Search
`
November 15, 2024

Posted on

Beyond Nuclear Leads Protest of Palisades’ Potential Reopening

Nearly 100 organizations and several hundred individuals have asked Michigan Gov. Gretchen Whitmer to abandon a strategy that would re-open the closed Palisades Nuclear Power Plant.

Led by the Beyond Nuclear campaign, the 94 groups and individuals sent a letter June 9 urging Whitmer to keep the nuclear plant shuttered. The plant was shut down in May, as promised in 2017 by Entergy (NYSE:ETR), its owner, and still has nine years remaining on its operating license.

Earlier this spring, Whitmer included Palisades for consideration in the Department of Energy’s $6 billion Civil Nuclear Credit (CNC) program to prevent nuclear generators’ early closure. The program originally had a mid-May deadline, but the DOE extended it to July 5. (See DOE Launches $6B Nuke Credit Program.)

“The bailout and restart scheme ignores Palisades’ severe, high-risk, age-related degradation, including multiple worsening pathways to catastrophic reactor core meltdown; the worst pressure vessel embrittlement in the country; severely degraded steam generators and reactor lid, exceedingly long overdue for replacement; a half-century worth of problem-plagued control rod drive mechanism seal failures, etc.,” Kevin Kamps, radioactive waste specialist at Beyond Nuclear, said in a press release.

Palisades’ reactor was removed from service in late May several days before Entergy’s official closure date. The utility said it was forced to shut the plant early because of performance issues with a control rod drive seal.

Entergy is in the process of selling the plant to Holtec International, which will dismantle the plant and remove spent fuel rods for long-term storage. The transaction is expected to take place next month and has already been approved by the U.S. Nuclear Regulatory Commission.

The closure coincides with a refueling deadline and the expiration of a 15-year power purchase agreement with Michigan utility Consumers Energy. Entergy has said it would entertain other potential buyers.

“Palisades produces more than 800 megawatts of reliable, clean, carbon-free power. Keeping Palisades open is a top priority,” Whitmer wrote in an April letter asking Palisades to be considered for the CNC program. “Doing so will allow us to make Michigan more competitive for economic development projects bringing billions in investment, protect hundreds of good-paying jobs for Michigan workers, and shore up Michigan’s clean energy supply and provide reliable lower energy costs for working families and small businesses.”

Whitmer said that over the last several years, Michigan’s government has worked to try to keep Palisades open “and voiced concern over the economic and energy impacts of losing the plant.” She said the Michigan Public Service Commission’s 2019 Statewide Energy Assessment showed that the plant strengthens reliability, helps temper commodity price risks, provides carbon-free energy, and offers fleet diversity.   

Kamps called Palisades a “zombie reactor.” He said it’s not worth the risk to the public to resurrect the plant for another nine years of “ever more high-risk operations.”

He argued that it’s now time to secure the radioactive waste stored on-site and clean up contamination at the plant, which borders Lake Michigan.

“Our analysis indicates that Palisades does not even qualify for such a bailout under the U.S. Department of Energy’s own rules,” said Diane D’Arrigo, radioactive waste project director at Nuclear Information and Resource Service. “For starters, the governor is not allowed to apply. The owner must do so, but Entergy has made clear it is not interested. In fact, Entergy closed Palisades 11 days earlier than scheduled, to transfer the site to another company to dismantle and decommission.”

The CNC program allows owners of commercial nuclear reactors facing closure to competitively bid on credits to keep them in operation. Applicants must prove their reactor will close for economic reasons and that the closure will result in increased air pollution. Credits would be allocated over a four-year period.

The DOE does not comment on reactors’ eligibility for the program.

Posted on

FERC Proposes Interconnection Process Overhaul

FERC on Thursday proposed long-awaited rule changes that it said would clear clogged interconnection queues and give generators more certainty on upgrade costs while ensuring fair treatment of new technologies.

The commission unanimously approved the Notice of Proposed Rulemaking (NOPR), which would replace the serial “first-come, first-served” study procedure with “first-ready, first-served” cluster studies (RM22-14).

The new approach “is a more efficient way of processing a large interconnection queue because it allows transmission providers to study numerous proposed generating facilities at the same time,” FERC staff said in a presentation at the commission’s monthly open meeting. “Additionally, conducting a single cluster study and cluster restudy each year can minimize delays that can arise from proposed generating facility interdependencies and minimize the risk of cascading restudies when a higher-queued interconnection customer withdraws.”

Delays caused by the inefficiency of the current process and the increasing volume of wind, solar and storage projects have been a major source of frustration for generation developers — and a threat to reliability, FERC said.

At the end of 2021, there were more than 1,000 GW of generation and 400 GW of storage pending in interconnection queues nationwide, more than triple the total of five years ago, officials said. Chairman Richard Glick (D) said projects now take an average of 3.7 years to complete the interconnection gauntlet, with less than a quarter of projects surviving to the end.

The NOPR would impose more stringent financial commitments and readiness requirements for interconnection customers, which FERC said would discourage speculative interconnection requests and allow transmission providers to concentrate on processing those with a greater chance of reaching commercial operation.

It also would impose tougher rules on transmission providers, replacing the current “reasonable efforts” standard for completing interconnection studies and subjecting those who fail to meet study deadlines to potential penalties.

Other provisions of the rule would:

  • require transmission providers to allocate network upgrade costs among interconnection customers in a cluster based on the degree to which each generating facility contributes to the need for the upgrade. Under current rules, an interconnection customer that triggers a network upgrade can be saddled with its entire cost even though subsequent interconnection customers benefit from it.
  • require transmission providers to use a standardized, transparent process for affected-systems studies, with specified modeling and pro forma study agreements.
  • simplify the process of studying interconnection requests that are related to the same state-authorized or ‑mandated resource solicitation. Transmission providers would be required to offer an optional process allowing resource planning entities to determine the costs of different combinations of projects that may be selected in a solicitation.
  • require transmission providers to allow more than one resource to co-locate on a shared site behind a single point of interconnection and using a single interconnection request. A generating facility could be added to an existing interconnection request without losing its place in the queue as long as it did not change the originally requested  service level.
  • require transmission providers to consider “alternative transmission solutions” if requested by an interconnection customer.
  • require interconnection studies to use assumptions that reflect the proposed operation of a generating facility.
  • require non-synchronous generating facilities to be able to ride-through disturbances and continue providing power and voltage support, addressing the reliability problem of momentary cessation. (See NERC, WECC Repeat Solar Performance Warnings.)

In calling for a switch to a “first-ready, first-served” study process, the commission endorsed rules it has already approved for MISO and SPP, and which PJM proposed in a filing Tuesday. (See related story, PJM Files Interconnection Proposal with FERC.)

