of key California political leaders, especially the California Energy Commission and California Public Utilities Commission.”

“Past efforts at regionalization have faced skepticism and resistance within California, and strong engagement from both California and Western leaders is needed to ensure that this effort produces an outcome that is acceptable to both California stakeholders and the wider West,” PGE said.

BPA suggested the first phase of the initiative focus “on demonstrating the viability of establishing an independent entity capable of administering contracted market services from an existing market platform.”

“While establishing effective independent governance of the initiative is of critical important [sic] to Bonneville, the requirements for an independent governance structure have been well-discussed through the existing market initiatives (WRAP, EDAM and Markets+). The initiative can draw from those experiences rather than spending the bulk of Phase 1 focused on what is needed for independent governance,” BPA wrote.

BPA also said it “respectfully” disagreed with an assertion by backers of the initiative that there was “broad stakeholder agreement” that the WEIM’s joint authority governance model would be sufficient for governing the EDAM.

“While Bonneville participated on the Governance Review Committee and supported its final recommendations within these constraints, we cautioned that ‘Broad adoption of EDAM across the interconnection is likely to be challenging if the market design is not founded upon an independent governance structure.’”

Transparency Required

A recurring theme in comments was the need for transparency around the initiative.

“It is important that whoever is leading this work create a process that is truly open, transparent, impartial, and inclusive,” said the British Columbia Ministry of Energy, Mines and Low-Carbon Innovation.

The ministry “strongly” encouraged the organizers “to identify which state/provinces [sic] are leading the initiative, the source of any funding received to date, and how decisions will be made with respect to a proposed governance structure.”

Arizona Public Service (APS) noted that “assistance from outside experts” will be needed to advance the effort in a timely way and “influence potential market participants’ decision making.

“Transparency is requested to monitor the source of funding for and perspective of initiative facilitators. At this juncture it is also unclear whether the regulator sponsors or broader WIEB membership is at the helm of the initiative,” APS said, expressing a concern shared also by NV Energy. The Nevada-based utility urged initiative backers to be transparent about the source of funding throughout the process.

Lack of transparency about funding appeared to be one of the key concerns for the Idaho Public Utilities Commission, which earlier this month voted unanimously to decline to sign on to the initiative. (See Idaho PUC Declines to Join Western RTO Governance Effort.) The PUC reiterated that concern in its terse filing.

The Utah Office of Consumer Services said the Aug. 29 letter’s “simple statement” that the funding is “derived from 501(c)(3) sources” was “wholly inadequate.”

“Unfortunately, experience has shown that having this tax status does not ensure that the organization has a mission consistent with the public interest and/or includes organizations with highly specific objectives that at best represent a subset of the public interest. Those promoting this initiative must disclose the specific funders so that potential participants can better understand potential goals associated with the funding,” the Utah agency said.

The Utah consumer advocate sought clarity on the rationale for seating the entity’s board during Phase 1.

“The timing does not appear to allow for a fulsome recruitment, vetting, and selection process. If only ‘key elements’ of governance are in place by December, that barely allows for enough time to have sectors coalesce and select nominating committee members by January,” the agency said.

Competitive Advantages

The initiative won strong praise in comments from a group that includes Western Freedom, Silicon Valley Leadership Group, Environmental Defense Fund, CalChamber, American Clean Power Association, California Environmental Voters and the Union of Concerned Scientists.

The proposal “identifies maximizing benefits for customers as the goal for the new entity and future market services it will provide,” the group said. “This sends a clear message that market decisions should be driven by and be able to demonstrate those benefits. It also signals a clear understanding of the sense of urgency for regionalization efforts to maximize benefits through expanded market services.”

The group said that large industrial and commercial electricity customers “face very real barriers to expansion in the West” because the region lacks an organized market to “provide affordable, reliable, and cleaner energy. A centralized market offers the ability to lower costs by unlocking the full potential of existing generation and decreasing costs.”

