TerraPower on June 11 broke ground on its Natrium reactor demonstration project in Wyoming, making it the first advanced reactor to enter construction.
TerraPower was founded by billionaire Bill Gates and the project is supported by a long-term contract with PacifiCorp, which is part of fellow billionaire Warren Buffett’s Berkshire Hathaway business empire.
“I’m proud of all the partners and people who helped get the most advanced nuclear project in the world built in Kemmerer, Wyo.,” Gates said in a statement. “I believe that TerraPower’s next-generation nuclear energy will power the future of our nation — and the world.”
Construction is expected to take five years and at its peak will employ 1,600 workers. Once the plant is operational, TerraPower expects it will support 250 permanent employees.
The Natrium reactor will be a fully functioning commercial power plant, which is being built at the site of a retiring coal-fired power plant in Kemmerer.
The 345-MW reactor uses sodium-cooling technology with a molten salt-based energy storage system that can boost its overall output to 500 MW when needed, which is enough to power 400,000 homes. The energy storage capability allows the project to help balance with renewable power, which has long been an issue with conventional nuclear plants that that lack ramping flexibility.
The company’s construction permit application is still pending at the Nuclear Regulatory Commission, but it was able to start construction on non-nuclear facilities while nuclear construction awaits regulatory approval.
The NRC announced last week that it was advancing its consideration of the project and noted that if it approves construction, TerraPower would have to submit another application to actually operate the power plant.
“This is a challenging yet exciting time in the energy industry,” PacifiCorp CEO Cindy Crane said in a statement. “In an era of rapid change, the need for reliable, affordable and dispatchable energy will remain a constant. Innovative technologies like the Natrium project will enhance our ability to serve our customers, meet growing demand and ensure a reliable and resilient energy future.”
Engineering firm Bechtel is building the facility, and company President Craig Albert said in a statement that the project will launch a new approach to nuclear construction that is meant to be safer, cleaner and faster. The company has built 150 nuclear plants around the world over the past 70 years.
“Working together, the combination of advanced technology and streamlined constructability has the potential to diversify the U.S. power generation industry,” Albert said. “The option of deploying smaller advanced nuclear plants that can work in concert with other clean energy sources will help speed our progress toward net-zero emissions.”
Constellation’s Dominguez Comments on State of the Industry
Speaking on a Reuters webinar June 10, Joseph Dominguez, CEO of Constellation Energy, which owns and operates one of the largest nuclear fleets in the country, said it’s still an open question which technology will dominate the future of the industry. Dominguez said the existing fleet of reactors could run until 2060 or beyond, but that would require major investments and Constellation is also focused on expanding nuclear production.
“We are expanding the output of our plants,” Dominguez said. “As we change over equipment, we tend to get better materials, better efficiencies and all sorts of things, generators, pumps, everything that allows us to increase the output of the machines and put on the grid almost immediately, at least in power terms — over a handful of years, new firm, clean energy. And then we’re also investigating the next generation of small modular reactors or large-scale nuclear plants.”
Some firm clean power is going to be necessary to reach net-zero goals, and nuclear faces competition from other technologies, including natural gas-fired generation with carbon capture and storage, which Constellation is also looking into, he added.
While the company recently bought NRG’s share of the South Texas Project, Dominguez said other opportunities to buy existing nuclear plants are not on the table because their owners recognize the value of those assets, focusing Constellation on organic growth through capacity uprates, the possibility of restarting its Three Mile Island plant in Pennsylvania, and eventually the potential for building new plants.
“Over the last 10 years, [the industry] only brought on two nuclear units,” Dominguez said, referring to Southern Co.’s Plant Vogtle expansion. “And some reports indicate that those have been as much as $20 billion apiece to build. So, the ability to restart a unit at a fraction of those costs, to create an environment where you can do all the state-of-the-art upgrades to the unit to allow it to be able to run for decades more — that’s an incredibly valuable opportunity for America.”
The theory with small modular reactors is that much of the equipment would be manufactured at a central facility and then transported to the power plant’s location, which is how the industry builds gas-fired and renewable power plants, Dominguez said.
“The way we think about it right now is we’ve got to see these technologies evolve, we’ve got to see folks prove out the competency,” he added. “I think they’ll do that in the next five or six years. And then we’ll select the technologies that best suit our needs, and our customers’ needs.”
DTE Energy said it will build a large battery energy storage system on the site of a coal-fired plant it is demolishing near Detroit.
With a capacity of 220 MW and 880 MWh, the Trenton Channel Energy Center is expected to be the largest standalone battery storage site in the Great Lakes region when completed in 2026.
Company officials said the project will bring the state closer to the MI Healthy Climate Plan goals outlined by Michigan Gov. Gretchen Whitmer (D), who joined them for a ceremonial groundbreaking at the riverfront site June 10.
“DTE’s new Trenton Channel Energy Center will help us strengthen our grid and produce more clean power when it’s less costly and store it for later when we need it,” she said in a prepared statement.
DTE CEO Jerry Norcia said in a news release the new battery facility will support the utility’s CleanVision Integrated Resource Plan and help move the state closer to its energy storage target. It is the largest of several energy storage projects DTE has in development.
A rendering shows the battery energy storage system planned to replace the Trenton Channel plant. | DTE Energy
DTE said the Inflation Reduction Act is providing an important financial boost for the Trenton Channel project — $140 million in tax incentives.
The original Trenton Channel Power Plant dated to 1924, and a companion plant running at higher steam conditions was built in 1950. The “low-side” plant was decommissioned in the 1970s, and its boiler house was demolished.
DTE’s annual fuel mix report compares its own statistics with the five-state regional average and shows mixed results for 2022, the last year in which Trenton Channel and St. Clair were fired up.
DTE has relied on coal for 54.16% of its generation vs. 41.8% for the region; its nitrogen oxide emissions per MWh of power generated were 50% higher than the region, and its sulfur dioxide emissions per MWh were 128% higher.
But DTE also generated 13.1% of its electricity with renewable sources — mostly wind — compared with a regional average of just 6.8%. DTE’s carbon dioxide emissions per MWh were 13.5% higher than the regional average.
