With the Order 1920 compliance window already halfway closed and an order on rehearing expected in the next couple of months, Americans for a Clean Energy Grid (ACEG) hosted a webinar Oct. 28 examining progress on the measure so far.
The group worked with Grid Strategies to release an update to its regional transmission report card, which showed all U.S. organized markets recently have been looking at changes to their planning practices. (See ACEG Report Checks in on Regional Planning After Order 1920.)
The original report, which predated Order 1920, attempted to examine best practices in planning. With Order 1920 compliance efforts underway, it was time for an update, said Rob Gramlich, president of Grid Strategies and co-author of both reports.
“There’s some signs of improvement,” Gramlich said. “CAISO and MISO continue to proceed with what they’re doing, which is, you know, largely close to Order 1920 and the best practices.”
CAISO and MISO received the best grades in the initial report, and other markets have all made improvements, though the report said areas outside organized markets — the Southeast and most of the West — have done little in terms of region-wide transmission planning, he added.
Compliance filings are due next summer, but some regions are starting to work on them. For example, several regions have launched their state engagement periods, which give six months for state regulators to craft a regional cost allocation methodology, said ACEG Executive Director Christina Hayes.
SPP launched that process Oct. 28 and its Regional State Committee was poised to vote on whether it would be the venue for those cost allocation discussions, said Christy Walsh, a senior attorney at the Natural Resources Defense Council. Walsh watches the organized markets for NRDC and its Sustainable FERC Project, and she noted a similar attitude among many of them.
“They say: ‘We know there’s need for regional transmission — it brings reliability and affordability benefits, but we’re doing it right,’” Walsh said.
WIRES Executive Director Larry Gasteiger said he sees some of that messaging from the RTOs/ISOs, but contended they still have many issues to deal with.
“What I really think is happening is they are saying we are working hard on trying to address these concerns. We think we’re meeting them in some respects,” he added. “I think there’s an acknowledgement that there can be some improvements, but I’m also hearing it against the background where they’re trying to get a heck of a lot of other things done at the same time.”
MISO got good grades on its ACEG report card, but it has asked for a year delay in complying with Order 1920 to avoid disturbing its ongoing planning processes. (See MISO to Request Year Deferral on FERC Order 1920.)
ISO-NE got a most-improved nod from Gramlich because of its recent work with member states around transmission planning, but it recently put a pause on Order 1920 compliance due to uncertainty around the rule’s fate. (ISO-NE Announces Pause of Order 1920 Compliance Discussions.)
Rehearing Order Imminent
In general, major FERC orders have not undergone significant changes on rehearing, but that might not be the case with 1920, Gasteiger said.
“There were some stark differences right from the get-go on this rule, and I don’t know with three new commissioners how that’s going to play out,” he said. “My guess is not huge changes, but I think the potential for more significant changes is greater here than in the past.”
FERC is expected to issue a rehearing order in the next couple of months because it has asked the 4th U.S. Circuit Court of Appeals to hold off on its review of the order until January, Walsh said. Gramlich agreed a rehearing order likely will come soon.
Another looming area of uncertainty is the elections, as a change in the White House would mean a change in FERC chairs and eventually a shift to a Republican majority on the commission.
“To the extent some regions are not racing [toward] compliance, I do think the industry will get some more clarity in the next couple of months about some things, and hopefully at that point they’ll be moving forward quickly,” Gramlich said.
NEW YORK — The Inflation Reduction Act and other policies have made the U.S. into one of the most attractive places to invest in clean energy, but completing the energy transition will require additional advances, panelists said Oct. 24 at the Aurora Energy Transition Forum.
Oliver Kerr, Aurora Energy Research’s managing director for North America, asked panelists whether they would pick the U.S. or Europe if they had $1 billion to invest.
“If I had a billion dollars, I would spend $100 million on the best development pipeline that required $2 billion of investment” in the U.S., RWE Clean Energy CEO Andrew Flanagan said. “And I’d invest that other $900 million into that portfolio, and then I’d claw back that additional billion, or $1.1 billion from our colleagues in Germany, or find some other equity source.”
Germany-based RWE is not alone, with Sandhya Ganapathy, CEO of EDP Renewables North America (a subsidiary of a Portuguese utility), saying the U.S. represents 45% of the parent firm’s investments, the largest share out of the 29 countries in which it is active.
“This is a great, great market to invest, and it’s also a great market where I truly believe that market fundamentals work really well,” Ganapathy said. “It’s not a lot of intervention; it’s really set by demand.”
There’s clearly still plenty of room to grow, as Europe is up to 35 to 40% renewable energy, while the U.S. is at just half of that. On top of federal policies spurring investments, 28 states have set some kind of mandate for renewables, and there is large and active demand from big corporate buyers, Ganapathy said.
Arguably the two leading states on the energy transition are California and Texas, which have deployed tens of thousands of megawatts using very different regulatory models.
“California, as we know, by state statute, has committed to decarbonizing the power sector by 2045,” CAISO CEO Elliot Mainzer said. “I think when you take the fifth-largest economy in the world and put it on that path, every major developer is going to want to have a piece of that, and so that’s why we have a 510-GW queue.”
Many developers come up against friction in the queue, but the issues around it can mask some realities like the fact that California has deployed 20,000 MW of new supply over the past four years, including 10,000 MW of batteries, he added.
California has a much more planning-based process with its various state agencies taking a bigger role in things than Texas, but part of the fix for that major backlog in the queue was borrowed from the Lone Star State. CAISO’s newest recently approved process involves studying which of those 510 GW actually are responding to demand and linking the transmission planning process to the queue, Mainzer said. (See FERC Approves CAISO Plan to Streamline Interconnection Process.)
CAISO borrowed “very shamelessly” Texas’ Competitive Renewable Energy Zone approach, which picked out the best areas for wind and built major transmission lines to connect them to cities, turning the state into the leader in wind capacity, Mainzer said.
“The way the ERCOT market has evolved, it has been very open and made it very easy for both supply and for load to come to the system,” CEO Pablo Vegas said. “We’ve got a light regulatory touch on virtually all facets of the interconnection process, and we’re very flexible in the way we manage those interconnection queues. And it’s been a benefit that has, I think, gotten us to where we are today, but the old adage of ‘what got you to where you are today won’t get you where you’re going to go’ applies very accurately in Texas, as we look forward.”
