President Joe Biden has more than doubled the Section 201 tariff rate quota for imported solar cells, from 5 GW to 12.5 GW per year.
As he imposed new regulations May 16 to protect U.S. solar manufacturers from unfair trade practices, Biden said he might raise the quota if necessary to maintain a supply of cells for U.S. solar module manufacturers as they scale up production through the supply chain.
His administration apparently did conclude this move was necessary: The higher quota was announced Aug. 12, to the praise of an industry group.
The decision affects imports of certain crystalline silicon photovoltaic cells, whether or not they are partly or fully assembled into other products.
The proclamation issued Aug. 12 indicates that a majority of representatives of the U.S. solar industry had requested the change. It reads:
“I have determined that the domestic industry has been making and is continuing to make a positive adjustment to import competition, shown by increased actual and planned module production; various announcements of planned domestic cell production; and improvements in several of the domestic industry’s financial, trade and employment indicators.”
The Solar Energy Industries Association welcomed the move. In a statement, CEO Abigail Ross Hopper said, “SEIA strongly commends President Biden’s decisive action to support American solar module manufacturers by raising the Section 201 tariff rate quota on cells. This move provides an important bridge for module producers to access the supply they need while the United States continues to progress on solar cell manufacturing. This decision will help create a strong, stable module manufacturing sector that can sustain robust cell production in the long run.
“Federal clean energy policies are fueling a surge in domestic manufacturing investments across the country, which are helping us secure our supply chain and uplift American communities. The president’s recent actions are critical for maximizing the impact of these policies and ensuring the long-term success of American solar manufacturing.”
Extensive manufacturing investments have been announced in the United States during his administration, but extensive plans to build solar generation also have been announced, with domestic demand outstripping domestic supply.
Representatives of the U.S. industry in September 2023 said the demand for imports would continue in the near term and petitioned for the tariff rate quota to be raised to 20 GW per year or eliminated altogether.
Eleven months later, they got 12.5 GW.
The new tariff rate quota pertains to products that entered the U.S. after July 31.
Home energy management company Renew Home released a position paper last week arguing that the virtual power plants it creates with aggregations of residential customers can quickly be stood up to help meet growing demand.
As the generation mix shifts ever more toward intermittent renewable resources, the grid needs to be balanced at specific times, which VPPs can help with, Renew Home Executive Vice President Cisco DeVries said in an interview.
“We need to find hundreds of gigawatts of additional capacity in order to meet the challenges faced by the growth in demand for electricity and the management of more intermittent renewables,” DeVries said.
VPPs are going to be key to meeting that demand because they can be stood up around the country much more cost effectively and quickly than other options, including building new natural gas plants, he argued.
“A lot of entities are taking an all-of-the-above approach: looking at natural gas, looking at batteries and looking at VPPs,” DeVries said. “And fundamentally, from an economic perspective, it’s really hard to get there with gas alone, right? Even if you set aside the climate and greenhouse gas impacts, which are significant, you still have an issue of building hundreds of gigawatts of new generation capacity, much of which is only needed for small portions of time in the year.”
Renew Home is a member of Sidewalk Infrastructure Partners, which was formed as an independent entity out of Alphabet, Google’s parent company. The company was created earlier this year by the merger of Google’s Nest Renew service and OhmConnect, and is the largest residential VPP provider in the country, with almost 3 GW under control and plans to expand up to 50 GW by 2030.
Core to that expansion will be growing the number of smart thermostats to cover more of the 82 million homes that have central HVAC systems. Pairing every single HVAC system with a smart thermostat and linking them to a VPP could create 70 GW of load-shifting potential, the company argues in the paper.
Smart thermostats are the quickest way to set up residential VPPs, it says, but electric vehicles and distributed batteries are also part of the plants. The paper forecasts 8 GW worth of EVs and 21 GW of batteries charging by 2030.
VPPs come out of traditional demand response and can still provide that emergency service to the grid when needed, DeVries said, but they are meant to operate more often with less of an impact on the individual customers in an aggregation. They are “designed to run 3 to 5% of the time [and to] have predictable, reliable dispatch in a way that can be just as good as, if not better than, fossil fuel plants.”
They can also do the same work as peaker plants, but even more cheaply without factoring any of the environmental externalities of their competitors, he said.
While most customers are not interested in being a resource that has to respond to changing grid conditions, spreading VPPs out among many customers with smart thermostats can get around and aggregate capacity without too much aggravation.
“We have millions of customers using Nest thermostats who have already given permission to flex their load,” DeVries said. “To say, ‘go ahead, make some modest adjustments in the temperature; pre-cool a little here; let it drift a little there; whatever you want to do. I’m comfortable with it.’”
Renew Home manages their thermostats every day to help customers manage time-of-use rates, save money on their bills and even to use power when the carbon intensity of the grid is lower.
“We have got not only an enormous stranded asset now, as far as gigawatts of existing load that is ready to be controlled today, but there is a near-term pathway to get that into the 50 to 70 GW over the coming few years, and that could transform the reliability of the U.S. grid and also help people actually reduce their energy bills pretty dramatically,” DeVries said.
Electric water heaters could provide another 16 GW in load shifting if connected to smart controllers.
“There are millions and millions of hot water heaters that are put into people’s homes every year, and with a small additional effort, those are all controllable and can be navigated in the same way we do thermostats,” DeVries said. “Customers won’t even notice it’s happening, but their hot water heater will participate, essentially as a thermal battery shifting load around. The capabilities of that are dramatic.”
FERC on Aug. 12 established settlement judge procedures in response to a waiver request from a generator seeking to exit ISO-NE’s inventoried energy program (IEP) and refund the net revenues received from the program (ER24-1407).
The IEP compensates generators for maintaining fuel inventories in the winter and applies to the winters of 2023/24 and 2024/25.
