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November 6, 2024

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NJ Boosts EV Charging Program for Tourist, Multifamily Locations

New Jersey has added $6 million to two incentive programs designed to encourage the development of electric vehicle charging stations at tourist locations and multifamily buildings, as the state prepares to launch the third phase of a program that has to date awarded incentives for the purchase of more than 12,000 EVs.

The New Jersey Board of Public Utilities (BPU) allocated $4.5 million to the tourist program last month. Launched in the fall, the program closed its second round of applications on Wednesday. The project in the first phase awarded more than $1 million in grants for the installation of chargers at 24 tourist sites, resulting in the installation of 61 chargers, including to four state parks and at least eight sites on the Jersey Shore.

The program awards an incentive of up to $2,000 for Level 2 chargers and 50% of the make-ready costs, up to $5,000, and up to 50% of the cost of a DC fast charger and up to $75,000 in make-ready costs. (See NJ Seeks to Lure Tourists with EV Chargers.)

The board also allocated $1.5 million to strengthen the program that awards incentive packages to stimulate the development of chargers at multifamily dwellings. The program, now in its second phase, awarded about $1 million for the purchase of 223 chargers and funded the preparation of sites at 67 multiunit dwellings in 41 municipalities, the BPU said. (See NJ Greenlights Incentives for Multi-dwelling EV Chargers.)

Cathleen Lewis, e-mobility program manager for the BPU, said the increased popularity of EVs and the future need for home chargers is already leading to multiunit dwelling developers planning for charging at their properties.

“What you’re seeing is developers know that this is coming; this is going to be an amenity that people are going to want,” Lewis said. She said there had been a “huge diversity” in applications, stretching from suburbs to overburdened communities and dwellings of different sizes.

The funding shifts come as the BPU also prepares to launch the third phase of its Charge Up New Jersey program, which provides incentives for the purchase of an EV. The agency at the end of last month released a straw proposal for the next phase of incentives, with a cut from $5,000 to $4,000 of the maximum incentive available, and an incentive of $250 for the purchase of a Level 2 smart charger for residential use.

The BPU says the program has so far incentivized the purchase of 12,225 vehicles with another 1,235 pending, for a total cost of $57.7 million. The agency expects the third phase, which will require board approval once the final draft is prepared, to start some time after the beginning of the state’s new fiscal year in July.

The state will also receive $15.5 million in federal funds under the National Electric Vehicle Infrastructure Formula program to buy and install chargers, funding that the Biden administration earlier this month said must be used to create a national network that has minimum reliability standards and charging speed, works for all cars and takes common payment methods. (See Biden Administration to Order EV Charging Standards.)

State plans are due in August. Proposed rules released by the Federal Highway Administration (FHWA) include requirements that EV infrastructure “operate on the same software platforms from one state to another”; that they be installed, operated and maintained with qualified technicians; and that basic information, such as location, connector type, power level, real-time status and real-time price, be available free of charge and easily publicized.

Growth in EVs, Charger Installations

The state’s portfolio of EV incentive and charger programs provide a window into the demand patterns in New Jersey as the state pursues aggressive EV and electric charging goals. The state’s Energy Master Plan calls for the state to deploy 330,000 light-duty EVs on the road by 2025 on the way to reaching 100% clean energy by 2050, and cutting emissions by 80% of 2006 levels by the same date.

The state in January 2020 enacted a law that called for the installation of at least 400 DC fast chargers, which can add about 60 to 80 miles to an EV in 20 minutes of charging, and 1,000 Level 2 chargers, which add 10 to 20 miles per hour of charging time, by Dec. 31, 2025.

The law also called for fast chargers with 150 kW of charging power to be located on travel corridors and spaced less than 25 miles apart. The law said by the same date, 15% of multiunit dwellings much have chargers of some sort and 20% of franchised overnight-lodging establishment must have chargers.

The law also required at least 25% of state-owned emergency light-duty vehicles to be plug-ins by Dec. 31, 2025, and 100% of state-owned nonemergency light-duty vehicles to be plug-ins by 2035.

The state had 64,300 registered plug-ins at the end of last year, compared to about 42,000 a year earlier, about one-fifth of the 2025 target.

The state has more than 300 public charging locations, and about 95% of the state is located within a 25-mile radius of a fast charger, according to the Drive Green website operated by the New Jersey Department of Environmental Protection (DEP). In total, there are about 750 chargers in the state, compared to about 675 a year ago, according to the recent state budget.

Local and state government has been slow to transition, however. The additional funding for the tourism and multiunit programs came from the $7 million set aside for the state’s Clean Fleet program, which was launched in 2019 and designed to encourage local and state government entities to convert their fleets to EVs.

“Due to logistical and budgetary reasons, the Clean Fleet program has not generated sufficient interest to utilize all the existing, remaining funding,” according to the BPU order detailing the shift in funds.

Some communities have nevertheless embraced them, with the help of other programs. The DEP on June 15 said the city of Paterson, in North Jersey, would soon receive a prototype electric ambulance, purchased with $908,686 in state funds that will also pay for two fast-charging stations. The city had earlier announced the purchase of 38 Nissan Leafs purchased with the help of $210,000 in state funds for use by fire, housing and health inspectors and the city’s Department of Public Works.

The ambulances, which are expected to go into service in about a year, will replace diesel vehicles, the DEP said in a release. Replacing ambulances has a strong impact in cutting emissions because they spend a large proportion of their time idling as they wait for a call, the department said.

Middle-income Purchasers

The BPU also believes it has had some success in bringing EVs, which are often seen as the domain of mainly wealthy buyers, to those in more modest income brackets.

The second phase of the Charge Up New Jersey Program provided incentives for the purchase of 3,791 EVs, of which 47% got the maximum incentive, according to figures released by the BPU at a June 13 public meeting on the program straw proposal. The figures showed the impact of the board’s decision to limit the maximum incentive of $5,000 to vehicles costing no more than $45,000, with an incentive of only $2,000 for higher-priced vehicles, to a maximum of $55,000.

The rule change was introduced for the second phase of the program, in June, after Tesla vehicles accounted for 83% of the incentives in the first phase, and 93% of the incentives were for the maximum grant. The BPU introduced the $45,000 vehicle cost cap — which meant that only the cheapest Tesla was eligible for the maximum incentive — in an effort to award the subsidies to “incentive essential” customers: those who would only buy an EV if there was an incentive available.

BPU officials also said that they were trying to incentivize the purchase of EVs among middle-income families, rather than just those with higher incomes.

Data for approved incentives and pending applications from the second phase show the impact of the shift, with Teslas accounting for only 66% of the incentives approved or with applications pending in the second round.