Projections for load growth in ERCOT call for as much as 150 GW to come online; it set its peak record of 85,508 MW in August 2023. It is far from clear that demand will grow that much, but like in other parts of the country, Texas is seeing demand growth on a scale that has not been witnessed since the years following World War II, Vegas said.
“In order to meet that challenge, we are going to have to think differently,” Vegas said. “In Texas, we have not historically planned where load or where supply gets sited. And when you’re trying to build transmission, which is going to become the linchpin to the success of this whole strategy, transmission has to know where load and supply is going to be. And so, we’re starting to take similar constructs and approaches to what Elliot just described.”
ERCOT is doing that less formally, making assumptions as to where demand is likely to show up on the grid based on where resources are and linking the two with transmission. None of that activity is required by rules, but the hope is that the market will follow suit and plan accordingly.
“It’ll be the fastest way to get there, and it will be the most efficient way to build the transmission infrastructure, but the market will respond to that,” Vegas said.
ISO-NE CEO Gordon van Welie said the transition involves four pillars, but one of them is much less discussed: ensuring the system has enough stored energy in fuel tanks or other long-term options to make it through times when renewable supply is low and demand is high, especially during winter.
“We’ve assumed that problem away,” van Welie said. “Actually, if you go back 25 years ago when we started the market construct, we just assumed that everyone was going to have a reliable fuel supply.”
The clean energy supply in New England is being driven by state mandates, while the issues around resource adequacy and reliability services is driven by the wholesale market. The states have said they do not want to take back authority for resource adequacy, van Welie said.
“They want the kudos from signing the contracts with the green stuff, and they want to leave the problem of how you pay for all that fossil stuff to the ISO and FERC, right?” he added. “So that’s the sort of political dynamic that’s going on there. But in this regard, I agree with [FERC] Commissioner [Mark] Christie, which is the states can’t just walk away from resource adequacy.”
The states have to get behind a market that can support resource adequacy over the long term, because otherwise it will be chaos, with the markets having to be redesigned every three or four years, van Welie said.
One of New England’s longstanding issues is ensuring reliability at the end of the pipeline network during harsh winter weather, which has bedeviled the market at the opposite end of many of those pipelines: Texas. Unlike the Northeast, Texas has plenty of natural gas supply, but it has had its worst reliability issues during the winters, Hunt Energy Network CEO Pat Wood said.
“Gas has two mistresses in the middle of a cold day, and it’s gas customers who keep their homes warm through natural gas and now 62% of Texans who keep their home warm through electric heat,” Wood said. “And that very tight period of time is where you’ve got the problem.”
Texas cannot count on its growing solar resources before the sun rises on a cold winter morning and when wind also is not producing at those times, and the market is not sending a strong price signal that resource adequacy is required in such times, Wood said. After Winter Storm Uri, the price cap was cut back from $9,000/MWh to $5,000/MWh.
The dispatchable reliability reserve service (DRRS), a proposal from the Texas Industrial Energy Consumers working its way through ERCOT’s processes, could help send the right kind of price signals to get needed generation built, Wood said.
While Texas and New England both face winter reliability issues, Calpine CEO Thad Hill, whose firm is active in both markets, noted they have very different causes.
“In the east, we’ve got a fundamental capacity shortage,” Hill said. “In ERCOT, we had a breakdown of preparation.”
Part of that breakdown ahead of Winter Storm Uri came from new oil and gas production capacity that had come online in the Permian Basin since ERCOT’s previous winter reliability problems in 2011, he added. Oil and gas production older than that performed better, while the new Permian capacity often was supplied by the grid and stopped producing when it lost power, exacerbating shortages in both gas and electricity.
While PJM had its hiccups in winters past, historically it has had very healthy reserve margins. But its recent capacity auction saw prices shoot up as those narrowed, which has sparked controversy. (See PJM Capacity Prices Spike 10-fold in 2025/2026 Auction.)
Hill noted that in the past when capacity prices have spiked, his firm and other suppliers have responded with new supply, and he expects that to happen again.
The New Jersey Board of Public Utilities has approved a three-year pilot program to create 200 MW of dual-use solar capacity that puts solar panels on functioning farmland in a precursor to a permanent program.
The board backed the plan with a 4-0 vote Oct. 23, concluding a three-year process designed to establish a framework to encourage the development of solar and also provide economic support for farmers to lease their land.
The program, which will start immediately, sets a target of 50 MW for the first year, with a minimum project size of 500 kW and a maximum of 10 MW. Eligible projects include net metered, non-residential projects with a capacity of more than 5 MW, as well as qualifying grid supply projects paired with a storage facility and net metered, non-residential solar projects of 5 MW or less, according to the board order outlining the program.
Dual-use solar, also known as agrivoltaics, is seen by supporters as way to help farmers struggling in a densely populated state with relatively small farms, while opening up farmland for solar development by ensuring it’s not permanently removed from farm use. Dual-use solar projects include growing crops beneath and around banks of solar panels, or grazing sheep and other animals in the same space. (See New Jersey Solar Push Squeezes Farms.)
Open space in New Jersey is under pressure from housing development and efforts to build warehouses and logistics buildings, fueled in part by the proximity of the Port of New York and New Jersey and vast e-commerce market in urban areas around New York and Philadelphia.
Through the pilot, the state is “advancing our solar energy goals and creating a powerful new tool to create revenue streams for our vibrant agricultural community while promoting farmland preservation,” Gov. Phil Murphy (D) said in a statement.
Projects in the New Jersey pilot will be eligible for incentives under the state’s Successor Solar Incentive (SuSI) Program. The BPU sets incentive levels under the Administratively Determined Incentive (ADI) program, for net metered non-residential solar projects of 5 MW or less, which can pay up to $85/MWh. Grid supply solar projects and non-residential net-metered solar installations with a capacity greater than 5 MW will be eligible for incentives under the Competitive Solar Incentive (CSI) program, but the pilot dual-use solar program will set a base incentive level rather than requiring them to take part in a competitive CSI solicitation.
Developers also can receive another incentive that “covers the incremental costs incurred as a result of participation in the Pilot Program, specific to the agricultural or horticultural aspects of a dual-use project,” according to the order.
