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.
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.
“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.”
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.”
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.
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 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.
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.”
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
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.
AUSTIN, Texas — ERCOT staff and Potomac Economics, the firm that serves as the grid operator’s Independent Market Monitor, set aside their differences this week and promised to work together to improve the ISO’s procurement and deployment of ancillary services.
Potomac Economics President David Patton said the IMM’s staff has had “encouraging” discussions with ERCOT over changes to its ancillary service methodology. The ISO’s staff has also agreed to revisit its use of ERCOT contingency reserve service (ECRS), its first new ancillary service in 20 years, which was deployed in June.
“I felt like the board and ERCOT were pretty receptive to the message,” Patton said after the ISO’s Board of Directors meeting Dec. 19. “I feel like there was an acknowledgement by ERCOT that this is an issue worth studying and potentially making some changes to address it. Ultimately, my goal was to try to address this as quickly as we can so that these costs don’t accumulate.”
The IMM has said ERCOT’s use of ECRS has created artificial supply shortages that produced “massive” inefficient market costs totaling about $12.5 billion this year through Nov. 27. (See “Members Support 2024’s Ancillary Services Methodology, Despite Costs,” ERCOT Technical Advisory Committee Briefs: Dec. 4, 2023.)
ECRS is economically dispatched within 10 minutes of deployment, using capacity resources that can be sustained at a specified level for two consecutive hours to supplement ERCOT’s conservative operations posture, in which it sets aside ample reserves to address sudden energy drops.
Patton said that because ERCOT doesn’t co-optimize energy and ancillary services in real time like other grid operators, the ECRS megawatts are quarantined from the real-time market. He said the problem comes when ERCOT bought more 10-minute reserves this year than it did in 2022 in quantities that “dwarfed” those of other RTOs and ISOs, most of which are smaller than the Texas grid.
“We went to a whole other level in terms of buying 10-minute reserves,” Patton told the board’s Reliability and Markets (R&M) Committee. “At that same time that we’re buying those very high quantities, we quarantine them off from the real-time market so that it exposes the market dispatch to believing that it’s short when it’s not actually short.”
There were few questions for Patton during his presentation to the R&M and none in the board meeting that followed. The directors did approve ERCOT’s ancillary services methodology for 2024, including the commitment to reevaluate ECRS and meet with stakeholders by May.
Dan Woodfin, ERCOT vice president of system operations, said the high prices generally come when ERCOT is short of capacity.
“It’s those days when we were really tight on capacity and we had to release ECRS just to have enough to have it available to serve energy. If we can release it earlier on those days, then that may help with the efficiency of the pricing outcomes,” he said. “We’ve agreed we’re going to look at that. You got to be careful with that because there are people that are out there making investment decisions that are looking for regulatory certainty. I think this is one of those places that it’ll be really good to talk through that with the stakeholders to figure out what’s the right balance there.”
Texas Public Utility Commissioner Lori Cobos said the PUC has received a petition from retail providers to pass on ECRS costs in fixed-rate contracts and that legislation passed this year requires the commission to revisit ancillary services and their structure.
“There’s a recognition amongst the commission that, ultimately, the PUC needs to be involved in approving the ancillary service methodology [for 2025],” she said. “The reevaluation that happens in April needs to be a true reevaluation, given all of these costs. ERCOT, PUC staff, IMM staff need to get together and look at some near-term perspectives and long-term perspectives and how the ancillary service methodology can be more thoroughly and diligently vetted.”
In recent months, IMM’s then-Director Carrie Bivens raised the board’s hackles and received vigorous pushback for saying ECRS “likely” increased the real-time market energy costs by at least $8 billion. (See ERCOT Board, IMM Debate Ancillary Service Costs.)
After Bivens resigned from the IMM in November, the Monitor took another look at the ECRS analysis. Simulating energy cost increases from higher online reserve procurements, the Monitor found prices in August were more than double what an efficient price would have been. Taking those prices and evaluating the total number of megawatts in the real-time market, that pricing phase had a value of $12.5 billion.