“So, we’ve seen a more diversified field in year 2 than we did in year 1,” said the BPU’s Lewis. “We’ve seen many more of the more affordable vehicles and those under $45,000 receiving incentives.

She noted that the BPU has seen “a significant increase” — to 40% of the total — in applicants who got incentives of $2,000 or less. That allows the BPU to “provide incentives for more vehicles with that same budget,” she said.

The next-placed make of vehicle was Ford, mainly the Mustang Mach-E, which accounted for 7% of awards. Hyundai also accounted for 7%, with awards for Kona Electric, Hyundai Ioniq Electric and Ioniq PHEV vehicles. Chevrolet Bolts accounted for 6%.

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Climate Bonds Initiative Issues Draft Steel Certification Criteria

The Climate Bonds Initiative (CBI) on Thursday asked for public comment on draft requirements for allowing steel-sector bonds to obtain certification under its Climate Bonds Standard.

“We’re really looking to expand our suite of criteria for the standard … and that expansion is effectively trying to move us into a wider array of sectors,” Anna Creed, CBI’s head of standards, said in a launch webinar for the draft steel sector criteria.

CBI’s standard focused originally on eligibility criteria for assets and projects in the energy sector, but Creed said the organization now plans to move “at scale” into heavy industry and harder-to-abate sectors.

“Each sector-specific criteria sets climate change benchmarks for that sector that are used to screen assets and capital projects so that only those that have climate integrity, either through their contribution to climate mitigation, and/or to adaptation and resilience to climate change, will be certified,” CBI explained in its draft document.

Certification of a climate bond or green bond under the standard prior to issuance allows the issuer to claim compliance with criteria for the asset or project related to the bond.

“We have criteria in the latter stages of development also for chemical production and for cement production, plus we’re working on hydrogen at the moment, and then we’re going to move on to oil and gas,” Creed said.

CBI’s draft criteria for steel production proposes one segment to address new facilities and another for facilities that existed prior to 2022, according to Fabiana Contreras, industry transition analyst at CBI.

For bonds related to new, fossil fuel-based facilities to achieve certification, the facilities must capture 70% of emissions for storage or use. And new electric arc-based facilities that use scrap metal for production will need to use at least 70% scrap or 100% hydrogen in iron-ore processing. CBI is working on additional cross-cutting criteria that will apply to hydrogen use to address emissions from electricity used in electrolysis, Contreras said.

Certified bonds related to pre-2022 fossil fuel-based facilities would require the facilities to achieve certain emission reductions by 2030, ranging from 15 to 50%, depending on age and emissions per metric ton of steel. Pre-2022 electric arc-based facilities using scrap metal would need to increase renewable energy use to reduce emissions from electricity.

The goal of the draft criteria is to help meet the Paris Agreement target of holding global warming to below 1.5 degrees Celsius.

“That is extremely ambitious … and for a lot of steel businesses the target and the criteria will appear very challenging,” said Max Åhman, associate professor at Lund University and member of the working group behind the criteria development.

Despite the challenge, Åhman believes that the steel sector is already demonstrating positive momentum in transitioning to clean and sustainable practices, and it could be a “role model” for other hard-to-abate sectors.

“If steel can show the way, there is a possibility even for those other sectors to take action to make it profitable and make it sustainable,” he said.

CBI is accepting comments on the draft criteria until Aug. 22.

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SERC: Ransomware Threats Continuing to Evolve

The threat of ransomware is only increasing amid Russia’s conflict with Ukraine, and electric utilities must be ready for the worst-case scenario, cybersecurity experts said last week at a SERC Reliability-hosted webinar.

In The Scoop: Ransomware, representatives from the law enforcement, electric industry, and cybersecurity communities discussed the changes in the worldwide threat landscape since Russia invaded Ukraine in February. Although fears that a global cyber offensive against Ukraine’s allies have yet to be realized, the U.S. Cybersecurity and Infrastructure Security Agency (CISA) has continued to warn about the capabilities of both Russia and the cybercrime groups with which it is unofficially affiliated. (See CISA Issues Fresh Russia Cyber Warnings.)

Those criminal groups took up a significant amount of attention at the webinar, with participants noting that some prominent threat actors seem to have added political allegiance to their traditional financial motivations.

“We’ve already seen some Russian-speaking ransomware groups voice their support for Russia, with the Conti ransomware gang showing their support within hours of Russia’s invasion into Ukraine,” said Lauren Cirillo, a cyber threat intelligence analyst with the Electricity Information Sharing and Analysis Center (E-ISAC). “Other ransomware and data breach groups such as Karma, Freecivilian, and CoomingProject have declared support for Russia as well.”

Cirillo pointed to last year’s ransomware attack on Colonial Pipeline, which shut down the company’s entire 5,500-mile system carrying almost half the supply of fuel products for the eastern U.S., as an early indication of the kind of disruption that ransomware groups could accomplish. The FBI attributed the attack to a criminal gang based in Eastern Europe called Darkside, which demanded a ransom payment of 75 bitcoin (then about $4.4 million).

“I personally find it fascinating that Colonial Pipeline paid the ransom in its entirety on the day of the ransomware’s deployment in their environment, but it still took five days to fully restart the pipeline,” Cirillo said. “This doesn’t include returning the pipeline supply chain to the state it was in before, which took several additional days to accomplish.”

Media reports following the incident claimed that while DarkSide provided Colonial with a decryption tool in exchange for payment as promised, the tool itself was too slow to be usable and the company had to rely on its backups to restore the affected systems. In testimony to Congress, Colonial’s CEO neither confirmed nor denied these stories. (See Colonial CEO Welcomes Federal Cyber Assistance.)

Despite an uptick in ransomware activity over the last year, Cirillo acknowledged that the E-ISAC has seen no sign of a sustained effort against the electric sector. One reason may be that the majority of actors in this space operate on a ransomware-as-a-service model, in which a core group develops and operates the ransomware while recruiting affiliates to hack into networks and deploy the app.

Cirillo said that for these organizations, “service definitely [appears] to be one of the top priorities,” and developers take pains to guard their reputations. For example, both DarkSide and its apparent successor group BlackMatter have promised to avoid attacking civilian infrastructure such as hospitals, water treatment facilities, and nuclear electric plants. Other groups have made similar pledges, such as donating their profits to charity.

However, this too may be changing, particularly among the ransomware groups that have aligned themselves with Russia’s invasion of Ukraine. Conti in particular became “one of the most heedless and unpredictable” actors in this space last year, with the E-ISAC recording multiple reports of attack attempts against small and medium-sized utilities, along with ransom demands far above those seen from other operators.