“There are RTOs and other transmission providers that are engaged in queue reform … and we said [in the NOPR] that we obviously want to take them into account. … We have to take each of those proposals on a case-by-case basis,” Glick said.

The commission proposed a transition process allowing late-stage customers to complete their interconnections under the existing process. Comments on the NOPR will be due 100 days after publication in the Federal Register, with reply comments due 30 days after that.

The current procedures resulted from Orders 2003 and 2006, which standardized interconnection procedures for large and small generating facilities, and Order 845, a 2018 attempt to streamline the process. (See FERC Order Seeks to Reduce Time, Uncertainty on Interconnections.)

Glick acknowledged FERC has done “queue reform” before, with Order 845. “But this is far and away the most aggressive [effort], and I believe it will finally help move the needle,” he said.

‘Second Track’

Notably, Commissioner James Danly (R), who frequently dissents from the commission’s actions, supported the majority Thursday. He opposed the commission’s April NOPR on transmission planning, saying he did not think the commission had sufficient evidence that the existing planning rules were unjust and unreasonable. (See FERC Issues 1st Proposal out of Transmission Proceeding.)

“That’s not the case here,” Danly said. “I think the problems of the interconnection queue are widespread and they’re manifest. … I always prefer it when the utilities grapple with their own problems rather than have their problems fixed by us, especially under widespread legislative fiat through rulemakings. But in this case, there were a number of meritorious proposals that are worthy of the commission’s and the public’s consideration. And while some of the proposals, I think, represent typical bureaucratic overreach and unnecessary nitpicking detail, others are truly worth us looking into. So I am looking forward to seeing the record developed.”

Glick said the April NOPR, which required transmission planners to make their planning processes more proactive, was the “first track” of the commission’s efforts to eliminate barriers to the connection of more renewables. “This is the second track … which is just as important, if not more important,” he said. “For the first time, we have real deadlines that [transmission providers] have to meet.”

At the same time, new rules on study deposits, demonstration of site control, commercial readiness milestones and withdrawal penalties will make it “much more difficult for” generators to make speculative interconnection requests, he said in a press conference after the meeting. “To me, both of those are significant.”

The two NOPRs arose from the commission’s Advance Notice of Proposed Rulemaking (ANOPR) on regional transmission planning, cost allocation and generator interconnection in July 2021. (See FERC Goes Back to the Drawing Board on Tx Planning, Cost Allocation.)

They won’t be the last actions resulting from the initiative, said Glick, who promised action on how to fund transmission upgrades and interregional transmission planning, among other issues. “I can’t give you a timetable, but I’m hoping sooner rather than later,” he said.

Reaction

The Solar Energy Industries Association expressed support for FERC’s “bold action,” saying the commission had adopted many of the recommendations the group made in an interconnection white paper issued earlier this week.

“The most significant part of these reforms is the built-in accountability for utilities,” said Ben Norris, SEIA’s senior director of regulatory affairs. “For years, utilities have been dragging their feet on interconnection, and this rulemaking would implement deadlines for completing interconnection studies and create penalties for utility inaction. … We also believe that the cluster studies, affected-system study changes and a more realistic look at operating conditions for renewable energy generators will significantly improve the interconnection process.”

Rob Gramlich, executive director of Americans for a Clean Energy Grid, also praised the commission’s action but said it must go further.

“The real root cause of the logjams is insufficient transmission capacity, which requires reform to transmission planning and cost allocation,” he said in a statement. “Problems with transmission planning are blocking economic development and job creation, especially in rural areas, and are leading to increasing electricity costs for consumers.”

Posted on

EV Charging Standards Leave Some Obstacles Untouched

WASHINGTON — Electric vehicle stakeholders have largely praised the Biden administration’s standards for a national network of EV fast chargers that Transportation Secretary Pete Buttigieg promises would make “finding a charge as easy as filling up at a gas station.”

But high demand charges, limited electric distribution capacity and a lack of charging sites in rural areas raise barriers to EV adoption that standards alone may not be able to address, some say. Others question how the standards will be enforced.

The standards proposed by the Federal Highway Administration June 9 would cover EV chargers funded through $5 billion in state grants from the Infrastructure Investment and Jobs Act (IIJA). The administration wants to install 500,000 chargers, with sites every 50 miles on U.S. highways. They would be 150-kW DC fast chargers that can power up any EV make or model, are publicly available 24-7, accept any debit or credit card, and are operating 97% of the time. (See Biden Administration to Order EV Charging Standards.)

Mike Calise, president of the Americas for Australia-based Tritium Charging, which is opening a new plant in Tennessee later this year, said standards are critical “because everyone has to be working to the standards in order for this widespread [EV] adoption to occur.

“It doesn’t matter whether they are perfect, what matters is that they’re adoptable by the masses,” he said.

Rural Challenges

Meeting the 50-mile goal could be a challenge for electric cooperatives, said Brian Sloboda, consumer solutions director at the National Rural Electric Cooperative Association (NRECA).

Co-ops often serve remote and rural areas with “major stretches of highway that actually don’t have suitable site hosts — no restaurants, no gas stations,” Sloboda said. “You can go more than 50 miles in parts of the country and not see anything along these highways.”

Joel Levin, executive director of Plug In America, a nonprofit focused on consumer issues, said fast chargers in remote areas could rack up high utility demand charges, creating yet another barrier.

Based on peak usage, demand charges for DC fast chargers “can be really significant,” Levin said. “Let’s say you’ve got four chargers and four people pull in, use them [simultaneously], and then no one uses them again for a week. Your demand charges are going to be really high, and you’re going to have practically no revenue to support it.”

Gas vs. Charging

For Anthony Castro, a sales consultant at Euro Motorcars, a Mercedes Benz dealership in Bethesda, Md., even fast chargers required by the standards may not close the gap between the time it takes to pump gas and the time it takes to charge an EV.

With a 200-kW fast charger, Mercedes’ new luxury EV, the EQS, can go from being 10% to 80% charged in 30 minutes, Castro said.

“So, a 150 [-kW charger] will take a little bit longer,” he said. “Maybe like 35 minutes.”

Tritium’s Calise believes the comparison between gas stations and EV charging stations needs to be reframed. For some consumers, fast charging stations will offer a “convenience lifestyle,” he said.

Tritium’s fast chargers can provide 100 miles of added range in about 10 minutes, Calise said. “The benefit is you’re in your car versus outside pumping. You sit back, relax in air conditioning and text your kids.”

Castro and Calise were among the electric automakers and EV charging providers showing off their wares at the Department of Transportation headquarters as part of the rollout of the new standards. U.S. sales of all-electric and plug-in hybrids grew from 308,000 in 2020 to 608,000 in 2021, according to figures from the Department of Energy.

