The PJM Board of Managers has re-elected Mark Takahashi to his fourth one-year term as its chair and named David Mills as chair-elect.
The chair-elect position signifies that Mills is slated to take over in 2025 if his election is reaffirmed by a second vote next year.
“Both Mark Takahashi and David Mills have the wealth of experience needed to help PJM manage the challenges of our evolving energy landscape,” CEO Manu Asthana said in a May 16 announcement. “I look forward to our ongoing work together toward maintaining a reliable grid amid our current energy transition.”
Takahashi joined the board in 2016 and has served as chair since 2021, having previously chaired the Competitive Markets Committee. Until 2018 he was CFO for the Ascendant Group, the parent company of Bermuda Electric Light Co. He also served as CFO of CLP Holdings, a vertically integrated utility in Hong Kong, between 2008 and 2014.
Mills was elected to the board in 2021 and serves as chair of the Competitive Markets Committee, in addition to being a member of the Risk & Audit and Human Resources committees, according to the announcement. He was re-elected to his second term on the board during the May 6 Members Committee meeting. (See “Stakeholders Re-elect 3 PJM Board Members Over Consumer Dissent,” PJM Members Committee Briefs: May 6, 2024.)
The announcement also included board committee assignments, with Terry Blackwell selected as chair of the Reliability & Security Committee and Vickie VanZandt named chair of the Human Resources Committee.
ALBANY, N.Y. — The promise of doing well for both the environment and the economy (and the obstacles to that goal) were highlighted as the 2024 edition of New York’s energy storage industry conference opened.
Manufacturers, developers, regulators and researchers — each looking for ways to overcome the challenges and be part of the solution — offered updates on their progress at Capture the Energy 2024.
William Acker, executive director of the New York Battery and Energy Storage Technology Consortium (NY-BEST), highlighted these parallel goals as he welcomed attendees to the conference on May 15.
“We will be focusing a lot of discussion in this conference around how we’re going to meet New York state’s climate and energy goals that are among the most aggressive in the country and really are an opportunity to redefine things and to really get a much better future for all of us,” he said.
In most decarbonization scenarios, storage is more than an opportunity; it is an imperative.
The transition from baseload fossil generation to intermittent zero-emission renewables is predicated on there being a way to store energy in periods of excess generation for use in periods of insufficient generation.
Building enough of that storage to accomplish that depends on technological, financial, regulatory and societal factors that are mostly still evolving.
The New York State Energy Research and Development Authority is working on multiple fronts to firm up some of those factors and streamline buildout of energy storage in the state.
State Efforts
In her keynote address, NYSERDA President Doreen Harris announced the latest step in this effort: the launch of the much awaited Block 5 of the retail energy storage incentive. The $58.5 million funding package is expected to incentivize construction of 135 to 150 MW of energy storage in New York City.
“Fundamentally, when we think about this funding, it’s intended to deploy what are the most mature projects across our state in the place that it is probably needed the most, to reduce peak flows, to mitigate the need for additional distribution grid upgrades and [to] displace some of the dirtiest fossil fuel peaker plants in the region,” Harris said.
New York’s official goal is 3 GW of storage installed by 2030, but Gov. Kathy Hochul has directed that it be doubled to 6 GW. A proposed road map that would formalize that target and lay out a path to reach it has been in an extended period of review by the Public Service Commission.
“I have to tell you, we are eagerly, like you, awaiting a decision on that road map,” Harris said. “But fundamentally, that is our next step that will allow us to partner with the industry to really scale up that next wave of projects and to deploy at a much greater scale toward the 6 GW goal.”
Beyond this, NYSERDA is helping fund research and development and supporting market reforms.
Word of the Day
Adam Cohen, chief technology officer and co-founder of NineDot Energy, focused his keynote on the need for market reforms to make storage work financially.
It now operates under a haphazard system that he described as “make it fit where it can, how it can.” The term for this is “kludge,” he said, and he proceeded to describe a situation just as clunky as that word sounds.
Utility rates for the past century have been based on the axiom that generation must be designed to meet maximum anticipated need because energy cannot be stored, he said. As a result, the characteristics and benefits of energy storage are fundamentally mismatched to existing tariffs.
“It should not be a kludge anymore when we have gigawatts of these things on the grid [and] terawatt-hours of energy going to be consumed and spit back out in bursts when it’s most needed,” Cohen said.
“You should charge the battery in an optimal way, and you should export the battery and apply grid services in an optimal way, and not have to build this duct-taped version of a tariff.”
