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.
Looking to protect the billions in private investment and thousands of new jobs spurred by tax credits in the Inflation Reduction Act, President Joe Biden on May 14 directed the U.S. trade representative to slap steep new tariffs on Chinese goods, including semiconductors, solar cells, battery components and electric vehicles.
Ranging from 25% on Chinese lithium-ion EV batteries and battery components to 100% on Chinese EVs, the tariffs could affect $18 billion in imports from the People’s Republic of China, according to a White House fact sheet.
“American workers and businesses can outcompete anyone — as long as they have fair competition. But for too long, China’s government has used unfair, nonmarket practices,” the fact sheet says.
Biden’s direction to U.S. Trade Representative Katherine Tai is authorized under Section 301 of the Trade Act of 1974, which allows the representative to investigate and act against foreign governments for “unjustified” or “discriminatory” actions that burden or restrict U.S. commerce.
Thus, a doubling of the tariff on Chinese solar cells, from 25% to 50%, is intended to “protect against China’s policy-driven overcapacity that depresses prices and inhibits the development of solar capacity outside of China,” the fact sheet says.
Global markets are glutted with cheap Chinese solar panels, which could increase available capacity to 1,100 GW this year — about three times expected demand — according to a recent report from the International Energy Agency.
In a separate announcement, Tai noted that the decisions to increase existing tariffs or impose new ones are the result of a mandated four-year review of the effectiveness of the tariffs already on the books. The report found that while current U.S. tariffs have prodded China to change some of its unfair trade practices, the country “has persisted, and in some cases become aggressive, including through cyberintrusions and cybertheft, in its attempts to acquire and absorb foreign technology, which further burden or restrict U.S. commerce.”
The report also found that the tariffs had helped spur production in the targeted industry sectors, while any related increases in consumer prices were mostly limited to goods subject to China’s own retaliatory tariffs.
The new increased tariffs target what the report calls China’s “big three” — solar, batteries and EVs — where Chinese exports have surged since 2022. They could go into effect approximately 90 days after publication in the Federal Register, which is expected next week, according to the U.S. trade representative.
Other tariffs on Chinese goods include an increase to 25% for lithium-ion batteries for stationary, non-EV storage and for natural graphite, a key battery component, neither of which will go into effect until 2026. Tariffs on a list of other critical minerals — such as cobalt, manganese, zinc and chromium — will jump to 25% this year, while those on semiconductors imported from China will double from 25% to 50%.
According to the report, the trade representative is also recommending 19 tariff exclusions for certain solar manufacturing equipment that is difficult to find outside China, which Solar Energy Industries Association CEO Abigail Ross Hopper quickly praised.
“A temporary tariff exclusion will help reduce production costs and incentivize increased investment in domestic manufacturing,” Hopper said. She also welcomed the delay on tariff increases for non-EV batteries, which she said “provides a runway for continued production and deployment of energy storage to meet growing demand for electricity.”
Spotty Record
The key questions now revolve around whether Biden’s decision could spark a renewed trade war with China, the extent to which the tariffs are calibrated to show the president as tough on China as the November election draws near, and the immediate impacts.
China responded quickly to the May 14 announcement, saying it “firmly opposes” the new tariffs, according to a statementfrom the country’s Commerce Ministry, reported by CNN.
“The increase in … tariffs by the United States contradicts President Joe Biden’s commitment to ‘not seek to suppress and contain China’s development’ and ‘not … seek to decouple and break links with China,’” the ministry said. “This action will seriously impact the atmosphere of bilateral cooperation.”
China would resolutely defend its rights and interests, and it urged the Biden administration to “correct its wrongdoing,” the ministry said.
As far as election-year impacts go, tariffs have had a decidedly spotty record as a spur to the domestic supply chain buildout needed to drive a clean energy transition in the U.S.
The Commerce Department’s International Trade Commission (ITC) imposed the first tariff on solar cells from China in 2012, followed by duties on solar cells from Taiwan in 2015. Under former President Donald Trump, the ITC imposed a 30% tariff on all imported solar cells, with the rate declining 5% per year for four years.
