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June 1, 2024

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White House Launches Initiative with 21 States on Grid Modernization

The Biden administration on May 28 launched an effort to work with 21 states to help roll out advanced grid technologies. 

The states participating in the Federal-State Modern Grid Deployment Initiative all have Democratic governors, who have committed to support the adoption of advanced grid solutions that expand capacity and add new capabilities to existing and new transmission and distribution lines. 

The White House also held a summit on modernizing the grid with industry, regulators and other stakeholders focusing on advanced conductors, dynamic line ratings and other grid-enhancing technologies (GETs). 

“We think this is the lowest-hanging fruit of being able to get additional capacity on the grid and for the least amount of money,” Energy Secretary Jennifer Granholm said at the White House summit. “So, there’s no reason not to love grid-enhancing technologies.” 

DOE is working to help utilities get comfortable with the technologies by testing advanced reconductoring at Idaho National Laboratory, with the Electric Power Research Institute and at the Georgia Institute of Technology. 

The agency also recently released one of its “liftoff” reports on GETs, which said the technologies by themselves could meet the projected demand growth over the next decade, Granholm said. (See DOE Report Highlights Benefits of Advanced Technologies.) 

Alongside the announcement, the U.S. Climate Alliance — a group of 24 states that includes the 21 in the initiative — said it would offer policy, technical and analytical assistance to help participating members carry out their commitments. 

The states in the initiative agreed to deploy innovative grid technologies to bolster the capacity of the electric grid and more effectively meet demand, maximize the benefits of new and existing transmission infrastructure, increase the grid resilience to the growing impacts of climate change, and better protect consumers from volatility in energy prices. 

The Infrastructure Investment and Jobs Act’s recently issued Order 1920 included a requirement that transmission planners evaluate their use in regional plans. In a recent interview on the order, Johannes Pfeifenberger, a principal at The Brattle Group, said GETs could be a key part of controlling transmission costs. 

“And then you can create another third by sort of upgrading existing lines to higher voltages and things like that,” Pfeifenberger said. “And then the last third of doubling our transmission capability, then you’d have to build new lines. But we cannot afford to ignore the lower cost.” 

LineVision CEO Hudson Gilmer said in an interview that dividing the grid buildout into thirds makes sense, though he thinks the monitors his firm sells to enable dynamic line ratings are so affordable they could be used on new transmission lines to maximize those investments. 

The firm has worked on dozens of projects in the U.S. and around the world, with two major domestic efforts being with AES utilities in Ohio and Indiana and National Grid in upstate New York, Gilmer said before the White House event.  

LineVision is developing other projects, and Gilmer explained why he sees growth for the industry. 

“The biggest thing that gives me optimism is the experience of the utilities [that] have deployed these technologies,” he said. “And you heard on the last panel from AES, you heard from National Grid, you heard from Dominion — all of whom are deploying our technology. And they’re not one and done. They’re not stopping there. They’re saying, ‘We’re seeing amazing results here, and we want to roll this out more and more widely.’” 

Dominion Energy’s Virginia Power utility is on pace to double its demand in the next 15 years, driven in large part by the rapid expansion of data centers in Data Center Alley about 30 miles west of the White House, said Matthew Gardner, the company’s vice president of electric transmission. He said that’s just half the challenge because the utility also sees its supply transition along with the most active interconnection queues in PJM. 

“In addition to capacity, we look at the promise of GETs to provide … capability and flexibility as well,” Gardner said. “So that’s where GETs come into play.” 

‘Absolutely Essential’

Dominion has run a number dynamic line rating (DLR) pilots over the past decade, some of which have shown that some of its operational assumptions were too conservative because it found more capacity than expected. But the opposite has occurred in other cases, with some assumptions being too loose and requiring a reduction of flows on lines. In general, Dominion has seen the technology either open up or lower line capacities by 10 to 12%, Gardner said.

“DLRs are key to maximizing grid capabilities, especially those in situations where we’re taking outages for constructing grid upgrades,” Gardner said. “So, I like to think of DLR as being like flex lanes on the interstate that sometimes allow for additional traffic flows.” 

GETs are poised to keep growing in Virginia due to recent legislation passed by both Democratic-controlled legislative chambers and signed by Gov. Glenn Younkin (R), said state Del. Phil Hernandez (D) at the White House summit. 

“So really all this bill does … it says that anytime that a utility submits an IRP as part of their long-term energy planning, they have to do a comprehensive assessment of the potential application of grid-enhancing technologies,” Hernandez said. “So that is a first step for us.” 

GETs have avoided the politicization accompanying transmission issues, as seen on Capitol Hill or in the dissent and concurrence related to FERC Order 1920, or with a bill passing unanimously out of the Utah Senate, though it ultimately did not clear the lower chamber this past session, said state Sen. Nate Blouin (D). The legislation was similar to what Hernandez helped push through in Virginia. 

The conservative “Eagle Forum” usually does not get involved in energy issues and Blouin said it has opposed many of his proposals in the past. 

“One of their representatives got up to speak on my bill,” Blouin said. “And I was just thinking, ‘Oh, shoot, what’s he going to say about this one,’ and actually, it was a really positive comment. They were … very interested in the potential grid security and resilience-type aspects.” 

The tool is resource-agnostic, which is important for states like Utah where the climate issues are not top of mind, but it still can help meet growing demand and provide resilience against issues like wildfires, he added. 

But GETs can help in states with very different policies, such as California, where climate laws require the industry to bring on about 8,000 MW of renewable resources per year on average, but reliably and cost effectively, said CAISO CEO Elliot Mainzer. 

