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November 2, 2024

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Biden Admin. Releases Proposed Rules for Hydrogen Tax Credits

To qualify for the Inflation Reduction Act’s tax credit for clean hydrogen, a plant’s power will have to be new clean energy generated in the same region as the plant and, by 2028, be matched to demand hour-for-hour, according to proposed rules the Treasury Department and Internal Revenue Service released Dec. 22.

Those three “pillars” — additionality, deliverability and time matching — are at the core of Treasury’s Notice of Proposed Rulemaking, which details all the definitions and conditions hydrogen producers will have to meet to cash in on the IRA’s 45V production tax credit. Meeting all the proposed requirements in the NOPR could be worth $3/kg of clean hydrogen produced for 10 years from the date a new clean hydrogen plant goes online.

The 45V credit is technology agnostic but requires that a plant’s lifecycle greenhouse gas emissions — measured from “well to gate,” or up to the point of production — must be between .45 kilograms and 4 kg per kilogram of hydrogen. As with other IRA tax credits, the plant also must pay prevailing wages and participate in registered apprenticeship programs.

The base amount of the tax credit has four tiers, beginning at $0.60/kg for emission of less than .45 kg per kilogram of hydrogen, and bottoming out at $0.12/kg for emissions of 2.5 kg to 4 kg. Those rates then can be multiplied by five if the prevailing wage and apprenticeship requirements are met.

To qualify for the credits, the clean hydrogen must be produced in the United States or a U.S. territory.

The NOPR’s provisions on measuring a plant’s lifecycle emissions are where things get complicated, especially if a plant is using electricity off its local grid, which in most cases will include some power generated with higher-emitting fossil fuels. The electrolyzers that split hydrogen off water molecules to make green hydrogen are “very energy intensive,” according to a senior administration official, speaking at a prerelease press call Dec. 21.

“If you put a lot of energy into [making hydrogen], and you’re taking those resources off of powering homes and industry and buildings, then that power has to come from someplace, and if it’s being backed up with fossil fuel power, you’re adding to emissions.”

Treasury worked with the Department of Energy and EPA to develop a workable strategy for measuring lifecycle emissions, Developers or plant owners will be able to use DOE’s Greenhouse Gases, Regulated Emissions and Energy Use in Transportation (GREET) platform, a computer modeling tool, modified for hydrogen, according to the Treasury press release.

The new model and a user’s manual were scheduled to be publicly available Dec. 22.

Treasury, DOE and EPA officials at the prerelease briefing stressed that the rules being released are only proposals. The NOPR includes questions on issues that are still unresolved and need more input from stakeholders, they said.

The release Dec. 22 begins a 60-day comment period. A public hearing is scheduled for 10 a.m. EST March 25.

Energy Attribute Credits

Under the proposed rules, producers would use energy attribute credits (EACs) to demonstrate that they are, in fact, purchasing clean power based on the three criteria. The goal here is to provide rigorous standards for clean energy, while also allowing flexibility to account for emerging and evolving technologies.

In a DOE white paper also released Dec. 22, EACs are defined as “legal instruments that represent an exclusive claim to the attributes of a unit of energy. … In the case of electricity, EACs verify that a certain unit of electricity was generated by a specific entity and has specific associated attributes.”

EACs include renewable energy credits but are not limited to renewable generation.

For the EACs used for the 45V tax credits, the critical attributes include:

    • New clean energy is defined as any generation that went online within three years of the hydrogen plant going into operation. It could also include existing plants that expand capacity.
    • The proposed rule on deliverability would be based on the transmission regions identified in DOE’s recent National Transmission Needs Study. Because California, New York and Texas are self-contained transmission regions, Treasury may consider allowing clean power from an adjacent region to qualify.
    • Technology to provide hourly time matching is not yet widely available, so Treasury is proposing a transition period to allow annual matching until 2028, “when hourly tracking systems are expected to be more widely available.”

The exact transition timeline for time matching is one of the questions raised in the NOPR for additional stakeholder input.

Others include whether electricity from existing clean power projects or power plants that otherwise might be retired, such as nuclear plants, might be classified as new clean energy under certain conditions, and whether hydrogen produced from renewable natural gas or “fugitive methane” might qualify.

“We’re looking for pathways that will create the environmental integrity that we’re seeking, but that we believe will allow the nuclear industry to participate in the clean hydrogen economy,” the senior official said. “There are a series of potential pathways, including upgrading the facility, relicensing pathways that anticipate losses in generation as a result of retirements that could happen and including a carveout that would create a safe harbor essentially, where a percentage of their production can go into clean hydrogen.”

What They’re Saying

The U.S. has a well-established hydrogen industry, based on “gray” hydrogen technologies that use methane or natural gas (which is predominantly methane) as feedstocks. Speaking at the prerelease briefing, DOE Deputy Secretary David Turk noted that at present, clean hydrogen production in the U.S. is under 1 million metric tons (MMT) per year. President Biden’s goal is an industry that can produce 50 MMT per year by 2050.

“The 45V clean energy, hydrogen production tax credit is an important part of our strategy to unlock private investment across sectors and build a clean energy economy and tackle the climate crisis,” White House Senior Advisor John Podesta said at the briefing. “Clean hydrogen will be critical for reducing emissions from hard-to-decarbonize sectors like heavy industry and heavy transportation.”

“There is significant industry support for this [three-pillar] approach, as well as billions of dollars being invested in projects that have already announced they will follow this basic structure,” said Deputy Treasury Secretary Wally Adeyemo. “In addition to industry, investors have made it very clear that they’re looking to invest in projects that produce clean hydrogen, as well. … Allies and partners have already put similar structures for hydrogen in place, [so] having clear rules to ensure the U.S. develops a clean hydrogen industry will help drive innovation and demand for more advanced American-made electrolyzers.”

Backing up such statements, Treasury also has released additional statements from industry stakeholders voicing mostly positive support for the NOPR in general and the three pillars.

A recent letter from seven clean hydrogen and electrolyzer companies, including Air Products, Nordex Green Hydrogen and Electric Hydrogen, expressed “confidence that proposed 45V guidance requiring … additionality from day one, strong deliverability standards and a phase-in of hourly matching by 2028 … will support scaled industry growth.”

Laura L. Luce, CEO of Hy Stor Energy, a Mississippi-based green hydrogen producer, also supported the three pillars as critical foundation for long-term off-take agreements for clean hydrogen. The time-matching provisions in the NOPR “ensure the production of competitively priced hydrogen advanced organizations that are fully committed to the most timely and efficient industrial decarbonization,” Luce said.

But U.S. lawmakers are split on how strictly the three pillars should be formulated and enforced. Sen. Maria Cantwell (D-Wash.) led a group of 11 Democratic senators in a recent letter to Treasury, DOE and the White House, warning that overly strict definitions of clean hydrogen in the proposed rules might hamper industry growth.

