CPS Energy has notified ERCOT it plans to “indefinitely suspend operations” at three aging gas-fired units in 2025, further reducing the Texas grid’s thermal capacity.
The San Antonio municipality filed a notification of the suspension with the Texas grid operator March 13. The three steam turbines at the V.H. Braunig facility have a combined summer seasonal net maximum sustainable rating of 859 MW.
CPS Energy says the units are nearing the end of their operational lives. The first unit came online in 1966, and the other two followed in 1968 and 1970. Four smaller gas turbines at the site each have a nameplate capacity of 61 MW.
The municipality has made a concerted effort in recent years to meet the city’s climate goals and maintain reliability with a fuel mix that relies on clean energy, storage and gas resources. Its Board of Trustees approved a generation plan last year that shifts the utility away from coal power by retiring one unit at its J.K. Spruce plant by the end of 2028 and converting another to run on natural gas.
CPS Energy decommissioned two coal-fired units at its J.T. Deely plant in 2018.
ERCOT is accepting comments through April 3 as it conducts a study to determine whether the closure will lead to reliability issues.
The grid operator began the year with 15.5 GW of interconnection requests from gas resources. Most of those are for quick-starting combustion turbine or combined cycle units.
Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee and Members Committee meetings March 20. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be covering the discussions and votes. See next week’s newsletter for a full report.
Markets and Reliability Committee
Consent Agenda (9:05-9:10)
As part of its consent agenda, the MRC will be asked to endorse:
B. proposed revisions to Manual 11: Energy and Ancillary Services Market Operations to conduct more regular reviews of interface pricing points. The changes would add a definition of interface pricing points, which group buses together when calculating LMPs for energy transfers between external areas and establish an annual review of power flow impacts on each interface. (See “Other Committee Business,” PJM MIC Briefs: March 6, 2024.)
C. proposed revisions to Manual 12: Balancing Operations identified through the document’s periodic review. The new language would seek to align with real-time market operations detailed in Manual 11 and add detail to hybrid resource market parameters. (See “Periodic Review Manual Revisions Endorsed,” PJM OC Briefs: March 7, 2024.)
D. proposed revisions to Manual 37: Reliability Coordination including administrative changes identified through periodic review and reflecting changes to NERC standards FAC-011 and FAC-014. (See “Periodic Review Manual Revisions Endorsed,” PJM OC Briefs: March 7, 2024.)
PJM’s Michele Greening will present proposed revisions to PJM’s governing documents endorsed by the Governing Documents Enhancements and Clarifications Subcommittee (GDECS) last month. Greening told the committee in February that most of the revisions are clarifications and corrections, though some stakeholders have argued that several changes are more significant than are typically made through the GDECS. (See “Other MRC Business,” PJM MRC/MC Briefs: Feb. 22, 2024.)
The committee will be asked to endorse the revisions to the tariff, Reliability Assurance Agreement and Operating Agreement.
Demand Response Window (9:30-9:55)
Bruce Campbell, principal of Campbell Energy Advisors representing demand response providers, will present a quick-fix proposal to extend the availability window for DR resources by two hours during the winter to reflect expanded ability for load to respond in the evening hours and to align with changes made to PJM’s market structure following the Critical Issue Fast Path (CIFP) process. (See “Demand Response Providers Seek Expanded Availability,” PJM MRC/MC Briefs: Feb. 22, 2024.)
The committee will be asked to approve the proposed issue charge and endorse the proposed solution to key work activity 2 using the quick-fix process outlined in Manual 34, which allows an issue charge and proposed solution to be voted on concurrently.
Manual 18B: Energy Efficiency Measurement and Verification (9:55-10:45)
The committee will be asked to endorse one of the following proposed packages of revisions to Manual 18B: Energy Efficiency Measurement and Verification.
A. PJM’s Pete Langbein will present the main motion to revise how the RTO measures and verifies the capacity offered by energy efficiency resources. Prior to endorsement from the Market Implementation Committee on March 6, Langbein told stakeholders the manual revisions would clarify which basepoint EE providers should use to measure the energy savings associated with a resource and require that they possess exclusive rights to offer those savings into the capacity market and that they can demonstrate installation of more efficient equipment was completed. (See PJM MIC Briefs: March 6, 2024.)
B. CPower’s Ken Schisler will present an alternative motion offering a proposal seeking to resolve several concerns that EE providers laid out during the March MIC meeting, including the requirement that an EE installation be causally linked to the capacity market and a three-year limit on the eligibility for technical reference manuals be used to compare the energy use of new technologies against.
