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November 30, 2024

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Data Center Load Uncertainty Tied to Broader Economy, Google Rep Says

SAN DIEGO — The volume of data center load growth in the U.S. will depend on how things play out in the broader economy, a Google representative told a gathering of Western state energy officials Oct. 23. 

“You should really think about data center demand as sort of an aggregation of the demand for digital services throughout the economy, and this demand is large and growing,” Dylan Sullivan, energy market development strategic negotiator at Google, said during a panel discussion on large loads at the fall joint meeting of the Committee on Regional Electric Power Cooperation and Western Interconnection Regional Advisory Body (CREPC-WIRAB) in San Diego. 

Sullivan kicked off his comments by asking audience members to raise their hands if they’d worked on a shared document or streamed video in the past week — or checked email within the past 15 minutes. 

“That’s everybody,” he said to laughter. “Well, then you used a data center.” 

Sullivan ticked off a list of Google’s online services, from Maps to YouTube to Gmail. He said Google Cloud provides computing services to hospitals, local governments, schools and “some of America’s fastest-growing companies” — including 70% of generative artificial intelligence companies, valued at more than $1 billion. 

As a result, Google’s global electricity consumption reached 25 TWh in 2023 — “equivalent to a North Dakota-sized state” and more than double its 2019 consumption. But he didn’t provide specific figures for Google’s demand in the U.S. or the West. 

And utility commissioners couldn’t pin him down on the company’s projections for future growth in data center load. 

Washington Commissioner Milt Doumit noted the share of U.S. electricity consumption from all data centers is expected to grow from 4% today to 9% by 2030. 

“What is your modeling [showing]? What is growth going to look like beyond 2030, if you can tell us?” Doumit asked Sullivan. 

“There’s some things that we just don’t know the answer to, and I think putting more provisions in place to put more of this forecast uncertainty onto large users is an important way to understand how much we can expect over time, but we don’t know the path of [the use of data] visualization and artificial intelligence in our economy,” Sullivan said. 

Sullivan noted that Google has three operating data centers in the West, including in The Dalles, Ore., and Storey County and Henderson, in Nevada, with another under construction in Mesa, Ariz., near Phoenix.  

Colorado Public Utility Commission Chair Eric Blank, the panel moderator, asked why companies such as Google are locating data centers in an increasingly heat-stressed area like Arizona, which has seen two straight summers of recording-breaking averages for daytime and overnight temperatures. 

Sullivan said the decision largely comes down to the location of its growing segment of cloud-based computing customers. 

“Basically, you click the mouse on a laptop, [and] you see the impact of that right on your screen,” he said. “If that computer were 200 miles away from you, you would notice the difference and not like it. And cloud customers are the same, so that they have certain requirements for latency [in computing]. They want ‘compute’ to be close to where they are.” 

In working with electricity and water utility Salt River Project (SRP) to supply the Mesa data center, Sullivan said Google determined its draw on the local water supply would be unsustainable, so it instead chose to air-cool the facility, which caused “a bit of an energy penalty.” 

“But we have a mix of resources through SRP that gets us to a very high percentage of renewable energy around the clock now, on a 24/7 basis,” he said.  

Real or Hype?

A recurring question during the panel and among attendees who spoke with RTO Insider at the CREPC-WIRAB meeting was whether the extreme projections for data center load growth are “real” or a speculative overestimate stemming from either hype or the fact that data center companies could be shopping multiple utility service areas for the same proposed facility, causing double-counting across utility load forecasts. 

“We don’t know how much the demand is real,” Sullivan said. He explained that when Google developed its first data center in The Dalles, the company was growing at a time when it was “soaking up” excess energy capacity on the grid, just as overall economic growth in the U.S. was decoupling from its historical connection with parallel increases in electricity use. 

“But now, with the onshoring of manufacturing, electrification [and] with data center demand, capacity is now tight, and that creates a problem for the industrial site selectors, where the time it takes to energize a site is lengthening,” he said. “And there’s uncertainty about the ability to interconnect the site, and that’s led to a natural response of people essentially filing multiple requests” for the same data center plan. 