“I think this is where the misunderstandings have come,” Patton said. “Some people believe that $12.5 billion is almost irrelevant and some people believe that $12.5 billion is sort of the market. It’s neither one of those. The most important price in this market is [the energy] price. This price is the one price that has to be right because this price drives everything else.”
When Patton first shared his presentation with the Technical Advisory Committee early in December, ERCOT called the numbers “absolutely false” in a document posted to its website.
“Electric consumers DID NOT pay $8 [billion] to $12 billion more for electricity in 2023 than they would have if ECRS were not purchased,” the grid operator said. “These types of hyperbolic declarations may be great for grabbing headlines or driving a particular narrative, but they do a grave disservice to Texans because they simply aren’t true.”
In his presentation Dec. 19, Patton said ERCOT’s response was “very disappointing.” He noted the IMM has always reported the numbers as wholesale market costs and that consumers are “partially protected” from those costs by suppliers’ hedges and contracts.
“Eventually, those hedges expire and then the future price that’s going to be paid and new bilateral contracts are all going to be based on expectations of what the spot price is going to be” in the future, Patton said. He said forward prices for next July and August have risen 67% with ECRS’ deployment.
“That suggests that as some of those hedges expire and they get re-signed, they’re going to be re-signed at a much, much higher cost,” Patton said. “Right now, the expectation is we’re going to have high and volatile prices next summer and the summer after that.”
Cobos to Rejoin Board
Cobos will rejoin the ERCOT board as a nonvoting, ex officio member for 2024. She was a member of the pre-Winter Storm Uri board through her position as the Office of Public Utility Counsel’s CEO and public counsel.
A recent rule change gives the PUC two nonvoting seats on the board. Interim PUC Chair Kathleen Jackson also is a board member.
Revised Budget Passes
The board approved the ERCOT budget and system administration fee for 2024/25 after both were recently trimmed by the PUC. The commission cut both original proposals, slicing a little over $31 million from the original biennial budget request and reducing the administration fee from 71 cents/MWh to 63 cents/MWh, a 13.5% increase over the current admin fee of 55.5 cents/MWh. (See Texas PUC OKs Smaller Budget, Admin Fee Increases for ERCOT.)
The grid operator’s original budget request of $424.03 million and $426.99 million for 2024 and 2025, respectively, was reduced to $405.7 million and $414.3 million.
The commission reduced the admin fee to be in place for two years, rather than four, because of future uncertainty. It also directed ERCOT to meet certain performance measures and file quarterly progress reports on the development of a reliability standard, dispatchable reliability reserve service and the performance credit mechanism, and the real-time co-optimization plus batteries project. The first report is due Sept. 1.
Bill Flores, chair of the Finance and Audit Committee, cautioned the board that ERCOT could revisit the admin fee for 2025 late next year. He said the budget relies on more interest income than any previous budget.
“Assumed interest income is not guaranteed, so while we’re comfortable that we have a locked-in budget and interest amount for 2024, 2025 is still at risk,” Flores said. “Each 1% change in interest rates … is equivalent to a $20 million budget impact. If you had a 4% drop in interest rates back to close to zero, where we were in late 2020, then your interest income would show a reduction of somewhere between $80 [million and] $100 million, and each 1% drop affects the system admin fee by several cents.
“The new rate is 63 cents, which I think is a good outcome for ratepayers in Texas, but there is a risk to what can happen to that rate as soon as 2025, 2026 and 2027.”
The board also confirmed the Technical Advisory Committee’s membership for next year, as selected by its members. TAC will elect its chair and vice chair during its Jan. 24 meeting. South Texas Electric Cooperative’s Clif Lange is leaving the committee after four years as chair.
The directors approved a nodal protocol revision request (NPRR1172) that passed despite opposition from the generator segment during the October TAC meeting. The NPRR, brought forward by consumer groups, removes the mitigated offer cap multipliers and creates a 100% claw-back for reliability unit commitments.
The change is intended to encourage generation resources to self-commit.