Developer Demand
“There’s definitely interest from the farming community,” said Ashley Kerr, legislative director for the New Jersey Farm Bureau, a trade group that represents farmers. “Farmers are already one of the first stewards of the land and do everything they can to maintain their agricultural viability. And this is another tool for that, you know, to minimize energy expenses and potentially even make some extra money.”
Christine Guhl-Sadovy, president of the BPU board, said the pilot will enable New Jersey to “maintain our position as the Garden State, and also our position as a leader in solar development.”
Developer Lightstar, a Boston-based solar developer with 45 MW of agrivoltaics projects in development that grow crops in between the solar equipment, welcomed the pilot’s approval.
Kelly Buchanan, policy manager, said she believes that “developers will jump into the pilot program.”
“There is pent-up demand for dual-use projects in New Jersey,” Buchanan said, noting the three-year wait for the pilot. “The process design ensures that the developers with mature and meaningful agrivoltaics projects can participate in the pilot program, while keeping costs to ratepayers low.”
“We hope that the first 200 MWs will further confirm the cost-effectiveness and multi-faceted benefits of agrivoltaics and will lead to a permanent dual-use program in New Jersey with more flexibility for farmers and lower costs in project design,” she said. The pilot, she added, can provide a “wealth of knowledge” about dual-use solar techniques to help shape future projects and offer “an opportunity for farmer education and training that will be useful examples of successful agrivoltaics projects for the public to see.”
However, she had slight reservations. The maximum project size of 10 MW is a large-enough share of the 50-MW annual capacity that it could crowd out two or three other smaller projects that could drive the sector forward, she said. She added that a pilot rule requiring each project to have a three-acre control plot “that mimics the conditions at the agrivoltaics array, including fencing and crops,” could dissuade some farmers from participating because it takes up too much land.
Improved Agricultural Viability
The pilot is based on the guidelines for an agrivoltaics program in the state set out in a bill signed by Murphy in July 2021. The bill, A5434, required that the BPU, in consultation with the New Jersey Department of Agriculture, adopt rules and regulations for the pilot program within 180 days, or by the end of January 2022. (See New Jersey Plans Dual-Use Solar Pilot Launch for mid-2024.)
The BPU issued a straw proposal for the pilot program in November 2023 and a preliminary rule draft in June. As the process has advanced, the New Jersey Agricultural Experiment Station (NJAES) and Rutgers University have begun a $2 million study at three sites to look at whether crops and cows can thrive next to bifacial vertical and rotating solar panels, which is ongoing. (See NJ’s $2M Agrivoltaics Study Advances.)
The pilot outline states that in addition to the health benefits, and reducing climate change emissions, dual-use solar can give the state “increased resilience in the form of distributed generation.”
In addition, dual-use solar “ensures that the agricultural community can play, not only a larger part, but a more sustainable part in the clean energy transition and can receive the economic benefits of doing so,” the order states. “Dual-use solar can provide farmers with an additional stream of revenue, assisting with farm financial viability and enabling continued agricultural or horticultural production.”
BPU staff recommended a two-stage application process with an initial expression of interest, after which the board would invite the best applicants to submit a full proposal. Proposals would be evaluated on criteria such as the incentive level sought by the project, the interconnection planning, how the developer addressed decommissioning of the project at the end of the 15-year project life and proposals for minimizing negative impacts to farmland.
The staff also recommended that program participants “provide documentation of active agricultural or horticultural use before and after the installation of solar panels.”
State Secretary of Agriculture Ed Wengryn said the program will give farmers “the opportunity for improved agriculture viability.”
“The pilot program will give the agriculture community the opportunity to identify the best production techniques and crops to grow and produce, while at the same time producing clean green renewable energy,” he said.
The Organization of MISO States and Organization of PJM States Inc. have dropped a second letter at MISO and PJM’s doorsteps to emphasize the need for vigorous interregional transmission planning.
This time, the regulators asked in an Oct. 24 letter that MISO and PJM’s interregional transfer capability study include more steps to ensure MISO and PJM conduct wide-ranging and transparent planning.
State regulators requested MISO and PJM as soon as possible compile a list of projects under consideration, their estimated costs and benefits and details as to why the projects are set to either advance or be abandoned.
OMS and OPSI said benefits “could include energy savings, reduced line losses, etc., as long as the benefits calculated lead to real, not hypothetical or theoretical, savings.”
The two organizations stressed that MISO and PJM should perform stakeholder outreach, firm up study deadlines, provide regular progress updates and communicate preliminary findings with stakeholders as soon as practical.
Most OMS members voted in favor of the letter at their Oct. 24 annual meeting; regulators from MISO South abstained from the vote. OMS President and Iowa Utilities Board Member Joshua Byrnes and OPSI President and D.C. Public Service Commissioner Emile Thompson signed the letter. They addressed it to MISO and PJM heads of planning Aubrey Johnson and Paul McGlynn, respectively.
Regulators and the grid operators since have met repeatedly in private to discuss the goals of the study; MISO and PJM have pledged the study will be a multi-act affair, with the first likely producing smaller upgrades and later iterations tackling longer-term needs. The RTOs have said they likely will settle on a first round of small project contenders early next year.
OMS and OPSI’s second letter also recommended the RTOs conduct at least the second segment of the study in accordance with FERC Order 1920, which dictates that solutions be tested against 20-year planning scenarios.
“We understand that a 2032 planning horizon is likely appropriate to identify the near-term upgrades for phase one of this study. However, given that FERC Order 1920 imposes a 20-year planning horizon, a 20-year planning horizon would likewise be more appropriate for future studies beyond phase one,” regulators wrote.
OMS and OPSI added that a follow-up to the first study should take “a more expansive look at interregional planning, including more ambitious studies and process reforms.”
The regulators said they would welcome MISO and PJM working from a joint model and the two adding more interfaces between their systems.
Finally, OMS and OPSI advised MISO and PJM to determine their current interregional transfer capability to use it as a baseline in the study.
“This will help identify current system limitations, the extent transfer capacity is underutilized today and will inform future needs as the bulk electric system continues to evolve,” the regulators said.
In a statement to RTO Insider, PJM said it appreciated “the constructive tone of the correspondence” from OMS and OPSI.
“PJM will review the requests made and will plan to communicate our thoughts to both organizations in the near future,” spokesperson Dan Lockwood said.
MISO likewise said it appreciated the “ongoing collaboration from OMS and OPSI” on interregional studies and promised to share preliminary results of the first interregional transfer capability study at the Nov. 22 teleconference of MISO and PJM’s Interregional Planning Stakeholder Advisory Committee.