The range of vehicles on display at the DOT reflected this growth and the expansion of consumer choices, from the high-end EQS (350-mile range, $102,310 sticker price) to the wallet-friendly Chevrolet Bolt (259-mile range; 2023 sticker price $26,595).

The fast chargers on display were not all compliant with the proposed standards — company executives said they had to bring smaller models for ease of shipping — but most said they had 150-kW models and expected they would be able to meet the administration’s benchmarks for convenience and reliability.

Reliability Complaints

But consumer advocates remain skeptical.

Carleen Cullen, executive director of nonprofit Cool the Earth, says the 97% reliability requirement, which includes extensive data collection and quarterly reports, has no teeth.

“There are no enforcement mechanisms, no penalties for failure and no third-party testing of charging reliability,” she said. “We simply will not achieve the essential transition to EVs without enforcement, penalties and verification of uptime reliability at publicly funded EV charging.”

Recent studies from Plug In America and Cool the Earth suggest that companies’ reliability claims are not always matched by consumers’ experiences. Plug In America’s survey of more than 5,500 EV owners found that broken or otherwise nonfunctioning chargers were a top complaint.

“The public charging network is kind of frustrating,” Levin said. “It’s a patchwork of different networks. Some of them take credit cards; a lot of them don’t. Some of them tell you how much you are paying up front; a lot of them don’t. … If you drive a gas car, you never have that experience.”

He believes the standards’ requirement that each federally funded public charging station have at least four ports could provide a higher level of reliability. Even if one charger is down, others may be available, he said.

Cool the Earth tested several hundred public fast chargers in California — in some cases, visiting twice — and found that almost 23% were not functional.

“The findings suggest a need for shared, precise definitions of and calculations for reliability, uptime, downtime and excluded time, as applied to open public [DC fast chargers], with verification by third-party evaluation,” the group’s report said.

Phil Jones, executive director of the Alliance for Transportation Electrification (ATE), said the standards may be setting the reliability bar too low. While “97% sounds high, it’s really not that high” Jones said. “When you think of a consumer, an EV owner who goes to [a fast-charging] station, they expect it to be on all the time. Having two hours a month or five hours a month for a certain charger to be out of service, some people would say is not acceptable.”

Demand Charges

ATE raised a second concern in a recent report arguing that high demand charges could “stymie the deployment of the new commercial fast charging stations.

“Since EVs come with many benefits to utilities, their customers and society at large, and because public policy considerations are part and parcel of the rate design process, the Alliance supports demand charge relief as the market develops,” the report says.

The issues are complex, Jones said, and utilities across the country are experimenting with different approaches to demand charge mitigation. Examples include traditional commercial rates with a short-term waiver of demand charges to offset low utilization rates in remote areas or nascent markets. Under subscription rates, by contrast, low or growing demand can be incorporated into a monthly charge included in the rate base.

As more EVs are on the road, and public charging stations see more vehicles, the report sees a cross-over point where mitigation measures could be more expensive than demand charges, the report says.

With waivers, Jones said, “It’s basically saying for six years, eight years, 10 years, the demand charge is going to be mitigated way down to either zero or 10%. And then when utilization of the charging station picks up, probably the demand charge is better … and kicks back in.”

Interconnection

Interconnecting fast chargers on utility distribution systems is yet another challenge, especially in locations where fast chargers add demand to already congested lines.

EV charging stations could run into the delays that have plagued commercial and community solar in some regions as individual feeders may not have the capacity required for four or more 150-kW chargers, Jones said. Further, the hosting capacity maps some utilities offer to help developers site their projects may be out of date or inadequate, he said.

“They’ll get a certain answer there, but when they actually go and talk to the [utility] program managers and the distribution engineers, it’s different. So, we have a lot of work to do there,” he said.

“We don’t have the distribution network to support these ultrafast charging loads on retail sites where you and I need to go to charge our vehicle,” said Arcady Sosinov, CEO of charging provider FreeWire Technologies, which has developed a fast charger with a built-in battery pack. “We’re not looking to charge next to utility substations; we’re looking to charge at Starbucks, at Whole Foods, at the quick-service restaurants. And these sites simply don’t have the power available today.

“You’re looking at total utility infrastructure buildout,” Sosinov said. “That means bringing new power to these sites, new transformers, new switchgears, new substations. That’s where the problem lies.”

Sosinov says fast chargers with built-in batteries, like FreeWire’s models, can address both interconnection challenges and demand charges. The battery can smooth out the spikes caused by fast charging, which in turn drive both interconnection and demand charge issues.

NRECA and the Edison Electric Institute (EEI) acknowledge that not all distribution lines are ready for the new load that DC fast chargers will bring. But they maintain that the way forward begins with good planning and communication with the state departments of transportation (DOTs) that are developing EV charging deployment plans governing how they will spend the IIJA funds.

Still another requirement is that charging stations be located no more than one mile off major highways or other key traffic corridors — another effort to replicate a gas station-like experience. If such locations do not have enough capacity, utilities can plan ahead to make the necessary system upgrades, Sloboda said. “The charger won’t be installed today. It’s going to take a while for that charger to show up, and what you do not want is to have that charger installed and not connected to the grid.”

“We would prefer states not submit a plan and say, ‘Okay now, electric companies, what can you do for me?’” said Kellen Schefter, EEI’s senior director of electric transportation. Early communication allows for “iterative conversations,” he said, so utilities can identify the locations where EV chargers can be deployed quickly and others where “a longer time horizon” is needed for system upgrades.

‘Different Vocabularies’

Both Sloboda and Schefter said planning for these fast-charging networks has opened new lines of communication between utilities and the state DOTs, which may lack expertise on utility distribution systems.

At the same time, energy officials may not know transport, said Jim McDonnell, director of engineering for the American Association of State Highway and Transportation Officials (AASHTO). His organization is planning sessions for state transportation and energy officials “to try to bridge the learning curve that needs to take place. The two industries have different vocabularies and different ways of doing things.”

He, Sloboda and Schefter all gave high marks to the Biden administration’s Joint Office of Energy and Transportation, set up earlier this year to help states develop their EV charging plans, which must be submitted by Aug. 1.

A 60-day comment period on the new standards will still be open at that time, but Susan Howard, AASHTO’s director of policy and government relations, said, such overlap is not uncommon.

“The state plans are really focused on where the charging is going to be, the requirements for the distance from the interstate, looking at the alternative fuel corridors,” she said. The standards are “really focused on the what.”