Demolition of the Trenton Channel Power Plant has begun.
The dual 563-foot smokestacks — local landmarks known as The Witches’ Socks or The Candy Canes for their red and white bands — were brought down with explosives March 15, and the boiler house is scheduled to meet the same fate at sunrise June 21.
The plant was not only a landmark for generations of area residents, but also a literal and figurative powerhouse for the area’s economy, with a nameplate capacity as high as 1,060 MW, plus a sizeable workforce and local tax impact.
DTE said the battery plant will generate tax revenue for the community to continue the coal plant’s legacy.
ISO-NE’s Order 2023 compliance filing received mixed comments from a range of clean energy stakeholders last week, drawing support from several large trade associations along with protests from multiple companies.
Order 2023 is intended to reduce wait times and costs associated with interconnection by mandating that transmission providers implement first-ready, first-served cluster study processes with defined timelines. (See FERC Updates Interconnection Queue Process with Order 2023.)
In comments supporting ISO-NE’s filing, Advanced Energy United, American Clean Power Association, Natural Resources Defense Council and Solar Energy Industries Association jointly praised the RTO’s adoption of several stakeholder amendments to its proposal.
“Throughout this process and right up to the final vote, there was extremely robust stakeholder engagement in the compliance proceeding,” the groups wrote. “Ultimately, from more than two dozen stakeholder amendments, ISO-NE adopted four priority stakeholder proposals identified by parties representing interconnection customers in part or in full in some form.
“While future reforms beyond Order No. 2023 will be needed to ensure a fully functional and efficient interconnection process in New England, ISO-NE’s Order No. 2023 reforms will mark an important first step in improving existing processes,” the groups added.
ISO-NE has committed to continuing work to improve interconnection, writing in its filing that it “will continue its engagement with stakeholders both to ensure successful implementation at the outset and to assess potential improvements going forward.”
The clean energy groups expressed interest in additional efforts to further reduce the overall cluster study timeline, provide more information and process transparency to interconnection customers and add flexibility to alter projects during the interconnection process to limit costs.
RENEW Northeast also supported the filing, specifically applauding ISO-NE’s proposal for studying storage resources.
Order 2023 directs RTOs to let storage developers dictate the system load at which they would charge, while requiring control technologies to prevent charging beyond this load. ISO-NE has proposed a variation in which it would study storage resources at “peak shoulder load” and rely on security-constrained economic dispatch to prevent storage “from being dispatched at load levels higher than the peak shoulder load under which the facility was studied.”
RENEW Northeast wrote that the approach “will afford energy storage the flexibility to optimize its operations according to real-time grid reliability conditions rather than under limits established during the interconnection study process that will likely become less relevant over time as the grid topography changes.”
Calls for Shorter Study Timelines, Expanded Use of Surety Bonds
New Leaf Energy also applauded the proposed storage methodology, along with ISO-NE’s proposal to continue work on late-stage interconnection studies that are projected to be complete by the end of August.
The company echoed the need for additional work to improve interconnection in the region, writing that “the success of the new interconnection process relies, in part, on the timely evaluation of how the new process is working and continuous improvement thereof.”
It recommended that ISO-NE establish an interconnection working group as a formalized setting to continue working on interconnection improvements.
Meanwhile, BlueWave called on FERC to require ISO-NE to follow the original timelines proposed in the order and increase the flexibility for interconnection customers to make changes to their request amid the interconnection process.
While Order 2023 puts a 150-day deadline on each cluster study and an additional 150-day deadline on cluster restudies, ISO-NE has proposed a 270-day deadline for cluster studies and a 90-day deadline for restudies.
“Protracted study timelines are one of the reasons for increased project costs and failures,” BlueWave wrote. “Short study timelines would also result in less queue backlog, fewer restudies and fewer requests for modifications.”
Longroad Energy argued that ISO-NE should expand the eligibility of surety bonds to meet the financial requirements within the interconnection process. ISO-NE has proposed to accept surety bonds only for commercial readiness deposit beginning in 2025.
“Surety bonds are generally easier and less expensive to procure than other accepted forms of financial security,” the renewable developer wrote, adding that CAISO “already accepts surety bonds for generator interconnection customers.”
Glenvale Solar took issue with ISO-NE’s proposed variation regarding study deposits and application fees, writing that the RTO’s proposal of uniform study deposits and application fees is “unduly burdensome and discriminatory to developers of smaller resources.”
The company called on FERC to require the RTO to follow the tiered approach outlined in Order 2023.
The National Highway Traffic Safety Administration on June 7 issued final Corporate Average Fuel Economy (CAFE) standards for U.S. passenger cars and light- and heavy-duty pickups for model years 2027 to 2031, with the goal of cutting gasoline consumption by 70 billion gallons and carbon dioxide emissions by 710 million metric tons by 2050.
The CAFE standard regulates how far a vehicle must be able to travel on a gallon of gas and represents the “maximum feasible level that the agency determines vehicle manufacturers can achieve in each [model year], in order to improve energy conservation,” the final rule says.
The rule sets regular 2% increases in fuel efficiency for passenger cars ― sedans and SUVs ― per year between the 2027 and 2031 model years, rising from 60 miles per gallon in 2027 to 65.1 mpg in 2031, the same as set in the proposed CAFE standards NHTSA issued in July 2023.
But the final standards for light- and heavy-duty pickups are less stringent than the proposed rules. A 2% fuel efficiency increase for light-duty pickups will not go into effect until 2029, starting at 42.6 mpg in 2027 and 2028, then rising to 43.5 mpg in 2029 and hitting 45.2 mpg in 2031. (See NHTSA Proposes 66.4-mpg Fuel Efficiency for Passenger Cars by 2032.)
The current CAFE standards are 48.7 mpg for passenger cars and 35.2 mpg for light-duty pickups, according to NHTSA, and are set to rise to 58.1 mpg and 41.5 mpg, respectively, in 2026.