NineDot and other retail developers in New York have collaborated to produce a series of bidirectional service classification principles they would like to see: The tariff should be market-based and transparent; be universal, so it provides certainty; optimize imports and exports; provide localized adders; be adaptable to the changing grid; share savings with low-income customers; and use rates that computers can read.
Headwinds, Tailwinds
Vanessa Witte, senior research analyst on Wood Mackenzie’s storage team, said the data and analytics provider has a bullish outlook on standalone storage, primarily because of the federal investment tax credit, but also all the wind and solar generation being planned: Their volatility creates a need for storage.
However, WoodMac also sees short-term hurdles in the renewable energy sector, such as permitting and interconnection delays, local opposition, interest rates and inflation.
“Really, we just need to accept the reality that total capex is high; interest rates are not expected to go down this year,” Witte said. “Despite some drops in supply cost and also lithium raw material costs, total capex does remain high.”
The data show multiple problems in New York, and as it stands now, she projects the state will not reach 6 GW of storage by 2030.
Fossil generation retirements are on track to far outstrip storage additions, Witte added: “Currently, what I’m showing right here is actually 2.8 GW of utility-scale [storage] by 2028. And then 4.5 GW of retirements.”
But the equation changes after 2030. Construction of wind and solar has fallen well behind schedule in New York — far enough perhaps that its 70%-by-2030 target is now out of reach — but extensive buildout still is expected. And storage must follow.
“Storage is very sensitive to state mandates, especially when paired with a financial incentive, other policies, other regulation [and] market signals; this is due to it being still very new,” Witte said. “So, New York also has a large amount of renewables coming online, not in the near future necessarily, more into the latter half of this decade, post of 2030. But it will create some clear market mechanisms by creating volatility on the grid.”
There’s one other factor at play in New York: It’s New York.
“New York is known to be one of the most difficult regions to build in. A number of developers actually don’t want to get involved in New York. There’s just too many permitting issues, the NIMBYism, the interconnection timeline, but also the interconnection costs,” Witte said. “The question is, what is the return for all of the difficulty and additional time to develop? Some areas do have higher volatility and better returns, but many areas don’t.”
She added: “Sometimes working with utilities has also proven to be really challenging. Some are not accepting the PPA cost. Others maybe want to move into ownership and don’t want to contract for PPA any more at all.”
Evolving Technology
Energy storage technology and applications are still evolving, especially the long-duration energy storage that will be critical if state policymakers do succeed in weaning New York off fossil fuels.
One after another, speakers discussed the need to advance not only the development of technology, but also high-quality execution of it.
Around the time of last year’s conference, New York City was reeling from a wave of hundreds of fires sparked by poorly made or incorrectly used lithium batteries for E-bikes and E-scooters. Soon after the 2023 conference, three unrelated fires hit New York grid-scale battery energy storage facilities in remote corners of the state, each one more serious and more widely publicized.
Harris said NYSERDA is part of the multiagency task force assembled to design safety standards and prevent further erosion of public trust in battery storage. Its work continues. (See NY Fire Code Updates Recommended for BESS Facilities.)
M. Stanley Whittingham, who was awarded the 2019 Nobel Prize in Chemistry for his work on lithium-ion batteries, raised the same issue.
“These fires we had last year … it’s sloppy manufacturing, cheap manufacturing — things go wrong,” he said. “Same as what we have in New York City with E-bikes. These are cheap batteries, all from a certain country.”
Whittingham, who is NY-BEST’s vice chair of research and a distinguished professor at Binghamton University, reminded the audience that all major commercial innovations in batteries came from the U.S. or U.K.
The U.S. can take the initiative back, he said.
“We don’t want to chase the Asians. That’s not going to work. We want to leapfrog them. So, we’re going to come up with more sustainable technology.”
The economics must get better too, Whittingham said.
“It takes 40 to 80 kWh to make a 1-kWh battery, so we have to change that.”
Brian Gemmell, COO of National Grid’s New York electric utility, said the state has only about 400 MW of utility-scale storage built toward its 6,000-MW goal at a critical time in the energy transition. He explained the need to sharply accelerate the buildout and why speed cannot be the overriding concern.
“We recognize that product development has slowed in the past year. The state has taken a crucial review of fire safety standards after the thermal runaways in 2023,” Gemmell said in his keynote address.
“So, we’re particularly focused on ensuring this standard is successfully implemented with the engagement of communities including fire first responders. I want to emphasize that safety and reliability must serve as the foundation of energy storage deployment going forward.”
Erik Spoerke, energy storage materials lead at Sandia National Laboratories, drew back to the longer view to give a better sense of where all these incremental setbacks and advances are leading.
He’s leaving Sandia after 20 years to take an advisory role in the U.S. Department of Energy’s Office of Electricity.