The seven hydrogen hubs being funded with $7 billion from the Infrastructure Investment and Jobs Act include projects that would use natural gas or nuclear, which might not qualify for the tax credits.

In an Oct. 16 letter, Sen. Sheldon Whitehouse (D-R.I.) and seven other Democratic senators lobbied for a strict definition of clean hydrogen, excluding any produced with natural gas.

The lawmakers expressed grave concern about “the risk posed by weak standards for what constitutes clean hydrogen. Fundamentally, the 45V tax credit must not be applied to any projects that directly or indirectly increase power sector GHG emissions. Without safeguards, 45V risks creating a shell game in power markets, where existing clean generation gets nominally claimed by hydrogen electrolyzers, but the resulting gap in grid capacity is backfilled by fossil fuel generation.”

Disagreements over Hourly Matching

The proposal’s timeline for requiring hourly matching won praise from environmental organizations but drew fire from industry groups, including the American Council on Renewable Energy (ACORE), the American Clean Power Association and the Edison Electric Institute.

ACP CEO Jason Grumet called it a “a fatal – but fixable – flaw.”

“Imposing an hourly matching provision too early for first-wave green hydrogen projects will discourage a significant majority of clean power companies from investing in green hydrogen manufacturing and facilities,” he said. “ACP is encouraged to see that the Treasury Department has specifically requested comment on the adequacy of the transition schedule.”

Richard McMahon, EEI’s senior vice president for energy supply and finance, said the proposal lacked the flexibility to allow a rapid scale up to support a hydrogen economy.

The 2028 matching requirement “would undermine the commercial viability of this nascent domestic sector and severely limit the widespread adoption of hydrogen that is produced using grid-connected facilities,” he said. “As a result, the cost-reducing benefits for hydrogen included in the Inflation Reduction Act would be squandered, and an important new tool that electric companies and customers could be using to drive down carbon emissions and costs would be sidelined.”

But the Union of Concerned Scientists praised the proposal, calling it a “a strong foundation for accurately capturing the true climate impact of hydrogen production projects.”

“Rigorous guardrails are necessary to ensure the hydrogen tax credit incentivizes the scale-up of the right hydrogen, not just any hydrogen,” said Julie McNamara, senior energy analyst and deputy policy director of UCS’s Climate and Energy Program. “No less than whether or not hydrogen actually serves as a tool for climate progress hangs in the balance.”

The Natural Resources Defense Council also endorsed the hourly matching proposal.

“Anything less than the climate and consumer protections proposed today would be a giveaway to legacy energy companies eager to hijack hydrogen at the direct expense of the climate and consumers,” said Rachel Fakhry, NRDC’s policy director for emerging technologies. “Broad loopholes would be disastrous for the climate, kneecap our efforts to clean up the power grid, and harm the global potential of the U.S. clean hydrogen industry. Treasury must hold firm and finalize this strong guidance.”

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ISO-NE Details Order 2023 Tariff Changes

WESTBOROUGH, Mass. — ISO-NE outlined key components of tariff changes it plans to make to comply with Order 2023 at the Dec. 21 Transmission Committee (TC) meeting, including cluster timelines and storage study assumptions. 

Al McBride, director of transmission services and resource qualification, outlined the RTO’s proposed timeline for the cluster process, which would span 582 days before the initiation of a subsequent cluster. This is longer than the process proposed by FERC due to a 270-day cluster study period, 120 days longer than FERC’s proposal. To help reduce the total timeline, ISO-NE has cut the cluster restudy period to 90 days compared to its initial proposal of 150 days. (See ISO-NE Details Proposed Order 2023 Compliance.) 

McBride said the RTO will allow letters of credit for the commercial readiness deposits, in response to a stakeholder request at the November TC meeting. ISO-NE is proposing a $5 million commercial readiness deposit for large generators seeking to enter the transitional cluster study, and a smaller fee for small generators.  

Customers with a valid interconnection request as of May 1, 2024, will be able to proceed with a transition study or withdraw from the interconnection queue without penalties. 

ISO-NE is also proposing to incorporate its existing cluster enabling transmission upgrade (CETU) process into the new interconnection procedures. ISO-NE can initiate CETUs for state resource procurements that seek interconnection in similar locations, as well as for withdrawn interconnection requests in the same part of the New England Control Area. 

For ongoing affected system operator studies, which look at the effects of distributed generation projects on grid reliability, ISO-NE is proposing to allow transmission owners to continue studies if they are on track to be completed within 90 days of the start of the transitional cluster study.  

McBride also outlined ISO-NE’s proposal for studying storage resources, which differs from the approach taken by Order 2023. The order would let interconnection customers choose the maximum system load at which batteries will be studied, while requiring control technologies to prevent batteries from charging when load exceeds these limits. 

ISO-NE is proposing an approach that would avoid the need for control technologies, instead relying on energy market bidding to determine which batteries can charge. During the study process, the RTO is proposing to study batteries at an 18,000-MW “shoulder” net system load. 

NEPOOL will turn its focus to stakeholder amendments to the RTO’s Order 2023 compliance proposal at its Jan. 4 meeting. 

Longer-Term Transmission Planning

Brent Oberlin of ISO-NE introduced tariff changes associated with the second phase of ISO-NE’s Longer-Term Transmission Planning project. The project is aimed at enabling forward-looking transmission projects that can prepare the region for the load growth and changing resource profile associated with the clean energy transition. (See ISO-NE Updates Longer-Term Tx Planning Proposal.) 

The new process will allow ISO-NE to issue a request for proposals (RFP) at the direction of the New England States Committee on Electricity (NESCOE) to address reliability needs identified in longer-term transmission studies.  

To be selected in the RFP, bids will first be evaluated on whether they solve the identified reliability needs. ISO-NE will then consider a quantification of a project’s benefits relative to its total costs. The quantified benefits of a project must outweigh its costs over a 20-year period for the project to be eligible for selection, Oberlin said.  

Once these thresholds are met, the cost-benefit ratio will be one of the aspects considered by ISO-NE when selecting the preferred solution, along with factors like operability and expansion capability.  

Oberlin noted that NESCOE can cancel the project at any time throughout the process. This could introduce uncertainty for transmission developers, as the process would be contingent on the states agreeing on a cost allocation method. 

David Burnham of Eversource said that some longer-term reliability concerns should be exempted from the RFP process and assigned to incumbent transmission owners. He said that an “overreliance on competitive RFPs” could incentivize greenfield projects over upgrades of existing infrastructure, reduce flexibility in the solutions selected and “increase risk of duplicative transmission investment,” such as overlap between the longer-term process and asset condition projects.