The CAFE standard for heavy-duty pickup trucks and vans ― weighing between 8,501 and 14,000 pounds ― is measured in the gallons required to drive 100 miles. The new standards cover the 2030 to 2035 model years and are slightly less rigorous than those in the proposed rule. For example, the 2030 standard in the final rule is 4.503 gallons per 100 miles versus 4.427 gallons in the proposed rule.
The NHTSA notes “real-world fuel economy is generally 20 to 30% lower than the estimated required CAFE level” and that some automakers are “over-complying” with the standards due to electric vehicles in their fleets achieving higher anticipated levels of fuel efficiency than required. The potential “achieved” 2031 efficiency for passenger cars could be 70.8 mpg versus the 65.1 mpg that is required.
But the NHTSA says some manufacturers are not complying with existing CAFE standards for light trucks and are choosing to pay resulting penalties. According to the manufacturers, “they cannot stop manufacturing large fuel inefficient light trucks while also transitioning to manufacturing electric vehicles,” and the NHTSA says it will no longer require them to pay penalties.
The final rule also stresses that the standards are “footprint target curves for passenger cars and light trucks … [which] means that the ultimate fleet-wide levels will vary depending on the mix of vehicles that industry produces for sale in those model years.”
But the NHTSA said in its announcement that it “does not consider electric and other alternative fuels when setting standards; manufacturers may use all available technologies ― including advanced internal combustion engines, hybrid technologies and electric vehicles ― for compliance.”
Administration officials framed the final standards as a win-win for consumers economically and environmentally.
“Not only will these new standards save Americans money at the pump every time they fill up, they will also decrease harmful pollution and make America less reliant on foreign oil,” Transportation Secretary Pete Buttigieg said in the NHTSA press release.
Buttigieg estimated $600 savings on gasoline over the lifetime of a vehicle.
“When Congress established the Corporate Average Fuel Economy program in the 1970s, the average vehicle got about 13 miles to the gallon,” NHTSA Deputy Administrator Sophie Shulman said. “These new fuel economy standards will save our nation billions of dollars, help reduce our dependence on fossil fuels and make our air cleaner for everyone. Americans will enjoy the benefits of this rule for decades to come.”
EPA vs. CAFE
Based on 2022 figures from EPA, the transportation sector pumps out the largest portion of U.S. greenhouse gases ― 28% ― with light-duty vehicles accounting for 57% of that total.
While President Joe Biden wants 50% of all new car sales to be electric by 2030, the impact of the CAFE standards on transportation electrification is an open question.
The final standards were developed to complement EPA’s recent update to limits on vehicle tailpipe emissions, which EPA Administrator Michael Regan hailed as “the strongest vehicle pollution technology standard ever finalized in the United States.”
The EPA rule could also cut total CO2 emissions by 7.2 billion MT by 2054, more than 10 times the estimated reductions for the NHTSA standard.
The NHTSA takes a more incremental view, stating that “although the vehicle fleet is undergoing a significant transformation now and in the coming years, for reasons other than the CAFE standards, … a significant percentage of the on-road (and new) vehicle fleet may remain propelled by internal combustion engines (ICEs) through 2031.”
Rather, NHTSA argues, “The final standards will encourage manufacturers producing those ICE vehicles during the standard-setting time frame to achieve significant fuel economy, improve energy security, and reduce harmful pollution by a large amount.”
Just days before the release of the NHTSA rule, Toyota, Subaru and Mazda made a joint announcement that they had each committed to developing new ICEs that are smaller and more energy efficient and will use alternative fuels ― such as synthetic and biofuels and liquid hydrogen ― to cut their carbon emissions to zero.
John Bozzella, CEO of the Alliance for Automotive Innovation, noted the alignment between the EPA and NHTSA standards. “The left hand knew what the right hand was doing,” he said, in astatement on the organization’s website.
But Bozzella also questioned whether the U.S. will need CAFE standards in the future “in a world rapidly moving toward electrification.”
”CAFE’s a relic of the 1970s ― a policy to promote energy conservation and energy independence by making internal combustion vehicles more efficient,” he said. “But those vehicles are already very efficient. And EVs? They don’t combust anything. They don’t even have a tailpipe!”
Stakeholders Endorse Revisions to CIR Transfer Issue Charge
VALLEY FORGE, Pa. — The PJM Planning Committee last week endorsed revising an issue charge focused on how capacity interconnection rights (CIRs) may be transferred from a deactivating generator to a new resource.
The issue charge seeks to solve the misalignment between the transfer process, which is tied to phases of the interconnection queue, and recent changes to the interconnection process. (See “Stakeholders Discuss Change to CIR Transfer Issue Charge,” PJM PC/TEAC Briefs: April 30, 2024.)
The endorsed change rewrites the out-of-scope language to prohibit changes to the process for transferring CIRs to replacement resources interconnecting to the same substation as the deactivating generator but at a different voltage level. It previously prohibited changes for when the replacement located at a different point of interconnection.
The revisions also shift the working group from the Interconnection Process Subcommittee to the PC to accommodate the wider scope. The issue charge was cosponsored by East Kentucky Power Cooperative and Elevate Renewables.
CIFP Manual Revisions Endorsed
Stakeholders endorsed a slate of manual revisions codifying PJM’s new approach to risk modeling and accreditation drafted through the Critical Issue Fast Path (CIFP) process last year and approved by FERC in January. (See “First Read on CIFP Manual Revisions,” PJM PC/TEAC Briefs: April 30, 2024.)
The changes include how PJM will use its marginal effective load-carrying capability (ELCC) framework for accrediting all generation resources, the simulation of resource outputs and the definition of the capacity emergency transfer objective (CETO), which sets the import capability needs to meet reliability objectives. The revisions also include several calculations used in accreditation and for setting capacity procurement targets through the Reserve Requirement Study (RRS).
Manuals 20, 21 and 21A would be replaced with Manuals 20A and 21B beginning with the 2025/26 delivery year, while Manual 14B would remain with language changes. The Markets and Reliability Committee is set to consider endorsement of changes on June 27 alongside a rewrite of Manual 18 to effectuate changes on the markets side. (See “Stakeholders Endorse Manual Revisions to Implement CIFP Changes to Capacity Market,” PJM MIC Briefs: May 1, 2024.)