C. Affirmed Energy’s Luke Fishback will present an alternative motion that seeks to resolve issues with the PJM proposal, which Fishback told the MIC could result in large amounts of EE being unable to offer into future auctions.
Capacity Obligations for Forecasted Large Load Adjustments Issue Charge (10:45-11:10)
Old Dominion Electric Cooperative’s Michael Cocco will present revisions to the issue charge framing an ongoing stakeholder discussion on how capacity obligations arising from forecasted large load adjustments should be assigned to electric distribution companies. The proposal would add language to the in-scope section of the issue charge to include changes to Manual 19 to add details on how load-serving entities forecast large load additions and how those are then incorporated into PJM’s load forecasted. (See “1st Read of Proposal on Capacity Obligations Resulting from Large Load Additions,” PJM MIC Briefs: March 6, 2024.)
The committee will be asked to approve the amendments to the issue charge on first read.
Forecast Pool Requirement and Installed Reserve Margin (11:10-11:35)
PJM’s Patricio Rocha Garrido will present revised installed reserve margin (IRM) and forecast pool requirement (FPR) values for the 2025/26 delivery year to reflect changes to the RTO’s risk modeling and generation accreditation processes following FERC approval of market changes in docket ER24-99 resulting from the CIFP process. The recommended IRM is 17.8% — up from the 17.7% IRM the MRC endorsed in October — and the recommended FPR value is 0.9387, down from 1.1170. (See “Recommended Values for 2023 Reserve Requirement Study,” PJM MRC Briefs: Oct. 25, 2023.)
The committee will be asked to endorse the results upon first read. Same-day endorsement may be sought at the MC.
Members Committee
Endorsements (2:10-2:25)
Forecast Pool Requirement and Installed Reserve Margin (2:10-2:25)
PJM’s Patricio Rocha Garrido will present the updated FPR and IRM figures for the 2025/26 delivery year discussed at the MRC. The MC may be asked to endorse the results upon first read.
The 2023/24 winter season was one of NYISO’s most humdrum winters, characterized by high temperatures, low gas prices and below-average loads, according to a presentation shared with the Operating Committee on March 15.
Aaron Markham, NYISO vice president of operations, told the OC that “moderate temperatures led to moderate fuel prices for much of the season,” and the few “short-duration cold snaps” were not “super impactful.”
He added, however, that those cold snaps meant NYISO needed to burn “a fair amount of stored fuel” and saw “some gas system constraints,” but the ISO would “continue to monitor [fuel] replenishment” and study how to ensure fuel could be delivered more effectively for future peak days.
The season’s coldest period occurred around the Martin Luther King Jr. Day weekend, when load peaked at 22,754 MW on Jan. 17. It was still one of the ISO’s lowest winter peaks over the past 15 years and represents only one of three times during the month when load went above 22,000 MW, which usually occurs an average of 11 times during January.
During the Jan. 17 peak hour, New York’s load was served by an estimated supply mix of 26% natural gas, 14% oil, 17% hydropower, 20% imports from neighboring regions, 14% nuclear, 8% wind and 1% from other renewables.
Markham said one of the highlights for the winter season was the generation fleet’s “very good” performance, especially during the season’s peak load hour, when there was only about “150 MW of unavailable capacity from the day-ahead to real-time.” Additionally, intermittent production during peak days, although “still relatively low compared to the total demand,” continued to “see more contribution to meet demand.”
Markham also delivered the February operations report to the OC, saying the month “continued the trend of mild weather and no real strenuous operating conditions,” with a peak load of 20,981 MW recorded on Feb. 14.
He also mentioned that NYISO expects to “be able to manage” the April 8 solar eclipse and has asked its solar forecast vendor to ensure the eclipse’s impact on solar production is included in the next forecast delivered to the ISO. (See “NYISO Updates,” NY State Reliability Council Executive Committee Briefs: March 8, 2024.)
Thermal and hydro outages by type over peak hours in January’s winter cold snap | NYISO
Bear Ridge Solar Waiver Denial
FERC on March 14 denied Bear Ridge Solar’s waiver request for remedial relief from certain NYISO interconnection tariff requirements, effectively removing the project from the ISO’s queue (ER22-2085).
Bear Ridge aimed to develop a 100-MW solar farm in Niagara County and requested an exemption from two of NYISO’s tariff requirements because of “unforeseen events” that were “beyond its control” and led it to “substantial difficultly” in adhering to state siting processes and critical regulatory deadlines.
As a result of its “failure to comply with the regulatory milestone requirements,” Bear Ridge’s project faced withdrawal from the interconnection queue and risked the loss of a $657,000 cash security deposit necessary to cover its share of the costs for transmission upgrades determined by NYISO to be required for the project’s interconnection.