The proposed exemptions would be focused on “needs that can be addressed cost-effectively by upgrades to existing facilities or by maximizing use of existing properties/[rights of way].” 

In Eversource’s proposal, ISO-NE could identify exemptions for “qualifying low-impact projects.” This definition would extend to upgrades or replacements of aging equipment, new infrastructure sited largely on existing rights of way and the deployment of grid-enhancing technologies. 

ISO-NE initially floated the possibility that some reliability projects could be assigned to incumbent transmission owners but said at the November TC meeting that it would abandon this aspect of the proposal. The RTO said it received mixed feedback from stakeholders on assigning needs to incumbents and was concerned the development of these RFP exemptions would delay the overall longer-term transmission planning effort. 

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CAISO Wins (Nearly) Sweeping FERC Approval for EDAM

CAISO marked a key milestone in its Western expansion efforts Dec. 20 after FERC approved nearly every aspect of its proposed Extended Day-Ahead Market (EDAM). 

The commission’s 181-page ruling rejected only one provision in the extensive proposal: a temporary measure designed to ensure interim compensation for any transmission providers that suffer financial losses during their transition into the new market (ER23-2686). 

“CAISO’s proposal to improve the performance of its existing day-ahead market with new products, and to offer balancing authority areas outside CAISO’s current footprint the opportunity to participate in and benefit from a new day-ahead market, will create significant savings for consumers in Western states,” FERC Chair Willie Phillips wrote in a concurring opinion. 

The ISO filed the EDAM proposal in August, not long after SPP began making significant inroads in the West with its own Markets+ day-ahead offering, setting the stage for a competition that could see the region divided into two different markets in the coming years. (See CAISO Files EDAM Proposal with FERC and Regulators Propose New Independent Western RTO.) 

EDAM, an extension of CAISO’s real-time Western Energy Imbalance Market (WEIM), is the product of a nearly five-year initiative by the ISO and Western electricity sector stakeholders. The ISO paused the effort for a year after persistent heat waves in August and September 2020 caused rolling blackouts in California and strained grid conditions in the wider West. (See CAISO Promotes EDAM Effort in Forum.) 

FERC’s relatively clean ruling signaled a solid endorsement of those efforts.  

“Yesterday, we accepted CAISO’s extended day-ahead market (EDAM) proposal and the accompanying improvements to its day-ahead market,” FERC Commissioner Allison Clements posted on X (formerly known as Twitter) on Dec. 21. “I am excited by the continued developments in the West and am happy to support today’s [sic] order.” 

CAISO CEO Elliot Mainzer said in a statement that he was “deeply appreciative of FERC’s decision and grateful for all the hard work that got us to this important milestone. As we turn the corner into 2024, we are excited to keep our momentum on implementation and to immediately begin working with stakeholders to address the one area FERC has asked for additional information for its consideration.” 

Andrew Campbell, chair of the WEIM’s Governing Body, hailed the approval as “a landmark moment for cooperation in the West.” 

“EDAM builds on the success of the WEIM real-time market by allowing participants to lower costs, reduce environmental impacts and improve reliability during the critical day-ahead planning period,” Campbell said. “With this market, the West will also be more resilient to unexpected changes in weather and other grid conditions.” 

DAME Products

CAISO’s proposal consisted of two broad sections: one outlining a set of Day-Ahead Market Enhancements (DAME) intended to better align day-ahead market outcomes with real-time conditions, and the other comprising measures needed to implement the EDAM itself. 

The DAME provisions create two new products designed to reduce “load imbalances” between the day-ahead and real-time markets. Resources with awards for either product will have to provide economic energy bids for the full range of their awards. 

The first product category consists of “imbalance reserves,” a “flexible reserve product” the ISO will procure “up” or “down” in the day-ahead market to reduce uncertainty between the day-ahead and real-time net load forecasts and deal with real-time ramping needs not addressed by hourly day-ahead market schedules. 

In approving the introduction of imbalance reserves, the commission said the product represents a “reasonable approach to help CAISO address new system needs brought on by the changing resource mix, such as large differences between CAISO’s day-ahead net load forecast and real-time system needs.” It said it was not persuaded by protests from NV Energy and the Western Power Trading Forum (WPTF) that imbalance reserves would be over-procured or “adversely affect the procurement of other ancillary services.” 

The commission also set aside concerns by WPTF and others in agreeing with CAISO that imbalance reserves should be procured on a nodal — rather than zonal — basis to avoid the potential for the reserves to be undeliverable to transmission-constrained areas. 

“Although the cost of procuring imbalance reserves nodally could be higher than if they were procured zonally, this does not render CAISO’s proposal to use nodal procurement unjust and unreasonable. Nodal procurement of imbalance reserves is intended to increase the probability that the capacity will be deliverable in real time,” FERC wrote. 

The commission additionally approved CAISO’s proposed $55/MWh offer cap for imbalance reserves, saying it agreed with the ISO and its Department of Market Monitoring “that it is appropriate to impose market power mitigation on imbalance reserves offers to address market power concerns and ensure competitive market outcomes.” 

The second new product category proposed under the DAME provisions is a “reliability capacity” product to be implemented into the ISO’s residual unit commitment process, a day-ahead process designed to ensure enough resources are committed to meet real-time needs. Under CAISO’s plan, reliability capacity will also be procured on an “up” or “down” basis “to meet positive or negative differences between cleared physical supply in [the ISO’s Integrated Forward Market] and the load forecast,” FERC explained. 

“We find that the proposal will aid CAISO in reducing the need for out-of-market operator actions, thus improving the transparency of market prices,” the commission said in approving the product proposal, which elicited no protests. 

Participation Model OK’d

FERC also largely approved the ISO’s participation model and implementation provisions for EDAM. 

Just as with the WEIM, participation in the EDAM will occur at the balancing authority area level rather than at the level of individual utilities. 

“Similar to participation in the WEIM, EDAM participation is voluntary, and an EDAM entity has flexibility in determining how much of its resource’s capacity it is willing to offer into the day-ahead market,” the commission wrote. “We agree with CAISO that WEIM entities (i.e., balancing authorities participating in the WEIM) are the appropriate participants in EDAM because in many cases, the EDAM entity will be the only or most significant transmission service provider in a BAA.” 

The commission disagreed with the contention by Tri-State Generation and Transmission Association that roles within EDAM require further clarification. 

“Although Tri-State argues that resources operating within an EDAM entity should not be forced to participate in EDAM, the commission’s obligation is to determine whether CAISO’s proposal is just and reasonable, and not whether it is superior to alternatives. Further, to the extent Tri-State’s arguments criticize the WEIM participation framework, we find that such arguments are outside the scope of the EDAM proposal,” FERC wrote. 