McDonnell said the Aug. 1 filings won’t be the last word. “The state plans are intended to be living documents that will be refined and updated and modified appropriately over the coming five-year period of the entire infrastructure bill,” he said. The standards “will come into play when they are actually putting RFPs out on the street for companies to help them build out their charging systems.”

Posted on

FERC Approves Extreme Weather Assessment NOPRs

Citing the “challenges that are growing every day” from climate change-induced severe weather, FERC on Thursday approved two draft Notices of Proposed Rulemaking intended to improve the long-term reliability of the bulk power system.

Because both measures relate to severe weather risks, FERC staff presented the NOPRs together at the commission’s open meeting. One proposes to direct NERC to modify reliability standard TPL-001-5.1 (Transmission system planning performance requirements) to set expectations for long-term planning by utilities (RM22-10).

Under the proposal, responsible entities would be required to:

  • develop benchmark planning cases based on historical extreme heat and cold weather events and future meteorological projections;
  • use steady state and transient stability analyses, covering a range of factors such as the grid’s changing resource mix and its performance during extreme weather, to plan for future extreme events; and
  • create a corrective action plan to mitigate any occasions where performance requirements for severe weather have not been met.

Tech Conference Spurs Standards Effort

The proposal grew out of a technical conference FERC held last year on climate change and severe weather and their impacts on the electric grid, according to Milena Yordanova from FERC’s office of the general counsel, who presented the NOPR during FERC’s open meeting on Thursday. (See FERC Tackles Grid Planning for an Unpredictable Climate.)

“Since 2011, the country has experienced at least seven major extreme heat and cold weather events, all of which stressed the bulk power system and resulted in some degree of load shed. In some cases, these events nearly caused system collapse and uncontrolled blackouts, which were only avoided by the actions of system operators,” Yordanova said. In particular, she pointed to the winter storms of February 2021, when the Texas power grid came close to total collapse amid record cold temperatures. (See ERCOT: Grid was ‘Seconds and Minutes’ from Total Collapse.)

Yordanova said the NOPR focused on TPL-001 because it already establishes requirements for utilities to plan to operate the grid under “a broad spectrum of system conditions and following a wide range of probable contingencies”; however, the standard does not currently include any specific measures relating to extreme weather. It also does not have any provisions requiring the development of corrective action plans, although it does provide for utilities to “evaluate possible actions to reduce the likelihood or mitigate the consequences of extreme events.”

Transmission Providers Need Climate Plans

The other NOPR introduced on Thursday, also inspired by last year’s technical conference, proposes to solicit one-time reports from transmission providers detailing their “current or planned policies and processes for conducting extreme weather vulnerability assessments and mitigating identified extreme weather risks” (RM22-16, AD21-13).

Presenting the NOPR, Alyssa Meyer of FERC’s Office of Energy Policy and Innovation said participants in the conference expressed “widespread agreement” that utilities and other bulk power system stakeholders should assess their vulnerability to extreme weather risks. However, while some transmission providers do conduct such assessments voluntarily, there is no industry-wide requirement that they do so.

Meyer emphasized that the NOPR is not meant to impose any new requirements on utilities that already conduct their own assessments, and that transmission providers that do not will only be required to do so once. The proposal does require transmission providers to submit a one-time report to FERC detailing how they:

  • establish the scope of their vulnerability assessments;
  • develop inputs;
  • identify vulnerabilities and determine exposure to extreme weather hazards;
  • estimate the cost of weather impacts; and
  • develop mitigation measures to address extreme weather risks.

While both items passed without objection, the discussion at Thursday’s meeting once more brought to light some philosophical differences between the commissioners. Notably, Commissioner James Danly warned that the commission should focus not only on the growing climate risks, but also on policies at the state and local level that he believes push the BES into a more vulnerable position.

“My belief is that there is a growing narrative that places the weather itself at the center of the reliability problems we’re facing, and when we look at the dire warnings we have of thinning capacity, margins and shortfalls, those are not driven by the weather,” Danly said. “When you reduce the amount of capacity you have, when you have market systems that create bad price signals that fail to properly incentivize the correct entry, exit and retention of the resources needed to keep the system running … then you are more vulnerable to any disruption, weather included.”

Asked about Danly’s comments in a press conference after the meeting, FERC Chair Richard Glick expressed strong disagreement, saying the commission can only act within the framework established by the Federal Power Act and has no legitimate role to play in influencing government policy decisions.

“FERC’s role is to take the situation as it is, react to it and ensure, to the greatest extent possible, that rules are in place to ensure grid reliability,” Glick said. “I think that this whole notion that we should sit here from FERC and tell the states they got it wrong is ridiculous. That’s not our role, and if you’re a strict constructionist, you would agree with that. Commissioner Danly calls himself a strict constructionist quite frequently, but if you look at the Federal Power Act, it’s very clear.”

Comments on both NOPRs are due 60 days after their publication in the Federal Register.

Posted on

California PUC Gets Feedback on Net Metering Alternatives

The California Public Utilities Commission received 30 sets of comments last week on possible changes to its controversial net metering plan, including an alternate way to compensate homeowners who export surplus solar power to the grid.

A CPUC administrative law judge issued the initial proposal, NEM 3.0, in December, saying the current approach, NEM 2.0, unfairly requires most utility customers to pay more for electricity to benefit those who can afford to put solar panels on their roofs.

“Our review of the current net energy metering tariff, referred to as NEM 2.0, found that the tariff negatively impacts nonparticipating customers, is not cost-effective, and disproportionately harms low-income ratepayers,” CPUC Administrative Law Judge Kelly Hymes wrote. (See California PUC Proposes New Net Metering Plan.)

After pushback from the solar industry, the CPUC put the plan on hold in January. (See CPUC Postpones Net Metering Plan.) In May, Hymes asked parties to comment on questions she posed regarding possible alternatives.

The judge’s questions focused on a “glide path” to transition rooftop solar owners from the generous benefits they now receive, and non-bypassable charges (NBCs) for solar owners based on their gross energy consumption, including use of the solar energy they generate.

The voluminous response to the judge’s questions came from industry groups and environmental advocates, among others.

The Solar Energy Industries Association (SEIA) contended that reducing solar subsidies “would place the future of the solar industry in California in jeopardy, and thereby not fulfill the Commission’s statutory obligation that customer-sited renewable distributed generation continues to grow sustainably.”

Most of the environmental groups that weighed in echoed the argument.

In their joint comments, the state’s three largest investor-owned utilities, which have pushed for net metering reform, supported the December proposed decision while urging the CPUC to “adopt a new successor tariff as expeditiously as possible.”

“Reform of the net-energy metering program is necessary to address its growing outsized subsidy and remedy the inequity between participating and non-participating customers created by the program,” Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric argued.

