New Jersey’s Senate voted Dec. 11 to allocate $15 million from the current state budget for the first year of the state’s long-awaited electric school bus program, in one of the final steps needed to launch the pilot program that will test the use of electric buses in six districts each year.
The Senate voted 22 -10 to approve the minor changes to S3044that Gov. Phil Murphy (D) recommended in a conditional vetohe issued Nov. 27, when the bill landed on his desk. Specifically, Murphy suggested the funds come from the fiscal year 2024 state budget, which runs from July 1 of this year to June 30, 2024, rather than the FY 2023 budget, as originally planned.
The Senate’s funding approval follows the Nov. 30 release of a report on the benefits of using electric school buses in New Jersey. Compiled by Environment New Jersey, an environmental group, and ChargEVC-NJ, an electric vehicle (EV) advocacy group, the report highlights the “significant potential” electric buses offer but cautions they “remain a nascent segment despite high expectations.”
Senate and Assembly votes are needed on the final bill with Murphy’s changes added before it goes back to the governor for signing. Final approval would start a pilot initiative that environmentalists and EV advocates have long urged the state to embrace more quickly due to its potential impact in cutting emissions.
Transportation is New Jersey’s largest source of greenhouse gas emissions, and very few of the state’s estimated 21,000 school buses — which range from Class 2 buses to heavy-duty Class 8 buses —are electric.
Murphy signed a bill, A1282, creating the three-year, $45 million program on Aug. 4, 2022, expecting the legislature to pay the first year of funding from the state’s 2023 general fund. When that allocation was not made, the program remained unfunded. (See Electric School Bus Pilot Awaits NJ Governor’s Signature.)
A1282 requires the New Jersey Department of Environmental Protection (DEP) to create a pilot program under which six districts or contractors each year would transport students to school in electric buses to assess the reliability and effectiveness of using them in place of diesel-powered vehicles.
The performance of the buses would be evaluated on factors such as cost, maintenance, fuel use and speed, and data would be collected and submitted to the DEP. At least half of the districts or contractors would be in low-income, urban or environmental justice communities.
Comparing Costs
The report, “Electrification of New Jersey’s School Buses,” lays out the opportunities and barriers that could affect the pilot program.
The report says electric buses would cut school bus emissions by 74.7% but would not lower emissions to zero as long as some of the electricity powering the vehicles comes from fossil fuel generators. Fuel and maintenance cost savings from running electric buses would be significant, cutting those expenditures statewide by 61.4% or $202.3 million, the report says.
However, the picture on the total cost of ownership (TCO) — the cost over the entirety of the life of an electric bus —is “challenging,” the report says. The “higher up-front costs” of electric vehicles over diesel- or gasoline-fueled vehicles can be mitigated by operational savings. But whether electric buses can compete overall on costs with internal-combustion-engine (ICE) buses depends on several factors, including whether the bus is used for short or long trips, how costs decline in the future and the availability of incentives, the report says.
At current cost levels, EV school buses can “approach parity” with ICE buses only on longer runs, during which the bus uses more fuel. The higher cost of fossil fuel drives up the cost, the report says.
At current costs, an electric bus used on short runs would need an incentive of $143,000 to achieve total ownership cost parity with a diesel bus, and a subsidy of $192,000 to reach parity with a gasoline bus, the report says. For electric buses used on long runs, the incentive would need to be $39,500 to reach parity with a diesel vehicle and $98,500 to reach parity with a gasoline-fueled bus.
If, as some analysts predict, electric bus purchase costs come down in the future, electric buses will be able to compete on short, average-length and long bus routes, the report says. For example, if battery costs are “reduced in 2030 by as much as 50%”, the up-front cost of an electric school bus could be on a “par” with fossil-fueled vehicles, the report said.
In addition, bus operators could reap income from vehicle-to-grid (V2G) revenue by tapping bus batteries to feed energy back to the grid to help address demand peaks, the report says. Electric school buses are well-placed for such demand management efforts because their use profiles are specific and predictable. School buses sit unused for much of the day and are used minimally during the summer months, the report says.
Researchers found the dollar value of such use is not clear, however, with estimates ranging between $500 and $15,000 a year per bus, the report says.
WASHINGTON — As utilities and regulators face unprecedented growth in power demand — from data centers, chip and other clean tech manufacturing, and building and transportation electrification — figuring out how to plan and finance distribution systems has become a similarly fast-moving target, according to speakers at the GridWise Alliance gridCONNEXT conference.
The industry now faces a “trilemma,” attempting to balance decarbonization, reliability and affordability, said Peter Fox-Penner, partner and chief impact officer at Energy Impact Partners (EIP), a clean tech investment firm funded by utilities.
“There are many related challenges of decarbonizing supply, doubling the size of the grid, while … incorporating AI, severe weather, institutional distrust and other things,” Fox-Penner said during a Dec. 6 panel on how to draw more, and more diverse, investment into grid expansion.
The effects of extreme weather, exacerbated by climate change, also are becoming a major challenge to the economic viability of utilities, he said. Citing figures from a recent analysis from Fitch, Fox-Penner noted that extreme weather events caused close to one quarter of the rating agency’s downgrades for utilities between 2018 and 2023 (year to date) versus none in the previous five-year period.