Although sympathetic to Bear Ridge’s situation, FERC said that granting the waiver would be “retroactive in nature and is prohibited by the filed-rate doctrine” in the Federal Power Act.
In a joint concurrence, Chair Willie Phillips and Commissioner Allison Clements said that although they were bound by the filed-rate doctrine, “the outcome here is neither equitable nor commercially reasonable” and is “emblematic of other waiver proceedings in which an applicant did not foresee that it would miss a deadline before it occurred.”
They acknowledged that FERC’s procedures are rigid and prevent it from granting even a modest milestone extension, which would “avoid sending the project back to the starting gate,” even though Bear Ridge satisfied the regulatory milestone at issue two months after submitting its waiver request unopposed by NYISO.
The commissioners called on transmission providers to revise their tariffs to permit FERC to waive such deadlines to allow the commission “greater flexibility in addressing sympathetic cases such as this one,” recognizing that the outcome “does not advance the goal of getting new resources online as quickly and reliably as possible” and “causes needless inefficiencies and deprives NYISO’s customers of the benefits that such a project provides.”
A lithium processing plant that could help put 800,000 electric vehicles on the road per year has received a conditional commitment for a $2.26 billion loan guarantee from the U.S. Department of Energy’s Loan Programs Office (LPO).
The plant would be in Humboldt County, on the Nevada-Oregon border, at Thacker Pass, where Lithium Americas Corp. and its Lithium Nevada Corp. subsidiary are developing a mine containing the largest proven lithium reserves in North America, according to the LPO announcement, released March 14.
The mine itself would be a shallow, open pit mine, located in a caldera, which is a collapsed volcanic crater, in this case formed millions of years ago. The processing plant would be located next to the mine.
The Thacker Pass lithium mine and processing plant will be located in the McDermitt caldera, a collapsed volcanic crater that was formed about 16 million years ago. | Lithium Americas
Lithium Americas is developing the site in two phases, with production from the first phase expected to total 40,000 metric tons (MT) of battery-quality lithium carbonate per year, according to the company website. A metric ton is 2,204 pounds. The output from Thacker Pass “could support the production of batteries for up to 800,000 electric vehicles,” LPO said.
General Motors also is investing $650 million in Thacker Pass and would receive all the lithium carbonate from the mine’s processing plant for its first 10 years, with an option to extend its contract for five more years. Another plus for GM: The output from the plant would qualify for the Inflation Reduction Act’s EV domestic content requirements and tax credits.
GM also would have a right of first bid for the lithium carbonate produced in the second phase, which Lithium Americas estimates would double output to 80,000 MT per year.
In a project update, also issued March 14, Lithium Americas reported that site preparation is complete, including “all site clearing, commissioning a water supply system, site access improvements and site infrastructure.” Bechtel is the main contractor for Thacker Pass and has entered into a labor agreement with North America’s Building Trades Unions for construction of the project.
Lithium Americas estimates Thacker Pass would create about 1,800 construction jobs and 360 permanent jobs.
The company estimates a three-year construction period, with work to begin pending the finalization of the LPO loan, which the company is anticipating for this year. According to the LPO, finalization would depend on the company achieving specific technical, legal, environmental and financial conditions.
Lithium Americas expects the mine and processing plant to reach full production in 2028. Plans for the second phase of development have yet to be announced.
Lithium Americas CEO Jonathan Evans called the LPO loan a “significant milestone” for Thacker Pass.
The mine will provide the U.S. “an incredible opportunity to lead the next chapter of global electrification in a way that both strengthens our battery supply chains and ensures that the economic benefits are directed toward American workers, companies and communities,” Evans said in the company’s announcement of the conditional commitment.
“The loan plus GM’s strategic investment will provide the vast majority of the capital necessary to fund Phase 1” at Thacker Pass, he said.
The GM Connection
President Joe Biden wants half of all light-duty vehicles sold in the U.S. to be electric by 2030, a goal that has made a swift buildout of a domestic supply chain for lithium and EV batteries a priority for government and industry, as both seek to counter China’s dominance in global markets.
The conditional commitment is the 10th the LPO has made since 2022 under its Advanced Technology Vehicles Manufacturing program, and two additional loans have been finalized during that time, according to the loan announcement.
One of the program’s earliest loans was its $465 million commitment to Tesla in 2010, which was repaid fully in May 2013.