The commission also deflected Bonneville Power Administration’s request that FERC emphasize the need for CAISO to develop a strategy for addressing market-to-market seams and acknowledge that entities such as BPA may require special provisions in agreement with the ISO with respect to EDAM and that such agreements should be required before the market can go live. 

The commission said that request fell outside the scope of the proceeded and noted “that CAISO has agreed to work with Bonneville to revise the Coordinated Transmission Agreement as necessary to facilitate Bonneville’s participation in EDAM.” 

The commission also approved EDAM provisions related to external resource participation; market design, market settlement and accounting, congestion and transfer revenue, market power mitigation, market monitoring, and governance. On the issue of governance, FERC dismissed concerns by BPA and Powerex regarding the lack of independence of the CAISO Board of Governors, the members of which are appointed by the governor of California. Powerex additionally contended that the ISO stakeholder process is biased in favor of California interests. 

“We note that CAISO’s proposed EDAM governance structure is consistent with the existing WEIM governance, which the commission previously concluded is just and reasonable,” FERC wrote. 

Access Charge Denied

The only portion of the EDAM proposal rejected by FERC was a provision that would have allowed transmission owners to recover shortfalls in short-term or non-firm transmission revenues that they could attribute to the transition of their assets into the market. 

CAISO proposed the “EDAM access charge” as a temporary measure to smooth adoption of the day-ahead market. It would have allowed TOs to recover three different components of lost transmission revenues: 

    • The difference between historical short-term revenues that would have been earned without joining EDAM and the actual amount earned; 
    • Eligible network upgrade costs for projects that increase transfer capability between EDAM BAAs; and 
    • Revenue shortfalls stemming from EDAM wheel-throughs in excess of an EDAM TO’s net transfers, represented by imports and exports. 

But in proposing the provision, CAISO also said the access charge was “severable” from the rest of the EDAM plan, arguing that rejection of the mechanism should not hinder passage of the broader proposal. 

FERC rejected the access charge despite a lack of protests from stakeholders, finding that CAISO had failed to justify its reason behind the three components. In her post on X, Clements emphasized the rejection was made “without prejudice.” 

“While yesterday’s order rejects CAISO’s proposed EDAM access charge, it does so without prejudice to a future filing in which CAISO provides additional support for the proposal,” she wrote. “I encourage CAISO to work with its stakeholders to timely submit a new proposal with sufficient support for consideration by the commission.” 

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Analysis Shows No Contamination from NY BESS Fires

A state review has found no sign so far of environmental damage or health risks from three battery energy storage fires in New York in mid-2023. 

State officials said Dec. 21 that analyses of air, soil and water data collected in the days after the fires do not show harmful levels of toxic substances or significant off-site migration of contaminants. No injuries were reported, they said. 

Gov. Kathy Hochul (D) in late July convened a fire safety working group to reduce the likelihood of fires in utility-scale battery energy storage systems (BESS) and ensure the safety of emergency personnel who respond to BESS fires.  

Thursday’s report is the first announced result of that effort. On-site assessments of BESS facilities and reviews of fire codes will continue into early to mid-2024. Fire code recommendations are expected to be released for comment in the first quarter. 

The task force was created after three BESS fires within two months in three different parts of the state. Lithium-ion battery fires are difficult to extinguish and can emit toxic smoke. 

There were no known injuries in the three BESS fires, but they came as battery fires were taking a terrible toll in New York City. Seventeen people have been killed and 124 injured in 239 blazes this year through Nov. 15. 

The New York City fires are being caused by micromobility batteries, which are entirely different from grid-scale batteries. But both use lithium-ion technology, and they are sometimes conflated in the public mind. (See Battery Storage Developers Bump Against Perception of Risk.) 

In the wake of this, numerous municipalities statewide have proposed or enacted BESS moratoria in 2023. 

Meanwhile, the state Public Service Commission is in the late stages of reviewing a proposed expansion of the state’s Energy Storage Roadmap from 3 GW to 6 GW installed by 2030. Many more gigawatts of capacity will be needed in the 2030s to supplement intermittent renewables. 

The New York Power Authority’s new battery energy storage system near Chateaugay, N.Y., is shown in May 2023. | NYPA

With storage forming an indispensable part of New York’s clean energy strategy, a large-picture review of safety practices became a pressing need.  

“As we continue to advance New York’s clean energy transition, maintaining this safety is of the utmost importance,” Hochul said Thursday as she announced the first results of that review. “Thankfully, the Working Group’s analysis shows no notable lasting impacts on the health or safety of the first responders or the communities they serve.” 

Hundreds of pages of data shared with NetZero Insider show an extensive array of tests performed at the three fire sites, with variations due to circumstances of the fires and conditions at the sites.  

For example, groundwater sampling was not performed at the site of the first fire, in East Hampton, because there was no sign of soil contamination by lithium or any of the other 25 metals that were targeted in testing. 

Groundwater also was not tested at the site of the second fire, in Warwick, because no water was used in firefighting efforts. But the nearby school district performed surface sampling in buses and facilities, and that came back negative. 

Testing is not complete at the site of the third fire, a 22.5-MW solar-storage facility in Chaumont.  

This fire drew the largest state response, with spill response teams, advisors, environmental law enforcement personnel, infrared-capable drones and air quality monitors sent to the rural area near the Canadian border. 

Over five days, large volumes of water were pumped onto the fire and adjacent equipment, leading neighbors to worry about their wells.  

The initial round of testing in 11 wells used for drinking water came back negative for fire contaminants. Results are expected in early January for tests on follow-up samples collected in early December. Collection of soil samples has been delayed until the damaged equipment is removed from the site. 

Air testing during the fires showed low levels of certain toxic substances.  

Carbon monoxide and hydrogen cyanide were present within a meter of the burning battery containers in Warwick but not outside the fence line. At the Chaumont fire, trace amounts of carbon monoxide and volatile organic compounds were detected. 

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EPA, FERC Hear from Stakeholders on Reliability

Both EPA and FERC received comments Dec. 20 on how reliability can be maintained under the former’s power plant rule that requires fossil fuel-fired units to curtail their emissions. (See New EPA Standards Designed to not Jeopardize Grid Reliability.)

EPA took comments on a supplemental request it issued in November seeking additional input on how to ensure reliability under its proposal. FERC took comments on its annual reliability technical conference, which featured testimony from EPA and others on the rule. (See FERC Dives into Reliability Implications of EPA’s Power Plant Rule.)

The two leading Republicans on the agencies’ oversight committees, Sen. John Barrasso (R-Wyo.) of the Energy and Natural Resources Committee and Sen. Shelley Moore Capito (R-W.Va.) of the Environment and Public Works Committee, filed a letter that expressed their continued doubts about the power plant’s feasibility.