GETs are in a place like where storage was just a few years ago — ready to take off, Mainzer added. California has 10 GW of storage now, while GETs are starting to be included in some of its regionally planned transmission projects. 

“The way that our grid is operating today is transitioning so quickly,” he said. “Any of you that operate in the West, just the patterns of flows that we’re seeing, the type of generation on the grid — having this sophisticated portfolio of tools that can manage flows and manage this next generation of resources and do it honestly, reliably and as affordably as possible is absolutely essential.” 

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ERO Pushes IBR Awareness for Policymakers

ERO officials urged state policymakers in a webinar to work with their utilities and regional entities to understand the reliability challenges and opportunities presented by the transition to renewable energy resources. 

The May 29 webinar was hosted by Midwest Reliability Organization CEO Sara Patrick, with participation by NERC, ReliabilityFirst and SERC Reliability, with the goal of giving state regulators a clearer picture of how grid reliability has been affected by the deployment of inverter-based resources (IBRs) such as wind, solar and battery facilities. 

Howard Gugel, NERC’s vice president of regulatory oversight, emphasized that “education is key” and recommended the regulatory community learn “as much as [they] can about these resources, how they’re going to be interconnected and integrated … and how your state policy can help influence” the reliability impact to end users. 

Gugel pointed out that summer peak demand in North America increased by 3% between 2012 and 2022, according to NERC’s analysis, while peak capacity decreased by 4%. In addition, wind, solar and batteries grew as a share of generation from 2.9% in 2012 to 9% in 2022, while the share comprising coal and oil shrank from 34.2% to 22%. 

The growth of IBRs and retirement of traditional generation has significant implications for reliability, Gugel explained. During a “wind drought” last year in ERCOT, SPP and MISO, installed wind generation with a total capacity of 60 GW generated only 300 MW at some points, he said. With demand likely to continue growing, especially in areas where transportation and heating are transitioning quickly to electricity, Gugel said policymakers need to understand the implications of renewable energy mandates.  

“At this point, we’re retiring generation faster than we’re putting it on. And there’s going to be a point at which there’s not going to be excess energy available there,” Gugel said. “And so we’ve [all] got to work together to ensure that we’re getting adequate capacity and energy installed in the system to meet the needs of our customers and to keep those lights on at all times.” 

The task is not as simple as replacing retired baseload generation with equivalent solar or wind capacity, Gugel added, presenting a simple example of 100 MW of baseload. Assuming the sun shines for eight hours, to replace this generation, a utility must provide 100 MW of solar capacity, 400 MW of batteries to discharge at the same rate during the night and an additional 200 MW of solar just to charge the batteries for eight hours. 

Gugel reiterated that NERC is doing its part to address IBR-related reliability concerns, citing the ERO’s work on developing registration criteria for the new resources and reliability standards to address their performance concerns. (See NERC Says IBR Work Proceeding as Planned.) Other presenters pointed out that IBRs also can be assets for reliability, noting their responsiveness compared to traditional generation. 

Asked by Patrick about the cost of complying with the new standards, Gugel acknowledged states must recognize this potential burden but should not let it stop them from implementing the policies to safeguard the grid for the future. 

“There’s going to be a cost for compliance with any type of regulation [that] will be rolled into [electric] rates,” Gugel said. “I don’t expect that to be substantial, but I’m not going to sit here and say that it’s not going to cost anything. But frankly, all existing generation has a cost for compliance. … So there will be somewhat of a cost for this, but it’s small, based on the reliability benefit that we’re going to receive from it.” 

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DOE Tackles Charging Challenges to Get More EVs on the Road

A recent study from the U.S. Department of Energy finds that managed charging ― that is, shifting the time electric vehicles charge to off-peak hours ― could be critical to controlling the costs of building charging networks and local electric distribution systems needed to power them. 

DOE’s Multi-state Transportation Electrification Impact Study looks at EV adoption and infrastructure buildout in California, Illinois, New York, Oklahoma and Pennsylvania, as accelerated by EPA’s recent rules aimed at slashing carbon dioxide emissions from light-, medium- and heavy-duty vehicles. (See Automakers Get More Time, Flexibility in EPA’s Final Vehicle GHG Rule and EPA Issues Final Standards on Heavy-duty Truck Emissions.)  

By 2032, those rules could put an extra 3.9 million plug-in EVs of all classes on the road in those states ― bringing the cross-state total to 20 million EVs ― along with 2.3 million additional EV chargers. But, the study finds, managed charging could halve the number of new substations needed and cut additional grid investments by $700 million.  

The study provides even more granular figures, based on a unique “bottom-up” methodology developed by Kevala, a grid analysis firm, which partnered with the National Renewable Energy Laboratory and the Lawrence Berkeley National Laboratory on the project. Drilling down to the parcel level, researchers were able to model the kinds of chargers that might be installed on individual feeders between 2027 and 2032.  

Again, managed charging could cut the number of extra feeder lines needed ― to carry power from substations to end users ― from 125 to 75, and the number of additional service transformers needed from 30,000 to 21,000. 

As defined in the study, managed charging not only shifts the time when charging occurs, but also minimizes its speed “such that the session is completed just prior to [an EV’s] departure from that location.”  

The study also notes that managed charging programs are best suited to home and commercial depot locations, where EVs are parked on a regular schedule and therefore “are considered most likely to have margins for adjusting charging speed without negatively impacting vehicle availability.” 