A shift is needed in the industry’s and consumers’ understanding of affordability, away from cost per kilowatt-hour on electric bills toward “wallet-share,” the amount households spend on electricity “versus everything else,” he said.
While electric rates certainly have been hit by inflation, wallet-share is at 1950s levels and even fell slightly in 2022, he said. “Affordability is a tremendous challenge … because of the macro environment we’re operating in, rather than the fact that electricity remains an incredible value.”
Prices will come down with new and better technologies for electrifying transportation and buildings, he said.
A paradigm shift also is needed in utilities’ approach to distribution planning, which typically runs in two- to five-year cycles, with system upgrades made incrementally, on an as-needed basis, said Jeff Smith, director of transmission and distribution operations and planning at the Electric Power Research Institute (EPRI).
“But if we keep doing that sort of incremental approach, will that lead us to a suboptimal location later down the road? … Is that something we’re going to regret doing by 2040, 2050?” he said.
Working with the Department of Energy and utilities, EPRI is trying to ask different questions, Smith said during a panel on distribution planning. The goal here is to “take that long-term look and identify the grid service needs, the grid design requirements, the operating requirements that are necessary for deep decarbonization,” he said.
Industry stakeholders and their concerns appear endlessly complex, Smith said — how many transformers will be needed, when and how to introduce time-of-use rates, how to integrate storage — “but we can’t let analysis paralysis stop us from moving forward. … The needs of the grid are changing at a pace we’ve never seen before.”
Distribution system design and projections of load growth typically have been based on historical information, Smith said. “We need to start looking to the future. … Our loads are changing, demand is changing, the shapes are changing, the flexibility of resources are changing. How does that change actually [affect] our design?”
Larry Bekkedahl, senior vice president for advanced energy delivery at Portland General Electric (PGE), also called for a closer focus on load, rather than the typical industry focus on generation capacity.
“You’ve really got to move and advance yourself to pick up these loads,” Bekkedahl said, noting the Portland area is producing 15% of all the computer chips manufactured in the U.S., with more chip plants and data centers on the way.
“When I think about our load, we right now have over 2 GW of requests on a 4.5-GW system,” he said. Demand is growing at 4% a year, versus a previous rate of about .5 to 1% a year.
“How do you plan for that? Because there’s a lot of two-way, bidirectional energy that’s going to be happening on the distribution side,” Bekkedahl said. “What we’re trying to do is bring the peaks down and push utilization up. That’s our motivation, and we want to use the system we have as much as possible but drive those peaks down wherever possible.”
Retrofit Everything Everywhere
The speed of change and its impacts on the electric power industry were core themes for both panels.
Fox-Penner sees “two distinct waves of [load] growth that are different in nature.” In the near term, artificial intelligence, cryptocurrency and other high-tech applications will produce “very lumpy” demand curves, while transportation and building electrification will take longer, but drive bigger growth, he said.
“It’s worth keeping those two things in mind, I think, because the policy responses … and the forecasting techniques we want to use are different,” he said.
They also will draw different investors, said Karen Wayland, CEO of the GridWise Alliance, noting that high-tech companies — such as Google and Microsoft — are pouring major investments into clean energy for their data centers. But the cost of building and transportation electrification likely will fall on utilities and their customers.
Wayland also said she believes the industry has the technology to meet anticipated load growth and is “looking in both the right places. We’re looking [at] developing utility scale. We’re looking for local resources.”
Phil Dion, senior vice president for customer solutions at the Edison Electric Institute (EEI), the industry trade group for investor-owned utilities, said he believes utilities will prioritize investments in familiar, low-risk priorities — retrofitting “everything we have as fast as possible,” energy efficiency and demand-side management and flexibility.
“The idea of building transmission lines is imperative, but it’s a way up. It’s a decade away,” Dion said. “So, we need to be investing in technologies, anything we can do to squeeze 10% more [electricity] out, without compromising safety.”
Wallet-share notwithstanding, consumers’ perceptions of power affordability may affect utilities and regulators’ willingness to invest in the infrastructure needed to electrify everything, everywhere, he said.
The cost of expanding distribution will fall primarily on utilities — and require regulatory approval — Dion said, so, “if we don’t start leveraging other piles of capital, this is going to be a problem.”
DOE’s Grid Resilience and Innovation Partnerships program — which recently awarded $3.46 billion for transmission and distribution system upgrades — is a step in the right direction, he said, but more money will be needed, including “leveraging customer capital as well.”
Smith argued for a focus on right-sizing distribution systems, since under- or over-sizing could result in added expense and underused or stranded assets. Right-sizing also means making sure infrastructure is built in the right location, at the right time, he said.
Challenges ahead include figuring out “how do we actually make a substation expandable … sizing them appropriately for the future” and making decisions about primary voltage levels, he said. Voltage levels range from 4 kV to 34.5 kV, with most utility distribution systems in the U.S. working at 15 kV.
“The questions we need to be asking ourselves is, for 2050 [clean energy goals], is 15 kV going to get us there?” Smith said. At 34.5 kV, “you can serve much more customers from a [distributed energy resource] and load perspective, and that’s why so many utilities are looking at maybe dual voltage transformers, recognizing that the voltage they’re using now isn’t something they’re going to use later down the road.”