“We urge the EPA to rescind its Clean Power Plan 2.0 proposal and make affordability, reliability and the limits of its authorities under the Clean Air Act cornerstones of any future proposal,” the two senators said. “The more time that has passed since the proposal, the more issues with the Clean Power Plan 2.0 have been uncovered. The proposal is beyond repair and must be withdrawn.”

The senators had also reached out to all four FERC commissioners for their thoughts on the rule and its impact on reliability, and those responses were filed with EPA. Both of the Democratic appointees indicated they are taking reliability seriously but did not bash the proposal like their Republican colleagues.

“The most significant threat to resource adequacy does not stem from a particular rule of any agency but rather from an energy system that was not built for the combination of challenges we face today, including extreme weather and a corresponding increase in unplanned outages, a changing resource mix, rising demand and more,” Commissioner Allison Clements (D) said in her response.

Commissioner Mark Christie (R) repeated his assertion from his testimony before the Energy Committee this year that the country was headed for a reliability crisis. (See Senators Praise Phillips, FERC’s Output at Oversight Hearing.)

“It is clear that the wave of retirements of dispatchable [electric generating units], especially coal but also gas — which is already happening at an unsustainable pace — will be intensified if Rule 2.0 ever goes into effect,” Christie said. “Even the threat of the pending Rule 2.0 is exacerbating the pace of retirements and having a chilling effect on the planning of new EGUs, because of its negative effect on the ability of existing dispatchable EGUs to obtain financing and its effect on state-level integrated resource plans.”

The Electric Power Supply Association’s members own 150,000 MW of those EGUs; it told EPA it was disappointed the agency did not reach out to those generation owners whose units will be directly impacted by the rule.

EPSA argued the hurdles to a nationwide buildout of the infrastructure needed to implement the “best system of emissions reduction” proposed — carbon capture and storage, or hydrogen — make the rule infeasible. It said that would need to be tackled in any “permitting reform” efforts.

“One need not look further for evidence of this view than recent announcements from two carbon pipeline developers (Navigator CO2 and Wolf Carbon Solutions U.S.) that they have canceled or temporarily withdrawn applications for major carbon pipeline investments citing the ‘unpredictable’ or ‘stringent’ nature of the regulatory process,” the trade group said.

On top of the need for additional infrastructure, retrofitting thousands of turbines will require a substantial supply chain of physical materials.

“The CCS/hydrogen industry will be built from scratch, requiring years to develop the supply chain for both the manufacturing of materials and a transportation network to deliver them,” EPSA said. “Even if physical materials are available, a trained, skilled workforce with the requisite knowledge to successfully install these upgrades doesn’t exist.”

EPSA also seconded Christie’s concerns about being able to finance the needed upgrades, noting the Inflation Reduction Act’s 45Q tax credit for carbon capture requires construction to start by the end of 2032, years before several compliance deadlines proposed by EPA.

The Edison Electric Institute told FERC that its investor-owned utility members are already in the middle of a long-term transformation in how electricity is generated, and they are committed to continuing that as fast as they can, while keeping reliability and affordability “front and center.”

The sector’s emissions were already at 1984’s levels as of the end of 2022 because of the growth in renewables, efficiency and demand-side resources, and a significant portion of the coal-fired fleet has been replaced by green energy and natural gas. EEI agrees with the long-term clean energy vision embodied in EPA’s proposal.

“With respect to reliability and in the development of such tools, EPA should be focused on compliance flexibility,” EEI said. “Compliance flexibility can help to limit the need for the use of any reliability mechanism, as well as the impact of extreme reliability events, by providing states and units with additional regulatory pathways and tools for compliance.”

Key compliance flexibilities include using mass-based approaches, annual and multiyear averaging, allowing states to recognize how plants will be operated in the future and the emissions benefits of retiring exiting units through appropriate subcategories. EPA’s subcategories give grid planners, and others in charge of reliability, concrete information on when specific units are going to retire, allowing them to be replaced in an orderly fashion.

However, when reliability issues cannot be addressed with those tools, EPA needs to have a mechanism available so generators can stay in compliance with the rule and reliability standards. While the subcategories give an idea of when units will retire, whether their closure will lead to reliability risks will not be known until later on, and that could require an additional mechanism to preserve reliability, EEI said.

It argued that EPA needs a mechanism that would allow for units needed for resource adequacy to stay open — more urgent emergencies can be covered under the Federal Power Act’s Section 202(c), which allows the Department of Energy to issue an order keeping plants running without being liable for violations of environmental regulations.

“The reliability challenges might require resources to increase their generation above forecasted levels or to delay a planned retirement until other assets (including transmission assets) are brought into service,” EEI said. “These scenarios often are time limited but may extend beyond the 90-day window envisioned by FPA 202(c).”

The Clean Air Task Force and Natural Resources Defense Council filed joint comments, agreeing with EEI that the industry is already changing significantly under business-as-usual regardless of EPA’s rule.

“Existing trends away from the most polluting plants, reinforced by the IRA incentives, mean that the most stringent performance standards under this rule will apply to a small portion of the fleet,” they said. “Experience demonstrates that transitions to a cleaner grid can be achieved reliably.”

EPA’s proposal is only modestly incremental to those changes that are already baked in, and it is designed to accommodate reliability while cutting emissions, the groups said.

“It is imperative for EPA to issue standards as required by the Clean Air Act to protect public health and the environment, to secure and extend the emission reductions expected from current trends and incentives,” they said. “EPA has a long history of fulfilling its environmental statutory mandate in the context of an evolving power sector without jeopardizing reliability. In fact, the extreme weather caused by climate change has been a major factor in many reliability events in recent years, in which fossil sources frequently proved to be the least effective at addressing shortfalls in electricity supply.”

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Western RTO Initiative Outlines Governance Options

Members of the West-Wide Governance Pathway Initiative working to establish a single Western RTO last week heard summaries of five potential options for creating a new governing body that could be independent of CAISO.  

Members of the initiative’s Launch Committee emphasized that the options are not formal proposals or recommendations, but rather should be used to further discussion.  

The group is seeking input on whether each option is independent, what the benefits and costs are, and whether it offers what California Community Choice Association’s Evelyn Kahl says could be the most important factor — equitable representation across the West. 

“That’s been an issue to date and it’s certainly something we’re looking to solve,” said Kahl, CalCCA’s general counsel and director of policy, at the Dec. 15 meeting.  

The launch committee hopes to address a host of other questions in the consideration of each option, including if the proposed governance structure facilitates growth of market services, allows participants autonomy to choose from those services and allows balancing authority areas to maintain independence.  

Spencer Gray, executive director of the Northwest and Intermountain Power Producers Coalition, said the committee spent the last few months scoping out governance structures.  

Five Governance Options

The five options offer varying degrees of independence from CAISO on a continuum between two “bookends”: the status quo and what it called “an abrupt full transition to an RTO.”  