The group also pointed out that 80% of Western residents live in areas with clean energy targets that can’t be met without the benefit of a “fully integrated market” across the region.

The group was among those commenters, including BPA, who cautioned about the large investment of time and resources required to pursue the effort, advising that “there is some essential research and analysis that needs to be conducted at the earliest stages of this process to ensure there is a viable path forward.” It called for the initiative’s backers to identify a lead organization that can hire consultants, including “a facilitator, legal counsel and technical research.”

“The Western Interstate Energy Board through the Committee on Regional Electric Power Cooperation could be ideal, given its membership of states and its Department of Energy funding,” the group said.

A group calling itself “Joint Competitive Stakeholders” also pointed to a different set of competitive benefits from a West-wide market — for competitive power suppliers, transmission and generation developers, and financial institutions. The group includes independent power producer associations in California and the Northwest; energy traders such as DC Energy and Shell; and developers like New Leaf Energy and Vistra.

“Phase 1 of the Initiative, and any future phases, must provide fair representation for all types of market participants and interested parties. This representation will ensure that any new regional Western market establishes policies and operates in a fair and non-discriminatory manner to foster competition and unlock the greatest benefits,” the group wrote.

The Competitive Stakeholders said the initiative’s first deliverable should be to develop “a conceptual framework” on governance in a process that includes members of its sector, followed by drafting of governing documents.

“It will be key to establish a sound governance framework and good governance principles in Phase 1 to be used in implementation by the founding board in Phase 2,” the group said.

NV Energy said it seeks to “have up front agreement on the objective — to develop a governance structure that is independent in both reality and perception.” Both APS and NV Energy urged that a new entity not differentiate by the size of participating states. The latter also raised the need for equal treatment of different public policies.

“If a Western organized market is to have broad participation it must accommodate states that have adopted GHG programs, states that have pursued decarbonization by means of renewable portfolio standards, and states that have not established carbon-related regulations,” NV Energy wrote.

The Nevada utility also asked the initiative to address some practical matters, such as: which CAISO activities could be transferred to the new entity; whether the entity would be responsible for reliability coordinator activities as well as market functions; the potential for the new entity to assume the role of a balancing authority; and the entity’s role related to transmission planning and cost allocation.

‘Broader’ Representation

Oregon-based PNGC Power, an electric cooperative with 16 members in seven Western states, expressed support for the Aug. 29 letter and encouraged expansion of the regulators’ coalition “to include broader industry sector representation.”

“This includes entities with an interest in exploring pathways to an RTO, including strong representation from the Northwest region, including BPA’s public power customers that explicitly and clearly support forming an RTO as an end state,” PNGC wrote.

The co-op also urged the coalition “to ask for financial and resource commitments from all participating members of the Founding Board to ensure that they are fully committed to the effort and that they are not just attending to express opposition and slow down the process.” The commitments should be significant enough to “weed out” those who might seek to impede development of an RTO but “reasonable enough” to allow participation by organizations of “varying sizes,” it said.

While backers of the Pathways Initiative appear to assume that a new entity would contract with CAISO to provide market operator services, some commenters suggested the selection process should be opened to competition.

BPA said the new entity should consider “all options” for a potential market operator and possibly rely on an “RFO-type solicitation” (request for offer) for making its choice. APS said the initiative’s Phase 1 activities should be expanded to include exploring a governance structure that could be applied to any potential market operator.

“Currently, both CAISO and SPP are maneuvering to offer expanded market services to the region. Additional program facilitators may emerge,” APS wrote.

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FERC Rebuffs PJM, SPP on FTR Credit Rules

FERC said last week it remains dissatisfied with PJM’s and SPP’s financial transmission rights (FTR) credit policies, while ending inquiries into those of CAISO, ISO-NE and NYISO.

The commission ordered PJM to institute a 99% confidence interval in its policy and said SPP’s tariff “appears” to be unjust and unreasonable in the absence of a mark-to-auction collateral requirement or comparable alternative.