MISO spokesperson Mike Deising pointed to MISO’s work on its near-final, second long-range transmission plan (LRTP) as evidence that the RTO is prepared to advance infrastructure for reliability. At $21.8 billion, Deising said the second LRTP is the largest transmission expansion portfolio in the nation and will establish a 765-kV backbone in the footprint that will “facilitate power transfers from the eastern edge of our footprint to the Dakotas.” (See MISO Affirms Commitment to $21.8B Long-range Tx Plan in Final Workshops.)
MADISON, Wis. — State regulators, MISO and members remain anxious over the fragile state of resource adequacy, how much load growth to expect and what a potential new resource adequacy standard might look like.
Regulators and stakeholders descended on Madison, Wis., to talk about the issues at the Organization of MISO States’ annual meeting Oct. 23-24.
Load Growth: Swift! Shocking! Legitimate?
Electric Power Research Institute’s David Larson said data center growth mapping efforts quickly become outdated as requests for interconnection routinely exceed expectations in number and size.
He said the “AI race has now become a powering-AI race.”
“There is a question of: ‘How much of this is real?’” Larson said. He said utilities sometimes treat requests as not definite until construction begins, while some assume only a percentage is likely.
Mike Benn, with data center developer STACK, said “availability and certainty of power” is top of mind for companies that require newly built data centers. He said that though load growth numbers are big and real, some speculators are calling utilities to inquire about available capacity or those in a race to try to hoard capacity.
Benn said it’s important that data centers be part of the solution in securing energy.
“It might be very cathartic to call up the utility and yell, ‘You promised you had this capacity to serve us, now you don’t!’ That helps no one,” Benn said.
“Has anybody checked their email by phone or computer? If so, you’ve used a data center,” Google’s Tyler Huebner asked.
Huebner said individual companies for the most part have abandoned their backroom servers and have migrated services to data centers. The eradication of the small server rooms to large data centers is more efficient and ultimately saves more water and power, he said.
Huebner said Google strives to forge partnerships with utilities and companies to become a market force for sustainable energy, backing geothermal projects, storage and small nuclear reactors, sometimes above market prices.
“We’re willing to bring financial commitments and collateral to the table,” he said.
However, Huebner said while Google doesn’t want to raise customer prices, it also doesn’t want to entirely fund projects it no longer has use for, especially when those projects’ output gets claimed by other industries.
Huebner said it used to be a matter of securing real estate and then figuring out the rest to site a data center.
“Now it’s power and nothing else,” he said.
NextEra Energy’s Erin Murphy said NextEra is approaching MISO, looking for ways to link proposed generation resources and their designated loads in MISO’s generation interconnection study process to meet the needs of industrial customers.
Murphy said with the MISO queue’s current five-year wait times, a MISO fast-track for resources with contractual agreements to serve load would be helpful.
Larson said some hyperscale loads might be flexible but that EPRI encounters challenges getting data centers to publicly share demand response capabilities for analysis.
“Data access is a huge bottleneck for us. We’ll have folks that say, ‘Trust us, it’s a flat load,’” he said.
Ryan Long, Xcel Energy president of Minnesota and the Dakotas, said much of the “angst” associated with the energy transition today boils down to the industry “living between” major eras.
“We’re in the seam between power-sector decarbonization and economy-wide decarbonization. … We’re trying to find our way through the energy transition and bring along other industries,” he told attendees.
Long said when Xcel Energy’s Northern States Power retires its Allen S. King and Sherco coal plants by 2030, it will lose 3 GW of its 9 GW portfolio.
“That means we’re going to lose a third of generating on our system. And we have a whole lot of work to do and construction to do,” he said.
Long said Xcel doesn’t assume it will rely on the MISO market to serve load in future-looking analyses. He said the move is somewhat controversial, but he believes load-serving entities should build generation to meet their native loads and use the market only to optimize financial outcomes and earn economic hedging.
Long said the rise of data center load can be considered the “first ship in the port,” with manufacturing and transportation growth to follow as the energy industry further decarbonizes and adds firm resources.
Long said ratepayers can benefit if utilities carefully structure agreements with large customers. He said large customers can help steer a swifter transition, and he predicted hyperscale customers will drive the advancement of small modular reactors.
“We’re running out of nuclear plants that are sitting around that could be brought back online,” he joked, and later said: “There is a real need to think about how we can all move faster.”
That’s led Xcel to turn to an iron-air, “rusting and unrusting” battery facility in Becker, Minn., through a partnership with Form Energy; a solar farm at the Sherco site; and extending the lives of its two nuclear plants beyond 2050, Long said. He added that Xcel is betting on battery storage by planning to build an additional 600 MW in addition to the iron-air battery facility.
He also said Xcel proposes to add anywhere from 400 MW to 1 GW of distributed resources at strategic locations.
“At the distribution level, you can add resources fairly quickly, and it feels like the moment certainly calls for an all options on the table strategy,” Long said.
RA Targets on the Move
MISO Executive Director of Markets and Grid Research DL Oates said given the zeitgeist, MISO’s role in providing supply and demand outlooks becomes more critical. He pointed to MISO and OMS’s annual resource adequacy survey and its regional resource assessment as increasingly important reference points for construction plans.
Oates said because the environment is so uncertain, publishing a range of possible outcomes from scenario-based modeling is appropriate. He said he realizes utilities are building long-lived assets, and a planned facility sometimes can be found to help under several possibilities.
Oates also said because risks are growing more complex, MISO needs a more complex reflection of resource adequacy, expressed partly through its new capacity accreditation method, which FERC happened to approve the next day (ER24-1638). (See related story, FERC Approves New MISO Probabilistic Capacity Accreditation.) Oates said MISO understands it needs to conduct analyses to predict how its proposed resource accreditations for resource classes are likely to change over time based on how much they can help.
Midwest Reliability Organization’s Mark Tiemeier said across NERC, EPRI and ESIG, there’s consensus that the one-day-in-10-years loss-of-load standard is passé when used alone.
“To me, it’s a very binary answer,” he said, though he added that he didn’t think grid operators would scrap it entirely.
Tiemeier said with the past no longer an indicator of what’s to come with reliability, grid operators need to turn more toward a least-regrets standard that combines multiple elements.