The board also approved five other NPRRs and single changes to the nodal operating guide (NOGRR), planning guide (PGRR) and retail market guide (RMGRR):
NPRR1181: Requires qualified scheduling entities representing coal or lignite resources to submit to ERCOT a seasonal declaration of coal and lignite inventory levels and to notify the ISO when the inventories drop below target and critical-level protocols.
NPRR1192: Incorporates the other binding document, “Requirements for Aggregate Load Resource Participation in the ERCOT Markets,” into the protocols.
NPRR1196: Corrects and updates equations used to determine ancillary service (AS) failed quantity calculations for load resources other than controllable load resources (NCLRs) developed under NPRR1149. Changes include calculation updates to account for AS allowances and restrictions that NCLRs can and cannot carry simultaneously with ERCOT contingency reserve service’s (ECRS) implementation; specifying the snapshot components to be used for the “telemetered AS for the NCLRs as calculated” variable; and adding a nonzero check for the “telemetered ECRS responsibility for the resource as calculated” variable.
NPRR1201: Reduces exposure from resettlements and default uplift invoices for historical operating days by limiting resettlement timelines due to errors that are discovered, and a market notice is provided to the market within one year after the operating day. This limit does not apply to alternative dispute resolution resettlements, a procedure for return of settlement funds or a board-directed resettlement addressing unusual circumstances.
NPRR1204: Implements the state-of-charge (SOC) concepts necessary for awareness, accounting and monitoring energy storage resources’ SOC within the RTC+B project.
NOGRR257: Resolves a conflict in emergency response service event-reporting timelines between the operating guide and protocols by striking the guide’s 90-day event-reporting requirement.
PGRR110: Removes a paragraph from the planning guide to accommodate the release of steady-state planning models in node-breaker format pursuant to a system change request.
RMGRR176: lays out the processes Lubbock Power & Light must use when it begins offering customers their choice of electric providers March 4.
FERC on Dec. 19 approved an exit fee for Tri-State Generation & Transmission Association members, rejecting the cooperative’s preferred method in favor of a modified version that its own trial staff came up with during a hearing process (ER21-2818).
Tri-State is a generation and transmission cooperative that provides wholesale power and transmission service to 45 members in Colorado, Nebraska, New Mexico and Wyoming. Its members have to buy almost all their power from it, with the exception of 5% of their needs that is carved out for self-supply and community solar.
The fact that members have to get most of their supply from Tri-State while the industry is shifting to more distributed and intermittent resources has driven some of its members to leave, said Guzman Energy Chief Commercial Officer Robin Lunt. Guzman is now providing wholesale services to two of Tri-State’s former members: Delta-Montrose Electric Association in Colorado and Kit Carson Electric Cooperative in New Mexico.
“I think that there was a combination of wanting more local control over generation mix and then the ability to build things in their community,” Lunt said in an interview. “And then [the] increasing prices and price volatility that was coming from Tri-State; so co-ops were looking at alternative paths.”
The case goes back to 2021 when FERC issued a show-cause order requiring Tri-State to demonstrate its tariff was just and reasonable without clear procedures for its members to withdraw by making a contract termination payment (CTP). (See FERC Accepts Tri-State’s Exit Fee Calculation.)
Tri-State filed a proposal for a CTP based on the higher of a lost revenues approach (LRA) or a debt covenant obligations (DCO) approach. A FERC administrative law judge came to an initial decision in September 2022, rejecting Tri-State’s method and others crafted by its members in favor of the trial staff’s proposal to base the exit fee on a “Balance Sheet Approach” (BSA).
The commission said that Tri-State had a chance to prove that its preferred LRA method with a floor based on the DCO was just and reasonable, even though the earlier hearing order signaled some concerns. However, Tri-State failed to adequately respond to those concerns, FERC said.
Tri-State argued the CTP was meant to hold remaining members harmless from early contract terminations by paying them for lost revenue under any terminated deals.
“We decline to provide an overarching, industry-wide rule for what a generally applicable tariff-based CTP must address,” FERC said. “The purpose of a CTP may vary depending on circumstances.”