In March, Canal Marketing asked FERC to allow the company to withdraw from the program for the 2023/24 winter period and return the net revenues, plus interest, that it received from its participation in the program.
The company operates a 333-MW gas and oil generator that has been out of service because of a mechanical issue since early 2023. Canal said it initially anticipated the generator would return to service in time for most of the 2023/24 winter, but delays extended the outage through the entire winter.
Canal alerted ISO-NE of the delay in December 2023 and determined the RTO’s tariff does not include provisions that enable “the return of net revenues by a market participant in this particular situation or for a participant to withdraw from the program once its election submission has been accepted by ISO-NE.”
In its request to FERC, Canal said granting the waiver “would not harm any third parties” and that the returned revenues would be “allocated to the market participants that are responsible for the costs of the program.”
Following the request, ISO-NE offered its support for the proposal to return the net revenues. The RTO’s Internal Market Monitor also supported the return of revenues in comments to FERC, while emphasizing the importance of sticking to a “narrow remedy” to the issue.
“Any remedy should be narrowly tailored to preserve the incentives and the design of the program,” the IMM wrote. The market monitor cautioned that any solution must not enable IEP participants in the upcoming winter period to retroactively exit the program if they experience net losses.
“This could create a ‘heads I win, tails you lose’ situation for the upcoming 2024-2025 winter program: a participant that erroneously (or even wrongfully) qualifies for the IEP, could wait-and-see the outcome, and then at the end of the program file for a waiver and return of money if it is in its favor, or not,” the IMM added.
In response comments filed with FERC, Canal disagreed with the IMM’s concerns about broader implications of a waiver, arguing the company communicated to ISO-NE its intention to withdraw from the program and return its net revenues in mid-December 2023, and that it took time to determine the best course of action to remedy the issue.
FERC ordered settlement judge procedures “to permit the parties to seek a settlement to resolve whether and how Canal Marketing should return to ISO-NE the revenues or net revenues.”
The Commission added that “with regard to the IMM’s concerns about future erroneous qualifications for, and late withdrawals from, the IEP, we note that we are establishing settlement judge procedures here based on the unique circumstances and the various arguments raised by parties to this proceeding.”
PJM Models Suggest Capacity Shortfall Possible in 2029/30 Delivery Year
PJM could see a growing capacity shortfall starting with the 2029/30 delivery year, the RTO found after running its effective load-carrying capability (ELCC) model on a generation mix forecast through the 2034/35 DY, PJM’s Patricio Rocha Garrido told the PJM Planning Committee during its Aug. 6 meeting.
Rocha Garrido said adjustments to resource accreditation drive a declining forecast pool requirement (FPR) in the analysis, leading to the forecast peak load surpassing the solved peak load.
In other words, the resources PJM expects to come onto the grid will have a declining marginal capacity contribution each year that, paired with generation deactivations, may lead to accredited capacity falling below forecast peak loads.
Rocha Garrido cautioned that the analysis should not be seen as a forecast and is instead the result of applying its ELCC modeling to a resource mix forecast supplied by a PJM vendor, which carries “significant uncertainty.” While the vendor’s assumed resource mix cannot be released publicly, Rocha Garrido said it can be supplied to individuals upon request.
“We’re getting lower reliability value of the additions,” Rocha Garrido said, adding that the declining capacity value is the driving factor “rather than demand-side adjustments.”
If peak loads were driving the imbalance, Rocha Garrido said the FPR would be trending up in the analysis.
PJM analysis found a potential capacity shortfall beginning in the 2029/30 delivery year based on projected resource accreditation ratings and a vendor’s forecast generation mix. | PJM
PJM received deactivation requests for combustion turbines that led to a higher CT rating in the 2026/27 Reserve Requirement Study (RRS) after the analysis was initiated, so they are not reflected in the assumed resource mix. (See PJM Presents Revised Reserve Requirement Study Values.)
Rocha Garrido said a decline in the capacity contribution of demand response resources is due to risk modeling concentrating expected unserved energy in winter hours outside the DR availability window.
Paul Sotkiewicz, president of E-cubed Policy Associates, questioned whether the vendor would readjust the resource mix forecast given the spike in capacity prices in the 2025/26 Base Residual Auction. He said it could make sense for generators to undergo retrofits rather than retire, given the possibility of higher capacity revenues, particularly for coal units that could see upgrades to comply with coal combustion residuals requirements becoming economically viable. (See PJM Capacity Prices Spike 10-fold in 2025/26 Auction.)
Several stakeholders questioned the accuracy of the resource mix forecast and urged PJM to conduct additional sensitivities. Rocha Garrido said more sensitivities would be helpful, but staff did not have time for this analysis while preparing the 2026/27 RRS parameters.
Stakeholders Endorse LAS Charter Revisions
The PC endorsed revisions to the Load Analysis Subcommittee (LAS) charter aimed at reflecting a shift in the group’s function toward reviewing the load forecasts produced by PJM and soliciting stakeholder comments on the forecast inputs.
PJM’s Andrew Gledhill said much of the status quo charter language is a holdover from when transmission owners presented their own forecasts to PJM and stakeholders through the LAS. The proposed changes were approved by the LAS on July 29.
Calpine’s David “Scarp” Scarpignato said stakeholders’ role at the LAS goes beyond reviewing PJM’s load forecasts, which he said was the focus of the original proposed charter revisions. He proposed that PJM’s language be amended to reflect that stakeholders provide substantive comments on how the forecast is prepared.
Gledhill said language in the “responsibilities” section of the charter was intended to reflect stakeholder comments and noted that members do not vote on or approve PJM’s forecasts. He accepted a friendly amendment to the revisions from Scarp to add “and is responsible for soliciting stakeholder input and providing review of PJM reports” to the charter’s mission statement.