The resulting reductions in peak demand could be significant. Rather than demand spiking in the late afternoon or early evening, when EV owners arrive home and plug in their cars to recharge, managed charging could keep demand curves relatively flat, with some variation throughout day. 

While the study is limited only to the effects of EV power demand and managed charging on distribution systems, the flexibility provided could have even broader system benefits when combined with other distributed energy resources on a feeder, said Troy Hodges, a data science manager with Kevala.  

“One last benefit of doing this at the parcel level is not only do we know which vehicles are on those feeders, but we also have … simulated the non-EV loads on the feeders,” Hodges said during a May 22 webinar on the report. “So, from there, we can start modeling a managed charging technique that is more responsive to the dynamic needs of particular equipment on the grid.” 

In one model scenario incorporating non-EV loads, the study found “further distribution cost savings, particularly on high-EV-penetration feeders,” Hodges said. In one example in California, managed charging incorporating non-EV loads cut peak demand by an additional 25%, he said. 

Flattening the duck: The DOE study also looks at the impact of managed charging on California’s famous duck curve. | DOE

“It really drove home the value on these high-penetration EV residential areas or commercial areas with fleet depots,” Hodges said. “This type of more advanced, active control approach could really have a big impact.”  

First Time, Every Time

Distribution grid planning has emerged as a vital part of EV charger installation, with lack of capacity on local systems slowing the deployment of chargers along the nation’s highways. Funded with $5 billion from the Infrastructure Investment and Jobs Act, the National Electric Vehicle Infrastructure (NEVI) program was created to help build out a network of 500,000 direct current (DC) fast chargers on major routes by 2030, but to date has installed eight stations with a total of 33 charging ports in six states. 

In its most recent NEVI update, the Joint Office of Energy and Transportation estimated the U.S. now has more than 183,000 public charging ports, but fewer than a quarter of those — 41,065 — are DC fast chargers. In addition, 9,472 public chargers, both Level 2 (L2) and DC fast chargers, are classified as “temporarily unavailable” — that is, not working.  

Depending on the EV and capacity of the chargers (NEVI-funded chargers must be at least 150 kW), DC fast chargers can recharge a battery to 80% capacity in 20 to 60 minutes. Typically used for home or workplace charging, L2 chargers can take several hours to repower an EV. 

The Multi-state Study is one of several DOE initiatives aimed at overcoming barriers to more rapid expansion of charging networks, efforts that have become increasingly urgent as the November election looms and growth in EV sales has slowed. According to Kelley Blue Book, Americans bought 268,909 EVs in the first three months of 2024, up a modest 2.6% over the first quarter of 2023, when EVs scored a 46.4% jump over the first quarter of 2022.  

Along with price, consumers’ concerns about EVs’ range and charger speed and availability are the most commonly cited brakes on the wider adoption of electric vehicles, Kelley said. 

DOE and the Joint Office launched the National Charging Experience (ChargeX) Consortium in August 2023 to help consumers get over those bumps. A public-private initiative, the consortium is focused on ensuring “that any driver of any EV can charge on any charger and have it work the first time, every time,” said ChargeX Director John Smart. 

The group includes industry stakeholders, along with consumer advocates, academics and state government officials, who collaborate on “complex issues … that no single company can solve on their own,” Smart said during a May 23 webinar providing a progress report on the group’s efforts. 

“To truly understand the customer experience, we need more metrics … that are used and measured uniformly across the industry, so that everyone’s speaking the same language, so that we’re properly measuring and therefore improving the customer experience,” Smart said. 

Top priorities include developing minimum standards ― or key performance indicators (KPIs) ― that will provide the benchmarks needed to make charging more predictable and reliable.  

Breaking down the KPIs

Frank Marotta Jr., assistant manager for charging network reliability at General Motors, detailed how the consortium breaks down a customer’s experience at a charger into discrete elements, each with its own KPI. 

“How effective are the mapping tools drivers can be using to locate the station? How effective are they at actually getting the vehicle right up to the plug?” Marotta said. 

“We have waiting probability, which is basically the probability that at least one port might be available to deliver energy when the EV arrives,” he said. “And under starting to charge, we have two KPIs … one that is meant to measure the effort required to actually start the charging session and then … the time required to actually get that session initiated.” 

Another priority is communication between EVs and chargers, and chargers and the cloud, Smart said. “What is needed to allow the industry to scale, and specifically as more makes and models of chargers come to market and more makes and models of electric vehicles, how do we ensure that they all work together going forward?” 

The answers will include better sharing of diagnostic data between stakeholders and improving interoperability “to efficiently verify that every charger works with every vehicle,” Smart said.  

Market growth and the resulting need for interoperability and better grid planning are coming. While only a handful of NEVI projects are online now, the Joint Office has reported that 36 states have at least issued their first solicitation for chargers, and 23 have made conditional awards or agreements for more than 550 charging stations, each with four or more ports. 

U.S. public EV charging ports by month | Joint Office of Energy and Transportation

The Joint Office’s checklist for state planners includes early communication with utilities to prepare for the interconnection of NEVI-funded stations. 

Also, consumer range anxiety could begin to taper off, with DOE reporting that 19 EV models that were on the market in 2023 could travel 300 miles or more on a charge, up 35% from 14 such models in 2022. 

While noting that “everything about EVs is controversial,” Kelley expects market growth to continue, driven by the increase in available models and some price reductions. The slowdown could be a sign that EVs are becoming mainstream in some parts of the country, Kelley said. “Segment growth typically slows as volume increases.” 