FERC noted the D.C. Circuit Court of Appeals has said an exit charge “protects members of a cooperative against rate increases caused by the exit of a member, while also increasing membership commitment and stability” and covers the costs that a cooperative incurs “to provide full requirements service to the member.”
When it comes to Tri-State, FERC previously stated that the exit fee is meant to compensate the association “for the costs that it has incurred or has an obligation to incur in the future to satisfy its service obligations” under its departing member’s contract.
“Tri-State invested in generation and transmission facilities, and entered into [power purchase agreements], in order to serve the generation and transmission needs of its members,” FERC said. “If a member withdraws, it is reasonable for Tri-State to recover the share of the debt and other obligations it incurred on that member’s behalf, in order to protect against cost shifts to other members.”
The exit fee should cover the debt and other obligations undertaken by Tri-State for the withdrawing member, but remaining members should not be held harmless for lost revenues that they would have received over the full term of the contract, FERC said. Paying for lost revenues would go beyond compensating Tri-State for actual costs and obligations it incurred to serve departing members.
Tri-State also argued that allowing members to leave early would undermine its cooperative business model, but FERC said that neither the wholesale contracts nor its bylaws entitle the association to benefits of scale.
An LRA could be valid for an exit fee, but FERC had issues specifically with what Tri-State proposed, finding that the association failed to show that revenues equal its costs over the short term. The LRA would also allow Tri-State to recover decades of revenues not yet earned from a department member — based on decades of projected costs that the association will never actually incur plus a margin.
Because the DCO was linked to the LRA, the latter’s unreasonableness was enough for FERC to reject the former on its own. But FERC also would have rejected the DCO on the merits, it said, because it fails to consider key credits and adjustments, and it would recover transmission debt from withdrawing members who continue to take transmission service from Tri-State.
Members could also time their withdrawals to whenever Tri-State has low debt, or the association could manage its debt in a way that discourages withdrawals, FERC said.
FERC wound up deciding that the BSA — which was first proposed by United Power, a departing member, and then modified by its trial staff before being tweaked by the commission — was the best way to go. FERC has never used the approach for utilities pulling out of similar deals, but it has also never precluded using it.
“We believe that the situation here is not analogous to a withdrawal from long-term requirements contracts, because it involves additional complications, such as: accounting for a withdrawing member’s ownership interest in Tri-State; the possibility of a withdrawing member continuing to take transmission service from Tri-State; and a specific set of obligations under the [wholesale electric service contracts] and bylaws, among other factors,” the commission said.
FERC found that the BSA is unlikely to lead to higher rates for remaining members, noting that its ALJ said the DCO would have kept rates stable in the near term and the BSA is likely to lead to higher exit fees than that method.
Tri-State said Dec. 19 that it was reviewing the order, which includes actually analyzing the CTP methodology adopted and calculating the payments withdrawing utilities must pay. The association has to make a compliance filing within 30 days.
United Power is withdrawing effective May 1, and its DCO was calculated at $736.4 million, Tri-State said. Northwest Rural Public Power District is also withdrawing in May, while Mountain Parks Electric has submitted a notice to withdraw by Feb. 1, 2025.
Tri-State does own the transmission grid that serves some of its members, but others, including its members in Wyoming, are on others’ transmission lines, so that could bring up issues that need to be clarified on rehearing, said Guzman’s Lunt. Some PPAs that Tri-State has could also be sold and then credited to departing members, which could also come up on rehearing.
While those issues could change the final amount, FERC’s order yesterday will give United Power and Northwest Rural more certainty about what they have to pay on their exit in May, with true-ups to follow, she said.
The issues in Tri-State are part of the same trend that is driving increased interest from corporate customers in their energy supply and even mass-market customers’ adoption of distributed solar and plug-in vehicles, Lunt said. Instead of building a large, central coal plant and building/procuring the transmission needed to get that supply to customers, now members want more control.
“There are efficient and cost-effective ways to have reliable power that’s more customer-focused rather than the big, coal-plant-focused,” Lunt said.