In 2022, the ITC imposed tariffs on solar cells and panels from several Southeast Asian countries — Cambodia, Malaysia, Thailand and Vietnam — where certain companies were found to be using Chinese components. Under heavy lobbying from the solar industry, Biden declared a two-year moratorium on those tariffs, which expires in June, and he has repeatedly said he will not extend the moratorium.
The bottom line is that solar tariffs have done little to provide the momentum needed for a major buildout of solar cell and panel manufacturing in the U.S. The ongoing tide of announcements was kick-started by the solar and advanced manufacturing tax credits in the Inflation Reduction Act.
At the same time, U.S. industry has been contending with supply chain and permitting issues and high interest rates, which could slow market growth. The residential solar market is expected to contract 13% year over year, according to industry analysts Wood Mackenzie.
On the upside, Elissa Pierce, a WoodMac research analyst, said she does not expect the increased tariffs to drive up prices of solar cells and panels in the U.S., due to the existing tariffs on Chinese imports.
“The U.S. imports very few of these products,” Pierce said in an email to NetZero Insider. “In 2023, just 0.03% of solar cell imports and 0.09% of solar module imports came from China, and this [minuscule] percentage continues to decrease even as Chinese module prices are bottoming out. In the first quarter of 2024, 0.02% of solar cells and 0.06% of solar modules were imported from China.”
‘Blunt Instrument’
The impact of Chinese imports on the EV market also could be negligible. While smaller, cheaper Chinese EVs are gaining ground in Europe, Trump-era tariffs — set at 25% — have kept them out of the U.S. market.
But unilateral action on tariffs, such as Biden is taking, is a “blunt instrument” that cannot solve all the challenges presented by China’s buildup of market dominance in EVs, batteries and solar, said Avery Ash, executive director of SAFE’s Coalition for Reimagined Mobility.
Focusing on the EV and battery tariffs, Ash said, “Addressing China’s unfair trade practices and market manipulation is [an] essential defense but must be coupled with effective offense — in this case, a clear national commitment to and strategy for the U.S. to double down on the development and deployment of market-defining technologies in the automotive sector. We’ve made early progress to this end in recent years, but much more is needed.”
Abigail Hunter, executive director of SAFE’s Center for Critical Minerals Strategy, also warned of the limited impact of unilateral tariffs on critical minerals. “Common border tariffs through a multilateral coordination with allies will be necessary to prevent dumping, and to block Chinese exports from causing global price collapses,” she said. “While challenging, such efforts are worth advancing in light of the devastating global impacts of China’s work to corner the market from minerals to EVs.”
SAFE, formerly Securing America’s Future Energy, is a nonprofit focused on advancing clean energy and EV technology and policy.
What the tariff announcement cannot conceal is that despite ongoing announcements of new factories and billions in private investment, the domestic supply chain buildout for solar, batteries and EVs is frustratingly slow. The solar industry continues to depend on imports from Southeast Asia, and U.S. automakers have slowed their rollout of EVs as the domestic content provisions of the IRA have narrowed the number of models eligible for the law’s $7,500 EV tax credits.
WoodMac’s Pierce added that “U.S. solar manufacturers are still relatively dependent on China for other module components, such as glass and wafers. While these products are also subject to the Section 301 tariffs, it doesn’t look like the tariff rate on these will be increased.”
And according to a report from Solar Power World, the Commerce Department is weighing yet another petition from a group of U.S. solar manufacturers to proceed with tariffs on companies in Southeast Asia, which the manufacturers allege have been circumventing rules on Chinese content in certain solar panel components. Commerce has yet to rule on whether it will take any action on the petition.
Three years after a deadly winter storm nearly imploded the ERCOT grid, killed hundreds of Texans and caused billions in financial damages after blackouts lasted for days, stakeholders in the Texas market have begun working on a reliability standard that may be stricter than industry norms.
