High levels of self-scheduled exports out of CAISO’s balancing area to support stressful conditions elsewhere led the ISO to declare Level 1 energy emergency alerts in late July, the Department of Market Monitoring explained last week.
The alerts, issued for July 20, 25 and 26, were not related to bad weather conditions in California, but actually in areas to its north and south, said Ryan Kurlinski, senior manager of market and policy analysis with the DMM.
Typically, during peak net load hours in the summer months, power flows from the Northwest into the rest of the system. But this July saw relatively low hydro conditions in the Northwest compared with relatively high ones in California. This was coupled with extremely high temperatures in the Southwest that lasted even after peak net load hours, leading to record demand there.
“What we saw this year was a significantly different pattern from previous years,” COO Mark Rothleder said. “What we saw was a higher level of exports and demand outside of our system, and for a large period of time, we could support that demand, but there were times … where we could not.”
When the EEA was declared on July 20, CAISO operators had not yet identified exports they were unable to support in the hour-ahead market. As solar began ramping down, there was still relatively high demand across the system between 6 and 8 p.m. Throughout the day, CAISO had sufficient bids from its contracted capacity to cover its own requirements, but beginning around 8 p.m., “the addition of the exports required CAISO to rely on bids from resources not contracted to serve CAISO load,” Kurlinski said.
While the ISO was close to being unable to deliver exports that had received hour-ahead market schedules, operators ultimately did not curtail any load.
On July 25 though, CAISO was unable to award several thousand megawatts of self-scheduled exports between 6 and 9 p.m.
“I’m calling that the first significant market issue impacting WEIM [the Western Energy Imbalance Market] in this period,” Kurlinski said. “CAISO did not give hour-ahead market awards to all exports that wanted to self-schedule in the hour-ahead market.”
Each of the three real-time markets have a load forecast that the market solves for, and operators frequently adjust this load above the forecast, particularly during net peak load in the hour-ahead and 15-minute markets to cover any uncertainty over available supply. Uncertainty materialized quickly on July 20, Kurlinski said, and by July 25, operators began dramatically increasing the load adjustment.
“These large hour-ahead market load adjustments contributed significantly to the large quantity of exports attempting to self-schedule out of CAISO that did not receive hour-ahead market awards,” Kurlinski said, but “CAISO operators did actually end up allowing a decent portion of these exports to tag … and ultimately flow to other balancing areas.”
Not enough supply could prevent the hour-ahead market to self-schedule exports, but the load adjustment can also be supplied by advisory WEIM transfers flowing into CAISO’s balancing area. If the transfers don’t flow into CAISO in the five-minute market, however, the ISO may not have enough supply to meet load requirements and self-scheduled exports in the hour-ahead market.
“This concern arose on July 25, and my understanding is that it prompted the CAISO balancing area to start limiting the WEIM transfers into its area in the hour-ahead market,” Kurlinski said. From 7 to 8 p.m., the ISO put a 4,000- to 5,000-MW load adjustment into the market, and while much of it was supported by WEIM transfers in the hour-ahead market, almost no five-minute transfers flowed into CAISO.
On July 26, CAISO started strictly limiting WEIM transfers into its balancing area during peak hours, which marked the second significant issue.
The limit significantly impacted transfers in other WEIM areas, such as in Arizona, where transfers to CAISO from Arizona Public Service decreased to zero at one point.
Observations and Lessons Learned
Rothleder shared observations that could help the ISO prepare for any similar conditions in the future, should they arise.
“Between the 20th and the 25th, we took the learnings and the observations, and we applied that [in the 7 p.m. hour] on the 26th,” Rothleder said. “This is what triggered us to limit the amount of transfers the California ISO was relying on from others when we were clearing that hour-ahead scheduling process.”
Limiting transfers, he said, helped reduce uncertainty and increase confidence in the ability to serve load. He also highlighted that the load adjustment aided in dealing with additional uncertainty.