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Tri-State CEO Gives Update on Energy Transition

Rural electric cooperatives face challenges different from investor-owned utilities as they pursue clean energy goals, the leader of Tri-State Generation and Transmission Association said. 

Tri-State CEO Duane Highley was the featured speaker in a May 28 webinar hosted by the American Clean Power Association. He pointed out that the customers served by cooperatives often are spread farther apart than IOUs’ customers and that the communities that cooperatives serve often have high rates of poverty. 

Tri-State CEO Duane Highley | American Clean Power

But one of the biggest differences is coal, which is in the crosshairs of most decarbonization scenarios. The Power Plant and Industrial Fuel Use Act of 1978 had the effect of steering cooperatives toward coal-burning plants at a time when they were rapidly expanding generation capacity, Highley said. As a result, they are more reliant on coal than other power industry sectors. 

“And now as we make a transition, it’s especially challenging because to reduce carbon emissions, we’re retiring coal, which for us is the majority,” he said. “So when you talk about, ‘Oh, just shut down your coal plant,’ what if that’s over half of your capacity in one plant?” 

Forty-one of Tri-State’s 44 members are electric distribution cooperatives and public power districts. They serve more than 1 million customers across nearly 200,000 square miles in Wyoming, Colorado, Nebraska and New Mexico. 

ACP CEO Jason Grumet asked Highley how Tri-State is managing its transition from coal to renewables. 

Tri-State’s board and its member-owners were supportive of the move, Highley replied, as long as the result was reliable and affordable. 

“So that’s what we’re doing, and we’re doing it at what I’d call light speed for a utility,” he said. “We … are building hundreds and hundreds of megawatts of wind and solar. And people who said ‘you can’t do that and keep the lights on’ are wrong. We’re able to do this and prove reliability at an accelerated level.” 

To meet reliability needs, Tri-State is overbuilding renewables and looking forward to long-duration energy storage technology maturing, he said. And it is retaining fossil backup. 

“We’re going to keep a lot of gas and oil generation around because we have to have it for reliability,” he said. 

Tri-State’s proposed resource plan calls for a new combined cycle gas-burning plant with carbon capture and sequestration capacity retrofitted later. 

Highley is excited about the potential of small modular reactors as well, again as a backstop for reliability. But he thinks they are at least a decade away and that cooperatives cannot be first adopters; someone else must take the risk of proving the concept. 

Tri-State also needs to be in an RTO, to transfer power between regions and balance out spikes or lulls in intermittent power generation, Highley said. 

“And that’s why we’ve been so much an advocate for promoting the western expansion of the Southwest Power Pool. And we believe it’ll be starting up the first quarter of 2026 in our area,” he said. 

Along with the challenges unique to cooperatives, Highley laid out some that are common across the power industry: rapid growth of demand and constraints on transmission to meet that demand. 

“There’s definitely growth coming, and it is exceeding what we had been previously forecasting,” he said, citing electric vehicles and overall electrification as the primary causes, along with data centers that can consume a gigawatt apiece. 

“There’s just not a utility that I know of in the West that has a gigawatt of surplus capacity that they say, ‘Hey, I’m not using it right now. Would you like to hook up?’” Highley said. 

“Plus the transmission question,” he added. “There are very few areas on the grid where you can drop hundreds of megawatts of load without making some significant transmission investments. And what we’ve seen in the past is it can take anywhere from five to 15 years to get a new transmission line built.” 

Highley gave a nod to the state and federal policymakers who set decarbonization goals but don’t have to do the actual work of meeting them. 

“We can make lots of growth. We just can’t make maybe as much as fast as people would like to see [in] some instances.” 

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BOEM Offers Maine Offshore Wind Research Lease

The United States is a step closer to its first potential floating offshore wind farm. 

The Bureau of Ocean Energy Management said May 28 it has completed its environmental assessment of the state of Maine’s request for a lease area where it could place a research array. It found the lease and the site assessment work that would be done on it would have no significant impact on the environment. 

BOEM offered the state a research lease May 24. Maine must accept or reject BOEM’s offer or request modifications within 30 days. 

Gov. Janet Mills (D) responded in a prepared statement May 28 that the lease offer is a “major milestone” for the state in its efforts to site offshore wind and that her administration looks forward to reviewing it. 

Floating wind turbines are a relatively new technology only now beginning to be installed on a larger scale. The technology is still being developed and tested, and at this point it is more expensive and complicated than the fixed-bottom turbine technology that has come into widespread use worldwide over the past three decades. 

For years, Maine has sought to be a leader in floating wind in the United States — as a way to extract emissions-free electricity from its lengthy but deep coastal waters and to build a new industry. (See Maine Finalizes Offshore Wind Roadmap.) 

The University of Maine has been researching the concept and execution for more than a decade, and generated electricity with a downscaled turbine it set afloat in 2013/14.  

In October 2021, Maine requested the research lease that has now been offered. 

It would allow the state to place up to 12 turbines with a combined rating of up to 144 MW on up to 9,728 acres within a 34,596-acre research lease area 28 nautical miles southeast of Portland. 

BOEM’s final environmental assessment determined the likely impacts of the research array would be negligible or negligible to minor. 

In its news release, BOEM Director Elizabeth Klein said: “Floating wind technology can make offshore wind a reality in the Gulf of Maine. BOEM will continue to work in partnership with the state of Maine as we move forward to facilitate the responsible development of offshore wind in this region, as well as the deployment of floating offshore wind technology nationwide.” 