‘Every Ounce of Flexibility’
As presented by Bekkedahl, PGE is a case study in the challenges utilities face in distribution planning in an extremely fast-changing energy landscape.
The utility was able to ride out Oregon’s asphalt-melting heat wave in the summer of 2021, just barely, he said. “We hit saturation; there was nothing else to turn on. We hit a flat peak … and we were kind of stunned by it, and we survived it, and the next summer, when it’s 95 degrees, we were almost at the same level because everybody went out and bought air conditioners.”
PGE has shifted from a winter-peaking to a summer-peaking system, and it also has been contending with south-to-north, very cheap energy flows from California, requiring quick curtailment of that power at the state border to protect the utility’s distribution system from overload, Bekkedahl said.
“If you’re in a dispatch room and you’ve got this big red screen in front of you that’s saying you’ve got to start curtailing customers, you’ve got to do something,” he said. PGE was able to call on 90 MW of demand response to shave its peak, which “made the difference in that moment. So, I want every ounce of flexibility I can get in the future.”
Looking ahead, Bekkedahl outlined the “big five” must-haves for successful distribution planning, beginning with visibility.
“You’ve got to be able to see into [the system] and think about the influence that you have,” he said. “If you don’t have visibility into your distribution system, none of this works. You’re going to build your plan, it’s going to be for the peak, it’s not going to be something that’s flexible.”
Better forecasting is next, followed by flexibility. In the home of the future, “every device is going to have intelligence,” Bekkedahl said. “How are we using them? How are we interfacing with them?”
Resiliency and redundancy — backup systems — come next, with Bekkedahl pointing to inverter-based systems as one way to keep household electricity running in the event of a power outage, and possibly to provide demand response.
The last must-have is power quality, with a basic paradigm shift that can take into account and monitor the performance of the thousands of devices being turned on and off across the system, he said.
De-risk, Decarbonize, Scale
Looking ahead, Fox-Penner anticipates that distribution upgrades and expansion could be the top draw on utility investments over the next decade. “And that’s where you hit resilience and affordability issues, and so that takes working with [existing] conditions, using every single tool,” he said.
For utilities, part of the challenge is the regulatory limits on their ability to plan and order equipment for the future, Dion said. “Imagine you’re a distribution full-time provider … and you’re sold out through 2026. You have nothing,” he said.
“We need regulatory regimes that allow us to make purchases into the future, not just replace the stuff that’s broken, but … the new stuff that needs to be developed for what we need, almost like a hedging policy,” he said.
“[We] have to be able to invest in things that we need that are facing the biggest barriers,” Fox-Penner agreed, pointing to building electrification as one sector that will be critical for both homeowners and apartment renters. “That’s right at the heart of our existence, and we need to go in there and change the heating and cooling system,” he said.
He sees continuing innovation as key, “particularly in the spaces where the solutions aren’t well developed, which are often called … the supplemental power sources to wind and solar,” such as nuclear, geothermal or carbon capture.
With its funding from utilities and other investors, EIP has developed a model that focuses on investing in technologies that utilities will need and can pilot and then scale, Fox-Penner said. The company has more than 100 businesses in its portfolio and “over $1.4 billion worth of business going on between our portfolio companies and the members of our coalition,” he said.
“I think of the industry as a fast follower,” he said. “Our model is to de-risk decarbonization measures for our incumbent investors. Once it’s de-risked, it can scale.”
After years of low load growth, U.S. grid planners now predict a sharp increase in electric demand, according to a report released Dec. 12 by consulting firm Grid Strategies.
The nationwide forecast for the next five years has nearly doubled to 4.7% from 2.6% last year, Grid Strategies said, citing data compiled from FERC filings.
The increased load growth translates to an additional 38 GW of demand through 2028, which will require new transmission and generation to be met reliably, Grid Strategies said in the report, “The Era of Flat Power Demand is Over.”
“Over the past decade, grid planners have been forecasting a mere 0.5% annual growth rate, as summarized by NERC,” the report said. “Yet in 2023, annual peak demand growth is up to at least 0.9%, driven by data centers, industrial facilities and other near-term investments.”
That is likely to be an underestimate, the report said, noting that since the forecasts were filed with FERC, Puget Sound Energy, Duke Energy, Georgia Power and the Tennessee Valley Authority have stated that their load expectations have grown even higher.
Since 2021, commitments for industrial and manufacturing facilities have totaled about $481 billion, and more than 200 manufacturing facilities have been announced in the past year. Data center growth is forecast to exceed $150 billion through 2028.
The data across the industry are uneven, with some regions like MISO not clearly explaining how large load development will impact peak demand, whereas PJM and Georgia Power’s latest forecasts include higher investment in industrial sites and data centers.
Only some utilities factor in the impacts of higher temperatures and more extreme weather in their projections. As those practices spread to more firms, the load growth figures should go up, according to the report’s authors, John D. Wilson and Zach Zimmerman.
Major new loads can take only one or two years to connect to the grid, compared to at least four years for new generation and even more for new transmission, the report said.
“It’s worrisome that a resurgent American manufacturing sector may face headwinds from the limited ability of the nation’s electricity systems to respond,” the report said. “Electricity systems need to supply new generation, connect that generation to load and — of course — connect new load to the system. There are real risks that some regions may miss out on economic development opportunities because the grid can’t keep up.”