Preliminary ELCC Class Ratings
PJM presented a preliminary set of ELCC class ratings projected through the 2034/35 delivery year that show declining values for renewable and storage resources and fairly stable or increasing ratings for fossil generation.
Offshore wind is hit particularly hard, with its class rating expected to go from 61% in 2026 to 20% in 2034. Onshore wind is projected to fall from 35% to 15%.
PJM presented preliminary effective load-carrying capability (ELCC) ratings for several capacity resource classes, which showed wind ratings decreasing through 2034. | PJM
PJM’s Patricio Rocha Garrido said the decline in wind generation ratings was driven largely by the hours of risk being increasingly concentrated on days when wind performance is projected to be low. Much of that data is derived from the 2014 polar vortex on Jan. 7 and 8, as well as low performance hours on Dec. 26, 2022, during Winter Storm Elliott.
As the amount of wind generation on the grid increases, Rocha Garrido said, the resource class is able to meet the need on a wider number of days. That in turn concentrates the risk that remains onto winter days with low wind performance.
Solar ratings similarly are being driven down by increased winter risk matching up poorly with times of peak solar availability. Tracking solar has a rating of 11% in 2026 dropping, to 4% in 2034, while fixed solar falls from 7% to 3%.
The longer duration of winter events also also a factor for declining ratings of shorter-term storage resources. Four-hour storage falls from 56% to 38% over the years analyzed, while six-, eight- and 10-hour storage see less significant drops.
While both coal and nuclear generation saw modest declines in their ELCC ratings, gas-fired resources saw upticks owing to risk patterns swaying toward days when they have stronger performance. Combustion turbines fared particularly well, increasing from 61% to 78%.
PJM spokesperson Jeff Shields said the increased gas generation ratings are from increased winter performance since the 2014 polar vortex and the pattern of risk shifting to days when other resources do not perform as well.
“The gas CT ratings increase because the risk shifts to winter days with poor wind performance in which the gas CT performance is not as low as during days such as the first polar vortex. Therefore, you can argue that the increase is driven by risk shifts that are caused by better gas CT performance, and other resources — wind, in particular — performing worse,” he said.
Rocha Garrido said the assumptions for the projections included using the 2025/26 delivery year assumed resource portfolio as a basepoint and modeling retirements and new entry using a vendor forecast. That includes growth in the wind, solar, four-hour storage and solar-storage hybrid classes, as well as coal generation deactivations.
PJM Pushes Pause on LTRTP to Focus on 1920
PJM plans to hold off on advancing its long-term regional transmission planning (LTRTP) proposal and shift its focus to its compliance filing for FERC Order 1920, which requires RTOs to develop scenario-based planning processes on a 20-year horizon. (See FERC Issues Transmission Rule Without ROFR Changes, Christie’s Vote.)
The PC endorsed the LTRTP approach in March, but deliberations were deferred at the MRC in April to see how it measured up against the commission’s long-awaited order. (See “Stakeholders Defer Vote on Long-term Planning Proposal,” PJM MRC Briefs: April 25, 2024.)
PJM’s Jason Connell laid out several differences between the LTRTP design developed over the past year and Order 1920’s requirements, which include at least one extreme weather scenario, “plausible” and “diverse” scenarios, and a wider range of planning factors. While the LTRTP would implement a 15-year planning horizon, the order requires at least 20 years, and the two reliability and policy scenarios PJM proposed fall short of the minimum of three scenarios the commission required.
“There is quite a bit of deviation between what we proposed and the order,” Connell said.
Presenting the Natural Resources Defense Council’s perspective on the differences, Senior Advocate Tom Rutigliano said the first year of PJM’s proposed LTRTP timeline involved building scenarios, work that could be done in parallel with preparing the compliance filing. Waiting until compliance is approved by FERC likely would result in delaying implementation until the fourth quarter of 2026. Laying some of the groundwork in scenario design ahead of time could shave a year off implementation and begin addressing PJM’s long-term resource adequacy concerns faster, he argued.
“This needs to start sooner, so what we’ve got here is work that can be done in parallel,” Rutigliano said.
Connell said PJM’s goal is to move quickly and bring manual revisions to stakeholders within a few months detailing how it will initiate the assumptions phase of a larger long-term planning effort. The revisions also may include starting on the analysis phase as well while the compliance filing is prepared and pending at the commission.
Transmission Expansion Advisory Committee
NJ BPU Pausing 2nd SAA Competitive Window for Offshore Transmission
The New Jersey Board of Public Utilities has suspended the second State Agreement Approach (SAA) competitive transmission solicitation window, which PJM was planning to administer in July.
Ryann Reagan, wholesale market policy specialist for the BPU, told the Transmission Expansion Advisory Committee that the board’s timeline no longer aligned with the 2024 Regional Transmission Expansion Plan (RTEP) cycle. The amount up in the air with regional transmission planning and offshore wind also contributed to the decision, she said, pointing to the board’s work updating the state’s Energy Master Plan and Offshore Wind Strategic Plan.
Reagan said it’s hard to see where the state’s offshore wind goals could align with PJM’s planning processes until there is more clarity around the LTRTP and Order 1920.
The board intends to move forward with its fourth and fifth solicitations for offshore wind generation, with awards likely prior to the transmission planning being completed.
Deactivation Request Update
Two generators have filed for deactivation over the past month, PJM’s Michael Herman told the TEAC.
J-Power USA Generation is seeking to bring nine gas-fired turbines in the ComEd zone offline in June 2025, while AES submitted a deactivation request for a 5-MW battery located at its Warrior Run cogeneration plant.
PJM also is in the process of studying a deactivation request for Cogentrix’s Elgin generator, which has four gas turbines amounting to 483 MW. Reliability analysis is set to begin in the third quarter of this year, Herman said.
IEC Remains on Hold
PJM’s Nick Dumitriu said the RTO’s annual re-evaluation of market efficiency projects recommended leaving Transource Energy’s Independence Energy Connection (IEC) project on suspension because of poor cost-benefit results and possible reliability violations. The PJM board voted to suspend the project on Sept. 22, 2021. (See “Transource Update,” PJM PC/TEAC Briefs: Oct. 5, 2021.)