This is the second LPO loan that would benefit GM. In 2022, the office finalized a $2.5 billion loan to Ultium Cells, the joint venture of GM and LG Energy Solution, to help build three plants ― one each in Michigan, Ohio and Tennessee ― to produce lithium-ion battery cells.
The Thacker Pass loan comes as GM has been rethinking its plans for EV production. In 2021, the company committed to sell only light-duty EVs by 2035, but in recent months, it has announced delays in planned production of certain EV models as sales continue to increase, though not at the pace the automaker originally projected.
During a January earnings call, GM CEO Mary Barra said the company’s plans for 2024 include the production and sale of 200,000 to 300,000 Chevrolet, GMC, Cadillac and BrightDrop EVs, all using Ultium batteries. BrightDrop is the company’s electric delivery van. Barra said GM also will bring back plug-in hybrid models for “select vehicles in North America.”
GM’s last plug-in hybrid was the Chevy Volt, which was discontinued in 2019. Barra hedged the company’s plans, saying GM’s ramp-up of EV production will follow customer demand.
The Thacker Pass mine has been controversial for some environmental and tribal groups, which have repeatedly but unsuccessfully gone to court to try to stop construction. The Bureau of Land Management approved the project in 2021 and reconfirmed that decision in 2023, following a court ruling that ordered the agency to perform a further evaluation.
The most recent legal challenge ended in November 2023, when a federal district court in Nevada dismissed a claim by tribal groups that the mine was near a sacred site, as reported by the Associated Press.
Environmental groups also have raised concerns about the mine’s potential use of ground water, a frequent challenge for lithium mines. However, Lithium America’s website notes the Thacker Pass open pit mine would be less than 400 feet deep, relatively shallow for an open pit mine, which could make it less likely to affect groundwater.
The project also has been designed ― and permitted by the Nevada Division of Environmental Protection ― to minimize any use of groundwater; plus, any water used on the site would be recycled at least seven times.
In addition, the company has a community benefits agreement with the Fort McDermitt Paiute and Shoshone Tribe, the closest tribe to the project, according to Lithium Americas. The company has offered job training for tribal members to prepare them for jobs at the project.
MISO discussed the second part of its long-range transmission planning (LRTP) project at a stakeholder workshop March 15, detailing how the project would help meet Midwestern transmission needs.
Tranche 2, the proposed transmission portfolio, includes a series of 765-kV lines intended to “enable a reliable and efficient transmission system while minimizing land use” as the region copes with increasing electricity demand and a changing resource mix. The project is projected to cost between $17 billion and $23 billion. (See MISO Says 2nd LRTP Portfolio Should Run About $20B, Rate Mostly 765 kV.)
“This anticipated portfolio builds on both the investment made in Tranche 1 and our existing system,” said Laura Rauch, executive director of transmission planning at MISO. Rauch added the proposal is intended to be a “least-regrets and robust step” to start solving anticipated transmission constraint issues and enable increased regional power flows.
MISO’s initial analyses indicate the transmission investments would significantly reduce thermal transmission constraints and the severity of overloads across the Midwest. The portfolio would also reduce resource curtailments throughout the region and decrease price differences between regions, MISO said.
The grid operator outlined its plans to quantify the portfolio’s potential savings from reduced losses, avoided capacity costs and decreased transmission outages, and asked for stakeholder feedback on the proposed methodology.
Tranche 2 is not intended to address all the potential regional transmission constraints, and “there is a need for additional transmission after this Tranche 2 portfolio,” Rauch said. She declined to specify the timing or targeted areas of this additional transmission.
Rauch stressed that the first phase of Tranche 2 proposal must be “independently valuable regardless of what next steps we might have.”
MISO expects the portfolio to “continue to be refined,” Rauch said. The RTO will continue to consider alternative solutions that could affect the outlined routes.
“We will make sure that we are not proposing a line that will not be valuable because of something that will be in service,” responded Rauch.
“There are legitimate questions about Grain Belt Express,” Rauch said, but added that MISO will address whether the merchant transmission project is likely to address issues similar to those met by Tranche 2 and adjust accordingly.
Some stakeholders expressed concern the portfolio is not based on the planning scenario that assumes the highest level of load growth and renewable energy penetration. MISO responded that running an additional analysis based on the more aggressive scenario would add six to nine months to the overall process, while the proposed portfolio would likely remain a good first step.
“We can’t continue to kick this can down the road; we need to start moving forward,” said Bob McKee of American Transmission.
McKee added his support for the consideration of 765-kV lines, saying stakeholders “should not be surprised that 765 is showing up on this map … it’s been two years that we’ve been talking about the possibility of 765.”
While MISO determined 765-kV lines make the most sense for Tranche 2, the RTO said it will continue to consider HVDC solutions in future proposals.