Conti appeared to be dealt a major blow earlier this year after a former member allegedly leaked the group’s internal chats online, exposing its tactics and processes. But Cirillo said that while researchers say the main group appears to have shut down operations, it is more likely that the leadership is pursuing a more distributed model by partnering with smaller ransomware groups to share expertise and plan attacks.

“Essentially, the Conti brand is allegedly being decommissioned, but their operations are expected to return,” Cirillo said. “Under this model, the smaller ransomware groups gain countless experienced operators while Conti gains mobility and greater evasion of law enforcement by splitting into smaller cells.”

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BOEM Draft EIS Finds Potential Major Impacts from 1st NJ OSW Project

The first draft environmental impact statement (DEIS) released by the U.S. Bureau of Ocean Energy Management (BOEM) for New Jersey’s first offshore wind project, Ørsted’s Ocean Wind 1, found that it would not have a major impact on most of the 19 environmental and related categories scrutinized.

But the 1,408-page report released Friday also found that the construction and installation, operations and maintenance, and eventual decommissioning of the project would certainly have a major impact on marine navigation and vessel traffic.

The report assessed the impact on four levels: negligible, minor, moderate and major. Categories that could experience up to a major impact are the scenic view, fishing sector and marine mammals; they could also experience negligible to minor impacts, the DEIS found.

The project could also have negligible to moderate impact on birds, sea turtles and recreation and tourism, as well as benthic resources, the sediments at the seafloor that provide nutrients for some sea organisms.

The release of the report triggers a 45-day public comment period that begins June 24, with public hearings on July 14, 20 and 26. BOEM will consider those comments in preparation for the final EIS, which could include recommendations or requirements to mitigate the project’s major impacts.

Shawn LaTourette, commissioner for the New Jersey Department of Environmental Protection, called the release of the DEIS “a significant milestone in the evaluation of the first offshore wind project off the coast of New Jersey.”

“Over the coming weeks DEP will thoroughly evaluate and provide comment on the DEIS to ensure the project has taken all steps necessary to avoid potential adverse impacts to New Jersey’s natural, historic and cultural resources,” he said in a release. The DEP said it expects the final EIS to be released in March 2023. Gov. Phil Murphy said the release of the DEIS brings New Jersey “one step closer to bringing its vision for a more sustainable future to fruition.”

Most Impacted

The DEIS said the impacts to marine navigation and traffic would include “changes in navigation routes, delays in ports, degraded communication and radar signals, and increased difficulty of offshore [search and rescue] or surveillance missions within the wind farm area, all of which would increase navigational safety risks.”

But most of the opposition to Ocean Wind 1 has been from local residents concerned about its potential harm to their view of the sea and from the commercial and leisure fishing sector, which fears that the turbines will damage marine life and impair their ability to fish. The tourism sector has said the site of turbines on the horizon will also harm the industry.

The DEIS said the impact of the project on commercial fishing would vary, and that the “majority of vessels would only have to adjust somewhat to account for disruptions due to impacts.” However, the report added, “it is conceivable that some of the small number of fishing operations that derive a large percentage of their total revenue from areas where project facilities would be located would choose to avoid these areas once the facilities become operational.”

“In the event that these specific fishing operations are unable to find suitable alternative fishing locations, they could experience long-term, major disruptions,” the report added.

The draft also said that “the daytime presence of offshore [turbines and substation], as well as their nighttime lighting, would change perception of ocean scenes from natural and undeveloped to a developed wind energy environment.” The project’s facilities “would be an unavoidable presence in views from the coastline, with moderate to major effects on seascape character and landscape character.”

The project would also “result in habitat disturbance (presence of structures and new cable emplacement), underwater and airborne noise, vessel traffic (strikes and noise), and potential discharges/spills and trash.”

Doug O’Malley, director for Environment New Jersey, said his organization’s biggest concern is the impact on marine life.

“The goal of offshore wind is to maximize clean, renewable energy and minimize environmental impacts,” he said. “This is early days. But the DEIS is clearly outlining how the project can maximize clean energy and minimize true environmental impacts.

“Offshore wind will clearly impact marine traffic and fishing, but, you know, we desperately need to clean, renewable energy from offshore wind,” he said.

The 1,100-MW Ocean Wind 1 project, approved by the New Jersey Board of Public Utilities in 2019, was the first of three offshore wind projects approved, totaling about half the state’s target of 7,500 MW by 2035. The other two, the 1,148-MW Ocean Wind 2 and the 1,510-MW Atlantic Shores, were approved in June 2021. The state expects the first of three more solicitations to begin early in 2023. (See NJ Awards Two Offshore Wind Projects.)

BOEM released the Ocean Wind 1 DEIS as the BPU evaluates an application by the project for an easement in Ocean City, where some transmission lines from the project would come ashore. The BPU will hold a public hearing on the issue Friday. (See Ørsted NJ Wind Project Faces Local Opposition.)

Offshore Wind 1 is projected to include 98 turbines with a maximum height of 906 feet at the top of the rotator blade tip. It is expected to come online in 2024.

Ørsted said the DEIS marks a “critical and exciting permitting milestone” for the project. The company looks forward to “reviewing it in detail as we begin a robust public engagement process over the coming weeks.”

The aim of the DEIS is to “assesses the reasonably foreseeable impacts on physical, biological, socioeconomic and cultural resources that could result” from the project, according to its introduction. The report will inform BOEM’s decision on “whether to approve, approve with modifications or disapprove the project.”

Other federal agencies also will use the report to inform their evaluation of the project, including the National Marine Fisheries Service and the U.S. Army Corps of Engineers.

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California Study Takes Read on Heat Pump Views

Widespread adoption of heat pump water heaters in California has been stymied by a preference for tankless water heaters among homeowners, who may feel that a heat pump appliance is a “step backward,” a new report says.

The California Public Utilities Commission last week announced release of the report, which is a market study of electric heat pump appliances in the state.

“It feels like a step backward when you have a HPWH [heat pump water heater], because you have this giant tank that takes up space and then it’s losing heat,” said a builder who was interviewed as part of the study. “That’s going to be a hard move for consumers.”

In addition to taking up more space than a tankless unit, heat pump water heaters can be noisy and cost more upfront than alternatives. And contractors might not be familiar with HPWHs and prefer “business as usual, which has largely been gas tankless water heaters,” the report said.

The report recommended more homeowner education on the benefits of HPWHs, which include a chance to relieve stress on the grid if the appliance is tied in with a demand response program.

Meeting Climate Goals

The focus on heat pump appliances comes as California moves toward building electrification as one way to meet climate goals.

About 12% of California’s greenhouse gas emissions are direct emissions from residential and commercial buildings. And much of that is from space and water heating, CPUC said.