Following a 2021 technical conference on RTO/ISO credit practices, FERC in July 2022 opened investigations under Section 206 of the Federal Power Act into SPP, CAISO, ISO-NE and NYISO. (See “Collateral Requirements” in FERC Proposes Allowing RTOs to Share Credit-related Info.)

The commission said it was concerned the grid operators’ tariffs did not ensure that FTR traders maintain sufficient collateral to reduce mutualized default risk, where a default by a market participant unsupported by collateral must be socialized among all participants.

The commission’s concerns were sparked by the 2018 bankruptcy of GreenHat, which cost the PJM membership nearly $180 million — only $1.4 million of which could be recovered from the company’s principals once GreenHat was insolvent. (See FERC OKs GreenHat Settlements.)

Excluding PJM and SPP, the commission last week found the other grid operators’ tariffs remain just and reasonable and terminated their proceedings. (See below.)

PJM Ordered to Institute 99% Confidence Interval

In its Sept. 21 order on PJM, FERC accepted all aspects of the RTO’s June 2022 filing revising its FTR rules, except for the RTO’s proposal to use a 97% confidence level in its historical simulation (HSIM) model. It ordered use of a 99% level instead (EL22-32).

The commission said a 97% confidence interval would capture only events occurring more than once every 2.75 years, failing to account for rare, but high-risk events such as large, unexpected transmission outages or the February 2021 winter storm that caused generation outages across Texas.

“The record before us fails to show that considering such a short period of time will produce adequate collateral requirements, as it would exclude major, albeit potentially infrequent, events that cause significant price moves affecting the value of FTRs. For example, such a short period of time could exclude extreme but foreseeable events like Winter Storm Uri or the 2014 Polar Vortex, which occurred more than three years apart,” the order states.

The commission said the 99% value would include events that occur at least once every 8.25 years. It directed PJM to submit a compliance filing within 30 days reflecting the change.

“As a general matter, FTR market participants should be, and are, in the best position to bear the principal cost of insuring against their risk of defaulting on the FTR portfolio positions that they acquire voluntarily. An HSIM model with a 99% confidence interval puts that principle into practice by striking an appropriate balance in requiring adequate collateral to protect market participants against the consequences of default without begetting the adverse impacts, e.g., reduced market liquidity, of over-collateralization. And contrary to PJM’s earlier claims, there appears to be little danger of significant ‘collateral shock’ or ‘market disruption’” by requiring FTR market participants to cover more of their own risk instead of transferring a portion of it to other PJM members,” the order states.

FERC agreed with the Independent Market Monitor’s contention that PJM’s cost-benefit analysis was flawed and did not capture the full benefits of a 99% vs. 97% confidence interval. PJM held throughout the proceeding that the costs of a 99% interval would exceed the benefits; several load serving entities, including Duke Energy and Old Dominion Electric Cooperative filed comments agreeing with PJM’s stance.

The commission accepted the remainder of PJM’s filing as is, including replacing the long-term FTR credit recalculation with real-time price updates, revising the $0.10/MWh volumetric minimum charge to apply after adjusting for auction revenue rights credits or mark-to-auction value and revising its tariff to explicitly state that a decline in FTR portfolio value leads to an increase in the FTR credit requirement, as well as the inverse. The order also removes the undiversified adder, which applies to market participants deemed to present heightened risk from being undiversified. Following the GreenHat default, PJM said, the adder was determined to not correlate with fluctuating market risk.

SPP Ordered to Show Cause on Lack of Mark-to-auction Mechanism

In a separate order, the commission expanded the scope of its show cause proceeding for SPP and directed further briefing (EL22-65).

The commission gave SPP 60 days to show cause as to why its tariff remains just and reasonable and to respond to eight questions. It directed the RTO to explain the tariff changes it believes would remedy FERC’s concerns.