Unusual conditions led to the issuing of the EEA, but all things considered, Rothleder emphasized that it was a successful summer overall for the ISO.
“It’s unprecedented that we would be a net exporter in a summer period, but this past July, we saw periods where we were a large net exporter supporting other parts of the West as they were approaching 96% of their record load outside of the ISO,” he said.
While CAISO did enter a few EEA watches and declared the Level 1 alert, it did not have to issue any flex alerts or experience any load-shedding events.
“The system is becoming more complicated, and we’re seeing flow patterns that are significantly different from historical patterns, and this highlights really the need for that coordination and awareness of the constraints that may arise earlier,” Rothleder said. “That’s why we believe things like the Extended Day-Ahead Market provide the vehicle for that strong coordination, awareness and insurance.”
BOSTON — Hoping for a mild winter is not a sustainable plan for reliability, FERC Chairman Willie Phillips said at the Dec. 7 NEPOOL Participants Committee meeting. He said he’s concerned premature retirements of legacy generators and infrastructure will threaten the reliability of the New England grid.
While ISO-NE’s winter reliability studies indicate Everett doesn’t significantly improve the reliability of the grid during extreme weather conditions, Phillips said the RTO should “continue to work and think about the assumptions and the methodology that are used in that study to make sure that we get this right.” (See ISO-NE Study Highlights the Importance of OSW, Nuclear, Stored Fuel.)
Asked whether electric ratepayers should bear the costs of keeping Everett open, Phillips responded “I don’t have an opinion — and I’m not here to give one — on who should pay,” adding that it’s not FERC’s jurisdiction to make the decision.
The chairman also connected the need to maintain grid reliability to the region’s decarbonization goals. While applauding the states’ clean energy ambitions, Phillips said the region must keep reliability “top of mind” as it pursues its clean energy goals.
“If we get this wrong, it is the transition that will be blamed,” Phillips said.
Phillips also emphasized the need to consider environmental justice and existing energy infrastructure burdens when planning and siting new infrastructure.
“I grew up in an environmental justice community,” Phillips said. “I know what it smells like.”
He said he hopes to issue an “outward-facing guidance document” detailing expectations regarding engagement with environmental justice communities.
Prior to Phillips’ speech, a group of climate activists associated with the organization No Coal No Gas pressed NEPOOL officers to let them sit in on the meeting, which the NEPOOL officers allowed.
While New England ratepayers can join the organization for a $500 membership fee, several members of ISO-NE’s Consumer Liaison Group Coordinating Committee (CLGCC) who lack institutional support are not NEPOOL members.
In December 2022, No Coal No Gas successfully elected a slate of candidates to the CLGCC which included several members of the climate group. (See Climate Activists Take Over Small Piece of ISO-NE.) The group now is pushing for elected CLGCC members to be given governance-only seats at NEPOOL.
Operations Report
The total energy market value in November was up by about 45% compared to October but was more than 40% less than the total value from November of 2022, ISO-NE COO Vamsi Chadalavada told the PC. The monthly increase relative to October was because of higher natural gas prices, Chadalavada said.
The estimated carbon emissions from November were down relative to both October of this year and November of 2022, Chadalavada added.
Regarding this winter, Chadalavada said ISO-NE’s capacity analyses based on the forecasted load indicate “a surplus even after accounting for generation at risk due to gas supply.” (See ISO-NE Says Region Has Enough Resources for Upcoming Winter.)
Chadalavada added that the region’s weather can change quickly and noted that “extended periods of cold weather may rapidly deplete stored fuel inventories and capacity outlook will be adjusted accordingly.”
IMM Report
David Naughton, executive director of ISO-NE’s Internal Market Monitor (IMM), presented to the PC on the IMM’s 2022 Annual Markets Report.
The report notes that weather-normalized load has increased slightly over the past two years following years of decline due to energy efficiency efforts.
“The trend of decreasing load may have reached an inflection point,” the report states, adding that “while it is difficult to attribute this directly to any particular driver, this change is consistent with the ISO forecast that average load will increase each year with the continued adoption of electricity-fueled transportation and electric heating.”