Transmission investments to meet the new demand are a particular challenge, as they will have to be sped up to meet the new demand after seeing declines in overall investment in the last couple of years.
“Transmission takes years to build, and current planning and regulatory practices make interregional transmission particularly difficult to build,” the report said. “Even though investing in transmission could save tens of billions of dollars in bringing on the new 38 GW of electricity demand, changes in policy and practice are required across the country to make this possible.”
The Inflation Reduction Act and Infrastructure Investment and Jobs Act are leading to an increase in industrial demand, while the computing power of artificial intelligence is driving increased demand from data centers. Longer-term electrification of heat and transportation is adding to growth as well.
Other potential sources of demand growth include new hydrogen fuel plants and the impact of more extreme weather.
“If grid planners are not accounting for these drivers, load forecasts will be too conservative, and the system will not be ready to meet growth in electricity demand,” the paper said.
The new sources of load growth are not uniform across the country with new industry favoring the Southeast (especially Georgia and the Carolinas), MISO (especially Michigan and Indiana) and the Southwest (especially Arizona and Nevada).
Data centers currently represent 2.5% of total electricity demand, but it could grow to as much as 7.5% by the end of the year, according to the Boston Consulting Group. That sector’s growth depends on land and power availability, and it can be located in specific regions, with the report highlighting “Data Center Alley” in Loudoun County, Va., outside D.C.
Virginia has the largest data center market in the world, with more than 35% of all known hyperscale data centers worldwide. (See related story, “PJM 2024 Load Forecast Sees Jumps from EVs, Data Centers, Heat Pumps,” PJM PC/TEAC Briefs: Dec. 5, 2023.)
Ten planning areas are home to most of the projected demand increase with 18 GW: ERCOT, PJM, SPP, Duke Energy, Georgia Power, NYISO, Arizona Public Service, TVA, CAISO and Puget.
APS and Puget are expecting demand to grow more than 10% in the next five years, while ERCOT sees the highest growth among organized markets at 6.6%.
“In 2018, ERCOT’s peak load record was 69.5 GW. This has grown by over 16 GW to 85.6 GW this summer,” the paper said. “The record-setting demand has been largely driven by industrial growth and extreme temperatures. While ERCOT continues to forecast most types of loads to remain relatively flat through 2028, its forecast for new large loads spiked up to 7.4 GW over the past year.”
The new large loads are evenly split between new industrial facilities and cryptocurrency miners, the latter of which are only expected to run when ERCOT’s energy market prices make that activity profitable.
The paper focused on summer peak demand because that is most closely related to transmission development, and on average across the country, it is larger than winter peaks. It acknowledged, however, that focusing on summer peak demand “may obscure important planning issues related to winter peak demand and overall energy resources.”
As the transition to clean energy resources contributes to the risk of energy shortfalls, particularly during the winter, electric industry stakeholders say keeping the grid operating reliably will require new ways of thinking.
“The reality is … that risk is increasing. NERC is pointing that out with their studies, you see it in the trending reports, we’re seeing it in all of our ISOs,” ERCOT CEO Pablo Vegas said in a media webinar Dec. 11 hosted by the U.S. Energy Association. “And it’s going to take a period of time to figure out what we’re going to do from a policy and an action perspective to manage that risk.”
CPS Energy CEO Rudy Garza | United States Energy Association
Concerns about energy shortfalls prompted ERCOT this year to attempt to increase operating reserves by requesting an additional 3,000 MW of capacity for the winter, including from decommissioned dispatchable resources. The grid operator called off the effort the following month after a limited response from utilities. (See ERCOT Cancels RFP for Additional Winter Capacity.)
Discussing the aborted capacity search, Vegas explained utilities had reported to ERCOT that the plants the grid operator thought could come back online could not be made ready in the timeframe it needed. He said ERCOT still believes there is untapped potential among Texas’ utilities to contribute to reliability but considered the events “a significant lesson learned” about ensuring the market has time to react to requests.
Other speakers on the call suggested the growth of renewables may have left the grid more vulnerable than it seems because their behavior under stressed conditions is not as well understood as that of traditional resources. As a result, current planning models can’t completely account for renewables’ reactions to unexpected situations.
“We’re at great jeopardy of purposely interrupting load, and it’s partly because the planning metrics we’ve been using … and the concept of planning reserve margin and effective load carrying capability don’t work when you’re in a system that’s dominated by renewables,” said Duane Highley, CEO of Colorado-based cooperative Tri-State Generation and Transmission Association.
Clinton Vince, chair of the U.S. energy practice at the Dentons law firm, called out the lack of transmission to move the energy generated by wind and solar resources to where it is needed. FERC’s slow pace of transmission approvals has been a common complaint among industry stakeholders, and Vince said reform is urgently needed to ensure the new resources can be used to their full potential. (See FERC Gets Growing Calls to Finish Transmission Rule in 2024.)
“It’s one of the real impediments to achieving a tripling of renewables and some of the other demand that’s called for,” Vince said. “Right now, it takes about 12 to 15 years to get transmission sited, permitted [and] built, which we just can’t wait for. So, I think it’s controversial, but … you’re going to need a lot more federal assistance and support on this.”
A pioneering Great Lakes offshore wind proposal progressing in fits and starts since 2009 has been put on hold.