Monitor Presents CIR Transfer Proposal
The Independent Market Monitor presented its proposal for an expedited process for transferring capacity interconnection rights (CIRs) held by deactivating generators to planned resources in the interconnection queue. (See “Elevate Reviews CIR Transfer Proposal,” PJM PC/TEAC Briefs: July 9, 2024.)
The biggest distinction between the Monitor’s concept and the four competing designs is that CIRs would not be bilaterally traded between market participants but instead would be made available to the next planned resources that could take advantage of the underlying transmission capability. If PJM identified that a deactivating resource would create transmission violations that would require offering the owner a reliability-must-run (RMR) agreement to keep the plant in operation, PJM would initiate an expedited process where it would assign the CIRs to the next resource in the queue that could address the violations.
If PJM did not identify projects within the interconnection queue that could resolve the transmission violations, it would conduct an auction, or a solicitation could be held for project designs.
Scarp questioned what guarantees can be provided to ensure that generation projects selected by PJM through the expedited process are built if they are meant to replace an RMR contract and constitute reliability projects.
“If you’re doing it for RMR purposes, I’m wondering if you need more of a solid commitment more than what is already in the generator interconnection process,” he said.
PJM, Gabel Associates, MN8 Energy and Elevate Renewables also have sponsored packages, differentiated by the resources that would be eligible to receive transferred CIRs, how potential impacts to the grid would be studied and the standard that would disqualify replacement resources from using transferred CIRs due to identified grid upgrades.
PJM’s Becky Carroll said the proposals are slated to go for first reads and an endorsement during the Sept. 10 PC meeting, but voting could be deferred to the Oct. 8 meeting if substantial changes are made over the next month.
Manual 14B Revisions Include Change to Light Load Model
Stakeholders endorsed revisions to Manual 14B: Region Transmission Planning Process to rework the inputs to PJM’s light load case, which is used in the Regional Transmission Expansion Process (RTEP) load forecast to reflect the growth of load with flat profiles unaffected by weather and season.
The light load case is designed to create an accurate representation of shoulder periods by scaling load down to 50% of the summer forecast peak using bus-level data provided by transmission owners. PJM’s Stan Sliwa said practice has been challenged by the growth of non-scalable load, such as data centers. The revisions would remove non-scalable load from the light load case.
The Manual 14B changes also expand the NERC TPL standards examined during generator deliverability analysis to match current practice, updating the system operating limit (SOL) definition and adding new standards created by NERC.
The language is set to go before the Markets and Reliability Committee for a first read Aug. 21 and an endorsement vote Sept. 25.
Transmission Expansion Advisory Committee
PJM Presents Results of 8-year RTEP Model
PJM has updated the needs in its 2024 RTEP Window 1 solicitation to include a longer eight-year model designed to capture issues that might take longer than the typical five-year cycle to resolve.
The additional three years capture the remainder of the New Jersey offshore wind being interconnected through the State Agreement Approach (SAA), the completion of the Coastal Virginia Offshore Wind (CVOW) project and the 1-GW Chesterfield gas generator near Richmond, Va.
Despite the additions, load growth and resource deactivations are expected to cause Dominion and the West regions to each lose over 1 GW of dispatchable energy in the summer, while the capability in MAAC would grow by 2 GW over the 2029 model. Dominion would lose 2 GW in the winter case, while MAAC and West would both gain around 1 GW. Both MAAC and the West likely would export energy as demand grows in Dominion.
PJM’s Sami Abdulsalam said a conservative approach is taken when considering which planned resources are expected to be available in the RTEP analysis. Both Chesterfield and CVOW have advanced queue positions that provide a strong certainty of them coming online, while the New Jersey SAA projects have commitments to PJM from a state backer.
More than 100 new thermal overloads were identified in the longer model, 76 of which were in the summer, 48 in the winter and 40 in the light load case. Abdulsalam said the analysis is meant to allow transmission owners submitting RTEP solutions to right-size their projects to meet the needs identified in the five-year model with an eye toward long-term needs.
The solicitation window opened July 15 and is set to close Sept. 13, but Abdulsalam noted the new analysis was released after the window opened.
Several ratepayers in Northern Virginia called for alternatives to the series of transmission projects built or that are planned to crisscross the region to supply rapid load growth, with residents particularly interested in the concept of an undergrounded DC line. They also questioned whether higher capacity prices will lead to generation development that could reduce the need for transmission projects.
PJM’s Susan McGill said the RTO’s role is to identify needs and it’s up to developers to propose transmission or generation solutions through the RTEP or interconnection queue.
Supplemental Projects
PPL presented a project to interconnect a 1,980-MW load sited near Hazleton, Pa., for $196.55 million. The customer would be supplied by a new 230-kV switchyard named Tomhicken, which would be cut into the Susquehanna-Harwood double circuit 230-kV line, as well as a new Nescopeck 230-kV switchyard.
Tomhicken would be configured as a six-bay, breaker-and-a-half facility with a 125-MVAR capacitor bank for $45 million, and Nescopeck would be configured as a three-bay breaker and a half switchyard for $29.5 million. Nescopeck would be cut into the Susquehanna-Sunbury 230-kV line with a partial rebuild of the portion between the new facility and Susquehanna to upgrade it to be double circuit for that portion. Additional 230-kV lines would be constructed between Nescopeck, Tomhicken and Harwood.
The customer is expected to come online in 2026 starting with a load of 240 MW, growing to 720 MW in two years, 1,440 MW by 2031 and reaching its full consumption in 2033. The project is in the conceptual phase, with a projected in-service date of June 1, 2027.