“Here’s my take on it: The load is real. It’s a question of what’s the actual volume,” said Brian Cole, vice president of resource management at Arizona Public Service (APS). “It’s hard to see where there’s overlap and where there’s not. That makes it difficult.”  

Cole said APS has created a new data center strategy team to deal with the issue. He said the utility “literally” is having daily conversations with data center companies. 

“We’re trying to learn from them, trying to understand what they need, trying to work with them, [and] trying to establish what is the best path forward,” he said. “Regardless of the path and how we do it, the reality is it’s going to require a lot of building, it’s going to be a lot of resources, and it’s going to be a lot of transmission.” 

Cole said the utility’s goal is to serve all customers while maintaining reliability and avoiding cost-shifts among those customers. 

Antoine Lucas, vice president of markets at SPP, said that, since the COVID-19 pandemic, his RTO has fielded 40 GW of customer interconnection requests, with about 15% of those resulting in load interconnection agreements. 

“Looking forward, though, we’ve seen quite a few projections that those numbers will increase,” Lucas said, partly driven by new demand, but also because SPP has integrated a large number of renewable resources. 

“That has been something that’s been attractive to a lot of these entities who are willing to bring data centers or other businesses into the footprint,” he said. 

Lucas also clarified that he thinks SPP’s 15% customer interconnection rate is like the section of prospectus for a mutual fund stating that “historical performance is not indicative of future returns.” 

“We know there will be an increase, but we know there are also factors that impact it as well — cost being one of those major considerations,” he said. “In my opinion, it’s not so much whether or not we’re going to see an increase, it’s just going to be where does it happen?” 

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Panels Debate PJM Capacity Market Design at OPSI Annual Meeting

COLUMBUS, Ohio — Uncertainty was the throughline across several panels on the state of PJM’s markets during the Organization of PJM States Inc. (OPSI) Annual Meeting, as state regulators, market participants and RTO officials discussed a possible delay in the 2026/27 Base Residual Auction (BRA) and debated the eightfold price spike in the prior auction.

PJM CEO Manu Asthana said that any time a change to auction rules or timelines is made, regardless of the merits, investor and consumer confidence in the outcomes can be damaged. Without certainty about price signals, he said the financing necessary to bring new resources to the markets can be impacted at a time when PJM projects resource adequacy shortfalls in the latter years of the decade. Balancing the need to deliver prices reasonable to consumers while sending price signals to invest could mean making hard decisions about what priorities the U.S. has in designing the future of the electric sector.

“I have a fear that without more explicitly choosing whether we’re going to actually relax some of our environmental goals; or if we’re going to relax our desire to win the AI race; or we’re going to be willing to pay higher prices; or we’re going to put all of our chips in to invent a new technology that comes up with this green and cheap power; that we will not actually have any of these things. We will not have a reliable grid; we will not have an affordable grid; and we may not be able to serve all of the data centers,” Asthana said.

In contrast to Asthana’s concerns about resource adequacy at the 2022 OPSI meeting, he said he’s more worried now about the confluence of permitting and supply chain challenges, accelerating load growth and increasing public policy pressure on generators. Developers considering building new gas-fired capacity in PJM have to weigh EPA regulations that require carbon capture and sequestration against the revenues that can be received through PJM’s markets.

“You’re seeing that in investment: If you look at what is coming through our queue, the picture is pretty dramatic. You saw gas plants, gas plants, gas plants; this year, almost no gas,” he said. “I’m not saying we only need gas; we need everything.”

To address resource adequacy concerns, Asthana said PJM seeks to make three key changes to how resources can come onto the grid: the process for transferring capacity interconnection rights (CIRs) from a deactivating generator to a new resource; surplus interconnection service (SIS) to allow new resources to be co-located at underutilized interconnections; and a reliability resource initiative (RRI) to create a one-time expedited application window for high capacity factor resources to be studied in Transitional Cycle 2.