The commission faulted SPP’s transmission-congestion rights (TCR) market for lacking a mark-to-auction collateral requirement or a comparable alternative. The mechanism can mitigate excessive risk-taking by allowing the grid operator to make a collateral call if auction prices reveal that FTRs acquired in a prior auction are declining in value.

The commission said SPP’s credit policy failed to “address the credit default risk the commission identified in the show cause order.”

The commissioners said the RTO’s existing reference price methodology relies solely on historical congestion patterns and does not incorporate updated TCR portfolio valuations. FERC also said SPP’s improved credit requirements for TCR market participants did not directly address the increased default risk.

The commission said it remained “concerned” that a mark-to-auction mechanism or comparable alternative was not included in SPP’s tariff and noted the grid operator said its TCR auction process is not within the show cause order’s scope. FERC said SPP’s response raised issues that “require augmentation of the existing record” and it included a list of questions.

SPP staff said they are reviewing the order and plan to respond by Nov. 20.

CAISO

In terminating the proceeding regarding CAISO, the commission found that the ISO’s mark-to-auction valuation addresses the risk that an FTR portfolio — congestion revenue rights (CRR) in CAISO’s nomenclature — may decline in value over time (EL22-62). “We also find that CAISO’s existing volumetric alternative minimum collateral approach ensures that market participants maintain some minimal level of collateral that scales with the size of their CRR portfolio and cannot minimize their required collateral without correspondingly reducing their risk,” the commission said.

“The risk of a CRR portfolio changing over time is captured by incorporating the most recent CRR auction results as part of the financial security requirement calculation,” the order continued. “As noted in CAISO’s response, this approach incorporates a mark-to-auction mechanism and captures risks that emerge when auction results diverge materially from historical outcomes.”

The commission said several other factors reduce overall risk in the CAISO CRR market: CRRs are offered with a maximum open position of only three months and may be purchased only for paths associated with physical supply delivery.

The commission noted that CAISO uses a different approach from PJM, MISO or SPP, all of which require a flat $/MWh amount on FTR portfolios. “CAISO nonetheless requires a volumetric value to be posted as collateral that is weighted to produce a $/MWh amount, which imposes a higher requirement on negative or low positively valued CRR portfolios,” it said.

ISO-NE

FERC said ISO-NE’s collateral requirements are just and reasonable, agreeing with the grid operator that the tariff’s existing provisions require market participants to maintain collateral scaled to the size and risk of their FTR portfolio (EL22-63).

It agreed with the RTO that “the lack of a volumetric minimum collateral requirement does not render ISO-NE’s existing collateral requirements unjust and unreasonable.”

The commission took issue in the show cause order with ISO-NE’s lack of a volumetric minimum collateral requirement. The RTO responded that it is already well protected from risk due to its FTR financial assurance requirements and the fact that it doesn’t offer long-term FTRs.

NYISO

The commission said NYISO convinced it that it has adequate protections against defaults in its FTR market — called transmission congestion contracts (TCC) — despite the absence of a volumetric alternative minimum collateral requirement (EL22-64).

The commission cited the ISO’s alternative approach to ensure market participants “maintain some minimal level of collateral that scales with the size of their FTR portfolio and cannot minimize their required collateral without correspondingly reducing their risk.”

Unlike PJM and MISO, NYISO requires full payment for TCCs purchased in auctions upon completion of the auction, except for the second year of a two-year TCC. “We find that this key difference in settlement design ensures that market participants at a minimum must post the full auction price of an awarded TCC and, thus, prevents a market participant from minimizing its collateral without reducing its risk,” the commission said.

The commission cited a NYISO analysis that found the grid operator’s existing collateral requirements — $0.15/MWh for balance-of-period TCCs, $0.40/MWh for future six-month TCC, and $0.053/MWh the second year of a two-year TCC — were always greater than the minimum requirements in other markets ($0.10/MWh for PJM and SPP, and $0.05/MWh for MISO).