“I’m trying to help them understand how we can make grid-scale long-duration storage viable,” he said in his keynote speech.
He gets asked why he’s making such a large transition, taking a policy position after decades of hands-on work in the lab.
“Really, an important part of the motivation here is to recognize that in the next 10 years, we’re expecting there to be more change to the grid infrastructure than in the last century. That’s a pretty good jump. … And there’s been a few times in history we can think about where there’s been that kind of colossal technical endeavor.”
MISO on May 15 said it plans to move ahead after all with Entergy Louisiana’s original version of a $260 million reliability project proposed for the southeast part of the state.
The RTO announced about eight months ago it would delay recommending Entergy’s project to study alternatives. But this week it revealed it was unable to choose a suitable substitution, as the project’s higher-voltage alternative configurations were not cost effective.
The project initially was introduced for MISO’s 2023 Transmission Expansion Plan (MTEP 23) as the third phase of Entergy Louisiana’s three-part, nearly $2 billion Amite South reliability project to satisfy the utility’s local reliability criteria. The RTO ultimately advanced a substitution for the first phase of the project last year. (See MTEP 23 Catapults to $9.4B; MISO Replaces South Reliability Projects.)
This time, however, MISO said Entergy’s original proposal to construct a 40-mile, 230-kV line between its Adams Creek and Robert substations and upgrade the substations is more appropriate for the area than the 500-kV possibilities it analyzed. Entergy said in addition to the line solving potential overloads, the project would help it meet load growth in the Amite South load pocket and address upcoming generation retirements, which could be exacerbated by EPA’s new power plant emissions rules. Entergy also reasoned the line would provide an “additional hardened path” into Amite South, which can be useful during restorations following hurricanes or other extreme events.
MISO studied two alternatives to Entergy’s proposal, including a $1.1 billion option involving construction of two 500-kV substations and more than 50 miles of 500-kV line. However, the RTO said construction costs would be too high and the project itself would be impractical to build.
A second alternative — resulting in a new 500/230-kV station, an 11-mile 500-kV line to operate at 230 kV and a 26-mile 230-kV line — was found to cost about $100 million more than Entergy’s original proposal without solving any other reliability issues, MISO said.
MISO plans to recommend Entergy’s project proceed as a late addition to MTEP 23. It will run its recommendation past the Planning Advisory Committee before seeking approval from the Board of Directors’ System Planning Committee and, later this year, from the board itself.
ISO-NE has re-elected current Directors Caren Anders, Steve Corneli and Michael Curran, the RTO announced May 16.
The re-elected members have “significant expertise in clean energy, consumer advocacy, transmission, wholesale electricity and financial markets, and deployment of complex IT systems,” ISO-NE wrote in a press release.
ISO-NE relies on a slate voting system to elect its board, which consists of 10 members serving three-year terms. Some NEPOOL stakeholders previously have taken issue with the system, arguing participants should be able to vote on individual candidates.
The slate was nominated by a committee featuring current board members, NEPOOL sector chairs and Phil Bartlett, chair of the Maine Public Utilities Commission. The slate was approved by the NEPOOL Participants Committee in early May.
“We’re thrilled to have Caren, Steve and Michael remaining with us,” ISO-NE CEO Gordon van Welie said. “Their extensive and diverse experience and expertise remain critical as the region continues its transition to a clean, reliable energy future.”
Anders has a background in transmission and has worked for Quanta Technology, Duke Energy and Exelon. Corneli works as an independent clean energy adviser and previously worked on climate and market policy issues for NRG Energy. Curran is the retired chair of the Boston Stock Exchange and has expertise in investment and financial services.
The RTO’s most recent IRS Form 990 shows that Anders, Corneli and Curran made between $138,000 and $164,000 for seven to nine hours of work per week in 2022.
Board members must not be affiliated with any company that participates in the region’s wholesale electricity markets.
AMES, Iowa — There’s no going back on waning capacity in MISO, panelists agreed this week at a gathering of state regulators, though predictions of escalating load growth have some skeptical.
New OMS Executive Director Tricia DeBleeckere opened the Organization of MISO States’ third annual Resource Adequacy Summit May 14-15 at Iowa State University, predicting that MISO will be managing a shallower supply for years to come.
“We’re going to have to live in this new world order of tight margins,” DeBleeckere said.
MISO President Clair Moeller agreed some capacity insufficiency within MISO is here to stay. He said it was unsurprising to MISO that one of the resource adequacy zones returned a shortage for the upcoming planning year. He said most zones were “right on the edge” of adequacy.