The RRI concept has been met with criticism from many stakeholders who argue it would amount to preferential treatment for some resource classes at the expense of renewables that have been waiting years for interconnection studies to be completed. PJM has responded that new resources with a high reliability contribution are needed to ward off a potential capacity shortfall in the 2029/30 delivery year. (See Stakeholders Divided on PJM Proposal to Expedite High-capacity Generation.)

The Planning Committee endorsed a proposal from a coalition of stakeholders to create an expedited study process for resources receiving CIRs from deactivating generators during its Oct. 8 meeting. (See PJM Stakeholders Endorse Coalition Proposal on CIR Transfers.)

Elevate Renewables, the original sponsor of that package, told RTO Insider it is encouraged by PJM’s supportive statements during the OPSI meeting and the recognition that a process is needed to allow the efficient development of new resources in the place of retiring units.

“The replacement of existing resource should not be relegated to the back of a backlogged, multiyear-long interconnection queue process,” Elevate said in an email. “Instead, there are efficiencies gained by aligning the timing of the de-energizing of the deactivating resource with the energizing of the new replacement resource. However, the current state of the PJM queue creates a timing mismatch, which, as we’ve seen, has resulted in mass closures of generating facilities, affecting more than just reliability but employee and communities.”

Elevate said SIS presents PJM with an opportunity to optimize the capacity contribution of resources that are not fully using their maximum facility output. The RTO’s current rules prohibit any projects that would increase line flow or short circuit current from utilizing the SIS process to fast-track their interconnection.

“However, as currently deployed, the PJM [SIS] process creates significant roadblocks for battery storage and many other newer technologies and fuel types to utilize the process FERC directed all RTOs to adopt in Order 845,” Elevate said. “We are hopeful that as PJM makes statements that they plan to make tweaks to the surplus interconnection service process, that those tweaks would include changing the triggering criteria for project failure in the SIS process to be actual reliability criteria violations, e.g., line overload or breaker over duty as failing criteria.”

OPSI Speakers Discuss Future Auction Design

Speaking on a panel focused on the future of the capacity market, Executive Vice President of Market Services and Strategy Stu Bresler said PJM is working toward a Federal Power Act Section 205 filing in December to make several changes to the design of the BRA.

While the 2026/27 auction currently is scheduled to be conducted in December, PJM has asked FERC to delay its opening by six months (ER25-118).

The filing could include changes to how PJM models the output of generators operating on a reliability-must-run (RMR) contract, the topic of a complaint filed in September by the Sierra Club, Natural Resources Defense Council, Public Citizen, Sustainable FERC Project and the Union of Concerned Scientists that argues the expected output of RMR units should be included in the capacity market supply stack (EL24-148).

Bresler said PJM also is looking at changing the reference resource for the 2026/27 auction, which would be the first to use a combined cycle rather than combustion turbine as the model unit on which several parameters are based. Because of the higher energy and ancillary service revenues for combined cycle generators, the net cost of new entry (CONE) value fell to $0, bringing the Capacity Performance (CP) penalty rate for units that fail to deliver during emergency conditions to zero as well.

The disparity between the net and gross CONE also resulted in a significantly sharper variable resource requirement (VRR) curve capped at $696/MW-day should 145,774 MW or less clear the auction, falling to $0 at 149,455 MW.

“I think the reason why we went to [the Reliability Pricing Model] and the sloped demand curve in the first place is because we thought that the sort of boom-bust cycle associated with a more vertical demand curve was not the best answer for long-term lowest reasonable cost to the customer,” Bresler said. “And so getting back to a VRR curve and a slope of a VRR curve that results in a more stable pricing outcome given the supply and demand conditions I think is important.”

Vitol’s Jason Barker said a vertical demand curve with a narrow band of prices can create whiplash that undermines the auction’s value as a data point for investors evaluating PJM’s markets.