“Heat pump systems provide hot water, heating and cooling using energy from the electric grid, which is increasingly renewable,” the CPUC said in a release.

The goal of the new study was to provide insights that may guide strategies to accelerate adoption of heat pump appliances. The CPUC worked with consultant Opinion Dynamics on the study.

The study examines five electric heat pump technologies: air source heating and cooling heat pumps, heat pump water heaters, ground source heating and cooling heat pumps, heat pump clothes dryers, and heat pump pool heaters.

The report included analysis of past research on heat pump technologies and interviews with a range of stakeholders. The study looked at construction of market-rate and affordable housing, and single-family and multi-family buildings.

Heat Pump Surge Expected

Most of the construction trade representatives interviewed for the study said they expect heat pump installation in new homes to increase substantially over the next five years. That’s due, in part, to the growing number of cities that have banned natural gas in new construction or adopted reach codes encouraging the use of heat pump appliances. A reach code is a city building code that goes beyond minimum state standards.

The trend may be amplified when California’s 2022 Energy Code takes effect on Jan. 1, 2023. (See Calif. Energy Commission Adopts 2022 Building Code.) The code includes a provision requiring developers to install either an electric heat pump water or space heater in new single-family homes. For new multi-family housing, heat pump space heating will be the new standard.

The current market share for electric heat pumps for water and space heating in new homes in California is less than 6%, according to the California Energy Commission.

Another factor increasing demand for heat pump technology is the growing number of homeowners who don’t have air conditioning but now want it. Heat pumps can provide heating and cooling in a single piece of equipment and are “an attractive value proposition,” the report said.

“It’s hard to explain to them the value of heat pumps unless they really, really want the cooling,” said one single-family home architect who was interviewed during the study.

Opportunity Ahead

The report also notes an opportunity for heat pump space heating. Almost half of California homeowners whose main heating source is a natural gas or electric space heating appliance have units that are more than 14 years old, and therefore may need replacing within the next 10 years.

Study consultants also researched heat pump programs in states that are having some success in promoting the technology, including New York, Vermont, Washington, Oregon, Maine and an unidentified Southwestern state.

Staff with those programs said a key to success was developing a strong contractor network, starting initially with a few high-volume companies.

They also advised running marketing campaigns to explain to consumers the benefits of heat pumps and how to use them for the most savings.

Another recommendation was to offer a range of incentives to contractors, such as technical training, continuing education credits or free heat pump units so they can try out the technology in their own homes.

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Jigar Shah: ‘Oil and Gas Sector Shouldn’t be Vilified’

WASHINGTON — The way Jigar Shah sees it, if the U.S. is to have any chance of decarbonizing the grid, building out transmission or standing up an energy storage supply chain, the clean energy industry has to stop vilifying the oil and gas industry and start answering some hard questions — like whether decarbonizing the grid by 2035 is even possible.

One of the industry’s most provocative thinkers, Shah is now director of the Department of Energy’s Loan Program Office (LPO), where he is making multimillion-dollar decisions about which clean energy startups and projects to invest the government’s dollars. That kind of money means clean energy is no longer the plucky, small disruptor that only has to advocate for itself, Shah said at the American Clean Power Association’s Energy Storage Policy Forum on Wednesday.

In the course of a 30-minute conversation with Jason Burwen, ACP’s vice president for energy storage, Shah set the industry a series of grown-up challenges.

“What responsibility do we have to actually answer … big tough questions, as opposed to saying, ‘I would like to not piss anybody off, so I’m not going to say anything,’ and I’m going to let people think that we can be at 90% renewable energy, and that it’s only an interconnection problem that’s holding us back, which is patently false,” he said.

“How much [do] you allow an uninformed part of your industry to vilify other parts of the industry? The oil and gas sector shouldn’t be vilified,” Shah said. “They actually have a lot of really valuable talents. We don’t know how to run refineries. If these people lose their jobs, and we can’t get them back, we’re screwed. All of us are screwed because you’re not all running electric vehicles yet for your installation crews.

“So, we all need to figure out how to coexist together as we make this transition occur, and that means a deep understanding of how all of these things interplay with each other,” he said.

“Where does LNG fit in the entire [energy] mix? What is the position of this audience? Do we want people to increase coal consumption by 25% over the next two years?” he said. “Because that’s what’s going to happen unless we figure out a way to give Asia the energy that they need to grow.”

20-year Payback

Shah was equally blunt about the industry’s failure to deal with core issues of transmission, equity and the manufacturing supply chain.

“The only thing harder to build than nuclear in this country is transmission, and so come on, we’re not going to [build] three to five times transmission in this country,” he said. “Who in this room actually thinks that’s going to happen by 2035? The lines that we’re building right now, we started 12 years ago.

“So, unless you know which lines you started 12 years ago that are going to solve the problem by 2035, what do you think is going to happen?”

Another example: “We are disrupting 300 communities across the country with coal plants that are getting retired. You’re telling me that all those communities want solar plus storage to go into that interconnection? No, they don’t, because they’re not getting jobs from solar plus storage, and that coal plant actually pays $2 million a year in property taxes. Which one of you is paying $2 million in property taxes? So, we need to figure that out.”

The LPO recently made a conditional commitment of a $107 million loan to Syrah Vidalia, a graphite manufacturer in Louisiana, to expand its plant to provide graphite for enough lithium-ion batteries to power 2.5 million EVs by 2040.

But Shah sees bigger challenges ahead for clean energy supply chains because “our country has not actually done this level of planning and forethought and what we would call industrial policy. That’s where industrial policy is defined by getting an outcome that’s slightly different than where the market would otherwise set,” he said. “We’ve always just said, ‘We want to get the lowest possible price, and if that’s importing it from other countries and not doing anything here, that will do.

“We haven’t manufactured stuff here in 40 years, and so a lot of the supply chain isn’t here — the training colleges, all that stuff that we need, it’s still atrophying. And so, we need to actually go the other way and strengthen it, and all of that gets tied into the Loan Program because we’re taking a 20-year [payback] on those loans, so they’re not going to pay back unless the ecosystem is supportive of that company for 20 years.”

VPPs and Net Metering

Pointing to growing penetrations of solar and wind on the grid, Shah pushed the energy storage industry to think beyond lithium-ion batteries.

“When you think about what storage really looks like in our country, it is all the natural gas that we store every single day in huge salt caverns across the country, and we store it all year for like, bursts of time, right? And so that’s what hydrogen storage is; that’s what pumped hydro is,” he said.

“And so, the question really becomes, as we move to this modern grid, can we also get away from real time: matching that electricity [supply and demand] in a way that is just stressful for everybody?”