The utilities said $4 billion in costs would be shifted this year from ratepayers with rooftop solar to those without it. NEM 2.0’s subsidy for solar owners raised electric rates by 10-21% for other ratepayers last year and will increase their bills as much as 31% by 2030, they said.

“Each additional adoption of rooftop solar increases rates for non-participants because a smaller pool of remaining customers must pay for fixed infrastructure and policy costs, including the NEM subsidy,” the utilities said. “Without reform, this unsustainable cycle will continue ad infinitum.”

ACC Plus and NBCs

The December decision proposed reducing compensation for customers with rooftop solar from the full retail rate, which is now much higher than the cost of utility-scale solar, to an avoided-cost rate that would consider the value of behind-the-meter generation for resource adequacy and grid reliability. That could cut the reimbursement rate by more than half.

The proposed decision would charge solar owners — who currently pay only small amounts for interconnection and grid maintenance — a grid participation charge (GPC) of about $40 per month on average. The decision proposes partly offsetting the charge with a market transition credit (MTC) of up to $5.25/kW per month, depending on the utility.

It would also establish a rebate program for customers who add storage to solar under what’s colloquially called NEM 3.0, but which the CPUC calls the net billing tariff.

In her May ruling, Hymes asked commenters to address possible alternatives. In place of the MTC, she asked parties to comment on another approach called “ACC Plus,” which would pay customers an export adder on top of the avoided-cost rate. (ACC stands for avoided cost calculator.)

The utilities said they preferred the MTC plan, in part because ACC Plus would incentivize exports to the grid instead of boosting behind-the-meter storage capacity.

SEIA and others said ACC Plus would be better than MTC because it would compensate ratepayers for exporting more to the grid, similar to the current setup under NEM 2.0.

The non-bypassable charges (NBCs) based on gross consumption were proposed by the Sierra Club, the judge said. Under the proposal, homeowners would be charged for using the behind-the-meter resources they generate as well as imports from the grid. Those with rooftop solar now only pay extra charges for imports.

The utilities supported the change. “Recovering fixed policy and infrastructure costs through mechanisms such as the grid participation charge or the Sierra Club gross-consumption mechanism for recovering NBCs are not only legal, but also are required to eliminate the burden of the NEM subsidy on non-participants.”

SEIA disagreed, saying the charges would be illegal.

“The Commission should not assess NBCs on any [behind-the-meter] consumption. The energy produced and consumed [behind-the-meter] does not originate nor travel on the systems of the Commission regulated investor-owned utilities,” the trade group said.

“The Commission does not have regulatory authority over individual NEM customers as generators,” it added. “These generators are not electrical corporations (and thus public utilities) over which the Commission has broad sweeping regulatory authority. Indeed, the definition of electrical corporation specifically excludes ‘independent solar energy producers.’”

Reply comments are due by June 24, and a revised proposed decision could be issued as early as mid-July.

Posted on

PJM Orders Load Sheds in AEP Following Storms

More than 200,000 American Electric Power (NASDAQ:AEP) customers in Ohio lost electricity after storms Monday damaged multiple transmission lines and forced PJM to order load sheds on at least three 138-kV lines.

AEP reported Tuesday morning that more than 145,000 customers lacked power after “straight line winds and lightning crossed the state and took down trees and power lines.” Crews had restored power to about 10,000 customers overnight.

But as of 5 p.m. Tuesday, AEP’s outage map listed more than 210,000 customers out of service in an area south of Akron and Toledo, including Columbus and the Southeastern part of the state. The number had dropped to 206,000 by 7 p.m.

PJM said “a transmission disturbance” around 1:40 p.m. ET “resulted in multiple 138-kV lines going out of service, creating overloads on other transmission lines.”

The RTO responded at 2:02 with a load-shed directive to prevent overloads on the 138-kV Kenny-Roberts line near Columbus; followed by a similar order for the 138-kV Clinton-Karl at 2:06 p.m., and one for the 138 kV Marion-Obetz at 2:35.

At 3:15 the RTO issued a maximum generation emergency/load management alert and an EEA1, indicating it “foresees or is experiencing conditions where all available resources are scheduled to meet firm load, firm transactions and reserve commitments, and is concerned about sustaining its required contingency reserves.”

Lineworker Reparing Power Line (AEP Ohio) Alt FI.jpg

AEP crews restored power to about 10,000 customers overnight after storms Monday. | AEP Ohio

The alert called maximum emergency generation into operating status. Generation dispatchers were directed to inform PJM an estimate of how much time they need to return to generation on planned outages to service.

By 3:50, PJM had ordered an emergency load management reduction action and declared a NERC level EEA2, signaling “public appeals to reduce demand, voltage reduction and interruption of non-firm load in accordance with applicable contracts, demand-side management or utility load conservation measures.”

In issuing the load shed, the RTO also declared that performance assessment hour guidance was in effect for AEP. Online generators were directed to follow PJM’s basepoints or manual dispatch instructions, and the RTO warned that those that underperform may be assessed a nonperformance charge; those that generated megawatts above the basepoint risked deviation charges.

PJM said it would directly call offline generators and load management resources available to help mitigate the emergency and that those that fail to meet the dispatch instructions may be assessed a non-performance charges.

The storms followed PJM’s issuance Monday of a Hot Weather Alert for the Western region Tuesday and Wednesday, directing transmission and generation dispatch operators to consider deferring or canceling scheduled maintenance and testing. Generation dispatchers also were asked to review and, if necessary, update their unit parameters to ensure the accuracy of their start-up and notification, minimum/maximum run times and emergency minimum/maximum information.

The forecasted peak for Tuesday was 130,888 MW, rising to a projected peak of 142,942 MW on Wednesday.

Posted on

NERC Posts Inverter, DER Guidance Documents

NERC on Tuesday added new guidance documents to its website aimed at helping registered entities deal with the “instability and potential risks to the system” introduced by the growing reliance on distributed energy resources and inverter-based resources (IBRs).

The documents are based on the work done in recent years by NERC’s Inverter-based Resource Performance Subcommittee (IRPS) and System Planning Impacts of Distributed Energy Resources Working Group (SPIDERWG), which the ERO formed to explore potential issues associated with IBRs and DERs and develop white papers, reliability guidelines and other resources to help utilities integrate them into their systems. Both groups have also instigated multiple standards development projects.

Inverter-based resources refer to generation types such as solar photovoltaic and wind facilities that “are asynchronously connected to the grid and are either completely or partially interfaced with the [bulk power system] through power electronics,” according to NERC’s reliability guideline for IBRs.

DERs include resources that produce electricity but are not included in the bulk power system as NERC defines it, such as rooftop solar panels and behind-the-meter batteries, or cogeneration plants in which electricity is generated from energy produced as a byproduct of another process.