Exelon presented a $158 million project to provide service to a customer seeking to bring 378 MW of load to the Elk Grove area in its ComEd zone. The customer would be served by a new 138-kV substation with 16 circuit breakers and in a double ring bus configuration and five 138/34-kV transformers. The facility would be cut into the Elk Grove-Schaumburg line.
The project would require a new 345-kV bus in a breaker-and-a-half configuration to be installed at the Elk Grove substation, including 12 new 345-kV circuit breakers. The bus would be cut into the Des Plaines-Lombard 345-kV double circuit line. Two 345/138-kV autotransformers also would be installed.
The customer expects to bring 117 MW of load in December 2026 and reach 333 MW in 2028. The project is in the conceptual phase, with a projected in-service date of Dec. 31, 2026.
Exelon presented an additional $40.6 million project to serve a customer in the Elk Grove region with 260 MW of load. A new 138-kV substation would be built with 15 circuit breakers in a double ring bus configuration with six 138/34-kV transformers. It would be connected to the Elk Grove East substation with new 1.7-mile, 138-kV lines.
Two 345/138-kV autotransformers would be required at the Itasca substation, as well as two 345-kV and two 138-kV circuit breakers.
The customer anticipates 25 MW of load in June 2027, 87 MW in 2028, growing ultimately to 260 MW. The projected in-service date for the transmission upgrades is Dec. 31, 2027.
FirstEnergy presented a $38.7 million project to replace steel H-frame structures along its Perry-Ashtabula-Erie West 345-kV line, reconductor 7.2 miles of the 20-mile line and replace insulators and related equipment. The line is around 60 years old, and the insulators, H-frames and guying are corroded. The line has experienced seven scheduled outages for repairs and four due to equipment failure since 2014. The project is in the conceptual phase, with a possible in-service date of April 9, 2027.
The utility also presented two projects amounting to $15.5 million to replace obsolete and misoperating relay equipment at its Doubs, Ringgold, Lime Kiln and Montgomery 230-kV substations in the APS zone. The work is in the engineering phase, with an estimated in-service date of Oct. 31, 2026, for Lime Kiln and Montgomery and Dec. 31, 2026, for Doubs and Ringgold.
Dominion presented a $180 million project to address reliability violations along its Fredericksburg-Possum Point 230-kV line, as 3 GW of load is expected to come online served by 13 new substations along its length.
A new Allman switching station would be built north of the Fredericksburg substation, with 10 230-kV line terminals in a breaker-and-a-half configuration. It would cut into 230-kV lines between Fredericksburg and the Cranes Corner, Aquia Harbour and Birchwood substations
About 4.5 miles of the line from Allman to Cranes Corner and 0.7 miles of line from Allman to Hospital Junction would be rebuilt with double circuit structures. The Cranes Corner substation would be expanded to support line realignment. The line to Aquia Harbour would be upgraded to double circuit and rebuilt with vacant arm positions to host two additional 230-kV lines to run from Allman, past Aquia and onto Possum Point on a new 7.1-mile double circuit pole line.
The project is in the conceptual phase, with a possible in-service date of June 1, 2029.
Dominion also presented a $30 million project to power a data center customer in Stafford, Va., with a projected summer 2029 load of 136 MW. A new Centreport switching station in a four-breaker ring bus configuration would be cut into the Spartan-Cranes Corner line with 2.5 miles of new double circuit line.
Vineyard Wind and GE Vernova on Aug. 9 released an overview of their action plan for cleaning up debris and eventually resuming construction on the Vineyard Wind 1 project in the wake of the blade failure and collapse on July 13. (See Blade Failure Brings Vineyard Wind 1 to Halt.)
According to blade maker GE Vernova, the failure was caused by an isolated “manufacturing deviation” at the factory. (See GE Vernova Finds Defect in Vineyard Wind Blade.) Construction and power production have been paused following the incident due to a suspension order from the U.S. Bureau of Safety and Environmental Enforcement.
“Vineyard Wind and GE Vernova are committed to safely removing the damaged blade, monitoring for and collecting any debris, assessing any environmental impacts, inspecting all of the other project blades and safely restarting the project,” the companies said in a statement.
While no personal injuries related to the blade collapse have been reported, foam, wood and fiberglass pieces of the blade have washed up on local beaches over the past month, temporarily closing several beaches. The action plan noted that the “primary risk of the debris is physical contact with fiberglass.”
The companies said they are working with Resolve Marine to prevent more debris from falling into the ocean, remove the broken blade and clean up seabed debris.
To ensure manufacturing issues do not affect any other blades, the companies said they are reviewing ultrasounds from the manufacturing process of the blades to identify any abnormalities. They also are conducting an internal inspection using “advanced remote-controlled robots,” or “crawlers.”
The action plan also indicated GE is developing an algorithm to better detect and avoid similar issues, which will “provide advanced warnings or automatic, safe turbine shutdown when required.”
Looking ahead to the eventual resumption of activities on the project, the companies said they first will resume tower and nacelle installations, followed by blade installations and finally move on to power production. The companies said they are “working with the Federal Interagency to ensure all operations are in compliance with all applicable orders, permits, regulations and laws.”
Despite relatively minimal local environmental impacts, the blade failure has drawn significant national attention. At the time of the failure, Vineyard Wind 1 was the largest operating offshore wind farm in the country.
Offshore wind opponents, including fishing industry organizations and conservative think tanks, have pointed to the blade collapse as evidence the industry is a bad investment of public resources and a danger to the environment.
“Offshore wind is just another of the Biden-Harris administration’s sinking policies,” said the Texas Public Policy Foundation, which called on the courts to strike down the project’s regulatory approvals. Attorneys for the foundation are representing fishing industry opponents to the project in a federal appeal of its approval.
Meanwhile, environmental advocates have expressed concern about the blade failures, but have emphasized that environmental impacts must be viewed in context, and that offshore oil spills are far more damaging to local communities and ecosystems.