The current rules, all under CAISO’s tariff, give the WEIM governing body shared voting authority with the CAISO board, but CAISO holds a limited veto, with the right to file proposed market rules with FERC under Federal Power Act Section 205.  

“Option 0” would continue the CAISO board’s and WEIM Governing Body’s shared authority over market rules but eliminate CAISO’s veto rights, requiring the filing of both proposals if the ISO and WEIM differ. Other examples of such a dual filing mechanism include the “jump ball” provision between ISO-NE and the New England Power Pool, and 205 filing rights held by the Regional State Committee of SPP and the Organization of MISO States over transmission cost allocation. 

The four remaining options require the creation of a new corporate entity, referred to in the Initial Evaluation Framework as a regional organization (RO).  

Option one is “the least amount of change possible to incrementally increase the autonomy of the EIM Governing Body,” according to Gray. It would place governance explicitly under the structure of the new RO, which would have primary voting rights and shared filing rights with CAISO, meaning they could file competing proposals.  

Option two, although still under the CAISO tariff, gives the RO sole authority over market rules and eliminates CAISO’s filing and voting rights. 

Option three starts to “pull apart the tariff,” according to Gray. In addition to having sole authority over market rules, voting and filing, the RO would establish its own tariff, while contracting with CAISO to operate its markets and services. CAISO also would maintain responsibility for balancing authority area operations, transmission planning and generator interconnection procedures. Gray raised the concern that this model could require duplication of interrelated tariff provisions for the RO and CAISO.  

Under the final option, rather than contracting CAISO for services, the RO would absorb CAISO staff and operate the markets and services itself.  

Gray said the committee rejected consideration of the “abrupt RTO transition” bookend following the failure of legislative efforts to transform CAISO into a multistate RTO independent of California.  

“We’ve tried to absorb more seriously the lessons of the recent legislative effort for an abrupt transition to a full RTO from the CAISO,” Gray said. “It doesn’t leave California and the CAISO balancing authority the kind of decision of whether to join the new regional organization that other balancing authorities outside of California … would be able to exercise or enjoy. So, we’re trying to think through as a Launch Committee the options that we’ve scoped and if they preserve that option both within California and outside.”  

The committee is planning to hire legal counsel to provide advice on potential legal barriers associated with the options. Key questions include, “does the option we’re considering require California legislative action, and if it does, what’s the scope of the action?” said Kahl. But the first question they’ll consider is whether the options they’re considering are consistent with existing FERC orders and regulations.  

Stakeholder Feedback

There was wide approval of the overall process among stakeholders.  

“This is really giving us the best and clearest path to markets to maximize value to the ratepayers,” said Conner Reiten, vice president of government affairs with PNGC Power. “We’re really encouraged by the quick pace that this is coming together … but I think what’s clear and what we’re finding is that there is a really new, really good opportunity for a single West-wide market to come into place.” 

Marc Joseph, the Launch Committee’s labor representative, echoed Gray’s concerns about the bookend option. He said he opposed the legislative effort to transform CAISO into a regional organization because it would have resulted in exporting thousands of the jobs required to build new generation and transmission outside of California.  

“We’re supporting the Pathways Initiative because the options that are under consideration could create cost savings and increase reliability without exporting California jobs,” he said.  

California Public Utilities Commission President Alice Reynolds also showed support.  

“California is very engaged in this effort and thinking about the West-wide benefits for reliability and for customers,” she said. “I just wanted to emphasize how important that is to California and how interested we are in increasing cooperation among Western states.”  

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SEEM’s Opponents Return to DC Circuit

Opponents of the Southeast Energy Exchange Market (SEEM) asked the D.C. Circuit Court of Appeals on Dec. 18 to review FERC’s approval of the market in 2021 after the commission once again denied their request for rehearing this year. 

The D.C. Circuit remanded FERC’s SEEM approval to the commission in July (ER21-1111, et al.), agreeing with the market’s opponents — a consortium of environmental groups including Advanced Energy United, the Clean Energy Buyers Association, the Natural Resources Defense Council and the Southern Alliance for Clean Energy — that the commission was wrong to deny requests for rehearing following the initial approval because they were filed too late. (See DC Circuit Sends SEEM Back to FERC.) 

When FERC approved the SEEM agreement in 2021, it did so by operation of law rather than by majority vote because commissioners were still split 2-2 when the deadline for approval arrived on Oct. 10. Under the Federal Power Act, in such a situation the measure under consideration is automatically considered approved. 

AEU and other petitioners filed a motion for rehearing on Nov. 12, which FERC denied, claiming that the petition was submitted after the 30-day deadline for rehearing motions expired. But the court ruled this July that because the approval date fell on a Sunday, and the following 30 days included two holidays, Nov. 12 was the correct due date for the motion. As a result, the court ordered FERC to deal with the rehearing request on its merits, issuing a mandate to that effect on Sept. 19, 2023. 

In their court filing, AEU and the other petitioners claimed that “the court’s mandate reset the 30-day clock” for the commission to act on their rehearing request. However, as of Oct. 18 — 30 days after the court’s September order — FERC had not acted on the petition. The petitioners therefore argued that FERC had once again denied the request and called on the court to review the SEEM approval directly. 

The court’s July decision also vacated FERC’s approval of SEEM’s non-firm energy exchange transmission service and found that it erred when determining that the market is not a loose power pool, remanding both decisions to the commission. FERC has not yet responded to this part of the court’s order, and AEU and the other petitioners did not ask the court to take up these issues in their filing. 

SEEM has faced criticism since before it began operations in November 2022. The market’s founding members — a group of utilities including Duke Energy, Southern Co., the Tennessee Valley Authority and Dominion Energy — promised that the expansion of bilateral trading in 12 Southeastern states would reduce trading friction while promoting the integration of renewable energy resources. 

However, its critics, including those involved in this week’s petition, continue to argue that the market would entrench the power of monopoly utilities while providing limited benefits to customers. Chris Carmody, executive director of the Carolinas Clean Energy Business Association, recently told RTO Insider that SEEM “needs dramatic reform” in order to be successful. In its first year of operations, the market has averaged about 72 MWh in hourly activity, a small fraction of the 1,323 MWh that sponsors projected before trading began. (See After One Year, SEEM Still Drawing Criticism.) 

Duke and other sponsors have said they are working to increase the number of successful trades through means such as automated tools to improve matches and additional training to help potential trading partners connect. The utilities also expressed confidence that FERC will allow trading on the market to continue despite the D.C. Circuit remanding the commission’s approval decision. 