Asked whether grid-enhancing technologies (GETs) are part of the solution to the transmission constraints, Rauch said GETs are unlikely to supplant the needs of the proposed Tranche 2 lines but could complement the upgrades and help the grid operator get the most out of the infrastructure.
Federal regulators have finalized their proposed wind energy area (WEA) in the Gulf of Maine.
The zone has been trimmed, slashed and reshaped repeatedly since the U.S. Bureau of Ocean Energy Management began to gauge commercial interest in a 13.7-million-acre zone south of Maine.
After carveouts to avoid fishing and lobstering grounds, key wildlife habitats and cultural resources, the final WEA that BOEM announced March 15 totals approximately 2 million acres.
Even with the reductions, the area is believed to hold the potential for up to 32 GW of offshore wind development.
The WEA is 23 to 92 miles from land and stretches across water far too deep for wind turbines with fixed-bottom foundations, like those being built farther south along the New England coast.
Wind power development in the Gulf of Maine would rely instead on floating turbine technology that is being refined, including at the University of Maine. Maine hopes to be a leader in this new subsector and is separately pursuing BOEM approval of a research lease to place up to a dozen floating turbines closer to shore.
With the WEA finalized, BOEM will assess the potential environmental impacts of wind power development there and decide whether to proceed to leasing.
Multiple public comment periods have been opened so far, and more are yet to come. BOEM said this engagement has helped shape the WEA and will continue to be incorporated into the plans.
Maine’s governor and congressional delegation had pressed BOEM to remove a key lobster management area from the WEA. In a joint statement March 15, they said:
“We appreciate that the Bureau has heeded our concerns and the majority of the concerns of Maine’s fishing communities in its final designation of wind energy areas for the Gulf of Maine. This decision preserves vital fishing grounds and seeks to minimize potential environmental and ecological impacts to the Gulf of Maine. We look forward to reviewing the final map in detail and urge the Bureau to continue to engage with Maine’s fishing industry, coastal communities, tribal governments, and other key maritime users and stakeholders as the commercial leasing process moves forward.”
As indicated in their statement, not every stakeholder priority was entirely addressed.
The Maine Lobstermen’s Association told local media it appreciated some of the most important fishing areas being removed from the final WEA but said too many unanswered questions remained about the impact of wind power development in the Gulf of Maine.
New England for Offshore Wind said more efforts are in progress to avoid and minimize use of areas of historic and cultural significance to Maine’s tribal nations.
Maine Audubon said the announcement was an important step in the right direction, but it would pursue more wildlife safeguards.
But overall, many labor and environmental advocacy groups were pleased with the WEA.
“Maine is setting an example for the rest of the nation for responsibly developing offshore wind, balancing the needs of coastal communities and wildlife protection with the urgency to address climate change — the greatest threat facing our woods, waters, trails and coastlines,” said Jack Shapiro of the Natural Resources Council of Maine.
“BOEM’s announcement today reflects a major step forward for responsible and equitable offshore wind development in the Gulf of Maine,” said Kelt Wilska of New England for Offshore Wind. “New England is once again setting a national model for reducing potential conflicts during project construction and respecting the critical role that heritage fishing industries play in our economy.”
The Viejas Band of Kumeyaay Indians could soon be powering their casino, resort and retail complex east of San Diego with a microgrid combining solar and long-duration storage, with the help of a $72.8 million loan guarantee from the Department of Energy’s Loan Programs Office (LPO).
Wahleah Johns, director of the DOE Office of Indian Energy, announced the LPO’s conditional commitment for the loan March 13 at the 2024 Reservation Economic Summit in Las Vegas. Currently under construction, the Viejas microgrid will combine 15 MW of solar with 38 MWh of long-duration, non-lithium storage and is the first loan the LPO has made under its long-dormant Tribal Energy Financing Program, Johns said in a video posted to LinkedIn.
Power from the microgrid will replace electricity the tribe buys from San Diego Gas & Electric, generated from natural gas, nuclear, coal and renewables, according to a DOE email to NetZero Insider. The solar will be installed on carport structures, and the storage system will include two types of long-duration batteries: 10 MWh of vanadium flow batteries provided by Invinity and 28 MWh of zinc-based batteries from Eos Energy. Both can provide up to 12 hours of power, according to the companies’ websites.
The project also received a $31 million grant from the California Energy Commission in 2022.
The California wildfires and resulting power outages of 2020 were the original impetus for the project, along with concerns about the fire hazards of lithium-ion batteries, according to a case study on Invinity’s website.