The two-pronged project seeks to alleviate congestion on the AP South Interface by building about 20 miles of lines between a new Furnace Run substation in York County, Pa., and Harford County, Md. The western portion would consist of a 230-kV double-circuit transmission line running 28.8 miles from Franklin County, Pa., into Washington County, Md.
Dumitriu said the project would reduce congestion on AP South by $84.97 million by 2033, along with reducing congestion by about $41 million on a series of other constraints, but a new $341.72 million constraint would be introduced on the 230-kV Ringgold-Frostown Junction line.
PJM’s Tim Horger said an update on the project’s future is planned for next month.
Supplemental Projects
American Electric Power proposed a $155.7 million project for a new service request to serve 1,100 MW of load in New Carlisle, Ind., expected to come online in December 2026.
The project would consist of two new 345-kV substations, Larrison Drive and New Prairie, cut into the Elderberry-Dumont and Dumont-Olive Bypass lines. End work also would be conducted on the Sorenson, Elderberry and Dumont substations.
PPL presented a new service request expected to interconnect 240 MW in 2026 and grow to 1,980 MW by 2033. The customer, located in Hazleton, Pa., would be served by a 230-kV source.
PECO Energy presented a $36 million project to rebuild its 6.24-mile, 230-kV Planebrook-Bradford line, which the utility said is nearing end of its life at 96 years old.
The utility also proposed a $17 million project to rebuild its nearly 100-year-old, 69-kV Tacony substation and install new equipment to upgrade it to 230 kV. Inspection of the site has found that equipment is in poor condition and cannot be repaired.
Duke Energy Ohio & Kentucky proposed a $7.8 million project to replace nine 345-kV oil-operated breakers at its Woodsdale substation because of maintenance issues. The project would install gas-filled circuit breakers, replace 17 switches and replace all bus conductor.
Duke also presented a new service request for a customer near Mount Orab, Ohio, seeking to interconnect 2,000 MW by 2029.
FirstEnergy presented a $9.8 million project to convert its 230-kV Milesburg substation, located in the APS zone, from a straight bus to a four-breaker ring bus. It said maintaining the existing configuration elevates outage risks for 3,116 customers with 107.6 MW of load if the facility experiences a single stuck breaker contingency.
Dominion Energy presented several projects to interconnect data center load in Northern Virginia totaling $57 million.
A new 230-kV Sloan Drive substation would be built for $30 million, which includes building two 230-kV lines to the future Bermuda Hundred substation. The substation has an projected in-service date of Dec. 31, 2027, and would serve more than 100 MW of data center load.
The utility proposed cutting into the 230-kV Techpark Place-White Oak line to build a new “Decoy Airfield” substation serving 100 MW of data center load. The new substation would cost an estimated $12 million to build with an in service date of Jan. 1, 2026. A $15 million project would tap the 230-kV ICI-Allied line to connect to the new Bermuda Hundred facility.
Additional Parameters for Demand Response Endorsed
VALLEY FORGE, Pa. — PJM’s Market Implementation Committee endorsed by acclamation a proposal to add two energy market parameters for economic demand response. (See “First Read on Proposed Demand Response Energy Market Parameters,” PJM MIC Briefs: May 1, 2024.)
The changes would allow DR providers to set a cap on how long they can be dispatched and a minimum interval before they can be committed again after being released from a previous dispatch.
FERC last July approved a PJM proposal to tighten performance assessment interval triggers, allowing pre-emergency demand response to be deployed without prompting a full capacity call for all resources. (See FERC Approves PJM Change to Emergency Triggers.)
PJM’s Pete Langbein offered an amendment to the proposed Manual 11 revisions to state that energy market parameters cannot supersede a load management deployment in the capacity market, a stipulation he argued already is reflected in the status quo language.
Langbein gave the example of a DR resource that had been released from an energy market commitment and was in the middle of a minimum release time when it was called on for capacity. If that resource did not respond and followed its energy market parameter, it could be subject to Capacity Performance (CP) penalties and testing requirements.
PJM plans to ask the Markets and Reliability Committee for endorsement at its Aug. 21 meeting, followed by the Members Committee on Sept. 25 and a FERC filing in October. The filing likely would ask for a sixth-month implementation period.
PJM to Refile Portions of Rejected CIFP Proposal
PJM laid out its plan to refile several components of its Critical Issue Fast Path (CIFP) proposal rejected by FERC in February, which focused on the CP construct and market seller offer caps (MSOC). (See FERC Rejects Changes to PJM Capacity Performance Penalties.)
PJM’s Walter Graf said the components selected for refiling were those that order rejecting the order either indicated support or did not touch on. For items where PJM received minimal feedback from the commission, Graf said PJM’s future filing is likely to be fairly similar.
The proposal includes “clarifying revisions” to the definition of Capacity Performance quantified risk (CPQR), MSOC values for planned generation based on net cost of new entry (CONE), segmented offer caps, and a forward-looking energy and ancillary service (EAS) offset for offer caps and the minimum offer price rule (MOPR).
The proposal would allow generators that intend to participate in the energy market regardless of whether they clear in the capacity market to offer into Base Residual Auctions (BRAs) at least as high as their capacity performance quantified risk (CPQR) value.
In its October 2023 transmittal letter, PJM said allowing generators likely to remain in operation regardless of their position in the capacity market would avoid over-mitigating market sellers with a low or negative avoidable cost rate (ACR). The filing argued that the status quo market seller offer cap (MSOC) prevents some market sellers from fully representing their costs to deliver capacity — a dynamic it said could be leading some resources not subject to the must-offer requirement to avoid participating in the capacity market entirely.
PJM does not plan for the refiling to include many of the core changes addressed in its original filing, such as limiting bonus payments for generators that overperformed during emergency conditions to only committed capacity resources, excusing generators whose price-based offers exceeded their cost-based offers from CP penalties and third-party review of unit-specific MSOC proposals.