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NJ Seeks to Advance Sole OSW Project After Ørsted Withdrawal

The New Jersey Board of Public Utilities (BPU) on Dec. 20 dismissed a citizen petition seeking to reassess the cost to ratepayers of Atlantic Shores, New Jersey’s sole offshore wind project in active development, as the struggling sector seeks to chart a new path amid persistent local opposition and the demise of two Ørsted projects.

The four board members voted unanimously to reject a petition filed in June by Save Long Beach Island (SLBI), a group that says it is made up of homeowners, residents, business owners and friends. The group had requested a public hearing to look at whether the value of the offshore wind renewable energy certificate (OREC) for Atlantic Shores could be reduced.

Requesting a “formal hearing to seek a reduction in the OREC,” SLBI submitted an economic analysis of the project that concluded that the BPU’s determination “relied on flawed cost-benefit analysis,” agency staff said at the meeting. The analysis did not consider the costs to tourism and fishing communities, and it projected the social cost of carbon incorrectly, SLBI claimed, according to the board order.

In response to the petition, Atlantic Shores, a joint venture between EDF Renewables North America and Shell New Energies US, filed its own petition seeking to dismiss SLBI’s request. It said the company had no right to a hearing under BPU rules and state law and that amending the OREC award could not be done without the backing of all parties involved, including Atlantic Shores.

The developer’s petition said SLBI’s only option was to appeal to the Appellate Division of the New Jersey Superior Court, but such an appeal should have been filed within 45 days of the OREC agreement, on June 22, 2020, a period that expired long ago, the board said.

After the vote, an attorney representing SLBI said in an email to NetZero Insider that the BPU had “abdicated its duty to objectively assess the merits of Save LBI’s petition.”

The “BPU’s determination that Atlantic Shores’ bid satisfied the relevant statutory requirements — namely, positive environmental, economic net benefits, and fair balancing risks and rewards between ratepayers and shareholders — was incorrect and remains incorrect,” said Thomas Stavola Jr. “Nonetheless, these issues, among many others, will continue to be pursued prospectively.”

NOAA Assessment of OSW Impact

The state is seeking to move its OSW program forward after Denmark-based Ørsted suddenly withdrew two of the state’s three approved projects, Ocean Wind 1 and 2, the first of which was the state’s first, and most advanced. (See Ørsted Cancels Ocean Wind, Suspends Skipjack.)

The BPU’s vote was one of three recent developments that underscored the challenge facing the state in retaining public support for OSW and ensuring that it remains a key plank in the state’s clean energy ambitions.

Opposition to New Jersey’s offshore wind projects increased this year, with opponents seizing on a series of whale deaths along the East Coast as a sign of the potential damage to marine life that the wind farms would cause. Although no construction has begun on any of the state’s coastal projects, opponents suggested that preliminary planning for the projects using sonar mapping could be tied to the whale deaths. However, state and federal investigators who have looked into the deaths have found no link to the OSW projects.

On Dec. 18, the National Oceanic and Atmospheric Administration’s National Marine Fisheries Services released its “final Biological Opinion” on the Atlantic Shores project that found it would have no great significant on marine life.

“NOAA Fisheries has concluded the proposed action is likely to adversely affect, but is not likely to jeopardize, the continued existence of any species of ESA-listed whales, sea turtles or fish,” it said, referring to the federal Endangered Species Act. “It is also not anticipated to destroy or adversely modify any designated critical habitat.

“NOAA Fisheries does not anticipate serious injuries to, or mortalities of, any ESA-listed whale. Additionally, no impacts to North Atlantic right whale critical habitat are anticipated.”

The conclusion is partly based on the fact that the proposed project “includes a number of measures designed to minimize, monitor and report effects” on endangered species, the agency said.

Coastal Mayor Concerns

In a separate incident Dec. 18, opposition to the OSW projects emerged in a hearing of the Senate Energy and Environment Committee, which removed a bill from its agenda to give the sponsor time to consider new input from opponents of the OSW projects.

The bill, S2978, would put into law the state’s goal to reach 100% clean energy by 2035, making it part of the state Renewable Portfolio Standard. (See NJ Committee Mulls Making 100% Clean Energy by 2035 Law.)

The committee took testimony on the bill Nov. 20. But committee Chair Bob Smith (D), the bill’s sponsor, said he abandoned a plan to vote on it this week, preferring to give the committee time to consider input from the mayors of a number of communities on the Jersey Shore.

“None of the stakeholders are happy, and we have another group of stakeholders that entered the field this past week — and they are Jersey coast mayors,” he said. “They are saying the Clean Energy Standard bill would require the erection of windmills, and they’re opposed to offshore wind.”

Expressing skepticism that he could draft the bill in such a way as to make the mayors happy, Smith said he would continue with the bill in the next legislative session, which begins Jan. 9.

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US Storage Market Sees Strong Growth, Strong Headwinds

The U.S. energy storage market scored a record-breaking third quarter, putting 2,354 MW and 7,322 MWh of new residential, commercial and utility-scale projects online, according to the Energy Storage Monitor/Q4 2023 report from industry analysts Wood Mackenzie (WoodMac) and industry advocates American Clean Power Association (ACP).

But the sector faces “multiple headwinds … resulting in a volatile near-term pipeline and difficulty in bringing projects to mechanical completion,” the report says, downgrading its predictions for total capacity by 2027 from about 66 GW to 63 GW, a 5% drop.

With WoodMac pegging U.S. market size at present at 8.3 GW and 24.7 GWh, even reaching the reduced target could require substantial growth.

Frank Macchiarola, ACP’s chief policy officer, hailed the numbers as clear evidence that “energy storage is increasingly a leading technology of choice for enhancing reliability and American energy security.” ­

“It will be essential to our future energy mix,” he said.

A 2022 analysis from the National Renewable Energy Laboratory estimated that, depending on the energy mix, the U.S. might need between 129 GW and 368 GW of storage to reach President Joe Biden’s goal of a 100% clean electric power system by 2035.

The WoodMac-ACP report highlights a number of key figures and trends on the current state of the market and the challenges ahead:

    • Grid- or utility-scale storage continues to be a primary driver of market growth, jumping from 1,261 MW in the third quarter of 2022 to 2,158 MW for the same quarter this year, a 71% increase.
    • Community, commercial and industrial (CCI) and residential storage both posted modest year-over-year increases: 3% and 4% respectively. CCI capacity stands at 30.3 MW, while residential is at 166.7 MW. California leads the residential market, with 78.4 MW installed in Q3 alone.
    • Despite the record-breaking Q3, storage market growth is hobbled by project delays, with 82% of projects originally scheduled to come online from July through September now pushed back. But these delays could result in ongoing growth in 2024, the report says.
    • The grid-scale pipeline is particularly volatile, with 86 GW of projects announced and 453 GW sitting in transmission interconnection queues, a 36% increase over Q3 2022.
    • But prices continue to fall for grid-scale lithium-ion battery storage systems, with WoodMac noting that “as of November 2023, [the] lithium carbonate spot price reached its lowest level since 2021.” However, while system prices are down, other “balance of plant” costs and labor costs are on the rise, the report said.