The Lake Erie Energy Development Corp. announced Friday that Icebreaker Wind has become financially untenable. In a Facebook post, LEEDCo said it is looking at ways to resume work on the project in the future, but for now, halting work is the most responsible decision given the circumstances.
As with other U.S. offshore wind projects, high interest rates and rising cost of materials have affected Icebreaker’s financials. But it also faced regulatory delays, legal challenges and other obstacles, LEEDCo said, to the point the project’s private development partner ceased financial support.
The Icebreaker plan calls for six 3.45-MW turbines to be placed in Lake Erie, 8 miles north of Cleveland. It was to be the first freshwater wind farm in the U.S.
Offshore wind in the Great Lakes faces a different set of challenges than the facilities being planned and built off the U.S. coast in the Atlantic and Pacific oceans: Ice develops on the Great Lakes in winter, some of the lakes are quite deep, the large vessels used for turbine installation cannot navigate lake locks and the cost is higher.
For these reasons, New York — an enthusiastic promoter of offshore wind — has shelved consideration of energy development in Lake Erie and Lake Ontario. (See NY Great Lakes OSW Too Expensive, Study Determines.)
With Icebreaker, LEEDCo had a long-running series of challenges placed in its path. The Ohio Power Siting Board, for example, placed no fewer than 33 conditions on the project when it approved construction in 2020. Among them: An initial requirement that the turbines not spin at night from March through October to reduce risk to bats and birds.
LEEDCo board member Will Friedman said the Siting Board’s lengthy review and the frivolous lawsuits funded by dark money tied to fossil fuel interests caused extensive delay and expenses for the project.
They also caused the U.S. Department of Energy — with LEEDCo’s agreement — to terminate a funding package because Icebreaker could not meet DOE milestones, he said.
PJM Steams Ahead with CIFP Filing Timeline After FERC Deficiency Notices
Deficiency notices FERC issued on two filings PJM made to overhaul its capacity market are not expected to interrupt the RTO’s plan to implement the changes in time for the 2025/26 Base Residual Auction (BRA) scheduled for June 2024 (ER24-98, ER24-99).
PJM Associate General Counsel Chen Lu told the Market Implementation Committee that the RTO will not seek any changes to the auction timeline, which was delayed by a year in June 2023. (See PJM Files Capacity Market Revamp with FERC.)
The deficiency notices reset the 60-day deadlines for FERC to act on PJM’s requests to two months after the RTO’s responses. PJM replied to the notice in ER24-99 on Dec. 1, resulting in a Jan. 30 deadline, and submitted a response in ER24-98 on Dec. 8, carrying a Jan. 6 deadline for the commission.
Lu said staff considered seeking another delay but determined that the pre-auction activities that will be conducted before the commission’s deadlines would not be affected by PJM’s proposals and can be run while the dockets are in limbo.
Stakeholders Begin Review of Energy Efficiency Resources
Stakeholders endorsed an issue charge to revisit how energy efficiency (EE) resources participate in the capacity market and began work on identifying stakeholder interests. The document states that its goal is to make EE market participation more effective by improving resource qualifications. Key work activities include eliminating any ambiguity around what qualifies as an EE resource and ensuring that energy savings attributed to resources are “unbiased, accurate and reasonably consistent across providers.”
Luke Fishback of Affirmed Energy said EE providers are concerned that the scope of the issue charge is ambiguous and would prefer more specificity.
Stakeholders discussed whether it was necessary to include a sentence specifying that a partial solution may be advanced sooner than the expected nine-month timeline. PJM’s Pete Langbein said the language was included to leave the door open to implementing changes in time for the 2025/26 BRA in June 2024.
Several stakeholders argued that the language was redundant, because issue charge timelines do not dictate when solutions may be advanced. The line was struck from the issue charge prior to its approval.
Initiating the education process of the work, PJM’s Tim Bachus said the value of an EE resource is based on the incremental amount of energy reduction above what is required by local building codes.
Stakeholders contributing to the interest identification list added avoiding payments for energy efficiency upgrades that would naturally occur, accounting for a “rebound effect” to ensure consumer behavior doesn’t undo EE benefits and allowing EE to be eligible for the useful life of the installation.
MIC Chair Foluso Afelumo said the next meeting will continue the education and issue identification processes.
Temporary Exceptions Supplant Real Time Values
PJM’s Lauren Strella Wahba outlined how the RTO plans to implement the process FERC approved on Nov. 30 for resources to submit temporary exceptions from their unit-specific parameters. The temporary exceptions replace the real-time values process PJM maintained for resources to reflect changes to their ability to operate according to their parameters during the operating day. The commission’s order approving temporary exceptions was effective Nov. 30.
Documentation of why a resource is seeking an exception must be submitted to PJM and the Independent Market Monitor within three days.
Strella Wahba said PJM is working on updating its Markets Gateway software to reflect the changes, with updates beginning over the next few days and expected to be complete by the second quarter of next year. In the meantime, real-time temporary exceptions can be submitted using the real-time values drop-down menu.
Dominion’s Jim Davis said the addition of temporary exceptions will improve resources’ ability to keep PJM updated of any issues experienced during strained system conditions and alleviate some of the incongruities between the electric and natural gas markets.