Shah also had some insights on the impact of transport and building electrification and the need for virtual power plants (VPPs).

“When you think about utility-scale battery storage, which is where most people are thinking about things these days, we’re going to have to have 800 GWh of automotive battery manufacturing in this country by 2030 to meet the president’s goal” of 50% of all new cars sold being electric.

“There’s no way to integrate those vehicles into the grid without a VPP. You cannot let anyone just charge whatever they want, however, they want, as often as they want without some management of the distribution rate,” he said.

In addition, VPPs might offer a possible solution for state-level battles over net metering reform,” Shah said.

Instead of incremental reform — currently being debated in California — he said, “Why don’t we just immediately let in VPPs and say, ‘If you want to do solar on your roof, you’re only going to get paid 5 cents/kWh, and then you’ll get paid another 7 cents/kWh for the integration within the grid out of VPP. So, you get paid the full 12 cents that you wanted before, but you get paid only if you become a grid resource.’”

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Low PJM Capacity Prices No Bargain, Coal & Gas Generators Say

Groups representing gas- and coal-fired generators said Wednesday that the sharp price drop in PJM’s 2023/24 capacity auction is a continuation of trends that threaten the RTO’s long-term reliability.

PJM reported Tuesday that its capacity bill for the year will be $2.2 billion, down from about $4 billion for the 2022/23 delivery year. It was the second year in a row that capacity prices have fallen, with Rest of RTO clearing at $34.13/MW-day, the third-lowest in the history of the Base Residual Auction. PJM said the results were likely depressed by the effective elimination of the minimum offer price rule (MOPR), a tougher cap on generator prices and robust forward energy prices. (See related story, PJM Capacity Prices Crater.)

“While the auction’s low capacity clearing price represents a savings for customers in the short term, these results portend real concerns over adequate compensation for resources needed to support reliability in all conditions and looking forward,” the Electric Power Supply Association said in a statement. “What appears to be developing is a trend where the addition of new supply resources is far outpaced by the retirement of resources that can deliver reliable power in the PJM BRA. Oversimplifying the results of the auction by cheering the lower price for capacity fails to recognize that there is a cost to ensuring the delivery of reliable power, and the most cost-effective way to deliver it is through well functioning markets, not from picking winners and losers among the resources that participate.”

EPSA said PJM’s market rules are undermining capacity price signals, calling on the RTO to “avoid rule changes intended to accommodate specific preferred resources or technologies.”

“The desire by some to defer to the policy choices of 13 states and D.C. to dictate the regional resource mix may seem sound but, in reality, threatens the reliability framework to which consumers of all types have become accustomed and expect as a part of their daily lives,” EPSA said.

The PJM Power Providers (P3) Group, which represents more than a dozen merchant generators in the RTO, was similarly critical.

“The auction-clearing prices are among the lowest they’ve ever been, so the compensation that generators will receive to commit to serving PJM’s region next year is greatly reduced,” P3 President Glen Thomas said in a statement. “However, the requirements they will commit to are more rigorous than ever. Increased obligations for decreased compensation is an incentive to leave the market rather than retain existing resources or attract new ones that will help maintain reliability going forward.”

EPSA and P3 members hold large portfolios of natural gas-fired generation.

Nuclear in the Money

Nuclear plants were big winners in the auction, clearing 5,315 MW more than last year. Solar resources increased 25% to 1,868 MW, while wind resources dropped by 434 MW. Natural gas resources cleared an additional 1,685 MW, while cleared capacity of steam units (primarily coal) dropped by 7,186 MW to 27,682 MW, reflecting a decrease of 7,813 MW offered into the auction because of plant retirements.

Coal trade group America’s Power said the auction will likely cause more coal retirements.

“PJM’s coal fleet was already expected to decline by half (more than 24,000 MW of announced coal retirements by 2030) even before the auction,” CEO Michelle Bloodworth said in a statement. “In addition, EPA regulations are expected to cause even more coal retirements, especially during the 2026-2028 time frame.”

Bloodworth reiterated the group’s request that PJM study how its reliability would be affected if half or more of its coal fleet retires by 2030, saying more coal retirements could also cost ratepayers when gas prices spike.

“We continue to urge PJM and other grid operators to value the reliability, resilience and affordability attributes of coal,” Bloodworth said. “Doing so would help put coal on a more level playing field with other resources that are receiving federal and state subsidies.”

Impacts Debated

At a press conference announcing the results Tuesday, PJM Senior Vice President of Market Services Stu Bresler noted several rule and timing changes that may have impacted the results, including the effective elimination of the MOPR, the use of a lower unit-specific market seller offer cap (MSOC) to counter market power and a historical, rather than a forward-looking, energy and ancillary services revenue offset. Bresler cautioned that because the RTO had not done any modeling, “we don’t know the magnitude of any [price] impacts.”

The less restrictive MOPR was applied to only seven resources totaling 76 MW that had failed to file for exemptions in time, Bresler said.

“Revisions demanded by FERC have virtually eliminated the MOPR, and it now fails in its purpose to prohibit subsidized resources from both suppressing the clearing price for resources who do not enjoy the benefit of a subsidy and preventing those otherwise economic resources from clearing,” P3 said.

The group said the elimination of the default MSOCs “promoted by proponents as necessary to protect against the potential to inappropriately influence prices, instead … forced suppliers to use unit-specific calculations of anticipated revenues from the energy and ancillary services markets to determine their necessary capacity market revenues while also prohibiting those calculations from accounting for the costs and risks of accepting a capacity obligation to operate when so directed by PJM.”

Jeff Dennis, managing director and general counsel of Advanced Energy Economy (AEE), offered a different take.

“There will be unfounded speculation that removal of the expanded MOPR caused the low prices; but past auctions run without an expanded MOPR produced even lower prices,” he tweeted. “PJM has been oversupplied for years; oversupplied markets produce low prices.”

He also expressed dismay at the increase in natural gas clearing the market, saying gas capacity is overvalued because of PJM’s use of an “outdated methodology” compared with the effective load-carrying capability (ELCC) used to value renewables.

P3, however, contended that the capacity capability provided by wind and solar is “overstated” even with ELCC.

“PJM’s proposed solution to rectify this issue is under dispute because it assumes utilization of extra room on the transmission system that should be available to all system users,” P3 said.

Constellation and Vistra Report on Auction Results

All of Constellation Energy’s (NASDAQ GS:CEG) nuclear-, natural gas- and oil-fired generation in PJM (18,775 MW) cleared in the auction, the company said in a filing with the U.S. Securities and Exchange Commission.

That included all 16,175 MW of its nuclear capacity, up from 9,900 MW last year, when the Byron, Dresden and Quad Cities plants in Illinois were left out of the money.