He also said MRO has asked for more consistency across the data regions to provide NERC for its reliability assessments. He said more data consistency would lead to more accurate comparisons between regions.
Oates agreed MISO likely needs multiple metrics beyond its one-day-in-10-years standard to measure adequacy. (See MISO Dips Toes into Potential New Resource Adequacy Standard; States Demand Key Role.) MISO has said it might consider a combination of conditional value at risk, loss-of-load hours and expected unserved energy in addition to the one-day-in-10-years criterion.
Oates said while multiple grid operators explore adopting new modes of resource adequacy measurements, they’re not all examining the same methods, creating the possibility that RA standards will become even less homogenous.
“When you look at where to move to, there’s a lot of heterogeneity there. And I think that’s a hallmark of living in a time of change,” he said.
“I think if there’s anything that be taken from this, it’s complicated,” joked Wisconsin Commissioner Marcus Hawkins.
Signifying how often RA issues have come to the fore, OMS members passed a motion to create a resource adequacy committee.
Former State Regulator Says Commissions Need More Hands, Data Analysis, Openness
Known for his frankness, Kent Chandler, former Kentucky Public Service Commissioner and a new addition to center-right think tank R Street, was invited to speak on how commissions should equip themselves as resource adequacy concerns and load growth take firmer hold in the footprint.
Chandler encouraged commission staff to “shoot for the stars” with their budget asks and correct understaffing now. He advised commissioners to double the level of resources they think they can operate with.
Chandler said commissions suffer from getting “asymmetrical” data from utilities. He said at the Kentucky commission, just one staff member usually would review data submittals from utilities for completeness.
Chandler also said commissions are privy to substantially more information from vertically integrated utilities in RTOs versus vertically integrated utilities that aren’t in RTOs.
“I couldn’t tell you where any congestion is on the [Louisville Gas & Electric and Kentucky Utilities] system,” he said as an example.
Chandler told commissioners and staff to “hold your utilities to account” based on the data they can retrieve. He told them to ask utilities what they’re doing about resource planning, why they’re making certain offers in the wholesale market, or why they’re not addressing congestion “that shows up five days a week.”
Commissions also are “woefully” short on distribution system expertise, Chandler said.
“Very few people who I’ve ever interacted with know how the distribution system works,” he said.
Chandler said it’s important to recruit people with distribution system knowledge as distributed resources — demand response, batteries, generation — will play a more integral role in resource adequacy, like it or not.
Chandler also said while he wouldn’t say MISO has it right on resource accreditation, it’s moving in the right direction by measuring capacity contributions when resource adequacy is the frailest.
“I think it gives owners an incentive to make sure their generation is best in class,” he said, adding that MISO could add a layer to its accreditation where it shows locally what type of generation would be most helpful.
“This is my Festivus. It’s my airing of the grievances. It’s professional; it’s not personal,” he joked.
Finally, Chandler said it might be worthwhile for OMS to set up private meetings between its board and the MISO Board of Directors to discuss major initiatives to be filed at FERC. He said the MISO board should want to know how its regulators fall on MISO’s proposals.
In closing, Chandler told regulators to be willing to admit when their processes aren’t working and work to improve them. He also told regulators to not be afraid to hear opposition, and said he never understood denying interventions in dockets. Chandler said though he’s not a “Kumbaya-type of person,” there’s value in interacting with people who disagree with you.
“Everybody thinks their baby is the cutest. It’s almost never true. There can only be one cutest baby. There’s always a way to do things better. … You can make your baby cuter,” Chandler said.
NYISO’s transmission planning requirements result in a need for more capacity than is required in the ISO’s market rules, according to Potomac Economics, the Market Monitoring Unit.
Potomac highlighted the gap between what it calls the “effective planning requirement” for transmission security and capacity market requirements in a presentation before the NYISO Operating Committee on Oct. 24.
“The reliability planning process effectively requires more capacity to meet transmission security needs than is represented in the capacity market requirements that are ostensibly based on transmission security,” according to a memo Potomac sent to the ISO. For the 2025/26 capability year, Potomac said the effective requirement for New York City is 743 MW higher than its locational capacity requirement.
NYISO this month found a potential reliability need by 2033 for New York City, which would trigger a process in which the ISO solicits solutions from utilities and stakeholders, including non-market interventions. (See NYISO Draft RNA Finds Reliability Need for New York City.)
“Within the next five years, the base case assumptions become much more important when reliability needs appear,” Pallas LeeVanSchaick, vice president at Potomac, told the committee. “If there are not forthcoming market-based solutions, then there’s the potential to identify a need that requires an out-of-market investment to resolve it. That raises concerns.”
The MMU noted the 565 MW of peaking units retained in Brooklyn to address a reliability need identified in a Short-Term Assessment of Reliability in 2023. Despite that, the city is expected to have an over 800-MW surplus in summer 2025.
“Out-of-market actions to satisfy the planning requirements increase risk to investors by depressing capacity prices below anticipated levels,” it said.
LeeVanSchaick said that special-case resources — a type of demand response for large loads — were not being counted in transmission security analyses because they are only called upon in emergency conditions. Surplus capacity, he said, was being overcompensated in part because it was being set by the inflated transmission security floors.
“When SCR program resources also participate in peak shaving programs, the resulting load reductions are not counted towards satisfying the reliability need even though they occur during normal operations,” the MMU said. “This treatment significantly increased capacity shortfalls in the transmission security analysis of the RNA and inflates the transmission security limit for New York City by a comparable amount.”
The MMU recommended including loads participating in peak shaving and emergency DR programs in transmission security analyses and compensating capacity suppliers based on the requirements they contribute to meeting. It also repeated a previous recommendation that NYISO implement more granular capacity zones, particularly in places like New York City, and update them dynamically.
The OC voted to send the draft RNA to the Management Committee, though it changed the motion from an approval of the draft itself to an approval of its findings.
NYISO also presented the results of the 2024-2025 Winter Assessment, finding that the ISO expects sufficient winter capacity assuming that all firm fuel generation is available under both normal and extreme weather conditions. The ISO cautioned that disruptions in fuel supplies could create problems for the grid given the reliance on firm fuel generation during extreme cold weather.
In a much-anticipated move, the New Jersey Board of Public Utilities on Oct. 23 adopted minimum filing requirements that allow utilities to propose programs to promote the development of medium- and heavy-duty (MHD) electric vehicle chargers.