PJM is not including a process for calculating alternative offer caps if it determines that a market seller’s proposed MSOC did not conform to the tariff as it awaits a FERC ruling on its rehearing request. The refiling also will exclude an element of PJM’s original proposal to remove the physical penalty option for fixed resource requirement entities. The PJM Power Providers (P3) and Electric Power Supply Associated (EPSA) have jointly requested rehearing on that element of FERC’s rejection of ER24-98.
PJM is not seeking to move forward with a standardized CPQR calculation because the specificity the commission sought would be difficult to uniformly produce across resource classes, Graf said. But he added that the calculation PJM proposed to use could be used by market sellers to aid in their own CPQR proposals.
Exelon’s Alex Stern said he’s glad PJM is reviewing the commission’s rejection order because the resource adequacy concerns which prompted the filing have only grown over the past year.
Energy Efficiency Proposals Deferred While Complaint Pending
Aaron Breidenbaugh, of CPower, said he understood that the EE providers named in the complaint have been counseled to avoid discussing issues raised in the filing until the issue has been resolved. Because the filing argues that mid- and upstream EE programs have not met the Reliability Pricing Model (RPM) participation requirements, he said the complaint overlaps with the very issue before the MIC.
Affirmed Energy’s Luke Fishback said the company withdrew its package from the June 5 agenda because it would be unproductive to engage with discussions about potential revisions to M&V requirements while the complaint about existing standards is pending.
Exelon’s Alex Stern said the pending complaint can’t help but “put a chilling effect on not only these stakeholder discussions but also EE generally.”
PJM Associate Counsel Chen Lu said he thinks the complaint is limited to the validity of post-installation measurement and verification (PIMV) reports filed for the 2024/25 delivery year and therefore would not clash with discussion about future M&V design.
Marji Philips, of LS Power, rebuked PJM for a communication sent to EE market participants on May 31, which said the RTO will be delaying action on PIMV reports until the complaint has been resolved, effectively holding up all EE revenues in the process. She said the complaint is an allegation that must be substantiated before PJM can take action through a deficiency process in accordance with a FERC order.
“It’s completely violative of any FERC procedure,” she said. ” … You don’t take an action based on a filed complaint.”
Responding to questions about the implications of the PIMV delay for EE providers, Lu said no payments are made and prospective market participants are not subject to deficiency charges until PJM has makes a determination on the reports. If the reports were rejected, he said, entities would be considered unavailable during the delivery year and subject to deficiency charges.
Langbein said PJM is reviewing the May 31 communication and plans to send out an update on how it intends to proceed with the PIMV reports and EE payments.
PJM Presents Revised CONE Values
The Brattle Group presented revised financial parameters used to calculate net CONE for the 2026/27 Base Residual Auction (BRA).
Net CONE is one of the inputs used for defining prices on the Variable Resource Requirement (VRR) curve. (See “Update Re-evaluation of CONE Inputs,” PJM MIC Briefs: May 1, 2024.)
PJM in April proposed reviewing the financial inputs to net CONE to account for shifting market conditions since the 2022 Quadrennial Review. Increasing interest rates were among the major contributors, PJM’s Skyler Marzewski said. The change is being pursued through the quick fix process, which allows an issue charge to be brought and voted on concurrent with a proposed solution.
“We’re trying to make sure net CONE would be better aligned with the financial conditions that we’re currently seeing,” Marzewski said.
Brattle recommended increasing the after-tax weighted-average cost of capital (ATWACC) from the 8.85% used in the quadrennial review to 10%, which increases the cost to construct a combined cycle resource — currently the reference resource — by $15 to $18/kW-year. The cost of combustion turbines increased by $10 to $12/kW-year and battery electric storage systems by $18 to $20/kW-year.
Given market volatility, Brattle’s Bin Zhou recommended adjusting the financial parameters for at least the next few auction cycles.
Responding to stakeholder questions about how the review was conducted, Brattle’s Sam Newell said it relied on the same study approach as the quadrennial review.
Marzewski said Brattle also is considering whether PJM needs to reconsider the overall cost for a new resource, with preliminary analysis suggesting there’s no need at this time. Newell encouraged market participants to reach out to Brattle with any specific market information to assist its reevaluation of financial parameters or cost indexing. Increased turbine prices could be one such data point, he said.
Stakeholders Discuss Path Forward on Multi-Schedule Modeling
PJM intends to move forward with an alternative solution for selecting schedules in the market clearing engine (MCE) to facilitate its multi-schedule modeling design, which is expected to significantly increase computing times under the status quo schedule selection approach. (See “Stakeholders Endorse Multi-schedule Modeling Solution,” PJM MRC/MC Briefs: Dec. 20, 2023.)
FERC in March rejected the multi-schedule modeling proposal endorsed by stakeholders in December 2023. That package would have introduced a formula to evaluate generators’ offers and select one expected to produce the lowest total dispatch cost and forward only that offer to the MCE.
The commission rejected that proposal, citing the “crossing offer curves” scenario the Monitor raised, under which PJM’s proposed formula would select market-based offer based on its dispatch cost at EcoMin even if it would be notably more expensive than a cost-based offer at higher outputs.
“PJM’s proposal would largely eliminate market power mitigation in the day-ahead Energy Market by selecting for consideration in PJM’s market clearing optimization software a single offer per resource solely on the lowest dispatch cost at EcoMin … it would no longer mitigate a seller’s offer to the offer producing the lowest total production cost by considering the entire offer curve for each of a seller’s offers,” the commission wrote.
PJM’s Keyur Patel said the RTO planned to advance the MIC proposal co-sponsored by PJM and the GT Power Group, which received the second-highest degree of support during an October 2023 vote. That proposal attempts to address the crossing curves issue by selecting market-based offers only when a resource passes the three pivotal suppliers (TPS) test under non-emergency conditions and select cost-based offers only when a resource fails the TPS test.
Several stakeholders took issue with presenting a proposal that was voted on months in the past as the presumptive motion to advance at the MRC. It was suggested a proposal sponsored by the Monitor during last year’s deliberations should be considered at the MRC as well and the truncated voting rules waived to allow the two to be voted on side-by-side.