While there is some overlap between these categories — for example, rooftop solar panels also use inverters — the IRPS focuses on grid-scale generation facilities rather than the smaller installations handled by the SPIDERWG; hence the new quick reference guides, which bring together all of each group’s activities into a single searchable document, have no items in common.

Both documents are 12 pages long, but the types of information covered are not identical. Elements shared between the two include reliability guidelines developed by the relevant subgroup, white papers published during their work, standard authorization requests (SARs), and records of industry webinars they have delivered.

The IBR reference guide also has links to the various reports the IRPS has created on disruptions to the BPS that touch on IBR performance issues. One such report concerns a series of disturbances involving solar resources last summer in California, developed alongside WECC staff; also included is NERC’s report on the Odessa disturbance that occurred last year in Texas. (See NERC-ERCOT Report Reviews Texas Solar Issues.) In addition, the IBR guide lists the alerts that NERC sent in 2017 and 2018 about potential loss of solar resources because of inverter settings.

The DER reference guide does not include disturbance reports, but it does have a similar section for presentations heard by SPIDERWG on previous issues with DER integration. Several of these reports concern the experience of smaller power systems such as those in Colombia and Hawaii, where the impact of DERs can be seen more easily than in a large grid; others concern markets such as California, where the penetration of DERs has been relatively high.

In an email to the IRPS and SPIDERWG on Tuesday, NERC Senior Manager Ryan Quint said the plan is for both groups to update their respective documents regularly so that they can serve as a “one-stop shop” for industry. The documents will have their own entry under the “Initiatives” tab on NERC’s website.

Posted on

PJM Files Interconnection Proposal with FERC

PJM filed its long-awaited plan for untangling its interconnection queues Tuesday, proposing to switch from a serial “first-come, first-served” approach to a “first-ready, first-served” cycle (ER22-2110).

The result of 18 months of stakeholder discussions, the changes won sector-weighted support of 87% at the Markets and Reliability Committee and 90% at the Members Committee in April, well above the necessary two-thirds threshold for approval. (See PJM Stakeholders Endorse New Interconnection Process.)

“PJM believes, as do the vast majority of PJM stakeholders, that these reforms will vastly improve today’s interconnection process in the PJM region,” the RTO said.

The new rules are laid out in three new parts of the Open Access Transmission Tariff and changes to four others. Separately, PJM’s transmission owners are expected to file tariff revisions to incorporate their controversial proposal to fund network upgrades and add them to their rate bases (ER21-2282). (See FERC Establishes Paper Hearing on PJM Rate-base Network Upgrades.)

PJM asked the commission to approve the provisions by Oct. 3 with an effective date of Jan. 3, 2023, for most of the changes and an “indefinite” effective date for the new Part VIII of the tariff, saying “it is unknown when the preconditions for those tariff sections will be satisfied.” It proposed a 30-day comment period rather than the standard 21-day period.

But the RTO also acknowledged that FERC is considering its own changes to the interconnection process (RM21-17) and that “that further reforms may be required in the future.” (See FERC Goes Back to the Drawing Board on Tx Planning, Cost Allocation.)

The new rules would transition from a serial queue process to a clustered cycle process for both studies and cost allocation. The proposal includes a transition period that PJM said would allow “mature” projects to complete the existing process.

PJM said the proposal is similar to the rules used by SPP, MISO and PacifiCorp. It would add multiple decision points at which those seeking interconnection will be required to make readiness deposits and meet other threshold requirements to continue, “thus permitting projects that are ready to progress to do so while incentivizing projects that are not ready to proceed to exit,” the RTO said.

It also said more timely processing of interconnection requests “will enable PJM to support federal and state public policy (including various renewable and clean energy initiatives).”

The process includes a “fast lane” for projects with minimal network impact or cost responsibility.

The existing interconnection process accepts new service requests during two six-month queue windows annually (April 1 to Sept. 30, and Oct. 1 to March 31 of the following year). Interconnection customers are required to provide evidence of site control only for their generator sites and only once, at the beginning of the process.

“The time-intensive serial approach of PJM’s current interconnection process, coupled with the exponential increase in new services requests received in each queue window in recent years has resulted in a mounting backlog,” PJM said. It noted that the volume of new service requests increased 25% in 2018 over 2017, with another 50% jump in 2019. By 2021, the requests had almost tripled from 2018.

Total new services requests (PJM) Content.jpgTotal new services requests by year | PJM

 

“The delays arising from sheer volume are exacerbated by the large number of speculative projects that withdraw from the queue because they cannot be completed,” PJM added. “For almost every project that withdraws, PJM must restudy lower-queued projects to ensure the proper upgrades are identified and built to meet planning criteria and maintain reliability, which results in delays in processing those other new service requests. These withdrawals also create significant cost uncertainty for lower-queued projects, which may cause those projects to withdraw, causing a cascade of withdrawals.”

In the past, about one-third of projects withdrew from the queue after the feasibility study, but that has dropped to about 5% currently, leaving “many projects languishing in the queue only to drop out at a rate that totals 80% of the total,” PJM said.

PJM proposed implementing the new rules to new service requests submitted on or after Oct. 1, 2021, the opening of the AH2 queue.

“The new rules also establish system impact studies and cost allocation on a cycle-wide basis, rather than an individual project basis, which are designed to streamline the study process, reduce retool studies, and reduce cost responsibility and cost allocation disputes,” PJM said. “Providing incentives for the early exit of projects that are not ready (financially or otherwise) and performing studies on a cycle-wide basis will greatly reduce the number of late-stage withdrawals and the accompanying retool studies, which disrupt lower-queued projects’ expectations.”

Posted on

RI Poised to Enact Nation’s Most Ambitious Renewables Standard

The Rhode Island House of Representatives passed a bill 56-13 Tuesday that would amend the state’s Renewable Energy Standard to require 100% of electricity to come from renewable sources by 2033.

The Senate passed the bill (S2274/H7277) May 31 with an amendment that removed language allowing regulators to delay interim compliance dates based on renewables’ availability. A Republican-sponsored amendment to reinstate that language failed in the House Tuesday.

Current state legislation sets the annual increase in renewable energy that utilities must procure at 1.5%, to reach 38.5% by 2035. The new standard raises those interim amounts, starting with a 4% increase next year and reaching a 9.5% increase in 2032 and 2033 to total 100%. Utilities will be able to demonstrate compliance through the purchase of renewable energy certificates.

Rep. Patricia Morgan (R) called the renewable energy goal in the bill “aggressive,” saying “it will lead to energy poverty for the people of Rhode Island.”