The 4-0 vote approving the rules concluded a three-year process to craft a plan to fund and install MHD charging infrastructure that is either publicly accessible or used to set up private fleet charging depots. The plan allows utilities to award incentives totaling up to $55 million over two years for charging infrastructure projects that meet the criteria.
State officials consider the availability of a heavy-duty charging system key to tackling the largest source of carbon emissions in the state: transportation. The goal is to motivate truck users to adopt electric vehicles by removing the fear that they will run low on power en route and won’t be able to find a recharge site.
The approval follows the initial release of a “straw proposal” of rules June 30, 2021, and a second straw proposal Dec. 22, 2023.
“I know this one was long and eagerly awaited,” BPU President Christine Guhl-Sadovy said after the vote.
“A lot of work went into this by staff, by our partners, and certainly by stakeholders in their comments and discussions over the years,” she said. “I think we’re all really excited to see this, and I know relieved.”
The vote came the same day that EPA Regional Administrator Lisa F. Garcia, New Jersey Department of Environmental Protection Commissioner Shawn M. LaTourette, and other federal and state officials gathered at a New Jersey Turnpike rest stop in Ridgefield to mark the receipt of $250 million in federal funds to install MHD EV chargers on the I-95 corridor.
The BPU’s process, however, is separate from the highway projects, which won’t be affected by the BPU’s rules, spokesman Bailey Lawrence said.
Anjuli Ramos-Busot, director of the New Jersey Sierra Club, called the approval a “huge milestone not only for clean transportation, but also for climate and clean air.”
“New Jersey is one of the most densely populated states in the nation, and as such, our transportation sector is one of the dirtiest,” she said. “Electrifying fleets at a local and state level will directly benefit our communities who experience roadway pollution.”
She added that “we are hopeful the utilities in the state will follow through with good programs to electrify our fleets and charging infrastructure that contain equity provisions.”
Shared Responsibility
The rules make the four electricity utilities that serve the state — PSE&G, Jersey Central Power and Light (JCPL), Atlantic City Electric (ACE) and Rockland Electric Co. (RECO) — “responsible for the wiring and backbone infrastructure necessary to enable a robust number of MHD make-ready locations throughout the state.” Each utility must file a two-year MHD plan within 120 days of the order’s approval.
The order describes a “shared responsibility model (that) will bring significant investment into MHD EV charging while protecting consumers and ratepayers, facilitating a smooth rollout of EV charging infrastructure.”
Private infrastructure companies, site owners and industries will own, operate and install the chargers, and an industry working group will address emerging issues such as rate levels, demand chargers and other factors, including interconnection, local generation and storage issues, the order approved by the board states.
Utilities can invest in and earn a return on backbone and infrastructure make-ready wiring for publicly accessible charging depots, those that serve public-serving fleets and government agencies. In each case, the utility can provide up to 100% funding, including offering incentives.
Utilities also can invest in infrastructure that supports private fleet charging depots that are in overburdened communities or municipalities but can provide only up to 50% funding, including incentives, according to the rules.
But utilities can own and operate MHD charging stations only in certain circumstances, according to the rules. That can happen if the proposed charging station is in an area of “last resort,” in which no private company has stepped up to install a charger for 18 months, and 24 months if the station is in an overburdened area, according to the rules.
This “shared responsibility model will bring significant investment into MHD EV charging while protecting consumers and ratepayers, facilitating a smooth rollout of EV charging infrastructure,” according to the board order.
The rules provide for PSE&G to award incentives up to $30 million, JCPL to award up to $15 million, and ACE and RECO to award up to $5 million each.
“Providing more charging for electric delivery vans, trucks, school buses and transit buses, especially for public fleets, is the path forward to clean our air and clean our fleets,” said Doug O’Malley, director of Environment New Jersey. “This board action will help pave the way for an electric bus and truck future.”
The newest crop of wind farm proposals off the New York coast includes the largest plan ever submitted there, or apparently anywhere else in U.S. waters.
The latest iteration of Community Offshore Wind is a two-phase project that would reach peak output of up to 2.8 GW in the early 2030s.
Community has a simultaneous 1.3-GW proposal under consideration by New Jersey regulators. (See 3 OSW Proposals Submitted to NJ.)
Daniel Sieger, head of development at Community Offshore Wind, spoke recently to NetZero Insider about the evolution of the joint effort by RWE and National Grid Ventures and its direction from here.
Community is not hedging by bidding different versions of the same project into two states at once, he said. It wants to send power to both.
“We have a large lease area that can accommodate multiple projects,” Sieger said. “We’ll see how the process plays out with both New York and New Jersey, but right now, those are both active proposals.”
Community Offshore Wind’s wind lease area is south of New York and east of New Jersey. | Community Offshore Wind
When Community won lease area OCS-A 0539 in the February 2022 New York Bight auction, the U.S. Bureau of Ocean Energy Management calculated the energy potential of its 125,964 acres conservatively at 1,387 MW.
Community’s decision to propose up to 4,100 MW there reflects how far technology has evolved in the intervening three years and how much further it is likely to improve before the time comes to put steel in the water.
“The full capacity is going to depend on turbine technology and permitting and will be done in consultation with state and federal officials,” Sieger said. “But we think that we have the possibility of three different phases of project development in our lease area.”
The path to this point has been neither straight nor smooth: Community has struggled against the same headwinds that have affected the entire industry in the past two years. This latest proposal is its fifth attempt to land a contract.
It proposed a 1.3-GW project in New Jersey’s third solicitation (NJ3), then withdrew it to reassess the financials and the process. (See NJ Awards Contracts for 3.7 GW of OSW Projects.)
It nearly won a 1.3-GW contract in NY3, along with two other developers, but all three conditional contracts had to be scrapped when the GE Vernova halted development of the 18-MW turbine that would have made the contracts financially viable. (See NY Offshore Wind Plans Implode Again.)
It submitted a 1.3-GW bid in NY4, a rush solicitation New York put together after the state’s offshore portfolio collapsed, but New York instead awarded contracts to two mature projects that could get steel in the water sooner. (See Sunrise Wind, Empire Wind Tapped for New OSW Contracts.)
Community now is awaiting the two states’ decisions on the combined 4.1 GW it proposed in NJ4 and NY5.