MISO’s capacity auction April 25 returned insufficient capacity for the upcoming fall and spring 2025 in Missouri’s Zone 5, where capacity prices hit a $719.81/MW-day limit, on par with building new generation. Otherwise, all local resource zones cleared at $30/MW-day in the summer, $15/MW-day in the fall, $0.75/MW-day in the winter and $34.10/MW-day in the spring. Zone 5 contains local balancing authorities Ameren Missouri and the city of Columbia, Mo.’s Water and Light Department. (See Missouri Zone Comes up Short in MISO’s 2nd Seasonal Capacity Auction, Prices Surpass $700/MW-day.)
Moeller defended his standing as a “storm crow” on resource adequacy.
“The reason it’s not bad is because I’ve been telling you all to worry about it,” he joked with regulators.
Former OMS Executive Director and Wisconsin Public Service Commissioner Marcus Hawkins said despite thinning reserves, MISO members are fortunate to operate under an established resource adequacy construct. Hawkins said parts of the country just now are trying to launch the “basic resource adequacy construct that’s been operating in MISO land since 2011.”
DeBleeckere said MISO’s recent and proposed modifications are “unheard of and groundbreaking” and probably the largest transformation of its resource adequacy construct ever.
Hawkins said that there’s a lot of buzz around booming load growth now, but he qualified that MISO at one time predicted as much as 12 GW of new demand that hasn’t materialized. He also said the footprint has lived through the “Groundhog Day” of MISO predicting major capacity shortfalls “three to five years from now for every year since 2015.”
Hawkins said despite dire estimates, MISO, utilities and states survived without catastrophe. He said there’s value in taking stock of predictions that didn’t pan out.
“We have to have these more nuanced conversations and be realistic about what has transpired after those predictions,” he said, prescribing “new, hard conversations on what is an appropriate level of risk to plan for.”
Hawkins said MISO’s and states’ plans will be reliant on one another’s information more than ever.
“Resource adequacy on paper is much different than serving load in operations. You can’t just feel good that you’ve hit your resource adequacy targets on paper,” Hawkins said.
Despite Hawkins’ plea for moderating expectations around load growth and capacity deficits, he was followed by a panel titled, “Load Growth Galore.”
Grid Strategies’ Rob Gramlich predicted the end of the country’s 25 years of flat load growth. He said Grid Strategies’ recent report shows Indiana and Michigan are especially ripe for new industrial load in MISO.
“Like many, we’ve gotten interested in load growth in the last six to nine months. It seems to be the biggest thing changing everything we thought we needed to do,” Gramlich said.
Gramlich said the nation is at an “inflection point” of new applications for data center servers occurring alongside the Biden administration’s push for stronger domestic manufacturing and the open question of hydrogen’s potential importance.
Gramlich said expanding load is evidenced in MISO by utilities’ requests for expedited project reviews, which have more than quadrupled since 2020. MISO’s expedited transmission project reviews are a bellwether of load growth, as they’re most often used to accommodate new load connections.
Gramlich said MISO is “already doing pretty well on forward-looking” transmission planning to connect new generation to serve load growth. He said the RTO likely is ahead of the curve on FERC’s newly issued Order 1920 concerning transmission planning. (See FERC Issues Transmission Rule Without ROFR Changes, Christie’s Vote.) However, he suggested MISO dedicate an internal group, or tap an independent entity or the Organization of MISO States, to contribute to load forecasting.
“We really as an industry have lost our muscle memory on load forecasting,” Gramlich said.
Google’s Betsy Beck said MISO should turn to “nontraditional data sources” and initiate discussions with large industrial customers in addition to compiling forecasts from their load-serving entities to more comprehensively view future demand.
Great River Energy Director of Resource Planning Zac Ruzycki urged utilities to have “open and honest discussions” with companies about the size, location and longevity of their new loads.
He said utilities and MISO may have to get comfortable with forecasting being “a lot more work” and more probabilistic going forward, given the confluence of sweeping changes.
Minnesota Public Utilities Commissioner Joe Sullivan said when he thinks about a hypothetical, 1-GW data center coming online in Minnesota, he can’t help but think that the new, daily load would be larger than the electricity ultimately produced from the state’s largest mining operation or refinery.
Ruzycki said it’s more likely than not that Great River Energy will be serving substantially more load within a decade.
“We feel fairly confident that’s going to be the case,” he said, adding that utilities are going to have to “do more with less” to serve larger loads with fewer baseload resources. Ruzycki said that’s why Great River is partnering with Form Energy to pilot a 1.5-MW long-duration iron-air battery capable of 100 hours of continuous dispatch.