While not specifically mentioned, the impact of the energy storage tax credits and other incentives in the Inflation Reduction Act are incorporated into the report’s analysis, according to Vanessa Witte, senior research analyst for energy storage at Wood Mackenzie.

Thus, the increase in project labor costs is due partly to a tight market for skilled labor, but also “administrative fee increases due to fulfilling the prevailing wage and apprenticeship requirements” that are part of the IRA’s tax incentives, the report says.

Waiting for Long Duration

As with solar and wind, the headwinds for storage are all too familiar: supply chains, permitting and interconnection. But Witte sees more nuanced and transitory issues at play.

“A near-term headwind is the increased cost of capital, which also increases the [due] diligence for these projects,” she said in an email to NetZero Insider. “As interest rates and inflation come down next year, this will likely calm down as well. For supply, as opposed to last year, where the supply issue was centered on the availability and price of cells, it is now centered on substation equipment, such as transformers, circuitry, switchgear[s], etc.”

Macchiarola sees the industry playing a strong role in the energy transition and in building out domestic supply chains. But he said, “streamlined permitting and evolving market rules” will be needed to “further accelerate the deployment of storage resources.”

Another critical trend to monitor is that growth in capacity may not be matched by growth in storage duration. Across all sectors, the average duration is just over three hours.

The capacity of a storage project is measured in megawatts or gigawatts: the energy it produces, in megawatt- or gigawatt-hours. Duration is a measure of how long a project can produce energy at its capacity. Thus, a 2-MW, 6-MWh project would have a three-hour duration.

As renewables increase on the grid ― and fossil fuel plants are retired ― longer-duration storage will be needed to provide a range of grid support and backup services.

“Duration is growing, generally speaking, but not over four hours,” Witte said. “There are no market signals to incentivize four-plus hours. … There are a handful of states that have average duration at or over four hours, but not many, [and] these systems are typically solar plus storage.”

“Paired systems fit better with a four-hour (or slightly longer) duration for the firming ability of the paired system versus standalone that just plays into the wholesale market,” she said. “Batteries are not typically getting revenue from ancillary services and capacity markets.”

A still-emerging market, long-duration storage is not yet on WoodMac’s radar, Witte said.

“Long duration is growing. We expect to see more traction next year in terms of pilot projects and increased manufacturing,” she said. “But again, there are no market signals for four-plus hours, so the only [companies] actually utilizing longer than four-hour are utilities, for the reliability aspect, and again, these are few and far between.

“One- to four-hour dominates and will still dominate in the next 10 years for sure.”

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ISO-NE PAC Briefs: Dec. 20, 2023

Increased electrification and reliance on solar and wind resources will make electricity supply and demand more weather-dependent, resulting in more variable winter peak loads on the New England grid, Benjamin Wilson of ISO-NE told the RTO’s Planning Advisory Committee (PAC) on Dec. 12. 

Analyzing the results of the Economic Planning for the Clean Energy Transition (EPCET) pilot study, ISO-NE anticipates the range between maximum and minimum peak load weather years will reach 14 GW by 2045, a significant increase compared to the 4-GW range expected for 2025. 

This gap could require a large subset of dispatchable resources that run only in high-end cases, Wilson told the PAC. 

“The region may end up paying for a pool of resources which are only needed once every few years,” Wilson said. “Uncertainty surrounding how often dispatchable resources will actually be needed may lead to a need for higher capacity payments.”  

Wilson noted that even with the continued penetration of wind and solar, dispatchable generators still will need to cover about 90% of the expected peak load, underlying the importance of ensuring adequate revenue sources for dispatchable resources.  

The EPCET study also compared two future policy scenarios focused on resource compensation. One scenario focused on the continued use of power purchase agreements (PPAs) similar to state procurements. The second scenario included PPAs along with a reliability adder (RA) charge to fossil resources that would be allocated to non-emitting dispatchable resources. 

The scenarios included a carbon constraint of about 6 million tons by 2045. For context, the New England power system was responsible for about 30 million tons of carbon emissions in 2021. 

In both scenarios, ISO-NE found the cost of PPAs will increase significantly between 2035 and 2045, with new intermittent resources lowering the capacity factor of existing intermittent resources. Both scenarios also projected declining revenues for existing solar and wind resources through 2045, as these resources are “increasingly underbid by new resources with higher priced PPAs,” Wilson said. 

In the PPA-only scenario, nuclear profits also declined significantly by 2045, coinciding with the decline in energy prices. In contrast, profits remained relatively stable with the introduction of the RA.  

The RA likely would result in lower capacity market prices compared to the PPA-only scenario by increasing the revenue available to clean dispatchable resources in the energy market, Wilson said.  

“The PPA plus RA scenario generally does a better job of securing resource revenue adequacy,” Wilson said. “Providing greater revenues to baseload resources may reduce the likelihood of retirement.” 

Wilson added that demand response resources may play a role in reducing demands but could be limited in their ability to ease extended winter peaks. 

“Significant development of demand response resources could help alleviate the uncertainty surrounding multiple weather years. However, it may prove difficult to curtail some load (such as heating, cooling or transportation) during periods of extreme weather,” Wilson said.  

Nuclear generator net profits in PPA and PPA+ revenue adder scenarios | ISO-NE

Asset Condition Project Updates

Also at the PAC, Alan Trotta of Avangrid provided an update to the New England Transmission Owners’ (NETOs) proposed asset condition project forecast database. The NETOs presented a draft version of the database at the Nov. 15 PAC meeting. (See New England Transmission Owners Issue Draft Asset Condition Forecast Database.) 

Instead of categorizing transmission lines’ original in-service year, the database will list the in-service year of each line’s oldest component to account for line rebuilds. For transformers, the database will list both the in-service year and the manufacturing year.  

Trotta said cost projections would not be included in the database. He said including accurate cost metrics would require a significant amount of work and noted that cost projections were included in a pair of recent presentations.  

He said the NETOs plan to update the database annually, and that the transmission owners will “evaluate the feasibility of adding additional information to the database,” including asset health scores and data on other pool transmission facilities, such as circuit breakers and control houses.  

The first iteration of the database, along with related stakeholder comments, will be published in January, Trotta said.  

Project Presentations

Eversource presented to the PAC a project to replace deteriorating wood structures on two 115-kV lines in New Hampshire with a total projected cost of $15.7 million. The expected in-service dates for the replacements are mid-2024. 

In accordance with the new asset condition presentation guidelines, Eversource is soliciting stakeholder feedback due Jan. 11.