“We must all work to ensure that the failure of a single turbine blade does not adversely impact the emergence of offshore wind as a critical solution for reducing dependence on fossil fuels and addressing the climate crisis,” said Nancy Pyne of the Sierra Club in a statement.
VALLEY FORGE, Pa. — The Operating Committee discussed PJM’stimeline for addressing technological and operational challenges the RTO plans to address over the next four years.
The document is one in a series of outlines PJM has formed to track the various stakeholder and internal staff efforts to address reliability issues identified in its Ensuring a Reliable Energy Transition analyses. The market-oriented road map was presented during the July 10 Market Implementation Committee meeting, while its planning sibling remains under design as staff works on FERC Order 1920 compliance. (See “PJM Presents Road Map of Market Design Changes,” PJM MIC Briefs: July 10, 2024.)
PJM Senior Director of Market Design Rebecca Carroll said the road maps are meant to be updated as new efforts begin or are completed, with the aim of ensuring none of the working areas fall through the cracks.
The operations road map includes:
Enhancing forecasting of intermittent resources, behind-the-meter generation and changing load behavior.
Implementing the Control Room 2030 plan to build dispatcher tools to facilitate the deployment of large volumes of intermittent, distributed and storage resources.
Continuing upgrades to PJM’s suite of energy management system (EMS) software, focusing on network application, training system and model management tools.
Developing risk-based operations approaches that account for variance in forecast error, generator outage performance and time of year considerations. That could impact reserve and regulation procurement or other operational decisions.
Continuing gas-electric coordination efforts to incorporate information about the gas pipeline and generation fleet into PJM operations.
Incorporating intermittent forecasting into the transmission outage analysis and approval process.
Ensuring any changes to reserve market structures remain aligned with operational needs.
PJM’s Chris Pilong said the number of risks the grid faces is increasing, challenging the ability for operators to schedule the appropriate generation with optimal lead times. Some of the initiatives likely will require the focus of stakeholders and the RTO indefinitely, such as the electric-gas coordination efforts that have been ongoing for a decade and are likely to continue as the gas industry evolves with shifting economics and policies.
Several stakeholders recommended PJM publish the three road maps and their related materials in one place for easy retrieval and provide more insight into in which forums each issue will be discussed.
Paul Sotkiewicz, president of E-cubed Policy Associates, said all of the items on PJM’s road map are interrelated topics, and he’s concerned that if they’re addressed in siloes, holistic solutions may remain out of reach.
Pilong said staff are coordinating across departments and when topics are brought to stakeholders PJM wants to make sure they’re brought to the correct working group.
Sotkiewicz also argued it’s inappropriate for the RTO to include the facilitating of decarbonization policies reliably in its three “Pillars of Strategy” guiding the focus of the road map. Instead, he said the focus should remain locked in on reliability amid changes external to PJM.
Voltage Reduction Action Test Planned
PJM plans to conduct a voltage reduction test Aug. 14 and 15 to validate a capability the RTO has not used for more than a decade.
Senior Dispatch Manager Kevin Hatch said the test is one of the recommendations in a PJM report on the performance of the grid in the wake of the December 2022 Winter Storm Elliott, when a voltage reduction warning was issued, and one additional generator trip could have required an action. The previous voltage reduction action PJM issued was in January 2014. (See PJM Recounts Emergency Conditions, Actions in Elliott Report.)
The Mid-Atlantic region will undergo testing at 2 p.m. ET on Aug. 14, followed by the western and southern regions the following day at the same hour. If the test cannot be conducted as scheduled, Aug. 28 and 29 have been identified as alternatives. The test is scheduled to run for half an hour.
The test will simulate a 5% voltage reduction on a load level above the seasonal upper quartile.
Hatch said the goals of the test are to determine whether changes in the characteristics of PJM load have led to any shifts in the efficacy of voltage reduction actions, to examine the functionality of updated procedures and to provide training for staff and members. PJM does not have a regular voltage reduction testing regimen, but Hatch said ISO-NE and other regions conduct tests twice a year.
July 16 saw one of the highest peaks for the month in PJM’s history at 153 GW. Presenting the month’s load forecast error, PJM’s Marcus Smith said the month as a whole averaged 5 GW higher than an average July.
PJM’s average peak and hourly forecast error rates for July both fell squarely at their 25-month averages of 1.64% and 1.52%, respectively.
The day-ahead forecast error did exceed PJM’s 3% target on a handful of days. July 13 saw a 5% under forecast as temperatures came in hotter than expected, while the following day was over forecast by about 6.5% because of storms bringing temperatures 15 degrees lower than anticipated.
Eight shared reserve events, three spin events and eight hot weather alerts were issued across the month. Generator trips led to two shortage cases on July 28 and one on July 8.
Social Manipulation Attacks a Rising Cybersecurity Threat
Artificial intelligence increasingly is being used in social manipulation cyberattacks, PJM’s Jim Gluck said, warning stakeholders that critical infrastructure is experiencing attacks at a higher rate than the economy as a whole.
He pointed to a software company that was targeted recently through its hiring process by attackers impersonating a prospective employee. Four video interviews, validation of credentials and background checks failed to identify that a stolen identity was being used and profile images augmented with AI. Once the individual was hired for the position, a company computer was mailed out, malicious software was installed on it and a breach was attempted. The company identified the attack and revoked the computer’s access before systems could be compromised.
Attackers also have taken advantage of widespread disruption caused by an issue with antivirus software developed by CrowdStrike. Individuals have impersonated CrowdStrike employees offering assistance with recovery to gain access to Microsoft systems.
“We’ve got to make sure we’ve got the processes in place to detect these kinds of situations wherever they are,” Gluck said.