American Municipal Power Vice President of Transmission and Regulatory Affairs Steve Lieberman noted that the Members Committee had endorsed an AMP-sponsored proposal to redefine the penalty rate to be based on the BRA clearing price, a change that was rejected by the PJM Board of Managers. Complaints subsequently were brought by the Independent Market Monitor and East Kentucky Power Cooperative, both of which were rejected by the commission in August. (See PJM Board Rejects Lowering Capacity Performance Penalties.)

Because the bonus payments for overperforming during a performance assessment interval (PAI) are paid out of the pool of penalties collected under the CP construct, Lieberman said the status quo net CONE would eliminate the incentive to perform during an emergency.

Monitor Joe Bowring said RMR units are being retained to provide reliability services and thus should be included in the capacity market supply stack, which is one component of a package of changes to PJM’s generation deactivation rules proposed by the Monitor at the Deactivation Enhancements Senior Task Force. The results of an online vote on four proposals before the task force are set to be presented during its Nov. 14 meeting. (See PJM Stakeholders Delay Vote on Generator Deactivation Rules.)

The need to enter into RMR agreements constitutes a deeper market failure, Bowring said, driven by market rules that do not recognize the full reliability contribution of generators.

PJM has defended not including RMR units in the supply stack by arguing that those resources have a stated desire to leave the market, so a price signal is needed to incentivize development to replace them. It also has pointed to differing obligations for capacity resources, which are held to CP rules that penalize underperformance, and RMR agreements that limit when units can be deployed. Going beyond counting them in the supply stack to require that RMR units offer into the capacity market also would subject those units to PAI penalty risks, creating a disincentive for voluntarily entering into an RMR agreement.

Bresler noted that in some cases RMR agreements allowed PJM to dispatch those units only to resolve specific transmission security needs, which is something PJM may be rethinking. He cautioned that a one-size-fits-all approach likely does not make sense for a construct created to address specific transmission needs.

“No. 1, when it comes to RMR resources, I don’t think we want to include them or treat them or model them as supply in the auctions unless the service they’re providing is comparable to that of a capacity resource,” Bresler said. “Otherwise they’re not interchangeable, so you wouldn’t want to change the supply-and-demand balance on the basis of that assumption unless that’s the comparable service that they are providing.”

Barker expressed a similar outlook, stating that RMR units have different performance obligations from capacity resources and including the former in the supply stack could be unduly discriminatory if they are treated comparably to capacity without being held to CP standards.

Susan Bruce, representing the PJM Industrial Customer Coalition, said that the compressed auction schedule has left little time for developers to respond to the high price signals prompted by a generator leaving the capacity market to operate on an RMR contract. At the same time that consumers are paying higher capacity prices, they are also paying for transmission upgrades necessary to resolve the violations necessitating the RMR agreement, she said.

Gregory Poulos, executive director of the Consumer Advocates of the PJM States, said the repeated auction delays have led to risk being shifted to consumers, pointing to a “miscalculation” in the reliability requirement for the DPL South zone in the 2024/25 auction that cost consumers about $100 million in higher capacity costs with no corresponding reliability benefit.

It also left little time for market participants to respond to changes in the guidelines for energy efficiency resources offering into the following auction, which caused a marked drop in supply, Poulos said. A PJM filing at FERC would eliminate the resource class outright from the capacity market. (See PJM Asks FERC to Eliminate Energy Efficiency from Capacity Market.)

Given the little direct insight consumer advocates have on market decisions, they often are reliant on PJM estimates of the potential impacts market changes could have on prices, Poulos said. He urged PJM to use the information at its disposal to do more proactive modeling and analysis, which he said would improve consumer confidence in future auction outcomes.

More analysis and modeling of potential market changes could give stakeholders more certainty on proposals they are asked to vote on and increase certainty in future auction outcomes, he said.

Maryland Public Service Commissioner Michael T. Richard, moderator of the panel, said high prices can disrupt the economies and lives of ratepayers in PJM states.