The tribe will purchase electricity from the project through a long-term power purchase agreement, according to the LPO announcement of the loan.
The Viejas microgrid “will allow the tribe to benefit from lower energy bills and use those savings [toward] investment by the tribe in infrastructure maintenance, operation of the fire department, tribal culture and education programs, and other tribal member services,” Johns said.
The project also represents a model of tribal collaboration, Johns said, with the developer, the 100% Indian-owned Indian Energy, partnering with the Turtle Mountain and Sault Ste. Marie bands of Chippewa Indians.
“It is incredible to see tribes investing in other tribes … and speaks to the energy sovereignty here,” she said.
Speaking at the summit, Kevin Carrizosa, a member of the Kumeyaay tribal council, similarly stressed the connection between energy independence and tribal sovereignty. The loan would provide “the necessary financial runway to launch not just our project but countless other tribal microgrids,” he said.
It also represents “truly tangible value that’s being provided by the U.S. federal government in support of Native America and our perseverance toward sovereignty,” said Allen Cadreau of Indian Energy. Sustainable energy projects like the microgrid “provide a means of maintaining our traditional way of life.”
The Tribal Energy Financing Program was first authorized in the Energy Policy Act of 1992 but was not funded by Congress until 2017, according to the loan announcement. DOE opened its first solicitations under the program in 2018 and has increased its outreach efforts to tribes, many of which have never applied for funding from federal programs, according to a department email. The Inflation Reduction Act increased the program’s loan authority from $2 billion to $20 billion.
A conditional commitment is the first step in LPO’s process for financing projects. According to the announcement, the Viejas microgrid will have to reach specific milestones and meet technical, legal and financial conditions before the loan is finalized.
SAN DIEGO — When the McMicken battery energy storage system (BESS) caught fire and exploded due to thermal runaway in April 2019, its operator, Arizona Public Service, opted for maximum transparency.
For Anthony Natale, director of risk and response at consulting firm Fire & Risk Alliance, APS’ response has been exactly what a utility should do after an experience like this.
“I can tell you, in working with APS, they’ve made a 180 — they do a tremendous amount for the fire service, a ton of testing, and really have come back and lead with safety,” Natale said at a March 14 meeting of NERC’s Reliability and Security Technical Committee.
But Natale’s goal was not to praise APS, but to observe how much still needs to be learned about fire safety at BESS facilities. Thermal runaway is better understood after the McMicken incident, but the industry has a long way to go to fully mitigate the risks associated with grid-connected batteries.
One challenge associated with a new grid resource — particularly batteries, which can act as load and generation at different times — is a lack of established performance assessment techniques. While many manufacturers use a common set of tests for their products, Natale suggested those tests don’t always predict a unit’s performance.
As an example, he showed a picture of a BESS facility that underwent the UL 9540A test, which is meant to determine if a single-unit battery fire will spread. In this case, the damage was isolated to a single unit, but things did not work out so well in practice.
The unit that underwent the test “did exactly what it’s supposed to do: failed, and did not [pass the fire on to] the adjacent units. However, in real life, in Warwick, New York, it ran through the entire array,” Natale said, referring to an incident at two BESS facilities using the same type of equipment where nearly an entire module was destroyed by flames.
“So these are the things we want to avoid. … It’s great to do the minimum level of testing, but let’s look at selecting a manufacturer that goes above and beyond,” he said.
Battery Aesthetics
Natale emphasized that he is not calling on manufacturers to stop using industry-standard tests like UL 9540A, which still play a valuable role in providing utilities a baseline performance measurement. Rather than throwing out existing tools, BESS makers can look at what they can do to forward the state-of-the-art, he said.
He recalled a test that Tesla conducted on one of its BESS products in which the company deliberately allowed a unit to fail and burn for eight hours in high-wind conditions. That technique could address the lack of accounting for wind in testing approaches, he said.
Natale also encouraged utilities pursuing battery projects to reach out proactively to communities they operate in. Fire departments are obvious targets for communication, as they will have to sign off on the safety of any proposed BESS facility.
But entities must also be prepared to make the case to locals who are concerned about safety of battery systems after seeing incidents like the McMicken and Warwick fires. Natale mentioned one community in which citizens “had shirts made up [and] showed up with pitchforks [and] torches” to oppose the local utility’s plans to install a BESS facility nearby.
“It’s not going to work; you’ve really got to give it your [all] or you’re wasting your time,” he said.
Utilities must show they understand citizens’ concerns and are willing to address them. In some cases, he said, communities have been satisfied with simple gestures like disguising a facility as something prettier, like a house.