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Plans Would Boost OSW Infrastructure, Supply Chain Development

A new road map issued by an offshore wind trade association lays out the onshore infrastructure that could help the marine power source reach its potential in the United States.

The plan offered by the Business Network for Offshore Wind is neither modest nor inexpensive: It calls for $36 billion in spending on a network of up to 119 ports nationwide.

The U.S. offshore wind industry now has a mere 42-MW nameplate capacity but is poised to grow as state and federal leaders try to expand it to several dozen gigawatts by midcentury.

Spiraling costs are commanding headlines because they will filter down to consumers, but constraints on the supply chain and supporting infrastructure are just as problematic.

Monday’s report followed a separate but not unrelated announcement by the White House last week: Nine of the East Coast states at the center of first-generation offshore development efforts have signed a memorandum of understanding with four federal agencies to develop joint implementation plans to help the industry grow.

The goal is to expand manufacturing, port facilities, workforce development and supply chain capacity in a coordinated and sustainable way.

Port Buildout

BNOW in its report Monday underlined the need for public and private investment in port development and suggested ways to unlock the funds to accomplish this.

After more than a decade of study, development and delays, the U.S. offshore wind sector began to gain momentum in the past two years, culminating this year with the first substations and turbines being installed for the first two utility-scale projects in U.S. waters.

The industry ran into economic headwinds and the practical reality of creating an entire industry to fabricate and install supersized equipment under challenging conditions. Ports are on the shopping list.

“The shortage of port infrastructure developments is a critical bottleneck to industry growth that risks derailing progress,” BNOW President Liz Burdock said in a news release. “Federal and state governments must work together with private industry to incentivize and finance new offshore wind port projects to support our growing industry and create thousands of jobs in the process.”

BNOW identified 35 shoreline facilities in operation or in development and said more than $2.5 billion has been invested. But it placed the need at 99 to 119 ports along the Atlantic, Pacific and Gulf coasts. That breaks down into facilities specializing in pre-assembly; staging and integration; flexible laydown; manufacturing; and operations and maintenance.

BNOW suggests a mix of public- and private-sector steps to secure this investment, including state and federal subsidies, project de-risking strategies and accelerated permitting for construction projects.

BNOW said the investment would bring substantial returns: The 110 GW of offshore wind envisioned by 2050 carries an estimated $440 billion to $660 billion price tag in 2023 dollars, it said.

Regional Cooperation

Offshore wind is a signature initiative of President Biden, who has set a national goal of 30 GW online by 2030 and directed his administration to make progress toward it.

But states have a large regulatory role of their own in the buildout, as well as individual targets that add up to more than 30 GW.

The potential exists for competing and/or duplicated efforts if each state pursues its own priorities without coordinating with its neighbors.

The East Coast Memorandum of Understanding on Offshore Wind Supply Chain Collaboration announced Thursday includes Connecticut, Maine, Maryland, New Hampshire, New Jersey, New York, North Carolina, Rhode Island and the U.S. Departments of Commerce, Energy, Interior and Transportation.

The states will develop subregional plans to harness each other’s strengths and fill high-priority gaps while advancing economic development and environmental justice.

The Cabinet agencies will provide technical support to the states and help develop a share procurement and leasing timeline.

The Atlantic Coast from North Carolina to Massachusetts is the focus of early offshore wind development, because existing fixed-bottom turbine technology can be used there. Floating turbine technology still in development will be needed in the deeper waters off the Pacific coast and off Maine. To the south, the first Gulf of Mexico wind lease auction this summer fell flat.

But the White House said these early investments in the Northeast will bring future benefits of national scope, creating a viable U.S. supply chain for the new industry.

Also last week, the U.S. departments of Energy and Interior issued an action plan to build an interregional offshore transmission grid cable in Northeast and Mid-Atlantic waters.

The plan is a suggested road map for Northeast states to follow in the interest of reducing the price tag and increasing capacity.