In her press release, Mills said: “Offshore wind offers our state a tremendous opportunity to harness abundant clean energy in our own backyard, to create good-paying jobs and drive economic development, and to reduce our over-reliance on fossil fuels and fight climate change.” 

As it advances Maine’s research lease request, BOEM simultaneously is setting the stage for commercial offshore wind development in the Gulf of Maine. 

In April, it proposed an auction for eight lease areas totaling nearly 1 million acres and holding a potential 15 GW of capacity. Six of the eight commercial areas would be well south of the research area, closer to the outer arm of Cape Cod than to Maine. (See Wind Energy Lease Areas Designated in Gulf of Maine, Oregon.) 

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NJ Accelerates OSW Plans Again

New Jersey Gov. Phil Murphy has directed the state Board of Public Utilities (BPU) to advance the opening of its fifth offshore wind solicitation by 15 months as the state scrambles to recover the time lost when Danish developer Ørsted abandoned two of the state’s first three projects. 

Murphy (D) said advancing the solicitation from the third quarter of 2026 to the second quarter of 2025 “builds upon the momentum of the state’s growing offshore wind industry” as it strives to reach its goal of installing 11 GW of OSW capacity by 2040. 

The May 28 announcement comes as concern about the effectiveness and public benefit of wind generation continues to surface at public hearings. It emerged at legislative budget hearings on the finances of the BPU and at a permit hearing for the state’s now-leading OSW project — Atlantic Shores — held May 14 by the state Department of Environmental Protection (DEP). 

$125M Payment

The state has pushed ahead undeterred since October, when Ørsted abandoned two of the state’s first three OSW projects, Ocean Wind 1 and 2. The BPU awarded two new projects in January at the conclusion of its third solicitation. And within weeks of Ørsted’s withdrawal, Murphy directed the BPU to speed up the normal two-year cycle between solicitations and prepare for the fourth solicitation, which opened in April and will close July 10. (See New Jersey Opens 4th Offshore Wind Solicitation.) 

Murphy said in a release announcing the accelerated timeline for the fifth solicitation that Ørsted has agreed to pay the state $125 million in a settlement to “release claims against each other arising out of or related to the Ocean Wind Projects.” 

The developer has agreed to put $200 million into an escrow fund New Jersey could spend on other wind-related projects. The law also required the developer to post a performance security of $100 million for the completion of the project, which would be forfeited if the project failed to reach commercial operation. Lawmakers set up the provision to strengthen the requirements on Ørsted in return for the state allowing the developer to receive federal tax credits awarded to support OSW projects. The credits otherwise would otherwise have gone to help state ratepayers. (See NJ Lawmakers Back Ørsted’s Tax Credit Plea.) 

Gov. Phil Murphy (D) | Gov. Phil Murphy

Murphy also said the state would “pause” its planned second solicitation for offshore infrastructure projects using the State Agreement Approach (SAA), which would allow coordinated offshore wind transmission planning with regional grid operator PJM. 

The BPU completed its first SAA process in October 2022, awarding $1.07 billion for transmission upgrades to deliver 6,400 MW of offshore wind generation to the PJM grid. BPU officials said it would save ratepayers hundreds of millions of dollars, but the solicitation award covered only upgrades to the landside portion of the transmission. (See NJ BPU OKs $1.07B OSW Transmission Expansion.) 

The BPU planned the second SAA to solicit coordinated transmission alternatives for the offshore portion of the transmission lines. But FERC on May 13 released Order 1920, the long-awaited final rule on long-term regional transmission planning and cost allocation. The order is of particular relevance to PJM’s ongoing interconnection queue reform process, Murphy said. 

His release said he paused the SAA process to give BPU staff the “opportunity to fully evaluate the implications of the new FERC rule and participate in PJM’s process to ensure the best outcome to meet New Jersey’s transmission needs at the least cost to ratepayers.” 

Efficiency Questioned

If all goes to plan, OSW projects now in the pipeline would account for about half — 5.25 GW — of New Jersey’s 11-GW goal. Aside from the 1,510-MW Atlantic Shores project, the state in January approved the 1,341-MW Attentive Energy Two project and the Leading Light project, with two phases of 1,200 MW each. 

The state’s wind projects have faced opposition from the commercial fishing industry and tourism-related businesses. That skepticism was present at the May 14 hearing of the Senate Budget and Appropriations Committee, at which Republican senators pushed back on the BPU’s aggressive drive to line up wind projects. They questioned whether the state should launch an initiative in which it has little experience, for which the technology is new, and for which the eventual cost to ratepayers is unknown. 

As he opened the hearing for lawmakers’ questions of BPU officials, Chairman Sen. Paul Sarlo (D), called the OSW projects “very controversial, as you know, politically charged” and queried whether the BPU is concerned the projects “may run the risk of not coming to fruition.”  

Sen. Douglas J. Steinhardt (R), assessing the program’s recent history, was more direct. 

“With so much uncertainty surrounding projects that are currently already underway, or were already underway and suspended, do you believe it is appropriate to open a new round of solicitation for future projects?” he asked BPU President Christine Guhl-Sadovy, referring to the fourth solicitation. 

Given the rising costs, isn’t it “a bit sort of a quixotic quest and a tilt at windmills, no pun intended there,” he asked. 

Great Opportunity

Guhl-Sadovy brushed aside his concerns. 

“Offshore wind is really a once-in-a-lifetime opportunity to bring not only clean energy to New Jersey, but [also] billions of dollars in economic benefits, tens of thousands of jobs across the state, primarily in South Jersey,” Guhl-Sadovy said.  