Naughton also noted total energy costs in 2022 nearly doubled compared to 2021 and were the highest since 2008.
In other NEPOOL business, the PC approved the 2024 NEPOOL expense budget and elected a slate of officers to run the PC in 2024, which will by chaired by Sarah Bresolin of ENGIE North America. The PC also voted to support changes to its Financial Assurance Policy regarding the calculation of Forward Capacity Market delivery financial assurance.
Washington state expects to collect $941 million in extra cap-and-trade money in the first half of 2024, bringing the overall income to roughly $3 billion over the system’s first 18 months.
The Washington Legislature already has appropriated $2.1 billion of previously predicted “cap-and-invest” income for its fiscal biennium, which runs from July 1, 2023, to June 30, 2025. Most of that money is going to climate change mitigation projects.
The state is on track to gather roughly $2 billion in calendar 2023. That’s more than $1 billion greater than what the Legislature expected when it originally approved the program in 2021.
The newly predicted $941 million will be added to Gov. Jay Inslee’s 2024 supplemental budget request to the Legislature in January — a tweaking of the approved 2023-2025 biennial budget. It’s up to the Legislature whether it will approve some or all of that request.
Inslee’s request includes:
A one-time $200 credit to the utility bills of roughly 750,000 low- and moderate-income households in Washington.
Speeding up the transition from diesel school buses to electric zero-emission school buses across the state.
Installing electric heat pumps in low-income multiple-family homes, replacing gas heat.
Providing matching funds for competitive federal grants to obtain clean-energy jobs.
Converting a large diesel ferry into to a hybrid fuel-electric ferry.
Washington’s ferries are breaking down in increasing numbers. Inslee said Dec. 11 that future cap-and-invest income could speed up replacing the old ferries with new hybrid ferries.
Legislative Priorities
Also Dec. 11, state officials unveiled Inslee’s top three climate-relate bills for the 2024 session.
The first bill — modeled after a new California entity — would create a division of petroleum market oversight under the Washington Utilities and Transportation Commission. “We’re gonna pass the transparency law so we are not victimized by the oil companies,” Inslee said at his press conference.
Inslee has been heavily criticized because the bid prices on Washington’s allowance have been linked to increased gasoline prices in the state.
The oversight entity would require details on fuel pricing, profit margins and transaction data by fuel suppliers, refinery operations and others in the fuel supply chain. The new office would analyze that information. The bill likely would explore setting up fines for collusion, shutting down fuel chain equipment and other forms of market manipulation, officials said in a press briefing prior to Inslee’s comments.
“This is to simply unpack the black box of how oil companies set their prices. … Who’s selling to whom, at what volume?” asked Becky Kelly, Inslee’s climate change policy adviser.
The Inslee administration contends the five biggest oil corporations made $200 billion in profits in 2022. “We’re not gonna surrender to the oil companies,” Inslee said.
The second bill would have Washington officials explore compatibilities with the cap-and-trade programs in California and Quebec, to try to stabilize carbon prices and shrink the costs of buying allowances. The California-Quebec coalition is the only other cap-and-trade market in the United States or Canada.
The meshing of the two systems would have to be addressed. For example, Washington limits a bidder to try to buy 10% of the available allowances per quarter. The California-Quebec alliance limits that to 25%.
A recent Ecology Department preliminary analysis concluded the proposed linkage likely would improve the cap-and-invest program’s economic durability, longevity and efficacy.
“In a larger, more liquid market with a greater number of participants, allowance prices would likely be lower and change more predictably. Predictable prices can foster greater investments in decarbonization,” the report said.
The third legislative effort is reviving House Bill 1589 by Rep. Beth Doglio (D) to limit methane emissions from landfills. The bill is aimed at encouraging Washington’s largest utility, Puget Sound Energy — which uses methane in some instances — to switch to other electric sources.
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.)