Ruzycki said Great River Energy is building the battery — due online at its Cambridge peaking plant sometime next year — not to make money, but to see how the technology behaves.
Ruzycki said MISO’s mostly solar and wind interconnection queue means there are days ahead with curtailments due to “extreme production and low demand.” He said a long-duration battery can soak up excess generation from renewable generation over multiple days.
“Including new technology is challenging but necessary,” Ruzycki said.
MISO President Advocates for Restraint in Load Forecasting, Unit Retirements
But MISO President Clair Moeller cautioned that load growth might not ascend to the heights some are expecting.
“I’ve noticed when people are selling you something, they can be hyperbolic. So, how much of this is hyperbole and how much of it really is load growth?” he asked rhetorically. He also told attendees not to confuse “the interested public with the public interest.”
Lumpy load growth matters depending on location, Moeller said. He joked that he doesn’t care if a new data center eyes Ohio as its home base, but that same data center sited in Indiana might give him anxiety.
Moeller said utilities are in the unenviable position of balancing customers representing new load, customer affordability, shareholder interests and governor’s offices desiring economic development before another state can snap it up.
He said utilities, regulators and RTO planners should engage with economic development organizations and lawmakers “so everybody’s goals get on the table at the same time.” He said “a lack of coordination is risky” for the grid.
Moeller said the supply chain is the “governor” on how fast new load can be served and said the COVID-19 pandemic showed the “brittleness” of the supply chain.
“It’s two years to a data center and four years to a transformer,” Moeller said. “We’ve got to think this through in order to get a safe transition.”
Moeller said past transitions in the energy industry since 1900 have been “layered,” where new technologies were spread on top of operating older technologies.
“We didn’t turn anything off until we were well and done with it. Now, this transition is: ‘Turn stuff off and then turn stuff on,’” Moeller said.
He said MISO isn’t opposed to inverter-based resources but wants to make sure the technologies to support them for 24/7 output are tested. MISO sometimes is criticized as “pro-gas” by environmental groups, Moeller said, but added that he sees MISO as “pro-reliability.”
“Reducing the carbon footprint doesn’t have to mean turning off all the carbon-producing resources. It could mean make sure you use it only when you need it,” he said.
Moeller said in the past two years, the electrification of the economy is accelerating, data center load is swelling and manufacturing is reshoring.
“Now, what we’ve got to say, ‘Is that a wave or is that a trend?’”
Moeller also said robust transmission connections keep the lights on during 100-year events that are beginning to occur every other year. He said it’s unlikely any one grid operator can hold enough available generation to weather all storms.
However, Moeller implied there’s a transactional nature to imports and exports aided by transmission. He said that while MISO has supported TVA with exports — at one point during December 2022’s winter storm it was forced to stop to protect its own system — TVA never has returned the favor. Now, MISO isn’t inclined to lend a hand to TVA in future weather events because of that flow’s one-sidedness, Moeller said.
Moeller said MISO is meticulously drafting its second, $17 billion to $23 billion long-range transmission portfolio.
“The worst thing you can do is plan $20 billion in transmission and miss all the locations where the data centers want to be,” he said.
NERC’s Standards Committee spent much of its monthly meeting May 15 pushing through three draft standard authorization requests (SAR) implementing FERC’s 2023 order on inverter-based resources (IBRs), with ERO staff emphasizing the organization is prioritizing the measures.
The IBR projects arise from the commission’s Order 901, issued last October, which required NERC to develop standards to improve the reliability of IBRs, including solar, wind, fuel cell and battery storage facilities. (See FERC Orders Reliability Rules for Inverter-Based Resources.) FERC directed NERC to submit the standards in three tranches, each addressing a key milestone of the order over the next three years beginning in 2024.
The first milestone is the submission of a work plan describing NERC’s approach to developing the standards, which the ERO submitted this January. Three of the standards projects approved May 15 apply to the second milestone, which concerns data sharing and model validation for all IBRs, whether or not they are registered with NERC. This milestone must be met by November 2025, NERC Manager of Standards Development Jamie Calderon said at the meeting.
Each of the three draft SARs will be assigned to an existing standards development team (SDT) working on related topics. Part 1, which deals with modeling and data-sharing requirements, will be assigned to Project 2022-02 (Modifications to TPL-001 and MOD-032).
Part 2, covering model validation and verification, will go to Project 2020-06 (Verifications of models and data for generators), and Part 3 will go to Project 2021-01 (Modifications to MOD-025 and PRC-019) to ensure the SDT for this project will not duplicate or conflict with the other teams’ efforts.