Sitting next to Guhl-Sadovy, Tim Sullivan, CEO of the New Jersey Economic Development Authority (EDA), which has funded much of the state’s OSW infrastructure investment, faced questions about the agency’s determination to position the state as an East Coast leader in offshore wind, quickly building an industry from scratch. 

“If this is a once-in-a-lifetime opportunity, it’s also a once-in-a-lifetime opportunity to get this correct, or catastrophically incorrect, in my opinion,” Steinhardt said. 

Sullivan acknowledged the risks of offshore wind. “Anytime we’ve got a new capital-intensive, regulatorily complex industry, you’re going to see fits and starts.” But the state must “focus on the competitive dynamics here, because other states want this leadership position.” 

At a May 15 hearing of the Assembly Budget Committee, Assemblyman Gerry Scharfenburger (R) said he’s concerned the state is transitioning from fossil fuels in favor of solar and wind energy, whose “intermittent” characteristics would create “economic and environmental problems down the road.” He questioned the Murphy administration’s “prioritization of wind turbines over, say, nuclear energy.”  

“I have no affinity for fossil fuels,” he said, adding that “I would put goose droppings in my car if it would make it run … We just have to look for the best alternative that is viable, is fiscally doable and is going to be there. It can’t be intermittent.” 

Guhl-Sadovy said there was no preference against nuclear, which would account for 40% of the state’s electricity generation in state clean energy plans. She said the BPU believes in the sector economics. 

“As we look at the clean energy that we’re investing in … we are going to see an economic development come to the state of New Jersey,” she said. 

Nuclear or not

The role of nuclear energy also surfaced at the DEP’s May 14 hearing seeking public input on the Atlantic Shores project. The agency is assessing the developer’s request for waterfront development, coastal wetlands and other offshore environmental permits, as well as onshore permits for a transmission cable to run to the Cardiff substation in Egg Harbor Township. 

Dennis DeForest, a member of Save the East Coast, a New Jersey group that opposes offshore wind, said the projects would damage the marine environment, disrupt neighborhoods when cables are run through them and hurt tourism. He added that voters never had a chance to vote on the issue. 

“There’s really no reason for us to use this unreliable energy,” he said. “There’s other ways to create energy, clean green energy, right, through nuclear, with small nuclear reactors.” 

Henry Waldron, a resident of Brigantine, one of the communities closest to the proposed OSW development, said the state already is too reliant on electricity produced by burning fossil fuels, and much of the power is imported from other states. He said his hometown — a barrier island near Atlantic City — already is affected by rising sea levels and damage to the beaches. 

“New Jersey is already in a deficit for electricity,” he said, foreseeing brownouts by the middle of this decade.  

“People talk small modular reactors,” which could be ready by 2040, but “big nukes” would take much longer, he said. “I don’t see anybody who’s yelling against wind offering their communities for more nuclear reactors. And a nuclear reactor would take 12 years (to build).” 

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NV Energy to Join CAISO’s Extended Day-Ahead Market

NV Energy will commit to joining CAISO’s Extended Day-Ahead Market (EDAM), sources have told RTO Insider, a move that will end months of speculation among Western electricity sector stakeholders about whether the Nevada utility would choose EDAM over SPP’s Markets+.

The utility plans to make its intent public May 31 when it files an integrated resource plan with the Public Utilities Commission of Nevada, multiple sources closely involved with market developments in the West said.

NV Energy did not respond to a request for comment on the matter, a topic of increasing interest in the region, with multiple sources recently telling RTO Insider that the utility has been revealing its decision in favor of EDAM in private meetings. An NV Energy executive offered the clearest public signal yet on the utility’s leaning during a May 22 joint session of the CAISO Board of Governors and Western Energy Imbalance Market (WEIM) Governing Body. (See Is NV Energy Leaning to CAISO’s EDAM?)

The selection still must be approved by the PUCN. A 2021 Nevada law requires the utility to join an RTO by 2030, with the decision subject to approval by the commission, which has been hosting workshops exploring the two day-ahead market options in the West as part of its RTO proceeding. (See Nevada RTO Proceeding Examines EDAM, Markets+ Design.)

At one of those workshops, the Brattle Group presented data showing NV Energy stood to gain $62 million to $149 million in annual economic benefits from joining the EDAM, while it stood to lose as much as $100 million from withdrawing from CAISO’s Western Energy Imbalance Market (WEIM). The results of joining Markets+ ranged from a loss of $17 million compared with the status quo to a benefit of $16 million. (See Nev. RTO Effort Turns Focus to NV Energy Day-ahead Studies.)

Big Win for EDAM

NV Energy’s decision spells a major victory for the EDAM in its ongoing competition for members with SPP’s Markets+ day-ahead offering.

The utility serves the majority of Nevada’s electricity users and is the balancing authority for the state. Its control area occupies a central position in the WEIM, functioning as the primary wheel-through point for energy transfers between the WEIM’s California participants — including the ISO — and PacifiCorp’s sprawling balancing authority area in the inland West.

PacifiCorp in April became the first entity to agree to sign an implementation agreement for the EDAM, sealing its participation in the market. (See PacifiCorp Fully Commits to CAISO’s EDAM.)

NV Energy’s membership in EDAM also would be consequential for Markets+ because the utility’s BAA sits between the territories of the entities that have shown the most interest in joining the SPP-run market, including the Bonneville Power Administration and Puget Sound Energy in the Northwest, and Arizona Public Service, Salt River Project and Tucson Electric Power in the Desert Southwest. The inclusion of Nevada’s transmission network in EDAM would limit the ability of those entities to transfer energy among each other in a geographically divided Markets+.