“If you really have to cite [a BESS facility] somewhere, then take the time to talk to these people and say, ‘Maybe we can make this aesthetically pleasing, and it will work,’” Natale said.
The NYISO Business Issues Committee on March 13 approved proposed tariff changes to allow energy storage resources (ESRs) co-located with a dispatchable generator behind a single point of interjection to participate in the markets.
The revisions would expand the list of resources eligible to be included in the ISO’s co-located storage resource (CSR) models. The proposal is part of the wider ongoing hybrid storage resource (HSR) effort, which was approved by stakeholders in 2022 with the aim of incentivizing developers to couple generators with ESRs and integrating aggregated HSRs into NYISO’s markets. (See “Hybrid Storage Resources,” NYISO Management Committee Briefs: Dec. 21, 2022.)
Graphic representation of energy storage resource co-located intermittent power resource | NYISO
Each unit within the expanded CSR model will have a distinct single point identifier, bid, schedule, settlement and its own participation model. The ISO already has updated the CSR model to include additional use cases, such as limited run-of-river hydro and landfill gas, but these changes will require further modifications and an additional compliance filing to align with FERC Order 2023.
NYISO has been developing changes to its energy market products, including a hybrid pricing scheme for CSRs and a ramping product, to account for the capabilities of fossil fuel peakers slated for retirement in 2025. Recently, it announced plans to study how hydrogen could fit in its marketplace as an emissions-free generator co-located with a load resource and whether this could be facilitated through new or modified participation models. (See Hydrogen Getting Resource-specific Rules in NYISO Markets.)
NYISO will seek approval from the Management Committee of its proposals at the March 27 meeting and plans to file them in the second quarter of this year.
PSEG Power’s Howard Fromer sought clarification on the timeline, asking if the changes approved in 2022 already had been presented to the ISO’s Board of Directors.
Katherine Zoellmer, a market design specialist with NYISO, responded that the board has not yet reviewed the previously approved changes but will do so once the CSR proposal is approved.
February Market Operations
NYISO Senior Vice President Rana Mukerji presented the February market operations report to the committee, noting that the month’s average locational-based marginal price (LBMP) of $31.33/MWh was lower than January’s $65.76/MWh and the $55.47/MWh observed in February of the previous year. He attributed these declines to the higher temperatures experienced throughout this year’s milder winter conditions.
February’s average energy cost was 0.6% higher than the previous year, increasing from $52.36/MWh to $52.70/MWh.
Mukerji also noted the continued decline in natural gas prices. The natural gas index price at Transco Z6 NY was $1.71/MMBtu in February, down from $6.37/MMBtu in January, with year-over-year gas prices declining by 73.2%.
Vote on Net EAS Revenue Proposal Postponed After Stakeholder Protests
The BIC was slated to vote on NYISO’s proposals to use five-minute real-time LBMPs for estimating the net energy and ancillary services (EAS) revenue earnings of peaking plants as part of the capacity market demand curves reset determination, but it was postponed after stakeholders expressed multiple concerns.
NYISO’s proposal would allow the use of a five-minute real-time dispatch (RTD) in the net EAS model and expand the existing allowable adders for net ancillary services revenue not determined by the model to include potential net real-time energy revenues.
The ISO argued that the operating characteristics of certain technologies as they evolve may warrant the consideration of using five-minute real-time prices instead of hourly prices for estimating net EAS revenue. This adjustment would provide NYISO with the flexibility to modify how these technologies are treated in each reset.
The reset is a quadrennial process for reviewing and adjusting the demand curves in NYISO’s capacity market to ensure they accurately reflect current costs and market conditions in New York.
According to a stakeholder who agreed to speak with RTO Insider on the condition of anonymity, NYISO decided not to proceed with a vote on the proposal because of concerns it would be rejected, after it received many emails from stakeholders complaining about the rapid pace of the proposal process — two weeks from proposal to stakeholder approval — and a lack of analysis on the potential market impacts of the proposed tariff changes.
Stakeholders had requested an evaluation of the proposals’ impacts by NYISO’s Market Monitoring Unit (MMU) at previous meetings, but the ISO proceeded with the expectation a vote would occur at the morning’s BIC meeting.
At the Installed Capacity Working Group’s meeting later that afternoon, the MMU presented its preliminary assessment and methodology for examining the ISO’s proposal to use five-minute real-time prices in the net EAS revenue model for energy storage and assessing the potential to develop an alternative solution for considering the potential impact of five-minute real-time prices if the model continues to use only hourly prices.