Calderon told committee members that, due to the pressing time requirements for this tranche of standards, NERC staff felt it best to split the task among existing SDTs already doing relevant work. But this division raised questions about the workload these teams will be asked to assume; for example, Amy Casuscelli of Xcel Energy asked whether the SDTs will be expected to “table the work on their previous assigned SAR and focus on this one.”
In response, Calderon affirmed that “the [FERC] directives are going to take precedence” over existing assignments and said NERC staff had made leaders of each team aware of the plan so they could prioritize the work properly.
Following a question from SPP‘s Charles Yeung, Latrice Harkness, director of standards development, confirmed SDTs would be allowed to continue their previous work alongside the Order 901 efforts if it did not prevent them from satisfying FERC’s directive by the deadline.
The committee approved the adoption of all three draft SARs and their assignment to the relevant SDTs, along with the solicitation of additional team members for the first two parts, which Calderon explained was necessary because some members said they could not commit to the additional time that might be required for the new directives.
Members did obtain one change to the proposal: The draft SARs will be posted for formal comment periods rather than informal comments. The update means SDT members will be required to address industry stakeholders’ comments on the drafts.
Committee members also agreed to accept a SAR revising the definitions of “generator owner” and “generator operator” in the ERO’s glossary of terms, to bring the definitions in line with proposed changes to NERC’s Rules of Procedure governing IBR registration. (See “Stakeholders Discuss ROP Changes,” NERC Board of Trustees/MRC Briefs: Feb. 14-15, 2024.) This proposal also was changed to require a formal rather than informal comment period.
Finally, the committee authorized posting of proposed standard CIP-014-4 (Physical security) (Page 47 of the agenda) for a formal ballot and comment period. The standard is the product of Project 2023-06 and is intended to improve physical security requirements for grid facilities. The comment period will last 45 days, with ballot pools formed in the first 30 days and voting conducted during the last 10 days of the period.
NERC’s 2024 Summer Reliability Assessment, released May 15, found that every region has met its reserve margin targets but that many areas would face difficult operations in lengthy, widespread heat waves.
Wide-area heat events that affect generation, wind output or transmission systems coupled with demand growth in some areas are contributing to risks in some regions. The report lists CAISO, ERCOT, ISO-NE, MISO and the Southwest as facing elevated risks this summer.
Weather forecasts call for above-average temperatures in most of the country, with the greatest chances for hot weather in the Northeast, Texas and much of the Intermountain West.
“What we’re really seeing is a transformation of our system, but also the types of risks,” said John Moura, NERC director of reliability assessments and performance analysis. “And as we address one risk, other risks pop up. As we bring on more wind and solar, certain risks need to be mitigated and addressed. As we also retire resources, we need to think about some of the essential reliability services that we’ve traditionally received from resources.”
The changing grid has regions relying on their neighbors more than ever, as transferring power between regions can deal with some of those new risks that come with the changing generation fleet.
“We have now what we call wind droughts that are persistent and widespread, and these affect areas, and so we’re seeing a greater need to not only economically trade with our neighbors, but really be reliant, and then have confidence in advance that those transactions are going to be there and they’re going to be reliable,” Moura said.
All of the areas assessed have adequate supply for normal peak load in part because of major capacity additions since last summer. The industry has added 25 GW of solar capacity in the past year, which comes on top of 19 GW added the prior year, said Mark Olson, NERC manager of reliability assessments.
“Really significant amounts of” battery storage have been added “in ERCOT and in the California-Mexico assessment area,” Olson said. “These areas have a lot of solar resources, and so the batteries are particularly important resources capable of helping manage the variation … as the solar ramps down in the late afternoon and early evening but demand is still high.”
Growing demand is being felt most acutely in Texas and SPP this summer, Olson said.
MISO has seen some resource additions since last year, but those were offset by continued retirements and a cut in expected imports.
“Like last year, wind generator performance is really the key factor in MISO in its ability to meet reserves during high-demand periods,” Olson said.
ISO-NE no longer can rely on the natural gas power plant at the Mystic site outside of Boston, which makes its reserve margins lower than last year.
ERCOT continues to see large load growth, along with massive growth in solar energy capacity, though it still will face issues when the sun goes down and demand remains high. The key to reliable operations there will be running storage properly so it can be fully charged when needed most, Moura said.
“California, under an extreme condition, would be highly reliant on its neighbors,” Moura said. “That’s really how the Western Interconnection works. We’ve shown improvements since last year, probably primarily because of the improving drought conditions. And so, this year, it has a better chance of relying on its neighbors because there’s a little more availability of hydro.”
Most of the biggest issues with reliability in the past decade have come during the winter, but Moura and Olson said the summer still presents significant issues for grid operators. Demand can be very high in some regions because of the heat.