Exelon (NASDAQ:EXC) spun Constellation — including its generation and competitive energy operations — off as a standalone company in February to focus on its regulated utilities.

Vistra (NYSE:VST) reported it cleared 6,868 MW at a weighted average clearing price of $37.20/MW-day, a total of $94 million.

It said it also expects incremental revenue of $70 million to $75 million from existing retail and other third-party bilateral sales above the auction clearing price, for total estimated revenues of $164 million to $169 million.

Public Service Enterprise Group (NYSE:PEG), owner of the Salem and Hope Creek nuclear plants in New Jersey, and Energy Harbor, which operates nuclear plants formerly owned by FirstEnergy Solutions, did not respond to requests for comment. Talen Energy declined to comment on whether its Susquehanna nuclear plant cleared.

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Overheard at East Coast Renewables Conference: Spotlight on NY

The Business Council of New York State, The Hudson Renewable Energy Institute and Pace University on June 21-22 hosted the 8th Annual 2022 Renewable Energy Conference, which explored the challenges of managing a fundamental change in society’s energy supply and infrastructure under New York’s climate law.

The following are comments heard at the conference that featured state officials and regulators, business leaders, utility representatives and other stakeholders.

Society does not change according to a stipulated schedule, but it is an evolutionary process, Hudson Institute Chair Allan Page said.

“Leadership in the state needs to take into account the voluntary beneficial behavior of citizens of New York to get to net carbon zero on a societal glide path free of deleterious unintended consequences,” Page said. “Competitive markets come back to balance or equilibrium that allows choice between competing needs. Regarding the [New York Climate Action Council’s] draft scoping plan, a little more balance is needed.”

Implementing CLCPA 

The Climate Leadership and Community Protection Act (CLCPA) requires New York to obtain 70% of its electricity from renewable sources by 2030 and to make the grid net-zero emissions by 2040.

The council in December unanimously approved a draft scoping plan that lays out the steps needed to achieve the emission limits set by the CLCPA.

Doreen Harris (BCNYS) Content.jpgNYSERDA CEO Doreen Harris | BCNYS

That plan provides several scenarios for meeting the state’s environmental directives and incorporates recommendations from the council’s seven sector-specific advisory panels, including from one on energy-intensive and trade-exposed industries, said Doreen Harris, president and CEO of the New York State Energy Research and Development Authority (NYSERDA) and council co-chair.

“When we look at the draft scoping plan in the broadest sense, it does show that the cost of inaction exceeds the cost of action by more than $90 billion, and ultimately the improvements in air quality, transportation and energy in low-income homes will generate health benefits ranging from approximately $165 billion to $170 billion,” Harris said.

In addition to hundreds of miles of transmission projects under construction, the Public Service Commission and NYISO have taken up utility investment plans needed to integrate renewables across the state, and the public policy transmission project, for example, advancing to provide better transfer capability from Long Island to New York City to allow the integration of more offshore wind energy into the city’s grid, she said.

“When we look at it in the longer term, that’s when the investments, that will be needed to realize that very reliable 2050 grid, are really topics that are to be determined through the work of NYISO, the Department of Public Service with NYSERDA, and of course with the federal investments that we are very excited to benefit from as they move forward,” Harris said.

Power Sector and DERs

Investing in and building new transmission in New York will be key to achieving the state’s public policy objectives, yet it is extraordinarily challenging, particularly on Long Island, where adding new infrastructure has always been difficult, said Scott Medla, managing partner at investment bank Ansonia Partners, who moderated a panel on distributed energy resources (DER).

“In my view, the bottom line is to find ways to use existing rights of way to build, not higher, not wider, not longer, be it underground or underwater, but to the extent possible to use leading technologies that are proven,” Medla said.

NYISO’s focus is on operating the grid to provide reliable service to customers, which requires having sufficient resources that can satisfy the CLCPA, while controlling their output, running for extended periods at specific output levels and being flexible, Nicole Bouchez, NYISO Principal Economist, said.

“The real puzzle now is that we don’t know what technology is going to step in and provide that service,” Bouchez said.

Maintaining affordability in the energy supply must be a part of the clean energy transition, said John Borchert, senior director of energy policy for Central Hudson Gas and Electric.

“One of the big steps that needs to be further explored is reducing emissions and energy use in the lowest cost way,” Borchert said. “Energy efficiency has always been the lowest-cost, most effective way to reduce emissions and save money,”  

New York, he added, should continue to support and evaluate further expansion of energy efficiency.

NYISO has been a leader in facilitating the complex integration of renewable resources onto the grid, said Luke Falk, senior vice president for development at EnergyRe, partner with Invenergy in developing the 1,300-MW Clean Path New York transmission project to bring upstate wind and solar energy into the city.

“We’re talking about 20-something, large-scale wind and solar development projects, all of which are advanced in parallel and in their own right, and a large, underground HVDC transmission line,” Falk said.

Developing those projects will be a complex process that requires precise orchestration, according to Falk, who says it’s reasonable to forecast a trend toward HVDC.

Regulatory Challenges

William Flynn, partner at law firm Harris Beach, moderated a discussion with two PSC commissioners to explore significant opportunities and challenges facing the state’s energy sector and business community regarding the energy sector transformation.

Environmental considerations have not always been a priority for the commission, particularly the impact of those pollutants on individuals, PSC Chair Rory Christian said.

“One of the first places I worked was at the Ravenswood power station Astoria Queens, and I was always surprised at how close it was to a very dense urban population center and significant [public] housing within walking distance,” Christian said.

Planners made decisions 50 or 60 years ago to site power plants in places that have had a deleterious effect on residents, according to Christian. Reducing those emissions allows the state to address those impacts and improve the health of affected communities.

“That’s probably one of the biggest priorities of the commission,” he said.

As the state leans into electrification, demand may far outpace reliable supply in meeting the growing electricity needs of New York, Commissioner Diane Burman said.

PSC Panel (BCNYS) Content.jpgClockwise from top left: William Flynn, partner at law firm Harris Beach; NYPSC Chair Rory Christian; and NYPSC Commissioner Diane Burman | BCNYS

 

The commission needs “to understand that we have a fiduciary responsibility to our ratepayers, and we need to look at it through the lens of us as economic regulators, which means that costs do matter, they impact on everyone, and to that end how do we do this in a way that achieves greenhouse gas reduction goals without going backwards,” Burman said.

As an example, Christian said New York has spent many decades building up the gas network and that it’s important to ensure continued use of it in the most efficient way possible toward meeting climate goals.