The progress to date might seem frustrating, but it is not wasted time. Development continues even as a particular path ends or is rerouted; proposals are updated and reshaped through what has become an iterative process.
“The project and the plans evolve as we go further into development and we mature the project,” Sieger said. “But this proposal that we have submitted here [to New York] I think is really well positioned for selection and well positioned to deliver.”
Sieger joined Community shortly after the 2022 auction and has seen shifts as industry, state and federal leaders tried to push offshore wind forward through some strong headwinds in the past two years.
Daniel Sieger, head of development for Community Offshore Wind. | Community Offshore Wind
“I think with any new industry, there’s going to be some ups and downs and some stops and starts,” he said. “But I think we’re really starting to see the industry mature here in the United States, to the point where we’ve got projects in operation in the United States, we’ve got projects under construction.”
In its NY5 bid, Community says it would start generating power in 2030 and reach completion in 2032. That time frame should give it some breathing room to let offshore wind technology evolve and a U.S. ecosystem grow to support it.
But there still is a chicken-and-egg balance to strike, in which enough projects are greenlighted far enough in advance to justify building ports and factories, and enough ports and factories are built soon enough to support those projects. The balance goes far beyond development in any one lease area, but Sieger said Community’s plans are big enough to help move the needle.
“I think that as the offshore wind industry and market matures in the United States, we’re going to see a lot of opportunity for localization of the supply chain,” Sieger said. Their project is an opportunity for certainty in the market, “to sort of lock in that pipeline that’ll unlock some of the investment for some of these supply chain entities to localize.”
Community still has not settled on a particular turbine model, port, installation vessel or many of the other critical pieces of building a wind farm.
One of its most publicly visible efforts has been toward public visibility — engaging with the stakeholders and local residents who will influence the reception Community’s proposals receive and the ease with which they move through the review process. Its social media feeds are packed with examples.
Community faces a potential public relations test with one of its possible export cable routes, which would run to the south shore of Long Island near a city that mounted strong opposition to Empire Wind 2’s proposal to use the same point of interconnection. (See ‘What Did We Do to Deserve This?’) That proposal was withdrawn recently, 27 months after it was launched. (See Equinor Yanks Request for Empire Wind 2 Export Cable.)
Sieger did not discount the prospect of local opposition, but he did not seem daunted by it, either.
“We have prioritized, since day one, active engagement on the ground with the communities where our project is going to be located,” he said. “As we enter into the permitting process and the siting process and the routing process, we intend to continue those conversations and work hand-in-hand with the local communities to determine the best route from the landfall to the point of interconnection.”
Along the way, Community is working to recruit allies. In its NY5 proposal, it has committed to $64 million in workforce development, up to $250 million in manufacturing development, $121 million in community support and more than $67 million in fisheries assistance. It also has pledged to support organized labor, disadvantaged communities, minority/women/veteran-owned business and other priorities baked into New York’s offshore wind initiative.
The projected cost of proposals submitted in NY5 by Community, Ørsted and Vineyard Offshore is likely to be substantial but will not be revealed until the state finalizes contracts, which is expected in the first quarter of 2025.
One clue: Community Offshore Wind said its 2.8-GW proposal would drive roughly $3 billion in economic activity, more than $2 billion of it in-state spending.
PUC Hears State’s First System Resiliency Plan, Filed by Oncor
The Texas Public Utility Commission postponed action on Oncor Electric Delivery’s resiliency plan, the first from a state utility under new legislation, during its Oct. 24 open meeting.
Commissioner Jimmy Glotfelty asked for more time before approving, modifying or denying Oncor’s three-year system resiliency plan. The commissioners — meeting without Lori Cobos, who was excused following a death in her family — agreed to postpone a decision until its Nov. 14 open meeting (56545).
“This proceeding is the first of its kind, and I would like to request additional time to consider the plan, the agreed modifications and Oncor’s responses to any questions from the commissioners,” he said in a pre-meeting memo.
Texas House Bill 2555 directed the state’s transmission and distribution utilities to strengthen the resiliency of their systems. Oncor said its resiliency plan is “comprehensive and forward-looking” to proactively withstand, mitigate or quickly recover from the “historical and evolving resiliency events” it expects to affect its system.
An administrative law judge approved the Oncor plan in September, finding it in the public interest.
Brian Lloyd, Oncor’s vice president of regulatory policy, told the PUC that a “constructive” settlement agreement with commission staff and several other parties gives the utility an opportunity to bring forward some of the plan’s spending into this year.
He said the utility mapped its entire distribution system against all extreme weather events since 1998, including extreme heat and cold, major storms and wildfires. Oncor has identified wildfire risk as a major threat to the distribution system; with much of Texas suffering from drought conditions, Lloyd appeared eager to put the plan into effect.
“We have had red flag days on our system this week,” he said. “The state is dry. We know that we are ready to go to further address that risk. As soon as you are comfortable with this, do so.”
Oncor said it’s limiting its recovery of the plan’s capital costs to $2.8 billion and another $521 million in incremental operations and maintenance expenses for 2024-2028. It will defer $309 million in capital costs and O&M expenses to a fourth system resiliency plan year.
Commission Delays Decision on CenterPoint
The PUC agreed to put off a decision on CenterPoint Energy’s attempt to withdraw a $60 million rate case until the commission’s next open meeting on Nov. 14 (56211).
PUC Chair Thomas Gleeson said he had been ready to reach a decision during the meeting but no longer was prepared to do so. He suggested to his fellow commissioners that they rule on CenterPoint’s request no later than the next open meeting.
“I still have some things I need to work through, because I’m still not sure which way to come down on this, honestly,” he said. “I think there are really good points on both sides.”
CenterPoint said withdrawing the rate case, originally filed in March, and refiling it next year would allow it to use 2024 as the test year. An administrative law judge denied CenterPoint’s request to withdraw the rate case in August. The utility then appealed the decision to the PUC.
Gleeson said that during a recent public hearing in Houston, residents expressed a desire for the PUC to evaluate CenterPoint’s performance during and after Hurricane Beryl. The Category 1 storm knocked out power to nearly 3 million customers in the Houston area. CenterPoint was castigated for its poor communications during a recovery effort that lasted more than a week. (See Texas Politicos, Residents Bash CenterPoint.)