“In California, that demand can be really variable in the summer,” Olson said. “They have a lot of rooftop solar; it just has a peakiness about it. That makes for demand challenges.”
Winter has more supply issues, as the industry is competing for natural gas at its peak demand and extreme cold can lead to weatherization issues, he added.
Moura noted the addition of solar has helped significantly in recent summers.
“We’ve almost had a perfectly correlated resource that we’re building extremely fast. That’s correlated with peak demand for now, which is solar,” Moura said. “And so, this recent solar summer assessment shows for the peak hours that we traditionally have seen … we’ve got a great resource that can provide that for that particular peak. But almost every other hour throughout the year has challenges.”
FERC on May 14 granted Nevada Power an exemption simplifying the NV Energy subsidiary’s filing of its triennial updated market power analysis (ER24-1518).
In a March 15 filing, Nevada Power asked FERC to change its designation from a Category 2 to a Category 1 seller in the Southwest Region.
A Category 2 seller must regularly file updated market power analyses, while sellers in Category 1 are exempt from that requirement. For a Category 1 designation, a seller must own or control no more than 500 MW of generation in the region, and it also faces limits on owning or operating transmission facilities.
Nevada Power noted in its filing that even with a Category 1 designation for the Southwest region, it would still have a Category 2 designation in the Northwest region, and therefore would continue to file triennial market power analyses.
With Category 2 designations in both regions, Nevada Power would be required to file duplicate triennial updates six months apart, the company said.
“To be clear, unlike other entities that have filed to be relieved of or exempted from Category 2 status, Nevada Power is and will remain a Category 2 seller in the Northwest Region — its home reporting region — and will continue to submit full triennial analyses addressing the whole of Nevada Power’s horizontal and vertical holdings, including those holdings in the Southwest region,” the company said in its filing.
FERC denied Nevada Power’s request for Category 1 status in the Southwest region, saying the company was disqualified by its ownership of transmission facilities in that region.
According to Nevada Power’s filing, the company partially owns the El Dorado substation in the Southwest region and within the CAISO market, as well as the Navajo-Crystal-McCullough line and associated substations in the Los Angeles Department of Water and Power (LADWP) balancing authority area.
But FERC agreed to grant Nevada Power an exemption from the filing requirements for a Category 2 seller. FERC Order 697 allows the commission to evaluate exemption requests on a case-by-case basis.
“In our attempt to keep the Category 1 criteria as simple and straightforward as possible, we may have swept under Category 2 particular sellers whose circumstances make it unlikely that they could ever exercise market power,” FERC acknowledged in Order No. 697.
FERC ordered Nevada Power to submit a compliance filing within 30 days with a revision to its market-based rate tariff reflecting the exemption.
No interventions or protests were filed in the case.
Nevada Power filed an updated tariff in 2014 designating itself as a Category 2 seller in the Northwest and Southwest regions, and a Category 1 seller in the remaining four regions: Central, Northeast, Southeast and SPP.
At the time, the company owned or controlled more than 500 MW of generation in the Southwest region, but that’s no longer the case, the company said in its March 15 filing.
Before 2014, the relevant regions for the Nevada Power balancing authority area and for the BAA of its sister company, Sierra Pacific Power, were the Southwest and Northwest regions, respectively.
But the two BAAs were consolidated in 2014, when the One Nevada transmission line came online. Nevada Power’s home reporting area became the Northwest region under the consolidation.
National Grid introduced a pair of asset condition projects estimated to cost about $538 million at the ISO-NE Planning Advisory Committee on May 15.
The bulk of the cost, $491 million, would come from the refurbishment of a 115-kV line along the Vermont-New Hampshire border. The project would consist of replacing wood structures with steel poles, installing optical ground wire and moving part of the line toward center of the right of way to reduce tree damage.
The line was refurbished in 2008 but has since deteriorated because of damage from woodpeckers and exposure to the elements, said Rafael Panos of National Grid.
Some stakeholders expressed concern about the high cost of the project and the short lifespan of the previous refurbishment.
Abigail Krich, president of Boreas Renewables, asked whether National Grid has considered whether the line overlaps with needs identified in ISO-NE’s 2050 Transmission Study. The study identified the North-South interface along the southern borders of Vermont and New Hampshire as a high-likelihood area for overloads in coming decades.
“The region is planning to have conversations very soon about right-sizing projects like this one,” Krich said. “This is a really big project, and I’d hate to miss that opportunity.”
Panos agreed regarding the importance of avoiding a “subsequent rebuild” and said he would consult with the National Grid team about a potential overlap with the needs identified in the 2050 study.