“In addition to that, we’ve also released the CLCPA order which in many ways is going to track all the various components and actions, specifically actions, that are taken by this commission towards meeting goals of the CLCPA, and that would be in addition to tracking the costs of those items moving towards meeting the goals,” Christian said.

While the state is on a good track, realistically it needs to address the challenge of transitioning away from natural gas without compromising reliability, Burman said.

“We need to look at how curtailing the use of natural gas can actually conflict with our state goals to reduce carbon emissions if the unavailability of gas leads to greater near-term reliance on other fossil fuels such as oil,” Burman said.

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37 States Fight Over California Tailpipe Standards

The first potentially decisive motions are due Monday in a case that pits 17 states and their allies against the U.S. Environmental Protection Agency over its waiver allowing California to enact stricter tailpipe emissions standards than the federal government.

California and 19 other states back the EPA’s decision, along with environmental groups, automakers and some utilities.

Ohio Attorney General Dave Yost filed the case, Ohio v. EPA, in the D.C. Circuit Court of Appeals in May, two months after the EPA rescinded a Trump administration decision that had revoked California’s decades-old Clean Air Act waiver. EPA also reinstated California’s requirement that all new passenger vehicles sold in-state must be emissions free by 2035. (See EPA Restores California Tailpipe Standards.)

Yost and the attorneys general of the 16 other states asked the court to decide if EPA’s action was unconstitutional, “arbitrary, capricious [and] an abuse of discretion” because the agency allowed stronger state regulations to supersede federal fuel economy standards.

They contended that the D.C. Circuit was the proper venue for the matter because the court, which normally hears cases on appeal, has primary authority to review decisions the EPA determines have “nationwide scope or effect.”

The petition for review was signed by Yost and the attorney generals of Alabama, Arkansas, Georgia, Indiana, Kansas, Kentucky, Louisiana, Mississippi, Missouri, Montana, Nebraska, Oklahoma, South Carolina, Texas, Utah, and West Virginia.

Asked to discuss the case with RTO Insider, Yost’s office declined to comment.

California Attorney General Rob Bonta quickly moved to intervene, joined by his counterparts in Colorado, Connecticut, Delaware, Hawaii, Illinois, Maine, Maryland, Massachusetts, Minnesota, Nevada, New Jersey, New Mexico, New York, North Carolina, Oregon, Pennsylvania, Rhode Island, Vermont and Washington. New York City, Los Angeles and Washington, D.C., also weighed in on the side of California and the EPA.

Congress has long allowed other states to adopt the more stringent vehicle emissions standards for which California was granted a Clean Air Act preemption waiver starting in the 1970s. (See NM Adopts Calif. Advanced Clean Cars Rules.)

“This regulatory regime has operated as Congress intended for more than half a century,” Bonta’s office wrote. “California has expanded its pioneering efforts to reduce new motor vehicle pollution, pursuant to preemption waivers granted by EPA. And EPA has continued to draw heavily on the California experience to fashion and to improve the national efforts at emissions control, thereby reducing vehicular air pollution nationwide.”

Environmental groups such as the Sierra Club, Natural Resources Defense Council and the Environmental Defense Fund asked the court for permission to intervene in support of the EPA and California. Automakers including Ford, Volkswagen and BMW also intervened.

“The automobile manufacturers … support the waiver decision and California’s ability to regulate greenhouse gas emissions from new light-duty motor vehicles,” their lawyers wrote. “Ford, Volkswagen, BMW Group, Honda, and Volvo Cars are committed to reducing greenhouse gas emissions in their own fleets.”

“Ford has committed to invest more than $50 billion by 2026 to put electric vehicles on the road across the world,” they said. “Similarly, the Volkswagen Group is in the midst of deploying a $40 billion electrification development plan to accelerate the timeline to introduce an increasingly broad range of electrified vehicles globally.”

Honda has said 100% of its vehicles worldwide will be electrified by 2040, with plans to launch more than 30 different electric vehicle models by 2030, the motion noted.

Advanced Energy Economy (AEE), Calpine Corp., National Grid USA, New York Power Authority and the Power Companies Climate Coalition filed a joint brief on June 14.

“California’s long-standing right to establish more stringent auto emissions standards is foundational to achieving the Clean Air Act’s goals of protecting public health and forcing the development of low and zero-emissions technologies like electric vehicles,” AEE General Counsel Jeff Dennis said in a news release. “AEE is intervening today to ensure that our business voice is heard in this case.”

On Ohio’s side, the American Fuel & Petrochemical Manufacturers, Domestic Energy Producers Alliance, Energy Marketers of America and the National Association of Convenience Stores argued in a court filing that the EPA’s action “financially harms [their] members … by reducing demand for products produced or sold by petitioners’ members.”

The court consolidated Ohio’s petition with related actions by parties representing ethanol producers such as the Clean Fuels Development Coalition, ethanol processor ICM Inc., and the Kansas Corn Growers Association.

The DC Circuit has set June 27 as the deadline for filing motions to dismiss the case or for summary judgement. None of the parties have said if they intend to file such motions, which are common but seldom successful in similar litigation.

John Funk contributed to this story.

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New Jersey Bill Would Offer Help to Delayed Solar Projects

A New Jersey bill designed to help solar developers who say that delays beyond their control are threatening the viability of some projects has raised concerns about the costs to ratepayers.

The bill, which the Senate Energy and Environment Committee backed 5-0 on June 9, would automatically extend the completion deadline for qualified projects. The extension would be available for projects that are in danger of failing to be completed by the designated deadline because of a “tolling” event and would continue as long as the event continues.

The definition of a “tolling event” includes: any action or inaction by PJM or an electric utility; a PJM or utility moratorium on new applications; any “new application process, study, report or analysis established” by the RTO or a utility; or an “undue” delay caused by local government planning board or other entity in supplying a required permit.

The bill, S2732, would cover 33 projects — mainly on landfills and brownfields — that together would total 500 MW, says Sen. Bob Smith (D), one of two bill sponsors and the committee chairman.

The bill touches an ongoing concern among solar developers that New Jersey projects can be derailed, and deadlines broken, by factors beyond their control, such as equipment delays stemming from supply chain issues, labor shortages, delays in getting municipal permits and difficulties getting projects connected to the grid.

“These problems have been devastating to the industry,” Lyle Rawlings, president of the Mid-Atlantic Solar & Storage Industries Association, told a hearing into the bill. “They’ve caused delays; they’ve caused tremendous price increases … it could be an existential threat to some businesses if they are not provided relief.”