“One way to [evaluate CenterPoint’s performance] is to allow them to withdraw this case and then force them to file sometime in 2025 with the 2024 test year, where we could hear evidence about performance during Beryl and their infrastructure improvements,” he said.
CenterPoint associate general counsel Patrick Peters told the PUC that allowing the utility to withdraw from the rate case would allow it to focus on its work improving resiliency and restoring public trust. He said the utility then would be able to incorporate its learnings from Beryl into a new rate case.
Politicians, including Houston Mayor John Whitmire, and several consumer groups have called for a rate decrease and oppose the withdrawal.
The commission also declined to act on CenterPoint’s proposed 138-kV line in a high-growth region north of Houston. The utility said the line is necessary to address the strained existing system, but it has run into opposition from local residents (55768).
At the same time, the PUC rejected CenterPoint’s settlement with commission staff, the city of Houston and the Gulf Coast Coalition of Cities to adjust the utility’s system-average interruption duration index (SAIDI) and system-average interruption frequency index (SAIFI). Gleeson said the utility’s continued use of a one-minute threshold for the next seven years is “incongruous” with improved technology that “already addressed the issue” (55361).
Processes Set for Permian Projects
The commissioners approved staff’s plans to streamline and expedite the selection of transmission companies responsible for building projects in the Permian Basin Reliability Plan (57152).
Staff recommended a bifurcated contested case system where projects without disputes between transmission service providers (TSPs) and ERCOT over the responsibility for building lines and facilities would be grouped together in one proceeding.
TSPs with disputes will be able to file petitions for authorization to file for permits. Multiple petitions for the same project will be merged into a single contested case proceeding “as soon as practicable.” If necessary, the state Office of Administrative Hearings will hold hearings on the dispute.
ERCOT has laid out suggested principles it would follow in determining ownership of the plan’s projects.
The PUC approved the plan in September. It includes 765-kV and 345-kV infrastructure to support the region’s current and future power needs and new and upgraded local projects, as well as eight new import paths that will bring more power to the petroleum-rich region. (See Texas PUC Approves Permian Reliability Plan.)
California regulators have approved changes to a zero-emission truck regulation to make compliance easier, keeping their end of a deal with truck manufacturers over the transition to ZEVs.
The California Air Resources Board (CARB) voted Oct. 24 to adopt amendments to the Advanced Clean Trucks (ACT) regulation. ACT requires medium- and heavy-duty truck manufacturers to provide zero-emission vehicles as an increasing percentage of their annual sales in the state. The regulation takes effect with model year 2024, but manufacturers have been able to earn early credits since model year 2021 with options to bank and trade credits.
If truck makers don’t meet their quota in a particular year, they’ll now have three years to make up the deficit, rather than the one year allowed before the amendment. Providing even more flexibility, credits from near-zero-emission trucks may now be used to meet up to half of the carried-over deficit. NZEVs, which include plug-in and wireless-charging hybrids, generate partial credits based on their all-electric range.
Another change to the ACT regulation is the manner in which ZEV credits are earned. Under the approved amendments, a manufacturer earns ZEV credits by producing and delivering a zero-emission truck for sale in California. Previously, the ZEV had to be sold to “the ultimate purchaser in California” in order to generate a credit.
“[Manufacturers] will no longer have to follow and document a vehicle’s entire pathway through upfitters and dealerships to its actual owner-operator,” Kat Talamantez of CARB’s mobile source control division said during the hearing.
Instead, manufacturers will receive credits when a ZEV is delivered to the initial entity, such as a dealer.
Clean Truck Partnership
CARB agreed to pursue changes to ACT as part of a deal it made with truck manufacturers in July 2023 called the Clean Truck Partnership. In exchange for CARB giving manufacturers more flexibility to comply with its regulations, the truck makers pledged to meet California’s vehicle standards, including a requirement to produce and sell only ZEVs starting with model year 2036. (See CARB, Manufacturers Partner to Support Clean Truck Rules.)
And under the agreement, the manufacturers’ commitment will continue even if the regulations face legal challenges. The partnership includes CARB, the Truck and Engine Manufacturers Association, and 10 truck manufacturers.
In addition to ACT, the agreement addresses CARB’s heavy-duty engine and vehicle omnibus rule, a 2021 regulation that increased the stringency of tailpipe emission standards for trucks with internal combustion engines. The regulation allows the sale of a certain number of “legacy” engines that meet 2010 standards; in 2023, CARB raised the cap on legacy engine sales to help prevent a shortfall during a 2024-2026 transition period.
Diesel Engine Shortages
The proposed amendments to ACT were presented to the CARB board in May, but a vote was postponed after several dealers said they were having problems getting diesel trucks from California manufacturers. Some said the ACT regulation was to blame. The speculation is that manufacturers are withholding internal combustion trucks to reduce the number of ZEVs they’re required to provide.
CARB staff researched the issue, meeting with more than 40 dealers, fleet owners and manufacturer representatives.
The issue turned out to be “complicated with several contributing factors,” Talamantez told the board.
“However, all manufacturers have explicitly indicated that the product availability issues for the 2024 model year are not caused by the ACT regulation,” she said.
Further evidence that ACT is not causing diesel truck shortages is the ample supply of ZEV credits, CARB Executive Officer Steven Cliff said in a memo to the board.
CARB has noted that the number of ACT credits from model years 2021 and 2022 were about 60% more than the amount needed to meet requirements expected for model year 2024, and even more credits were racked up in model year 2023. (See California Far Outpacing Clean Truck Targets.)
Many truck manufacturers have accumulated their own ACT credits, and most are open to buying credits “if the economics make sense,” the memo said.
Instead, the diesel truck shortage may be related in part to the heavy-duty omnibus regulation and manufacturers’ “intentional business decision” to produce the limited number of engines that are not compliant with the regulation, as allowed by its legacy provisions, Talamantez said during the meeting.
Other factors contributing to the diesel truck shortage include a nationwide downturn in the market, lingering supply chain issues and manufacturers not yet being ready to comply with the omnibus regulation.
Cliff noted in his memo an apparent “discrepancy” between what manufacturers are telling their customers about the diesel truck shortage versus what they’re saying to CARB.
Cliff said truck makers might be telling customers the shortage is due to ACT as “a sales strategy to continue ramping up ZEV sales and towards building a credit bank for the ACT requirements in the 2025 and 2026 MYs despite the current surplus of ACT credits.”