“It’s certainly a first step to allow resources to reflect their capabilities, especially during these extreme events … and it’s also a first step for addressing the challenges around electric-gas coordination,” he said.
Migration from eDART to Account Manager Nearly Complete
PJM’s Chidi Ofoegbu urged market participants to ensure that they have completed the transfer of their eDART accounts to the new Account Manager software before Dec. 13, when eDART access will be revoked.
She also encouraged users to begin working in Account Manager prior to Dec. 13 to build up familiarity and give time to work with PJM to resolve any issues before eDART access is terminated.
Several stakeholders encouraged their peers to take the software change seriously, stating that it would be difficult for any market participant to conduct business and meet their obligations without having access to PJM’s online tools.
Generation Operators Urged to Participate in SOS Calls Ahead of Storms
PJM Senior Vice President of Operations Mike Bryson said participation in the System Operations Subcommittee (SOS) conference calls it holds ahead of major storms has been troublingly low, with only a few dozen individuals typically participating. Discussions with generators that did not meet their capacity obligations during the December 2022 winter storm suggested one of the contributors to the strained system conditions experienced Dec. 23-24 was poor understanding of emergency procedures.
Senior Dispatch Manager Donnie Bielak said a recent emergency procedure drill also had much lower attendance than anticipated. He encouraged stakeholders to familiarize themselves with the resource limitations detailed in Manual 13 to ensure resources know how to report any limits to dispatchers during an emergency. While a voltage reduction was not instituted during Winter Storm Elliott, Bielak said it was a close enough call staff might conduct a test of the ability to implement the emergency procedure.
PJM Reviews FERC and NERC Winter Preparedness Recommendations
PJM Associate General Counsel Mark Stanisz reviewed the findings of the FERC/NERC inquiry into the impact of Winter Storm Elliott and the NERC Winter Reliability Assessment for the upcoming season.
The NERC assessment found that much of the Eastern Interconnection is at elevated risk during peak winter conditions, suggesting potential for reserves to be insufficient during an emergency. Generators’ winter preparations are improving, but the growing complexity of forecasting demand during cold temperatures remains a concern. So does the potential for generator fuel storage to run dry during long-duration events. Interregional energy transfers to strained areas also are at risk of curtailment, presenting a growing reliability concern.
The NERC/FERC inquiry recommended balancing authorities conduct fuel surveys and state regulators be prepared to respond to any environmental, emissions and transportation waivers grid operators may request during a storm.
The PJM Markets and Reliability Committee endorsed several additions to its generation winterization checklist during its Nov. 15 meeting, drawing on NERC’s Lessons Learned. (See “New Winterization Requirements Endorsed,” PJM MRC/MC Briefs: Nov. 15, 2023.)
PJM 2024 Load Forecast Sees Jump from EVs, Data Centers, Heat Pumps
PJM’s preliminary load forecast for 2024 sees higher growth for both summer and winter, driven by electric vehicles, data centers and state incentives for heat pumps.
The 15-year annualized growth rate increased to 1.6%, doubling the 0.8% growth rate in the 2023 forecast, with the difference between the two forecasts accelerating in later years, said Molly Mooney, who presented the forecast to the Planning Committee on Dec. 5.
The 2027 preliminary forecast is 4.4% higher than the 2023 forecast (6,600 MW) while the 2038 preliminary figures are 13.9% higher (22,400 MW).
The main drivers behind rising summer loads are EVs and data centers, which respectively contributed 3,700 MW and 4,000 MW in load growth over the 2023 forecast, without which Mooney said summer loads would remain largely flat. Solar generation reduced summer loads by 200 MW and energy efficiency provided a 750 MW reduction.
The 15-year outlook for winter loads increased to a 1.9% annualized growth rate over the 0.9% in the 2023 forecast.
The main policy change affecting the winter load forecast is New Jersey’s Executive Order 316, which has a goal of electrifying 400,000 homes and 20,000 commercial buildings by 2030. (See “Transitioning Commercial Buildings,” NJ Advances Multifaceted Building Decarbonization Strategy.)
Mooney said this is the second year that PJM conducted the study using hourly forecasting rather than the daily peak methodology previously used. The commercial and residential data used in the study is based on 2013-2022 census figures.
This was the first year that S&P Global was contracted to provide estimates of plug-in EV data. The company forecasted that there would be around 7.5 million such vehicles in PJM’s footprint by 2030. The Met-Ed territory is expected to see the largest number of medium and heavy duty EVs, owing to the large number of warehouses and shipping corridors in its region.
Transmission Expansion Advisory Committee
Second Read of $5 Billion in RTEP Projects
PJM reviewed its proposed $5 billion package of transmission projects in the third window of the 2022 Regional Transmission Expansion Plan (RTEP), which is primarily aimed at addressing data center load growth in northern Virginia and generation retirements. (See PJM Recommends $5B in RTEP Transmission Projects.)
PJM’s Sami Abdulsalam said the proposal is the most efficient, cost-effective and resilient set of solutions of the 80-plus project combinations staff analyzed. The package would construct new 500-kV lines from northern Virginia out to the Peach Bottom substation to the northeast, the 502 Junction substation to the northwest and the Morrisville substation to the south.
When considering the 72 proposals PJM received during the competitive process, Abdulsalam said staff prioritized cost, maximizing use of existing rights-of-way and scalability.