PJMpresented the Operating Committee last week with a set of revisions to Manual 12 regarding fuel assurance requirements for black start resources.
The RTO said the language approved June 6 was included in the package the OC advanced two years ago but inadvertently was excluded from manual revisions approved by the Markets and Reliability Committee in November 2022. (See “Black Start Fuel Requirements Advance to Members Committee,” PJM MRC Briefs: Oct. 24, 2022.)
The effort established a new category of “fuel-assured” generators and required at least one such unit to be committed in each transmission zone. The criteria to qualify as a fuel-assured unit vary based on resource type, including connections to multiple interstate gas pipelines, on-site fuel storage and dual-fuel capability.
The latest manual revisions create an exception to allow fuel-assured black start resources to avoid penalties if they fall below mandated consumable storage levels because they responded to a performance assessment interval (PAI) or if the storage vessels were taken out of service for regulatory inspections.
The changes also remove a fuel assurance notification requirement from Manual 12 and replace it with a stipulation that generators must provide verification they have adequate fuel and consumables upon PJM request, along with an annual verification requirement in the black start test form.
The language is set to go before the OC for an endorsement vote July 11 and the MRC on July 24.
PJM Details Temporary Exception Submission Process
PJM’s Lauren Strella Wahba presented the process for market participants to submit temporary exceptions in Markets Gateway once software updates go live Aug. 1.
The “Daily” and “Real Time Temp Except” fields have been used as an interim solution since FERC approved PJM’s real-time temporary exception design last November. (See “Stakeholders Endorse Real-time Temporary Exception Manual Revisions,” PJM MIC Briefs: Feb. 7, 2024.)
Rather than submitting supporting documentation to PJM by email, the “Exception” page of Markets Gateway will have buttons for uploading documents, though the email option will remain as a fallback.
Market participants withdrawing an active temporary exception will be required to first restore their cost-based and price parameter-limited schedules.
PJM Reviews May Operating Metrics
Inaccurate weather forecasting caused several days of high load forecast error in May, PJM’s Marcus Smith told the OC. Conditions were warmer than expected between May 16 and 21, which follows a trend of load forecasts becoming highly sensitive to numerous variables when temperatures are around 70 degrees Fahrenheit.
The May average hourly forecast error was 1.51%, with an average peak error of 1.81%, falling near the 25-month average for both figures.
PJM presented the daily peak forecast error for May 2024 to the Operating Committee. | PJM
The month saw one shared reserve event, a high system voltage action, a geomagnetic disturbance (GMD) action and 20 post-contingency local load relief warnings (PCLLRWs).
PJM’s Kevin Hatch said the GMD action was in effect May 10 and 11 after two transformers were in violation for 10 minutes. Geomagnetically induced current (GIC) was seen on multiple transformers, and two reactive control devices tripped offline.
While increased geomagnetic activity was seen for a week after May 10, Hatch said the action was not needed for the entirety of the period and the grid experienced no major impacts.
Rising costs of materials and labor and an increased use of H-frame structures as an environmental mitigation have contributed to a $1.755 billion increase in the projected cost of NV Energy’s Greenlink transmission projects.
The costs for Greenlink North and Greenlink West, estimated at $2.484 billion in 2020, grew to $4.239 billion as of May 2024 — a 70.6% increase.
NV Energy disclosed the figures in its 2025/27 integrated resource plan, filed with the Public Utilities Commission of Nevada on May 31.
Of the $1.755 billion cost increase for the Greenlink projects, NV Energy attributed $340 million to the rising costs of materials, equipment and labor.
“Inflation has played a major role,” Shahzad Lateef, NV Energy’s senior project director for transmission development, said in the filing.
The Bureau of Land Management is requiring NV Energy to use an additional 160 miles of H-frame structures to mitigate risk to desert tortoise and sage grouse habitat, an extra cost of $124 million. Shorter span lengths and more expensive materials contribute to a 42% higher cost for H-frame structures compared to the guyed-V lattice structures that were previously planned, according to the filing.
Other environmental mitigations will add about $30 million to Greenlink costs.
Costs have also gone up $252 million because of changes in project scope, NV Energy said, and new estimates have added $101 million in sales and use taxes that previously weren’t included.
‘Vital’ to Renewables
Greenlink West will be a 525-kV line along the west side of Nevada from Las Vegas to the Fort Churchill substation near Yerington. In Northern Nevada, Greenlink North will connect the Robinson Summit substation near Ely to Fort Churchill via a 525-kV line.
The Greenlink lines, combined with the existing One Nevada line, will form a transmission triangle around the state.
“The Greenlink projects are vital to the robust development of renewable resources throughout Nevada as well as low-cost reliability for the growing load,” Ryan Atkins, NV Energy’s vice president of resource optimization and resource planning, said in the filing. “The Greenlink project remains the best alternative to meet [NV Energy’s] future transmission needs despite the cost increases.”
Breaking down the costs by project, cost estimates for Greenlink West have increased from $1.22 billion in 2020 to $1.907 billion. Greenlink North costs have gone from $854 million to $1.490 billion.
And the costs for “common ties” in the project — including a substation expansion at Fort Churchill and 345-kV connecting lines to nearby areas — have grown from $410 million to $841 million.
John Tsoukalis, a principal with The Brattle Group, also provided testimony regarding the Greenlink projects as part of NV Energy’s IRP filing.
Tsoukalis said the Greenlink projects would increase the resilience of the NV Energy system, particularly in the case of an outage of the One Nevada Line.
Greenlink also could increase interconnections with nearby entities, potentially enhancing the benefits of NV Energy’s participation in the Western Resource Adequacy Program (WRAP), Tsoukalis said.
Tsoukalis estimated the Greenlink projects would reduce costs to NV Energy customers by $50.8 million per year. Customer benefits would increase by about $57.3 million a year, as operating costs and purchased power costs declined and off-system sales revenues grew by $38 million a year, he projected.
Those gains would be offset slightly by reductions in short-term wheeling revenues, market congestion revenues and bilateral trading profits.
The next steps in the BLM permitting process for Greenlink West will be publication of the final environmental impact statement, expected this month, followed by a record of decision in August and a notice to proceed in December.