Asset Condition Process Guide
Dave Burnham of Eversource Energy gave an overview of the draft asset condition process guide that was developed jointly by the New England transmission owners (NETOs).
The guide outlines how the NETOs monitor their assets, identify asset condition needs and select solutions. The document comes in response to requests from the New England states for more transparency and oversight on the asset condition process. (See States Press New England TOs on Asset Condition Projects.)
Burnham requested stakeholder feedback on the draft by May 29.
FERC Order 881
Brent Oberlin, executive director of transmission planning at ISO-NE, presented on how FERC Order 881 compliance will affect transmission planning. The order requires transmission providers to use ambient-adjusted line ratings to evaluate short-term transmission service and seasonal ratings for long-term service.
Oberlin noted the order does not require any changes to the ratings used in transmission planning but said ISO-NE intends to update its winter ambient temperature assumptions.
While ISO-NE’s winter planning assumes an ambient temperature of 50 degrees Fahrenheit, winter peak loads typically occur as the temperature drops, a trend that will increase with heating electrification, Oberlin said. To account for this, ISO-NE plans to assume 20 F for transmission planning.
Oberlin emphasized that ISO-NE has a lot of work to do to be ready for the July 2025 implementation date.
“We’re going to be coming in on two wheels to actually get this done,” he said.
ISO-NE on May 14 outlined for the NEPOOL Reliability Committee its work on a potential metric quantifying energy shortfall risk in the Northeast based on extreme weather to complement the traditional one-day-in-10-years loss-of-load expectation.
The so-called Regional Energy Shortfall Threshold (REST) is intended to be a “reliability-based threshold that reflects the region’s level of risk tolerance with respect to energy shortfalls during extreme weather,” according to the RTO. (See ISO-NE Details Proposal for Regional Energy Shortfall Threshold.)
As climate change causes extreme weather events to become more frequent, there has been growing concern that the widely used one-in-10 standard — requiring grid operators to procure sufficient resources so that its likely load is shed only one day in 10 years — is not enough to maintain reliability. (See related story, ERCOT Proposes ‘Multi-metric’ Approach for Reliability Standard.)
Once the REST is hit, ISO-NE would require certain measures based on possible 21-day extreme weather events. But the RTO still is working on the threshold’s exact value, what weather events would be used in the evaluation to set it and how often evaluations would be conducted.
ISO-NE told the committee that stakeholders prefer a metric based on expected unserved energy, defined as the expected amount of energy not supplied by the generating system during a certain period. It would consider the probability, magnitude and duration of an energy shortfall; percent of unserved load; customer impacts; and seasonal differences.
Jinye Zhao of ISO-NE said the RTO is considering a “maximum normalized seven-day energy shortfall,” which “would represent the system’s energy shortfall as a percentage of the system’s demand over rolling seven-day periods within the 21-day events.”
This metric would capture both the severity and duration of shortfall risks and would minimize the need for frequent major updates as demand and resource profiles change, Zhao said.
ISO-NE said it still is evaluating how it would establish the threshold for whichever metrics it selects and noted that it is “in the process of studying a number of additional 2027 winter events in order to help quantify a meaningful threshold.”
The RTO would rank all 4,680 possible 21-day weather events based on average system risk and select a top percentage of them to weigh against the threshold. It then would use the Probabilistic Energy Adequacy Tool (PEAT), developed with the Electric Power Research Institute, to quantify the selected set’s risks. (See ISO-NE Study Highlights the Importance of OSW, Nuclear, Stored Fuel.)
Regarding the assessments’ timing, the RTO said stakeholders have shown “a notable preference for seasonal assessments ahead of the winter and summer seasons,” as well as for annual PEAT assessments that look three to five years ahead.
“[ISO-NE’s] current thinking is that a seasonal assessment of operational peak periods for the energy shortfall risk against the REST criteria is most appropriate,” said Stephen George of ISO-NE. The RTO likely would perform these assessments two to four months in advance of a given season, he said.
“This timing would facilitate the use of the most up-to-date resource mix, demand profiles and fuel inventory assumptions,” while giving enough time to implement solutions to address shortfall risks, George said.
The RTO also is considering longer-term annual shortfall assessments to identify trends and upcoming risks, George added.
Once ISO-NE establishes the REST, it plans to embark on “a subsequent effort” to evaluate possible solutions to risks identified in the process, George said. Potential solutions include “market enhancements” and “responsiveness by end-use consumers.”
ISO-NE plans to provide more information on the REST at the July RC meeting and present a proposal in August, with the hope of presenting a final proposal by the end of the year.