Environmental advocates expect Democratic Gov. Dan McKee to sign the bill.

“Rhode Island’s ambitious timeline puts it at the head of the table with America’s top clean energy states,” Johanna Neumann, senior director of the Research and Policy Center at Environment America, said in a statement. “Rhode Island committing to 100% renewable energy faster than any state to date marks a milestone in America’s journey toward a future powered by clean energy.”

Nine states have a 100% RES in place, with target dates ranging from 2040 to 2050.

Supporters of the goal to increase the RES are also watching the status of another bill backed by McKee that would require Rhode Island Energy (NYSE:PPL) to issue a request for proposals for up to 600 MW of offshore wind by Aug. 15. The Senate passed the bill (S2583) June 7, and it is now before the House Corporations Committee.

“We are making great progress toward this goal of 100% with many offshore wind projects in Rhode Island and Massachusetts,” said Rep. Deborah Ruggiero (D), sponsor of H7277. “This doesn’t mean we won’t have any dependence on gas and oil, but this will make us much less dependent on fossil fuel and more reliant on renewables, to move us toward a resilient future.”

Posted on

NJ Lagging in Energy Storage Progress

Severely behind on meeting its goal of having 600 MW of energy storage in place by 2021, New Jersey is slowly focusing on how to stimulate development to handle its ambitious offshore wind, solar and electric vehicle policies.

Gov. Phil Murphy’s 2019 Energy Master Plan set the 600-MW goal and directed New Jersey to plan for 2,000 MW of storage in place by 2030. Yet the state at present has only 500 MW “installed or in the pipeline,” according to the New Jersey Board of Public Utilities (BPU). And most of that has been in place for decades.

Storage is key to managing the electricity supply in the clean energy era. It ensures that when the wind blows and the sun shines, the state can create a store of electricity ready to be tapped when the wind stops or there is no available sun energy, such as at night or when the sky is cloud covered.

Without storage, that extra electricity would likely have to come from fossil-fueled peaker plants, which are dirty and expensive and undercut carbon reduction efforts.

“Energy storage is probably the single most important clean energy technology that we don’t talk enough about, and we don’t invest enough in,” Doug O’Malley, director of Environment New Jersey, told a recent hearing of the Senate Energy and Environment Committee. “It’s been kind of an afterthought in our state policy,” he said in a later interview.

Other states have made more progress than New Jersey. The large-scale storage capacity of the U.S. as a whole grew about 35%, to about 1,800 MW, in 2020 and has tripled in the last five years, according to the U.S. Energy Information Administration. And utilities have reported plans to install 10,000 MW of power from 2021 to 2023. The pacesetters include New York, which released a report this year that says it is closing in on one of its goals: to create 1,500 MW of storage by 2025. And California, considered by some in the industry to be the most advanced state for storage, said in December that it has 2,500 MW in place and is close to reaching its storage goal for 2030.

Yet, there are signs that New Jersey’s relative inactivity may be changing. The Senate E&E Committee on June 9 backed a bill, S2185, that would require the BPU to develop a $60 million/year pilot program providing incentives for the installation of new energy storage systems in the state. The bill would require the BPU to adopt rules for a permanent storage incentive program no more than three years after the bill is enacted.

The pilot would offer upfront incentives based on the installed capacity of the storage that would account for up to 40% of the designated funds. It also would include a performance incentive based on how much it improves the efficiency of the grid and helps reduce peak demand.

The goal of the pilot, according to the bill, would be to provide “increased stability [for] the power supply, smoother integration of renewable energy sources, a reduction in the peak demand placed on centralized power plants and cost savings.”

Incentives for Grid Storage

In a separate initiative, the BPU is looking to incentivize the development of storage through the Competitive Solar Incentive (CSI) program, which provides subsidies for large-scale solar projects. And the BPU is developing a second phase of the storage proposals and expects to release them in a straw proposal in the second half of 2022, BPU spokesman Peter Peretzman said.

“Energy storage remains a priority of the board,” he said.

Part of the Successor Solar Incentive (SuSI) program approved by the BPU in July, the CSI program sets incentive levels for developers of solar projects above 5 MW through a competitive process, rather than the BPU setting the level.

The straw proposal, which stakeholders discussed at a May 26 BPU hearing, recommends that developers submitting a solar and storage project first compete for an incentive on the generation project alone. The developer seeking to develop storage would then submit a “storage adder” price in a second bid. (See Proposed NJ Solar REC Program Wins Initial Support.)

“Adding storage to a solar project carries some benefits that can result in increased project revenues over time,” the proposal states. “Solar projects that include storage can benefit from increased capacity ratings in PJM wholesale markets and from being able to store energy produced when local wholesale prices are low and sell when those prices are higher.”

The proposal also noted that “New Jersey does not currently have an independent energy storage program,” despite the fact that the state Clean Energy Act of 2018 required the state to develop “mechanisms for achieving energy storage goals.”

Indeed, little of the state’s existing storage stems from that legislative requirement. The state’s current storage capacity mainly consists of 68 MW of lithium-ion batteries, and the remainder comes from the 420-MW Yards Creek Pumped Storage Facility in Blairstown, the BPU told RTO Insider.

Yet the Yards Creek facility was actually developed in 1965, said Sen. Bob Smith (D), who co-sponsored S2185 and is chairman of the Senate E&E Committee. He called it a “screaming scandal” that the BPU includes the facility in its calculation of storage capacity.

“Come on BPU, you can’t take credit for that facility as meeting the state’s energy storage needs,” he said at a May 16 committee hearing. “There should have been some significant expansion. And we’re trying with this bill to nudge them along.”

Storage Growth

Nationwide, storage continues to grow. Capacity additions grew 173% in the first quarter of 2022, compared to the first quarter of 2021, according to American Clean Power. The increase was driven by the installation of 24 new battery storage projects totaling 758 MW, the organization said.

Most of the recent growth in storage capacity comes from battery energy systems co-located with or connected to solar projects, EIA said. Five states accounted for 70% of the nation’s battery storage capacity as of December 2020: California, Texas, Illinois, Massachusetts and Hawaii, with California accounting for nearly a third of the total.

CAISO said in December that it added 250 MW of storage from August 2020 to the end of 2021, at which point California had a capacity that, in the words of the ISO, was “the highest concentration of lithium-ion battery storage in the world.” The development of new storage puts the state on track to outpace the Energy Commission’s January 2021 forecast that its battery storage would reach 2,600 MW by 2030. (See California Energy Commission Updates Long-Term Forecast.)

Meanwhile, New York Gov. Kathy Hochul on June 2 announced what the state said was its largest ever land-based renewable energy procurement, with 22 solar and energy storage projects totaling 2,078 MW. (See NY Contracts More Than 2 GW in Solar and Storage Projects.)