PJM Senior Vice President of Planning Ken Seiler said the concerns members of the public have raised during previous TEAC meetings and letters to the Board of Managers have been noted. Many of the objections centered around siting issues, which he said will be the focus of the routing process transmission owners would go through after possible board approval.
“This is a pretty significant body of work and we’ve received a lot of pushback and a number of letters from residents … we’ve heard from you,” Seiler said.
PJM included with its meeting materials an FAQ detailing its role in selecting the proposals in the window.
First Window of 2023 RTEP Set for Board Consideration in February
Abdulsalam presented a first read of three projects being added to PJM’s recommended transmission expansion in the first window of its 2023 RTEP, which is set to go before the Board of Managers for approval in February.
The window includes a $42.05 million project to address an overload of APS’ Belmont 765/345-kV transformer by replacing the equipment with a new transformer bank; a $10.22 million rebuild of Commonwealth Edison’s 138-kV Haumesser Road-West DeKalb Tap line; and a $7.75 million proposal to add three 345-kV circuit breakers to ComEd’s Cherry Valley substation.
The three proposals join several projects in the first window aimed at addressing reliability issues identified in the Public Service Enterprise Group, PECO Energy, Dayton Light and Power, American Electric Power (and Ohio Valley Electric Corp. zones.
Abdulsalam presented a second read of the existing projects, which amount to around $42.4 million. The proposals include:
Replacing 230-kV and 345-kV fixed shunt reactors with higher rated variable reactors for $29.6 million to resolve high voltage issues around PSEG’s Waldwick substation;
Replacing an over-duty 345-kV circuit breaker at AEP’s Olive substation for $1 million;
Replacing breakers, switches and other equipment owned by AEP and OVEC at the Kyger Creek station for $1.16 million; and
Reconductoring 8.8 miles of DPL’s Silver Run-Cedar Creek double-circuit 230-kV line and replacing infrastructure at both substations for a total of $8.7 million.
The U.S. Supreme Court on Dec. 11 declined to take up an appeal of a lower court’s ruling that a Texas law giving incumbent transmission companies the right of first refusal (ROFR) to build new transmission lines was unconstitutional.
The Texas Public Utility Commission, with then-Chair Peter Lake as the lead petitioner, requested a writ of certiorari last December after the 5th U.S. Circuit Court of Appeals’ decision earlier in 2022. (See Texas Petitions SCOTUS to Review ROFR Ruling.)
The appeals court found for NextEra Energy in its challenge to a 2019 Texas law (Senate Bill 1938) that set up a ROFR within state lines. It ruled the legislation violated the U.S. Constitution’s dormant Commerce Clause, and it remanded the case back to the U.S. District Court for Western Texas. (See 5th Circuit Finds in Favor of NextEra’s ROFR Appeal.)
The Supreme Court gave no reason for not taking up the appeal, as is typical. It included the rejection (22-601) among dozens of other appeals it will not take up this term.
The high court says it receives about 10,000 requests for certiorari each year. Only about 100 of those are granted, allowing petitioners to make oral arguments before the justices on why the lower court was wrong.
U.S. Solicitor General Elizabeth Prelogar in October recommended the Supreme Court not to take up the ROFR case. She said the petition is not a “suitable vehicle” for reviewing the constitutionality of ROFR laws.
“The 5th Circuit got it right that the Texas law was unconstitutional,” Paul Cicio, chair of the Electricity Transmission Competition Coalition, said in an email to RTO Insider. “Blocking new entrants from competing on transmission projects isn’t just unconstitutional; it’s anti-consumer, anti-free-market policy that costs consumers billions of dollars in higher electricity rates.”
The coalition said FERC should see the denial as a “clear signal in support of transmission competition.” It said FERC has an opportunity to take action now in a pending complaint under Section 206 of the Federal Power Act against MISO to ensure the grid operator no longer applies ROFR laws when conducting transmission planning (EL22-78). (See Big Savings for Tx Competition Claimed as FERC Considers a New ROFR.)
NextEra Energy Capital Holdings, NextEra Energy Transmission (NEET), NextEra Energy Transmission Midwest, Lone Star Transmission, NextEra Energy Transmission Southwest, Southwestern Public Service, Entergy Texas, Oncor, LSP Transmission Holdings II and East Texas Electric Cooperative were also named as respondents in the petition.
NextEra subsidiaries were involved in two projects in Texas’ non-ERCOT footprint that ran afoul of the ROFR law. NEET Midwest won a competitive bid in 2018 for a $130 million, 500-kV project in East Texas. MISO said last year that planned capacity in the region had negated much of the project’s economic benefits. (See MISO on Verge of Cancelling Hartburg-Sabine Tx Project.)
NEET Southwest also applied to the Texas PUC in 2018 to transfer ownership of 30 miles of 138-kV facilities from Rayburn Country Electric Cooperative in SPP’s East Texas footprint. That application was withdrawn in 2020 after SB 1938 became law (48071).
ALBANY, N.Y. — After four rounds of voting, the New York State Reliability Council Executive Committee agreed Dec. 8 to set the installed reserve margin (IRM) for the state’s 2024/25 capability year at 22%, up from 20% for the previous year. (See New York PSC Approves 20% Installed Reserve Margin.)