For Greenlink North, BLM is expected to release a draft environmental impact statement in July.
A new paper examines how the electricity sector can properly value distributed energy resources so they can be deployed efficiently as non-wires alternatives to reduce grid operating costs and delay system upgrades.
Published in the latest issue of Electric Power Systems Research, “Valuing distributed energy resources for non-wires alternatives” was written by Nicholas Laws, Michael Webber and Dongmei Chen of the University of Texas’ Walker Department of Mechanical Engineering.
With electricity demand growing because of electrification, population growth and other factors, distribution utilities need to increase overall capacity and upgrade equipment to maintain reliability.
“However, those traditional actions related to the wires and poles of the distribution system might not keep pace with load growth that will accommodate rapid electric vehicle adoption or widespread installation of electric heat pumps as a way to reduce on-site fuel use for space and water heating,” the paper said. “As a consequence, there is an acute need for non-wires alternatives that can be used to improve overall system performance. Some of those alternatives include demand response and distributed energy resources, such as local power generation and/or storage.”
DERs can help meet growing demand at a lower cost than gold-plating the grid, but traditional utility funding models and market signals are not adapted to deploying them properly.
The trick is making it so that DERs and the distribution system both benefit from the investment. DERs can be built to serve a customer’s need without any thought to their impact on the grid, but getting the price signals right can ensure they are available to address overloaded and other problem areas on the system.
“Valuing DER for non-wires alternatives appropriately is a difficult task,” the paper said. “The framework proposed in this work accounts for both the system planner’s perspective and the DER investor perspectives.”
The paper advocates for a “bilevel optimization framework” to minimize system planning costs while ensuring that DER developers get their required rate of returns.
Under FERC Order 2222, which requires all jurisdictional RTOs/ISOs to allow DER aggregations to participate in wholesale markets, system planners will have to work with DER investors to plan efficient distribution power systems.
The paper ran a study of the optimization it proposed on a 20-year lifecycle for some upgrades: including four power lines and three transformers.
Without any DERs or battery storage, it found upgrades would total $8.41 million, which fell to $6.43 million with the utility investing in batteries. While the batteries save money over time, they effectively doubled the upfront costs of the utility.
But paying DERs to do the same avoids the higher capital expenditure from the utility up front and cuts costs over 20 years to just $5.42 million. DERs cut back required grid upgrades to just one line and one transformer — instead of four lines and three transformers — while the batteries still required three lines upgraded and two transformers.
The right price signals can help DERs offset their costs through energy sales, which also lower systemwide power costs, the paper said.
ERCOT stakeholders and staff came to an agreement last week on a rule change that imposes ride-through voltage requirements on inverter-based resources, a result of more than a year’s worth of back-and-forth redlined comments and negotiations.
During a special June 7 conference call, the Technical Advisory Committee endorsed a change to the Nodal Operating Guide (NOGRR245) that aligns ERCOT’s rules with NERC reliability guidelines and the most relevant parts of the Institute of Electrical and Electronics Engineers’ standard for IBRs interconnecting with the grid.
ERCOT’s Board of Directors remanded the NOGRR back to TAC in April, directing the language — approved by the committee over staff’s objections — be modified to address staff’s reliability concerns. (See ERCOT Board of Directors Briefs: April 22-23, 2024.)
A pair of IBR-related voltage disturbances in West Texas in 2021 and 2022, dubbed the Odessa Disturbances, only added urgency to the measure’s eventual passage. (See NERC Repeats IBR Warnings After Second Odessa Event.)
TAC has held a workshop and two conference calls devoted to NOGRR245 since April.
Staff said the revisions in their latest comments, submitted June 5, addressed their concerns and reflected TAC discussions offering compromise on generation interconnection agreements, requiring all IBRs maximize up to the equipment’s full capability. Staff said they will support an exemption process allowing them to assess reliability risk and costs during a review and a one-time exemption process with no after-the-fact exemptions for performance failures or later discovery.
However, staff said they would not support a “subjective commercially reasonable” standard and would only support considering cost during the exemption process if the solution is “clear, objective, quantifiable and repeatable regardless of technology, unique commercial characteristics or plant age.”
(“Commercially reasonable” is defined as terms “conducted in good faith and in accordance with commonly accepted commercial practice.”)
TAC accepted the comments but added gray-box language with potential modifications that would enable entities to meet the applicable ride-through requirements when they have not yet added a “technically feasible” change. The modifications are for those entities where the upgrade costs are less than 40% of the full, in-kind replacement cost of a plant’s inverters or turbines and converters.
Members accepted a friendly amendment to extend the gray-box language’s effective date from August to March 2025.
Speaking for the ad hoc “joint commenters” stakeholder group, Eric Goff said the group’s latest comments represent a “serious and good faith commitment” to making the upgrades. He said their comments have been updated to allow for immediate implementation of the standards and to decouple software and more expensive hardware ride-through considerations.
“We think that this maximization procedure meets ERCOT’s goals. … I think we have the same intention and desires or very similar intentions and desires,” Goff said.
TAC endorsed the NOGRR in an 18-1 vote, with 10 abstentions. Demand Control 2, a member of the retail segment, cast the lone opposing vote. The municipal, retail and power marketing segments accounted for nine of the abstentions.
Demand Control 2 CEO Chris Hendrix told RTO Insider that the joint commenters’ proposal was not posted until the night before the conference call and didn’t allow enough time for full consideration. He also said ERCOT’s 40% threshold for replacement costs was arbitrary, “extremely” high, and didn’t consider the life of generating units or existing contracts.
“Either the threshold should be a lot lower or some aspect of commercial reasonableness added,” he said.
Hendrix motioned to table the change. However, he was unable to secure a second.
TAC members did not celebrate the NOGRR’s passage, although American Electric Power’s Richard Ross did promise to award Luminant’s Ned Bonskowski with one of his Gold Star awards for staying up until 2 a.m. June 7 to compare the ERCOT and joint commenters’ proposals.
“I’ve never received a higher honor in my professional career,” Bonskowski said.
“Don’t forget to put that on your performance review,” Ross replied.