Implementing multi-factor authentication, patching software regularly and staying vigilant for phishing attacks can reduce the risk of attacks being successful, he said.
PJM not Planning to Refile Components of Rejected CIFP Proposal
VALLEY FORGE, Pa. — PJM has scuttled plans to refile several components of its proposed capacity market redesign that was rejected by FERC in February (ER24-98).
Drafted through the Critical Issue Fast Path (CIFP) process conducted last year, the filing sought to rework the market seller offer cap (MSOC) and Capacity Performance (CP) structure, and establish a forward-looking energy and ancillary service (EAS) offset for the MSOC and minimum offer price rule (MOPR). The filing was one of two arising from the CIFP process last year; the other was approved by the commission in January and focused on risk modeling and generation accreditation. (See FERC Rejects Changes to PJM Capacity Performance Penalties.)
During the MIC’s meeting June 5, Chief Economist Walter Graf said PJM was considering refiling components that the commission either seemed supportive of or did not comment on in its rejection order. That included “clarifying revisions” to the definition of Capacity Performance quantified risk (CPQR), MSOC values for planned generation based on net cost of new entry, segmented offer caps and the forward-looking EAS offset. (See “PJM to Refile Portions of Rejected CIFP Proposal,” PJM MIC Briefs: June 5, 2024.)
But last week, PJM Lead Market Design Specialist Pat Bruno said the decision to not refile was made following mixed stakeholder feedback during the June meeting, as well as outreach to members over the past two months. He said the overall sentiment seemed to be that there is not a major imperative to refile at this time, particularly given the Quadrennial Review and second phase of the capacity market redesign, both expected to begin next year. Those two forums may be where PJM seeks to propose the items it intended to refile. (See “PJM Presents Road Map of Market Design Changes,” PJM MIC Briefs: July 10, 2024.)
The RTO envisions the Phase 2 discussion to center around a seasonal or sub-annual capacity construct, Bruno said.
PJM’s proposal did not subject intermittent resources to the must-offer requirement, but the RTO had considered doing so as part of a sub-annual market design while forming its proposals. A sub-annual design would allow for greater alignment of intermittent resource performance expectations and accreditation, he said.
Stakeholders Endorse FTR Manual Revisions
The MIC endorsed revisions to Manual 6: Financial Transmission Rights to conform with three FERC orders on storage, hybrid resources and bilateral trade agreements (ER19-469, ER22-1420 and ER24-374).
The revisions state that transmission customers using firm service to deliver energy for charging storage or open-loop hybrid resources cannot receive auction revenue right allocations. (See RTOs Move Closer to Full Order 841 Implementation.)
They also require reporting bilateral trades to PJM, including confirming that the seller has no continuing interests in the FTR once it has been transacted.
The revisions are set to go before the Markets and Reliability Committee for a first read Aug. 21 and move to an endorsement vote Sept. 25.
PJM Proposes Elimination of 2 Interface Pricing Options
PJM presented a quick-fix proposal to remove its high/low and marginal cost proxy interface pricing options because of lacking utilization. The quick fix process allows for an issue charge and proposed solution to be voted on concurrently.
Since their implementation in 2009, the options have been used only once, when Duke Energy Progress received FERC approval of a dynamic schedule with PJM, according to the RTO’s problem statement. That agreement was terminated in 2019, and the options have not been used since.
“PJM and its stakeholders have the opportunity to retire the aforementioned processes associated with the development of interface pricing points for non-market entities,” the problem statement reads. “There is an opportunity to simplify the existing language to remove outdated processes no longer used and better align with the existing language for the current interface pricing process in use.”
PJM’s Phil D’Antonio said the marginal cost proxy option required a congestion management agreement to be reached, but the RTO removed the management process in 2021.
Updated Guidance for Entering Dual-fuel Units into Markets Gateway
PJM’s Joseph Tutino reviewed the RTO’s updated guidance for how dual-fuel generators should reflect their fuel availability in Markets Gateway.
Resources assigned a cost schedule through the day-ahead or real-time markets are unable to subsequently switch their schedules, so dual-fuel generators that intend to switch the fuel they are operating on should update their schedule to state the fuel they will be consuming and the associated price, Tutino said.
If a gas-fired dual-fuel unit is committed to run on gas and then becomes unavailable later in the operating day, its gas cost schedule, incremental offer curve and no-load cost should be updated to reflect the cost of oil. The “reference schedule” field also should be updated to reflect the cost schedule ID of the alternative fuel.
PJM Presents Data on DR Availability
PJM analysis of demand response availability during the 10 days in 2022 and 2023 that comprised the top five weather load days for each year suggests that actual metered load reductions required to meet winter curtailment obligations were below the effective load-carrying capability (ELCC) rating assumptions for the resource class during the winter availability window hours. (See “Voltus Discusses DR Market Issues,” PJM MIC Briefs: July 10, 2024.)
The data were presented as part of a stakeholder discussion on whether the window in which DR resources are considered available to supply capacity should be expanded during the wintertime hours to reflect changes to PJM risk modeling that shifted focus to the evening.
Bruno said the ELCC analysis assumes that there is zero reduction capability outside the availability window of 6 a.m. to 9 p.m., which curtailment service providers argue undervalues the capacity they could offer. Bruno said the other side of the coin is that the data suggest that capability within the window is lower than ELCC ratings expect, and performance falls off even more outside the window.
Dave Mabry, of the PJM Industrial Customer Coalition, said the December 2022 data are skewed by emergency conditions overlapping with a holiday weekend, as PJM data for Dec. 23, a Friday, show many DR participants shutting down ahead of the holiday weekend starting as early as the morning prior to the load management event that occurred later in the evening.