The problem is complicated by a reshaping of the state’s solar incentive programs by the Board of Public Utilities (BPU) in recent years as it has sought to reduce the cost to ratepayers of solar subsidies, which has increased the consequences of a project missing a completion deadline. The BPU in May 2020 replaced the state’s long-time solar incentive program, the Solar Renewable Energy Certificate (SREC) program, which paid about $250/MWh, with the temporary Transition Renewable Energy Certificate (TREC) program, which granted incentives of $90 to $150/MWh. In July, the TREC program ended and was replaced by the Successor Solar Incentive (SuSi) program, which pays incentives of $70 to $100/MWh depending on the project.

The changes mean that a project with a TREC incentive that fails to meet its completion deadline could lose the incentive and have to apply for another under the less lucrative SuSi program. The only remedy would be to apply for a deadline extension to the BPU, which has been reluctant to grant extensions.

Evaluating such extension requests, the BPU has to consider, for example, whether the delay is genuinely because of circumstances beyond the developer’s control, or the applicant’s project was from the beginning unlikely to make the deadline and they are is seeking to remedy the problem with an extension.

During the hearing, Smith recounted that the BPU told him that about 75% of the 4,000 applications for TREC incentives were “bogus, meaning that it was just somebody putting in a slip to keep their name in line for a TREC, but not necessarily with any intention to build.”

The proposed legislation, however, would remove the need for a BPU deadline extension and instead grant qualified applicants an “automatic extension.”

Extension Questions

In a June 8 letter to the committee, the New Jersey Division of Rate Counsel opposed the bill, saying it “will inevitably result in increased rates for utility ratepayers.”

The bill would remove the BPU’s ability to deny extensions and prohibit it “from even investigating the factual accuracy of the certification” by a developer claiming that a tolling event had delayed its project, the Rate Counsel said. The legislation also would prevent the board from setting the length of an extension, if it concluded one was warranted, and replace its expertise in judging whether a project deserved the extension with an automatic extension award, the agency said.

That would enable projects to continue, and eventually receive incentives, that otherwise would fail because they otherwise would not meet the deadline, the counsel said.

“It would eliminate the board’s ability to enforce any deadlines and result in the payment of substantial excess incentives,” it said. “And since ratepayers ultimately fund these financial incentives, this bill will increase utility rates.”

Developers testifying before the committee, however, outlined the kind of scenarios that highlight the need for the legislation.

Melissa Sims, owner of Ecological Systems, a Manalapan-based solar development company, said she has two projects underway that will be finished within the deadline, except that each will be missing a small part. In one, she has waited several months for a circuit breaker that she was initially told would take 70 days to arrive.

Sims said she feared that because of the delay, she will fail to meet the deadline of the TREC grant awarded for the project.

“I cannot stress enough how serious and devastating it will be for anyone who has a solar project under construction who is experiencing these types of delays,” she said. “If I don’t have the breaker, I can’t call for my electrical inspection. And if I can’t call for my electrical inspection, I can’t get permission to operate from the utility. And if I can’t get permission to operate from the utility, I can’t get my TREC.”

Joshua Lewin, president of Helios Solar Energy, said he also has two projects in jeopardy because of similar problems, including a 1-MW project in Millville that could miss the completion deadline because he is still waiting for the arrival of the main distribution panel, which was ordered last July. He estimated that the customer would lose about $780,000 in revenue if the delay causes the project to miss its completion deadline.

“We’re constantly re-engineering some of the one-line diagrams and pieces of equipment to try to accommodate what might be available in the next couple of weeks or a couple of months,” he said. “But there are items that are just unavailable.”

Connection Obstacles

Business groups — among them the New Jersey Business and Industry Association and the South Jersey Chamber of Commerce — support the bill, as do environmentalists, including the New Jersey league of Conservation Voters.

Smith said the delays mean that New Jersey is “not keeping its promises” to provide a transition period between the SREC and the SuSi program, because developers find they can’t meet the deadlines of the temporary TREC program, which was meant to soften the transition.

“We said we would do lower [incentives] to have a transition, ultimately, to no subsidies,” he said. “But we were not performing.” Instead, he said, developers and their customers — through no fault of their own — face the loss of those incentives because of delays, and “we’re just saying, ‘Hey, tough, tough on you.’”

Lengthy delays connecting new projects to PJM are also common. The RTO said in February that it had 220 GW of capacity in the queue, of which renewables made up 95%. (See PJM Files Interconnection Proposal with FERC.)

“This is not an issue with New Jersey; this is an issue with PJM,” Doug O’Malley, director of Environment New Jersey, told the Senate Energy and Environment Committee as he offered support for the bill on June 9. “PJM is essentially throwing up the red stop sign and saying ‘do not proceed with solar,’ and that’s creating massive problems for the projects that have been teed up.”

The difficulty of connecting solar projects in the state to the grid is also well known. In May developers, testifying in support of a bill that would levy a fee that would raise funds to modernize the grid, said the grid is so old and its capacity so limited that new projects can’t be connected in some areas of the state. (See Solar Developers: NJ’s Aging Grid Can’t Accept New Projects.)

Awaiting Permission

A recent case before the BPU at its June 8 meeting, the latest in a series of deadline extension requests, highlighted the difficulties.

Project developer ESNJ-Key-Gibbstown, seeking to finish a 1.38-MW carport solar project located in Gibbstown, in South Jersey, had received three extensions since the project was approved for TREC incentives in June 2020. It then sought an additional extension to move the deadline to Dec. 31 because of the inability to connect the project to the grid through Atlantic City Electric (ACE).

The developer, according to the BPU order on the case, had “completed construction,” had a conditional permit to operate and was “capable of being fully energized and connected to the grid.” However, the order said, the developer could not get ACE to deliver the project’s full capacity to the grid because “ACE has not yet completed offsite upgrades necessary to allow interconnection for the full capacity of the project.” As a result, the project could only operate generating 50 kW.

The order said that BPU staff have “traditionally been reluctant to recommend that the board provide extensions for solar projects that miss their expiration dates because of supply chain issues, general interconnection processing delays and other factors that, while regrettable, do not rise to the level of warranting an extension.” Yet the staff recommended a deadline extension, and the board approved it.

“This does not appear to be a case of a project coming into the [TREC] program with an underdeveloped project development plan,” staff concluded, noting that the developer had done “everything in its power to complete its project” by the April deadline.

BPU President Joseph Fiordaliso said the board’s decision “struck the necessary balance of fairness to applicants whose projects are otherwise complete with a strong interest of the ratepayer who should always receive what they pay for, no more and no less.”

Still, he said, the case highlights the difficulties facing the state.

“When we’re talking to executives from utility companies, we are constantly talking about interconnection,” he said. “If anything keeps me awake at night, it is the fact that we’re going to have wind turbines out there; we have solar programs out there, and there’s no place to plug them in.”