The IRM represents the additional supply capacity NYISO mandates load-serving entities maintain as a precaution against unexpected outages or demand surges.
Following a yearlong examination, the NYSRC’s Installed Capacity Subcommittee (ICS), in collaboration with NYISO, published a technical study report, which originally found that an IRM under base conditions of 23.1% would satisfy the resource adequacy criteria without violating a loss of load expectation (LOLE) of no greater than 0.1 events-days/year in the next capability year, extending from May 1, 2024, through April 30, 2025.
NYSRC Report
The ICS’ report studied how several sensitivities, including new topology changes, transmission security limit (TSL) floor inputs and increases in renewable generation, might impact the final base case modeling and the final IRM necessary to meet the state’s future requirements.
For instance, the ICS noted that a reduction in emergency assistance import limits increased the IRM by 2.24% and expected updates in the performance of special case resources raised the IRM by 0.14%. Conversely, the ICS observed that expected increases in the amount of behind-the-meter solar caused the IRM to decrease by 0.5%.
The report also documented the observation that using a 23.1% IRM while incorporating higher TSL floors in the locational capacity requirement (LCR) setting process, which is administered the ISO under its tariff, results in a system with a LOLE of 0.069, below the minimum reliability requirement of 0.1.
TSL floors are used in the LCR calculations, conducted by NYISO in its process, as the lower limit beyond which LCRs cannot fall below, resulting in minimum capacity margins that a locality, such as Zone J (New York City), Zone K (Long Island) or Zone G (Lower Hudson Valley), must maintain to ensure grid stability under standard N-1-1 system conditions.
Additional analysis using TSL floors in the LCR study, where the statewide LOLE is readjusted to 0.1, caused “noticeably better” results and produced an IRM of 21.5%.
This adjustment also yielded preliminary LCRs of 81.7% for Zone J, 105.3% for Zone K and 81% for Zone G, which contrasts with the final base case IRM results for these zones that were 72.73%, 103.21% and 84.58%, respectively.
Both NYISO and the NYSRC agree that more analysis, modeling and discussion are needed before the NYSRC Policy 5 IRM and the ISO’s TSL/LCR processes can be merged to ensure no unexpected consequences result from any process change. The NYSRC said at the meeting that this is a priority effort for 2024 and beyond.
The committee members approved the report’s base case, data parameters and sensitivities at last month’s EC meeting after extensive stakeholder development and feedback. (See “IRM Modeling Updates Approved,” NY Reliability Council OKs Interconnection Standards for Large IBRs.)
Comments
The NYSRC, responsible for establishing the IRM, determines the annual ICR that generators must maintain throughout the next capability year. The ICS’ report highlighted the disagreements among the EC about how New York should address its future reliability challenges.
Consolidated Edison’s Mayer Sasson, former chair of the EC, urged members to carefully consider the report’s findings before voting, saying, “make sure to interpret the TSL correctly before we set the IRM.”
Mark Younger, president of Hudson Energy Economics, also urged caution, saying, “while 21.5% results in a LOLE event value of 0.1, don’t kid yourself that it is reliable, since that is absolutely inconsistent with NYISO’s STAR [short-term assessment of reliability] reports and CRP [comprehensive reliability plan].” (See NYISO’s 10-Year Forecast: Challenges Ahead, but No Immediate Needs.)
On the other side, Roger Clayton, chair of the NYSRC’s Reliability Rules Subcommittee, while not explicitly endorsing an IRM of 21.5% appeared supportive, saying, “from a reliability point of view and thinking about nothing else, 21.5% is reliable according to the analysis that has been performed.”
Timothy Lynch, senior director of transmission services at Avangrid, concurred, saying, “21.5% is a reasonable step at this time, given ratepayer pressures and so forth.” He added, “There’s a lot of changes in the study year-over-year, and I think some of that needs to play out to see what the future brings.”
Similarly, Michael Mager, a partner at Couch White who represents Multiple Intervenors, a group of large industrial, commercial and institutional energy consumers, was comfortable with 21.5% despite it being the highest IRM adopted, saying, “it meets the LOLE requirements … and moves in the right direction that we should be going, but in a more moderate step than the base case result.”
Curt Dahl, director of engineering at PSEG Long Island and chair of the NYSRC’s Extreme Weather Working Group, although partial to lower IRM values, advocated for a balanced approach, saying, “I always have a range of [IRM values] in my mind.”
EC Chair Chris Wentlent, a member of the Municipal & Electric Cooperative Sector, approached the IRM vote from a policy and environmental perspective, saying, “our reliability picture is getting more complicated going forward, not less complicated,” referring to how last year’s Winter Storm Elliott significantly impacted Northeastern state grids and unexpected costs and risks to energy consumers and triggered emergency operating procedures.
“Based on everything, I see a 22% as a reasonable outcome, because, in my opinion, this balances the cost issues, some of the [emergency operating procedures] issues, and other future risks we need to pay attention to,” he added.
In an email to RTO Insider, Richard Bratton, director of market and regulatory policy at the Independent Power Producers of New York, said “the IRM is a careful balance between maintaining system reliability and protecting ratepayer costs. Less than a year after Winter Storm Elliott, the NYSRC voted to significantly decrease the IRM from the number produced by the NYISO through its analysis. IPPNY is continually committed to advocating for system reliability through competitive markets.”