Mark Younger, president of Hudson Energy Economics, captured the confusion and reluctance expressed by many stakeholders, saying, “The concern I have, at the moment, is that we don’t know enough about what you’re proposing to do, nor all of the [proposal’s] details, to go ahead and bless putting it into the tariff.”
Doreen Saia, an attorney with Greenberg Traurig, echoed that sentiment, saying, “I just don’t get it” and “to me, it seems inherently flawed.”
NYISO intends to maintain the schedule for the 2025/29 DCR and initiate the reset no later than this month. It will seek stakeholder approval of the proposed concepts at the BIC’s March 19 and MC’s March 27 meetings, but the MMU indicated its final analysis of the proposals would not be completed and presented until April.
Pennsylvania Gov. Josh Shapiro (D) on March 13 announced a new state energy plan he says will ramp up renewable production and save ratepayers $252 million while generating $5.1 billion in clean energy investments.
The Keystone State is home to the nation’s first oil well and civilian nuclear reactor, but Shapiro’s office said it’s now falling behind other states in diversifying energy sources.
Shapiro’s legislative plan aims to change that by establishing an emissions reduction program that will create a resilient electricity grid by 2035, attract more federal dollars, and support clean nuclear and low-carbon natural gas-fired generators.
“From the very beginning, I have made clear that any energy policy supported by my administration must meet the three-part test of protecting and creating energy jobs, taking real action to address climate change pollution and ensuring reliable, affordable power for consumers in the long term,” Shapiro said in a statement. “My energy plan is built to do all three, making sure the first dollar goes to Pennsylvania ratepayers and ensuring Pennsylvania will continue to be a leader on energy for decades to come.”
The governor is proposing the Pennsylvania Climate Emissions Reduction Act (PACER) to set up a cap-and-invest program that would take the commonwealth out of the Regional Greenhouse Gas Initiative and allow it to set its own cap on emissions.
Seventy percent of PACER’s benefits would be returned to end-use customers as rebates on their electric bill — a higher percentage than any cap-and-trade program in the country. PACER also would support projects that cut air pollution, further reduce customer energy bills and invest in new job-creating clean energy projects, including carbon capture and storage, geothermal, and clean hydrogen.
Shapiro also proposed a new renewable portfolio standard under legislation called the Pennsylvania Reliable Energy Sustainability Standard (PRESS), which builds on the state’s existing Alternative Energy Portfolio Standards (AEPS). It adds nuclear power and next-generation technologies like fusion and clean-burning forms of natural gas.
PRESS would require Pennsylvania to get 50% of its electricity from a diverse range of resources by 2035, including 35% from clean resources such as solar, wind, small modular reactors and fusion; 10% from sustainable sources like hydropower and battery storage; and 5% from “ultra-low emission” forms of natural gas and other traditional fuels.
PACER and PRESS are meant to work together to deliver the governor’s goals of protecting and creating energy jobs, cutting costs, and ensuring energy independence. Shapiro also wants legislators to create legal and regulatory frameworks around carbon capture and storage.
Democratic Support, Republican Opposition
Shapiro’s office released a supporting statement from leaders in the state’s Democrat-controlled House of Representatives.
“House Democrats are committed to reducing harmful greenhouse gas emissions while strengthening our economy and energy infrastructure, investing in our communities, and cutting costs for families,” their statement said. “Governor Shapiro has brought together many different sectors to explore how Pennsylvania can be a clean energy leader, and today’s announcement represents a step forward toward that goal.”
While Democratic leaders in the Republican-run Senate also voiced support for the legislation, the body’s majority leader, Sen. Joe Pittman (R), came out against a cap-and-trade program. The senator has opposed the state’s membership in RGGI, the subject of a state court case.
“It now appears the governor agrees with the Commonwealth Court’s ruling asserting a cap-and-trade program for electric generation is a tax on electricity and would require legislative approval,” Pittman said. “The governor correctly points out it is time we stop losing to Ohio, however, any cap-and-trade program applying solely to electric generation in Pennsylvania and not our competitors, does not fit the bill.”
He added that any energy policy changes in Pennsylvania must prioritize generation, grid reliability and consumer affordability.
Pennsylvania Public Utility Commission Chair Stephen DeFrank expressed support for the plan.
“The PUC stands ready to work with Gov. Shapiro’s administration and the General Assembly to implement a comprehensive energy policy,” DeFrank said in a statement. “We are at a very critical point in energy transition for our state, our nation and globally and it’s incumbent upon all parties to work together to develop new solutions. The commission has implemented provisions of the AEPS Act for two decades, and we understand it is time to take the next positive and important step for this commonwealth, while giving our consumers a voice in the process.”