ERCOT is proposing a “multi-metric” framework that establishes thresholds on three criteria: frequency, duration and magnitude of loss-of-load events.
Its baseline recommendations would set a loss-of-load expectation (LOLE) frequency of once every 10 years; 14 hours of rolling outages during an event; and no more than 19 GW of load shed to maintain the ability to roll the outages (54584).
The grid operator said using maximum magnitude as a probabilistic measure addresses a key physical reliability constraint: how many megawatts can be effectively managed at one time for rotating load shed purposes. It included maximum duration because one reliability policy constraint is the acceptable length to customers of an outage event.
Pete Warnken, ERCOT senior manager of resource adequacy, told the Texas Public Utility Commission during a May 2 technical workshop that after Winter Storm Uri in 2021, it became clear that the industry’s normal one-in-10 LOLE wasn’t enough on its own. He said staff reviewed other grid operators’ reliability standards and dug into background materials to come up with their proposal.
“One overarching theme became apparent: Simply relying on the 0.1 LOLE industry standard was not acceptable, and any reliability standard for ERCOT needed to expand beyond this single metric,” Warnken said. “There is an expectation for the commission to establish a reliability standard for ERCOT and take action to ensure the reliability and needs of the region are met both in the near and long term.”
The 2021 storm came 10 years after a less severe cold weather event in 2011. The rolling outages during the week leading up to Super Bowl XLV, played in the Dallas-Fort Worth area, were shorter and less severe than Uri’s.
“It makes me think that at a basic level, we are hitting that one-in-10 standard, but we’re still getting the massive outages that we want to try to avoid,” Commissioner Jimmy Glotfelty said. “So, semantics. Two massive outages in 20 years, that’s one in 10.”
The commission and stakeholders generally supported ERCOT’s approach.
“I think what ERCOT is proposing makes sense,” PUC Chair Thomas Gleeson said, expressing more interest in what market participants had to say.
“This is probably the most important policy decision this commission is going to make in terms of the impact to the state and reliability for our system,” NRG Energy’s Bill Barnes said, adding that his company “strongly supports” the resource adequacy-based reliability standard.
“We feel that this is the missing piece of our market structure. For the most important reliability type of our grid, resource adequacy, up to this point it’s been a shoulder shrug and, ‘Let’s just see what we get.’ That’s why this is such an important decision,” he added.
Katie Coleman, representing Texas Industrial Energy Consumers and its large industrial users, said the standard could be a “useful tool” as a reference point to decisions on whether to increase the offer cap, change the shape of the operating reserve demand curve or add ancillary services.
“There’s a lot of judgment involved in a reliability standard. It’s extremely imprecise,” Coleman said. “We continue to have concerns about using it as a single reference point to move billions of dollars around through a capacity construct. So that’s our sensitivity, but not the reliability standard in and of itself.”
‘Reasonable Starting Point’
PUC staff have since filed a memo responding to several points made during the technical conference. It lays out the decision points staff say it needs to prepare a proposal for the reliability standard’s rulemaking.
The commissioners will use the memo as the basis for discussions during their May 16 and 23 open meetings. A final rule could possibly be published by June 13, and a final PUC vote taken on the rule in August.
Commission staff said they view ERCOT’s approach to a reliability standard recommendation to be a “reasonable starting point” and that a commission-approved standard is “essential to achieving long-term resource adequacy.” They said setting the LOLE at close to one event every 10 years is a “reasonable benchmark” that alternative values can be compared to.
“At a minimum, the commission-approved reliability standard should target a level of reliability that is comparable to other markets and regions across the country,” they said in the memo.
Staff also noted that adopting a reliability standard does not require implementing the performance credit mechanism (PCM), saying it is not the only tool that could be used to meet the standard. They suggested “alterations” to existing ancillary service products, new reliability products or changes to the scarcity pricing signals as other policy options that could be “tailored” to affect reliability standard metrics.