“Markets are created for the customer. The concern I think some of us have is that after we see a sudden 800% jump in the market, we just have to ask, is this really a stable and predictable environment for customers, for state economies?” Richard said. “This essential service needs to be available to everybody and needs to be something that’s affordable.”

Panelists Discuss Price Surge in 2025/26 Auction

Speaking on a panel focused on the results of the 2025/26 BRA, Bresler defended the eightfold increase in prices, stating that the increase properly reflected tightening supply and demand. He said the capacity market has seen years of low prices owing to a surplus of generation in the market, leading to deactivations that are putting pressure on supply.

LS Power Senior Vice President of Wholesale Market Policy Marji Philips said the original concept of the capacity market was for prices to increase when demand is tight and fall when it is low, averaging out to net CONE over the lifespan of the reference resource. While regular market interventions have been creating price volatility and uncertainty, she said the return of prices to net CONE levels signals that investments in new generation are needed.

Bowring disagreed that the auction accurately reflected supply and demand, stating that administrative changes to the definition of capacity, namely the use of marginal effective load-carrying capability for resource accreditation, actually inflated prices. He also argued that supply is being suppressed by PJM’s categorical exemption of intermittent and storage resources from the requirement that all resources holding CIRs offer into the BRA. Both points were raised in the first two sections of the Monitor’s report on the 2025/26 auction. (See PJM Market Monitor Releases Second Section of 2025/26 Capacity Auction Report.)

“The design of the market did not reveal what the actual supply and demand was,” he said.

Clara Summers, campaign manager of the Consumers for a Better Grid project at the Illinois Citizens Utility Board, said there were changes in supply and demand, but they were not significant enough to account for the scale of the price jump seen in the July auction. Moreover, she argued that the capacity market is incapable of sending price signals to build because of the backlogged interconnection queue, an issue she said also is present when considering if high capacity prices can incentivize replacement resources while transmission upgrades are built.

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Tx Supporters Check in on Order 1920 Compliance Efforts

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. 

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Future of Power Markets Discussed at Aurora Energy Conference

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.

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NJ Enacts 200-MW Dual-solar Pilot Program

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. 

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OMS, OPSI Pen 2nd Letter to MISO and PJM to Compel Meaningful Interregional Planning

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.

The second letter arrives after some OMS members panned MISO and PJM’s original aim to study only smaller projects as too shallow to fit the constructive planning the regulators asked for. OMS and OPSI wrote their first joint letter in February to inspire MISO and PJM to do more interregional planning. (See Some MISO Regulators Signal Early Discontent with New MISO-PJM Interregional Study and Smaller Projects Expected from Maiden MISO-PJM Joint Tx Study.)

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.)

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RA Fear and Load Growth at OMS Annual Meeting

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.  

Huebner said Google is working with peers on demand response and said the company does have a “vested interest” in MISO’s recent proposal to reduce capacity credits for its load-modifying resources. (See MISO Tries to Win over Stakeholders on New LMR Capacity Accreditation.) 

‘Angsty’ Times

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. 

Ryan Long, Xcel Energy | © RTO Insider LLC

“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.  

Mark Tiemeier of Midwest Reliability Organization (left) and DL Oates of MISO | © RTO Insider LLC

“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.  

From left: Kent Chandler of R Street, OMS Executive Director Tricia DeBleeckere and Minnesota Public Utilities Commissioner Joe Sullivan | © RTO Insider LLC

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.  

The OMS annual meeting was held at the Best Western Premier Park Hotel steps from the Wisconsin Capitol in Madison | © RTO Insider LLC

“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.  

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NYISO Monitor Highlights Gap Between Planning, Market Requirements

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.

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NJ BPU Approves EV Charging Station Rules for MHD Vehicles

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. 

New Jersey and Connecticut, Delaware and Maryland, which make up the Clean Corridor Coalition, will install 450 charging ports at 24 sites along the highway. (See NJ To Install 167 Heavy Truck Chargers with $250M Federal Grant.) 

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.” 

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NY Receives Largest OSW Proposal Yet

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 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.