Calpine’s David “Scarp” Scarpignato said the difference between thermal generation’s winter and summer capability is also not well captured in ELCC ratings. He said it would be more efficient for stakeholders to focus on overall ELCC improvements rather than having several complex stakeholder processes focused on the construct.
Several Corrections to Formulas Included in Proposed Manual 15 Revisions
PJM’s Jennifer Warner-Freeman presented a package of revisions to Manual 15: Cost Development Guidelines drafted through the document’s biennial review. The changes mainly focus on correcting formulas throughout the manual.
The revisions also would remove a table displaying variable operations and maintenance costs to prevent any confusion about which values should be used. Freeman said the costs are updated annually to account for inflation, and staff are concerned members may believe the manual values are static. The updated values are posted to the PJM website.
“What I am reviewing here, from NYISO’s perspective, are the highlights,” said Yachi Lin, the ISO’s director of systems planning. “But absolutely please do your own review, bring back your points, and we can start a discussion.”
The rule requires regional transmission planners to plan on a 20-year horizon with several benefits. Cost allocation plans for projects must ensure only customers who receive those benefits pay for projects.
“You’re going to hear these terms repeated over and over again throughout the order: ‘sufficiently long-term,’ ‘forward-looking,’ ‘comprehensive,’” Lin said.
The order went into effect Aug. 12. Lin said NYISO needs to submit its compliance filing with the regional planning requirements to FERC by June 12, 2025. Interregional planning requirements are due later in August.
Between October and December of this year, NYISO will be drafting a straw proposal to comply with the order, followed by tariff revisions during the first six months of 2025.
NYISO will be required to develop three long-term scenarios that project out 20 years based on seven factors prescribed by FERC. Once projects have been winnowed down to the selected projects, the reasons for the selections and rejections will be explained to stakeholders.
One TPAS member pointed out that the process looked similar to parts of NYISO’s extant three-pronged process and wondered how much this would change the ISO’s existing process.
“That is the question we are very much interested in hearing your opinion on,” Lin said. She went into detail on the NYISO planning process and then asked whether it was better to expand the existing process or build an additional tracker on top to comply with the order. “I don’t have an answer to tell you. What we really need to do is hear from you.”
One stakeholder said it was unclear to him whether NYISO was the “transmission provider” under the rule or whether that was the New York Public Service Commission.
“The transmission provider has an affirmative obligation to determine the need,” Lin said. “The relevant state entity does have a role to play in providing the input for how the scenario is developed, how the need is established. So there’s also an affirmative role for the relevant state entity to play.”
Lin also noted the four technologies that were specified as grid-enhancing technologies, which under the order must be considered for efficiency and cost-effectiveness against new facilities or upgrades that do not incorporate them. They are dynamic line ratings, advanced power control devices, advanced conductors and transmission switching.
FERC approved two enforcement orders requiring several battery storage operators to pay more than $1 million in fines and remit nearly $1.9 million back to CAISO.
In the first order, issued Aug. 6, the commission found that Vista Energy Storage submitted bids into CAISO that overstated the availability and capability of its Vista Battery (IN24-11). The misrepresented bids occurred for over a month during the summer of 2022. As a result, Vista will pay $1 million in fines and disgorge $1,670,000 in profits to CAISO.
Vista is a subsidiary of REV, a renewable power company formed by LS Power in 2021 that operates about 2.8 GW in generation assets. The Vista Battery’s maximum storage capacity is 40 MWh, and it offers both energy and ancillary services into the CAISO market.
During a 33-day period in 2022, Vista each day told CAISO that it forecast the battery’s initial state of charge the following day to be at or below 4 MWh even though the battery had a 36 MW or larger regulation up award for the final hour of that day.
“Vista knew, or should have known, that because of that regulation up award, the ancillary services state of charge constraint would ensure that Vista’s actual state of charge would be around 20 MWh during the final hour that day,” the order reads.
Vista received 40 MW regulation down awards for the first hour of the next day due to its 4 MWh lower initial states of charge. It would not have received these awards in the first hour of the day if it had submitted an initial state of charge value of 20 MWh. The lower values also enabled the company to earn awards of 40 MW of regulation down for several hours after the first hour.
“Because the battery was actually at a state of charge around 20 MWh at the beginning of each of the 33 days within the relevant period, there was a conflict between operation of the regulation down product (which seeks to charge the battery to adjust frequency on the grid) and the ancillary service state of charge constraint,” FERC stated.
To resolve the conflict, the ancillary service state of charge constraint frequently discharged the battery to make Vista’s regulation down awards feasible.
As a result, Vista received approximately $1,485,000 in bid cost recovery payments because of regulation down awards it would not have obtained if it had submitted accurate initial state of charge values.
NextEra Order
The second order, issued Aug. 8, involved Arlington Energy Center III, Blythe Solar 110, Blythe Solar III, Blythe Solar IV, Desert Sunlight 250, Sunlight Storage and McCoy Solar (IN24-10).
The companies are all indirect subsidies of NextEra Energy Resources and operate battery energy storage systems co-located with solar generation. Each storage system and solar facility function as separate resources but share the same point of interconnection (POI). As per CAISO’s large generator interconnection agreement, the resources cannot exceed the POI limit.
In December 2021, CAISO modified its tariff to prohibit co-located battery facilities from deviating from dispatch instructions. According to the order, NextEra was unaware of the tariff change and thus didn’t update its software to comply.
“During the relevant period, when the combined output of a plant’s battery and solar facilities approached the POI limit, the programmable logic controllers at the plant that controlled the output of the solar and battery facilities automatically curtailed the battery facility, allowing the solar facility to continue to deliver its output to the CAISO grid, as was permitted prior to CAISO’s December 2021 tariff change,” the order states. “NextEra’s software did so even during intervals in which the plants’ batteries received ancillary services awards.”