While staff agreed with using the industry’s one-in-10 LOLE standard, they found setting a firm megawatt value for the 19-GW magnitude metric is not appropriate as it is directly tied to the system’s operational capability. They suggested a 0.25% exceedance probability for magnitude and updating the metric on a predictable, scheduled basis that aligns with future load-shed capabilities.
Staff also recommended the duration metric be reduced to 12 hours, with a “more relaxed” 1% exceedance probability. They noted ERCOT’s emergency pricing program will kick in after prices have been at the high systemwide offer cap for more than 12 consecutive hours.
According to ERCOT’s cost analysis, a 0.1 LOLE is not enough to constrain the maximum magnitude to 19 GW; instead, it would require a 0.04 LOLE. The incremental system cost to achieve this increased reliability is between $195 million and $271 million per year above the amount that supports a 0.1 LOLE, staff said.
ERCOT’s sensitivity variables include using weather years dating back to 1980 to ensure a “robust weather history” is accounted for. It also suggests a retirement assumption of 900 MW over the next several years and using combustion turbines for capacity, as the latter can be converted into any other combination of resource types.
American Electric Power’s Ohio utility is asking state regulators to create new tariffs forcing data center developers to pay for 90 to 95% of their projected electrical demand for their first decade of operation, even if they use less (24-0508-EL-ATA).
AEP Ohio filed the application with the Public Utilities Commission on May 13. Utility President Marc Reitter said in a news release that the company needs that level of commitment to make the investments required to supply the power-intensive facilities being planned in large numbers in its territory, particularly Central Ohio.
The proposals would apply to new data centers with a maximum monthly demand of at least 25 MW at a single location or mobile data centers, such as cryptocurrency mining operations, with a maximum monthly demand of at least 1 MW. Data centers that already have signed agreements with AEP at the time the proposed tariffs took effect would be subject to its existing general service tariffs, at least initially.
According to its filing, AEP’s peak demand in Central Ohio is approximately 4,000 MW, and it has signed binding electric service agreements for 5 GW of new data center load to come online by 2030. But more than 50 customers have submitted requests reserving over 30 GW of additional load.
“AEP Ohio’s current tariffs were not designed to address (and did [not] contemplate) either the current growth curve based on hyperscale data center development or the unique demands for serving this new class of data center customers,” it said.
There is also no RTO-controlled generation in Central Ohio, so AEP must import power over the 765-kV backbone system. Using existing transmission, the company will be able to import enough power to serve the new data centers with the 5 GW it has committed to, but serving additional data centers would require construction of new lines at great cost and time, it said: 120 miles of 765-kV line would take seven to 10 years and hundreds of millions of dollars to build.
In March 2023, AEP imposed a temporary moratorium on data center service requests in Central Ohio so it could analyze the likely impact of future data centers. It will keep the moratorium in place until its proposal is resolved.
The utility argued in its filing that state law requires it to serve all customers in its service territory, but not in a way that would be unreasonable or impose unjust risk for the company or its other customers.
Data centers would be billed for the greater of 90% of their contracted capacity or the highest previously established billing demand in the preceding 11 months. That would increase to 95% for mobile data centers.
The proposed tariffs would also:
require contracts for an initial term of at least 10 years;
include an exit fee for customers that leave early;
impose security and collateral provisions determined by AEP to protect against customer bankruptcy or other failure to meet financial commitments;
impose technical requirements such as a ban on intentionally or unintentionally cycling load in a way that unbalances system frequency; and
mandate participation in the PJM Emergency Demand Response Program and in any emergency event declared by AEP Ohio, with potential service disconnection if the customer does not respond.
In its request, AEP said it expects data centers to hold at least the top five spots on its list of largest customers by 2030.
“AEP Ohio has helped the state of Ohio attract thousands of new jobs and billions of dollars in investment because over the decades, AEP has built an extensive network of transmission lines to deliver the power these customers need,” Reitter said in the company’s statement. “This is one of the reasons data center developers targeted Central Ohio, and they continue to request large amounts of power. We need to ensure they can follow through with their commitments as significant new investments are made to serve them.”