A report released in April by the New York Public Service Commission concluded that the state by the end of 2021 “deployed, awarded or contracted” projects totaling 1,239 MW in capacity, or about 82% of the state’s target of having 1,500 MW of storage in place by 2025.

In her State of the State speech in January, Hochul doubled the state’s 2030 target of 3,000 MW. In the report supporting her proposals, the governor said the that adding storage would create a “pathway to supplant fossil-fueled generators that disproportionately affect disadvantaged communities, while ensuring a clean, reliable and resilient electric grid.”

Documenting the Storage Need

New Jersey is not unaware that it needs to advance its plans to create storage.

Speaking to the Senate Environment and Energy Committee on Feb. 10, BPU President Joseph Fiordaliso cited the topic in response to a question on what more the state should be doing to mitigate the threat of climate change.

“We have to get more involved in storage,” he said. “Storage is an expensive part of this. However, it’s one of the vehicles that’s going to make green energy work. We have to get involved with it.”

In response to a request for comment by RTO Insider on why New Jersey has not made more progress in meeting its storage goals, the BPU released a statement that said it “has taken a deliberate approach to developing energy storage programs which are an important component of our clean energy program. Although our progress to date has been deliberate, we have taken significant recent strides that will enable us to meet our goal of 2,000 MW of energy storage by 2030.”

Both Atlantic City Electric (ACE) and Public Service Electric and Gas, two of the state’s largest utilities, said they are waiting for the BPU to implement its storage plan, which will enable their own storage projects to advance. In the meantime, ACE said it expects to break ground in September on a battery storage project that will support the local grid and enhance service for customers in Beach Haven and Long Beach Island, two communities on the Jersey Shore.

PSE&G in October submitted a plan to the BPU to spend $180 million over six years to build 35 MW of storage. That plan is still pending because it has not yet received BPU approval, the company said. The project will “help us better manage power outages, reduce peak demands at substations that are under construction and allow critical facilities to maintain a reliable supply of electricity during extended power outages,” according to the company website.

The project would follow several small-scale storage projects developed by PSE&G in connection with solar projects, including one that is designed to supply power to the Department of Public Works building in Pennington and enable it to keep operating if the power goes out. The storage works in conjunction with a 158-MW solar farm at the building.

PSE&G said it also has built similar projects at the municipal wastewater treatment facility in Caldwell, Hopewell Valley Central High School in Pennington and Cooper University Medical Center in Camden.

Planning for Growth

The Clean Energy Act also required the BPU to compile a report assessing the amount of storage in the state and recommending ways to increase it. Based on that report, the board should “establish a process and mechanism for achieving the goal of 600 MW of energy storage by 2021 and 2,000 MW of energy storage by 2030.”

In part because of that ambitious goal and the state’s plan for a community solar program, the Interstate Renewable Energy Council in 2019 named New Jersey one of four states on its Clean Energy States Honor Roll for having the “most growth potential.”

Researchers at Rutgers University compiled the report required by the Clean Energy Act, and released the New Jersey Energy Storage Analysis (ESA) in May 2019. It concluded that “energy storage is an essential component of New Jersey’s sustainable energy future because it enables the grid to handle increasing amounts of clean renewable energy and manage changing, highly variable electricity demand.”

The report estimated that two technologies were cost effective and did not face excessive financial barriers: pumped hydro and thermal storage, in which energy is stored as heat and is then released when it needed. The report added that the cost of storing electricity in lithium-ion batteries, the least expensive battery storage at the time, was “dropping rapidly, but it is not currently cost-competitive for most applications.”

Meeting the state’s storage goal of 600 MW by developing battery capacity would likely require incentives totaling between $140 million to $650 million, the report concluded.

‘Variability and Balancing’

The Energy Master Plan determined that the state could meet its electricity demand by building 32 GW of in-state solar, 11 GW of offshore wind and 9 GW of storage.

“As New Jersey increases the amount of renewable generation in its energy mix, variability and balancing become critical,” the plan said. “Energy storage resources are extremely well suited to provide these services.”

The plan found that the state will need 2.5 GW of storage by 2030 and 8.7 GW by 2050. When the plan was published, New Jersey had 475 MW of existing storage — not far below the 500 MW it has now.

To promote storage development, the state at one point launched the Renewable Electric Storage Program (RESP), which lists projects initiated in 2016 and later. However, the program’s webpage has no data after Jan. 7, 2019. A report on the page shows only one storage project installed through the program, a lithium-ion battery project approved in 2017 for a $300,000 grant for Atlantic County Utilities Authority’s Wastewater Treatment Facility, which is powered by a small wind farm and a 500-kW solar project.

Program administrators also approved two other projects for funding — at a meat packer and a charter school — totaling $210,000, but it is not clear what happened. Another 15 projects were canceled, according to the page.

Asked what happened with the program, BPU spokesman Peretzman said that the “board cannot say with certainty why storage projects offered an award in the Renewable Electric Storage Program did not reach commercial operation,” and he suggested speaking to the project developers.

He added, however, that BPU staff had noted that the time when the incentive program was operating “overlapped with rules changes at PJM that made the behind-the-meter storage projects at issue in RESP less financially attractive and that likely contributed to the lack of participation.”

Storage for Home, EV, Tech Use

O’Malley, of Environment New Jersey, said the state’s failure to create storage stems in part from the BPU’s allocation of resources to other priorities.

“Obviously, we haven’t seen state investment or [the BPU] meeting the mandate set out in the Energy Master Plan,” he said. “The BPU is doing a lot. And energy storage has drawn the short stick.”

Former BPU President Jeanne Fox told the board at a hearing on the SuSI program in November that for all the impressive advances in wind and solar energy in the state “we’re behind on” energy storage. She said that homeowners such as herself and small business owners want the capability to have solar and storage projects ready to provide power if extreme weather damages the grid, and that will take an incentive program to help build capacity.

Fox, who has solar installed at her homes in Central New Jersey and the Jersey Shore, said that she lost power during Superstorm Sandy in 2012, and she wants to install storage in case it happens again.

“What you want is battery backup with that,” she said. “There will be more extreme weather events,” and storage can help mitigate the impact, she said.

James Sherman — vice president of Climate Change Mitigation Technologies (CCMT), which helps customers purchase electric trucks, buses and other vehicles — told the BPU in October that storage would be needed to support the proposed incentive program designed to generate the installation of medium- and heavy-duty EV chargers around the state for trucks and buses.

Many fleets will want a package of solar energy and storage capability to support the installation of chargers, and the cost of such a package is “impossible to know” until the BPU produces an incentive program, Sherman said.