The decision also is significant for the West-Wide Governance Pathways Initiative. Backers of that effort in April issued a proposal to make stepwise changes to the governance of the WEIM/EDAM, with the objective of eventually putting the market under the authority of an independent “regional organization” after seeking changes to California law related to CAISO. (See Pathways Initiative to Act Fast on ‘Stepwise’ Governance Plan.)

But step 1 in that proposal entails elevating the “joint” authority the WEIM’s Governing Body currently shares with CAISO’s Board of Governors over WEIM matters to “primary” authority. Under the plan, the ISO would pursue that change with FERC only after the EDAM secures implementation agreements with a “set of geographically diverse” WEIM participants representing load equal to or greater than 70% of CAISO BAA annual load in 2022. With commitments from PacifiCorp, Balancing Authority of Northern California, Idaho Power, Los Angeles Department of Water and Power, and Portland General Electric, NV Energy has been cited by Pathways supporters as the entity needed to trigger that move.

NV Energy’s filing with the PUCN on May 31 will coincide with a monthly meeting of the Pathways Initiative’s Launch Committee, at which the committee is expected to vote on adopting step 1 of the governance proposal.

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CAISO, WEIM Boards Approve Proposal to Raise Offer Cap

The CAISO Board of Governors and Western Energy Imbalance Market (WEIM) Governing Body voted unanimously May 22 to approve an expedited proposal to increase the ISO’s soft offer cap from $1,000/MWh to $2,000.  

CAISO staff and stakeholders participating in the ISO’s Price Formation Enhancements (PFE) Working Group quickly crafted the plan as part of a strategy to improve the bidding prospects of energy-limited resources — such as battery storage and hydroelectric resources — ahead of late summer. 

The ISO hopes to win FERC approval for the proposal by Aug. 1, the date that typically marks the start of the most challenging period for grid operations in the West because of declining hydro availability and the onset of what usually are the warmest conditions of the year in California’s load centers. 

Grid operators across the region are preparing for the prospect of tight supplies this summer based on low water conditions in the Northwestern U.S. and the Canadian province of British Columbia. 

“I see these changes as urgent, given the difficult hydro conditions in the Pacific Northwest. The market will benefit if more hydro resources are fully in the market as much as they can be,” Governing Body Chair Andrew Campbell said during the body’s joint session with the ISO’s board. “There’s urgency for batteries too. There’s so many batteries online this summer, and I support relying more on the market to manage charge and discharge rather than market operator directives.” 

The two-part proposal is designed to allow energy-limited resources with “intraday opportunity costs” — specifically batteries and hydro — to factor those costs into their default energy bids (DEBs), but the new rules will apply to gas-fired generation as well. The ISO has emphasized that all resources will still need to justify the costs behind their bids. (See CAISO Moves for Expedited Change to Soft Offer Cap.) 

Those opportunity costs arise on stressed days for the grid when supplies become tight, usually from extreme weather. In those circumstances, an energy-limited resource committed to the market at the $1,000/MWh soft offer cap can find itself dispatched at high prices occurring relatively early in the day, leaving it unable to provide energy later when prices are even higher. 

To address the issue, the proposal seeks to revise CAISO’s rules related to FERC Order 831, the 2016 directive that required RTOs and ISOs to limit the market bids of energy resources to the higher of either a soft offer cap of $1,000/MWh or a cost-based offer already verified by the market operator, up to a hard cap of $2,000 MWh. 

‘Loud and Clear’

The proposal had solid backing from many industry stakeholders, including hydro-heavy WEIM participants Bonneville Power Administration and Seattle City Light, and was endorsed by CAISO’s Market Surveillance Committee (MSC) during its May 15 meeting. 

Some stakeholders, such as BPA and the Western Power Trading Forum, expressed concern about a last-minute change to the proposal that limits storage resources to bidding above the $1,000/MWh cap only in the real-time market — and not in the day-ahead market — made in response to the MSC’s opinion that the ISO’s integrated forward market process already solves the opportunity cost issue for storage in the day-ahead. 

Opponents included the California Public Utilities Commission and its Public Advocates Office, both of which raised concerns about the potential costs to ratepayers from increasing the cap and the speed with which the plan moved through CAISO’s stakeholder process. 

Supporters among stakeholders and the CAISO and WEIM oversight bodies emphasized the measures should be considered only a temporary remedy. Some said the PFE Working Group should come up with a more complete solution before summer 2025, one that would more completely address the bidding requirements for storage and take up the needs of hybrid and demand response resources as well. 

After expressing gratitude for the quick efforts by CAISO staff and stakeholders on the proposal, ISO Board Chair Jan Schori acknowledged how much more needs to be done on the matter. 

“I am hearing loud and clear, from all the comments that we’ve received, that we simply have to do a lot more work on batteries and storage, and particularly fixing the [bid-cost recovery] rules,” Schori said. “But [batteries] are unique; they are different; and we need to probably come up with a set of rules that really works to match that resource and enable us to both have it be a long-term resource for the industry and for customers, but also to make sure it’s deployed at the time that we need it available to us to address the reliability issues that we may be confronting.” 

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State Briefs

CONNECTICUT 

Solar Farm Developer Issued Stop-work Order

New Windsor Supervisor Steven Bedetti last week said the town has issued AHC Development Construction Consulting a stop-work order after the solar developer clear-cut dozens of trees that were supposed to be left as a buffer. 