FERC on Dec. 19 reiterated its rejection of SPP’s proposal to allocate “byway” transmission projects case by case, urging the RTO to vet the proposal through a stakeholder process (ER22-1846-004).
The commission’s order addressing arguments raised on rehearing defended its July 13 order, which rejected SPP’s proposed methodology. It said a rehearing request filed Aug. 14 by Sunflower Electric Power, Basin Electric Power Cooperative, Midwest Energy and Kansas Electric Power Cooperative had been denied “by operation of law” when the commission failed to act within 30 days.
Since 2010, SPP has allocated transmission facilities based on the highway/byway method, with highway facilities (300 kV or above) assigned 100% on a regional, postage-stamp basis and byway facilities (between 100 and 300 kV) split, with 33% assigned regionally and 67% assigned to the pricing zone in which the facilities are located. Facilities at or below 100 kV are allocated 100% to the host zone.
Some stakeholders said that allocation method was unjust as applied in “generation-rich” pricing zones, where generation that is not affiliated with load in the zone significantly exceeds the amount of load in the zone — an issue of increasing importance because of the influx of wind generation on the SPP system.
In 2022, SPP proposed allowing parties to petition the RTO’s Board of Directors to reallocate byways as highways if they satisfy three criteria:
Capacity: The total nameplate capacity of generating resources that are physically connected in the zone where the byway facility is located (and that are not affiliated with load in that zone) exceeds 100% of the prior calendar year’s average 12-coincident peak resident load.
Flow: Energy flow on each byway facility that is attributed to generating resources physically connected in the zone where the byway is located and that are not affiliated with load in that zone exceeds 70% of the sum of flows on the byway facility attributed to generating resources affiliated with the load in the zone and generation physically connected in the zone and not affiliated with load there.
Benefit: The byway facility provides benefits to load outside the pricing zone where the facility is located (e.g., adjusted production cost savings or savings through the Integrated Marketplace).
The commission initially approved the changes, saying it would help ensure the costs of byway facilities are allocated in a manner at least roughly commensurate with estimated benefits. It ordered the RTO to modify the language to specify that the board’s decision on such requests would be based solely on whether the three criteria were satisfied.
The decision was 3-2, with then-Chair Richard Glick and fellow Democrats Allison Clements and Willie Phillips in the majority, and Republicans James Danly and Mark Christie dissenting.
But after Glick’s term expired and Phillips was appointed chair, the commission reversed course in July in response to rehearing requests by utilities including Southwestern Electric Power Co., Oklahoma Gas & Electric and municipal utilities in Springfield and Kansas City, Mo. This time, Phillips and Clements joined Danly and Christie.
FERC ruled that even with the modifications it required, the tariff changes would grant the SPP board too much discretion because it could deny a requested reallocation even when RTO staff had determined the criteria were met, or approve a reallocation in which the criteria were not met.
The commission said it may reverse its prior position as long as it explains itself and that it does not need to establish that its newer position is superior to the previous one. The commission said allegations that SPP’s existing cost allocation method is unjust and unreasonable “are misplaced in a proceeding addressing a filing made under [Federal Power Act] Section 205. The proper vehicle for challenging existing tariff provisions as unjust and unreasonable is a complaint under FPA Section 206.”
In a joint concurrence with the order, Phillips and Clements said they were “sympathetic to … concerns that the commission’s decisions in this docket have caused parties to spend considerable resources over several years, without a solution to the deeper cost allocation challenges that prompted SPP’s filings in this proceeding.”
The commissioners said that while those seeking rehearing of the July ruling “raised compelling points that revisions to the highway/byway cost allocation approach may be appropriate under these circumstances, in our view the best path forward to address this issue would be an open, collaborative process between the relevant parties and stakeholders. Such open dialogue would allow for fulsome exploration of any legal or administrative barriers to potential cost allocation approaches, without some of the rigidity of a contested proceeding.”
The rehearing process, they said, “is not the ideal venue for the collaborative discussions that we envision would lead to durable policy solutions.”