There were 3,835 five-minute intervals during which the plants’ batteries deviated from dispatch instructions while holding ancillary service awards, resulting in the companies’ receiving approximately $381,724 in revenues.
NextEra has since updated its software and will pay a civil penalty of $105,000 and $381,724 in disgorgement to CAISO.
Intense heat coupled with this summer’s early and active fire season likely will increase the need for public safety power shutoffs (PSPS) this year, according to utilities presenting at a California Public Utilities Commission workshop Aug. 7-8.
Southern California Edison COO Jill Anderson spoke about the “relentless heat waves” and “months of wildfires” that have hit the state this summer.
“We’ve been setting records, certainly in SCE’s service area and other places, and all of that for us is a reminder of how critical it is that we are ready with all the tools at our disposal to make sure that we can be managing and responding to extreme weather,” Anderson said. “We know that one of those tools — what we consider a last resort tool — is PSPS.”
PSPS allow utilities to temporarily shut off power in certain areas to reduce the risk of fires caused by electric infrastructure. Several utilities, including SCE, Pacific Gas and Electric, PacifiCorp, and San Diego Gas and Electric, discussed the summer forecast in their service territories, PSPS predictions, and methods of implementing and preventing power shutoff events.
The transition to the La Niña weather pattern, associated with decreased rainfall in California, could extend high fire danger conditions later into fall and winter and increase the number of PSPS events, the utilities noted.
“We’re concerned about the La Niña weather pattern because it historically correlates with more offshore wind days and also less precipitation, and these are not good markers for PSPS,” said Tom Brady, principal manager of business resiliency at SCE.
But that correlation isn’t always the case, Brady noted. In some instances, meteorologists have seen rains come early during La Niña weather patterns. Climate change also could weaken the relationship between La Niña and precipitation in Southern California, Brady said.
The utilities highlighted that above-normal precipitation this past winter and in the past few years contributed to the vegetation growth that is fueling wildfires across the state.
“August fuel levels are now at critical levels, and any moisture benefit from 2024 has mainly elapsed,” Brady said. “We’re in PSPS season, and in fact, we’re activated today for a small event with localized impacts on the border of Kern and Los Angeles counties. We can begin to expect larger events to begin occurring when weather patterns shift and we have more widespread high winds across our service territory.”
PG&E painted a similar picture, highlighting extreme weather conditions that have increased the likelihood of PSPS events.
Scott Strenfel, PG&E senior director of meteorology operations and fire science, said historically high temperatures have rapidly dried the fuels and “set the stage for what’s already been a very challenging fire season.”
“It is more probable than not that this will be a more active PSPS season compared to the last two years, just because of the danger of fuel,” Strenfel said. “But all of that is going to depend on how many wind events we get and the timing of rainfall that could occur before or after those dry wind events that we get from the northeast.”
Conditions are similar in SDG&E’s service territory, with hot temperatures, increased vegetation and high fire risk.
“It’s certainly not the forecast that a lot of us want to see going into the fall, but it is one that our situational awareness is very focused on, and we’re very prepared,” said Brian D’Agostino, vice president of wildfire and climate science at SDG&E.
‘Positive Trend’
The utilities all highlighted ways they’ve worked to prevent PSPS events through system hardening, undergrounding, sectionalizing devices and transmission switches, and using cameras and weather stations.
In 2023, SDG&E completed 72 miles of undergrounding, trimmed and removed 13,000 trees, conducted 15,000 drone inspections, implemented 60 miles of covered conductors and more. In 2024, the utility aims to implement 40 more miles of covered conductors, 125 miles of undergrounding, trimming and removing 11,000 more trees, and conducting 17,000 detailed asset inspections.
PG&E completed 664 miles of undergrounding between 2019 and 2023, hardened 1,664 miles of power lines, and installed 602 cameras and 1,424 weather stations. The utility plans to underground 250 more miles, harden 280 more miles, enable the use of AI for the cameras and continue to optimize the weather stations.
PacifiCorp has made similar progress, replacing over 95 miles of bare conductor with insulated covered conductor in 2023, undergrounding five miles of line, upgrading more than 35 reclosers, relays and circuit breakers, and installing over 4,000 non-expulsion fuses. The utility also implemented the FireSight model to identify areas of heightened fire risk, which led it to identify a new high fire-risk area. In total, high fire-threat districts encompass approximately 1,700 overhead line miles and 54% of PacifiCorp’s territory in California.
SCE implemented about 5,900 miles of covered conductor and 26 miles of undergrounding, trimmed or removed over 2 million trees, installed or replaced over 14,200 fast-acting fuses and 160 remote-controlled sectionalizing devices, and conducted over 1 million equipment inspections.
The utilities also highlighted the importance of artificial intelligence and machine learning in their modeling, forecasting and preparedness for PSPS events. For example, SDG&E is using machine learning at each of its 222 weather stations to train AI models to predict exactly which areas could experience a shutoff, allowing the utility to more accurately target notifications.
SDG&E also relies on three primary AI-based tools to enhance its PSPS response: gridded AI-based fuel models that provide a holistic look at fuel moisture content, machine learning wind gust models and AI smoke detection. The utilities also rely on enhanced powerline safety settings (EPSS), which allows powerlines to automatically turn off power within one-tenth of a second.
PG&E relies on outage and ignition probability weather models, as well as a fire potential index, to calculate the need for PSPS.
CPUC President Alice Reynolds expressed optimism despite predictions for increased PSPS events.
“I’m really pleased to see the progress that has been made on PSPS events over the last several years,” Reynolds said, noting that PSPS customer notifications across all utilities declined from 5.8 million in 2019 to about 500,000 in 2023.
“There’s a positive trend for the number of customers that have been de-energized … so clearly significant improvements,” Reynolds said.