AHC President Keith Libold said the company’s contractor mistakenly cut trees that were supposed to be left and that they have submitted a new proposal that includes replacing trees in the original, agreed-upon buffer zone. 

More: News 12 Connecticut 

IOWA 

Tornado Topples Several Turbines

Multiple tornados ripped through the state May 21, with one toppling several 250-foot wind turbines in the Prescott area. 

Wind farms are built to withstand tornadoes, hurricanes and other powerful winds. According to the U.S. Department of Energy, turbines are designed to shut off when winds exceed certain thresholds, typically around 55 mph. They also lock and feather their blades, and turn into the wind, to minimize the strain. 

More: The Associated Press; AccuWeather 

LOUISIANA 

PSC Approves Entergy’s Plan to Add 3 GW of Solar

The Public Service Commission has approved Entergy Louisiana’s request to add up to 3 GW of solar power to its generation portfolio. 

The initiative is part of the utility’s plans to achieve net-zero carbon emissions by 2050. 

“This approval underscores our commitment to meeting operational and sustainability needs, driving economic development, and protecting the environment,” Entergy Louisiana CEO Phillip May said in a May 22 statement. 

More: Entergy  

MASSACHUSETTS 

Eversource Wraps up Upgrade of Tx Program

Eversource Energy last week said it has completed the first phase of the Cape Cod Solution Transmission Program, which requires rebuilding of the grid to enhance resilience and reliability while supporting the infrastructure needed to connect offshore wind projects. 

Phase 1 of the Cape Cod Solution is one of only two transmission projects underway in New England that will allow for the interconnection of offshore wind and included the expansion of Eversource’s West Barnstable substation and the installation of a 12.5-mile transmission line. 

More: Renews 

MINNESOTA 

Legislation on Permitting, Community Solar Credits Passed

Democrats overcame a split within the party last week to pass legislation that would cut red tape for wind, solar and transmission projects and uphold a Public Utilities Commission decision to shrink bill credits. 

The legislation was part of a larger package that included agriculture policy and spending. Senate Democrats backed the permitting legislation, while those in the House of Representatives chose to use that as leverage to change community solar credits. The final deal included most of the Senate permitting plan, including a transfer that will give the PUC more staff. 

The House was able to add extra staff at the Department of Commerce to help analyze energy projects, as the agency acts as a public-interest watchdog at the PUC. The bill also does not include a study of small nuclear reactors and questions of long-term nuclear waste storage. 

More: Star Tribune 

State Investment Board Passes Climate Resolution

The State Investment Board last week passed a resolution stating it will consider longer-term risks to pension investments such as climate change. 

Environmental, social and governance has been part of the state’s investment strategy for years. Last week, the investment board passed a resolution to “consider all material risks and opportunities” of its investments, with state leaders underlining their interest in considering climate change risks. 

Board of Investment Executive Director Jill Schurtz said the state has preferred to take an active role as a shareholder in pushing companies to change their practices, rather than divesting. 

More: Star Tribune 

NEW MEXICO

Climate Investment Center Becomes State’s 1st Green Bank

The New Mexico Climate Investment Center, a nonprofit aiming to help equitably finance the state’s clean energy transition, was unveiled last week. 

The center will finance clean energy technologies and the use of those technologies and is designed to increase climate resilience. Loans will be used to develop clean energy with a focus on low-income, disadvantaged and tribal communities. 

More: The Albuquerque Journal 

WYOMING 

Siting Council Approves Large Solar Farm

The Industrial Siting Council last week approved the 771-MW Cowboy Solar Farm in Laramie County. It will be the state’s largest solar project and include 269 MW of battery storage. It will be built on private lands, with construction set to begin next March. 

More: Casper Star-Tribune 

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Federal Briefs

Supreme Court Denies Appeal of Mountain Valley Pipeline Case

The U.S. Supreme Court last week declined to weigh in on the question of whether the Mountain Valley Pipeline can take private land for its project. 

Without comment, the court denied a request from six property owners that it hear their challenge of the company’s use of eminent domain to forcefully acquire easements through their land for the natural gas pipeline. The landowners argued that Congress improperly delegated its power to seize private property to FERC. After finding there was a public need for the pipeline, FERC then passed its eminent domain authority on to Mountain Valley. 

More: The Roanoke Times 

Republicans Press Granholm About Pause in LNG Export Permits

House Republicans last week grilled Energy Secretary Jennifer Granholm on the Biden administration’s pause on LNG exports and accused the administration of halting new permits for political gain. 

During a House Oversight and Accountability Committee hearing, Rep. Pat Fallon (Texas) said he was perplexed the U.S. would pause natural gas exports when other countries such as China and Russia have not made the same commitment to cleaner energy sources. Rep. Clay Higgins (La.) said that under the Natural Gas Act, the Energy Department has to issue permits unless it finds that it is not in the public interest. 

Granholm said the point of the assessment, which she said is slated to wrap up early next year, was to find out whether exporting natural gas to foreign countries was in the public interest. 

More: The Washington Times 

FERC Grants Extension for Gulf LNG Import Terminal

FERC last week awarded Gulf Liquefaction and Gulf Energy an extension to construct their Gulf LNG liquefaction project. 

The companies requested a five-year extension in February, saying the COVID-19 pandemic and litigation with import customers had affected their ability to meet the project’s deadline. The project now has until July 16, 2029, to be completed and operational. 

More: LNG Prime