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November 16, 2024

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NJ EV Incentives Target Low-income Buyers

New Jersey soon will reopen its $30 million Charge Up electric vehicle (EV) incentive program for a fifth year with new rules that offer the top incentive — $4,000 — only to low- and moderate-income buyers. The just-passed state budget also tops up the program with an extra $20 million. 

The New Jersey Board of Public Utilities (BPU) on June 27 approved the $30 million as part of a package of $82.5 million in EV-related expenditures in the agency’s clean energy budget, among them incentives to support charger installation at tourist sites and in multiunit dwellings, as well as local government EV purchases and charger installations. 

The BPU has not released a date for the start of the Charge Up program, which will include the $20 million in additional funds put in the state budget by Gov. Phil Murphy (D), for a total of $50 million. But the launch is expected in two phases: The first one — offering a $2,000 incentive to all vehicle buyers — will start early this month, and the additional $2,000 for low- and moderate-income buyers will be available in the fall. 

The shift in incentive strategy comes as New Jersey seeks to continue its recent relatively strong EV sales amid signs they are weakening in other states. The state also is considering how the program can have the deepest impact in a market in which buyers now can access much larger $7,500 federal incentives under the Inflation Reduction Act. (See Will Final Rules on EV Tax Credits Help or Hurt US Market Growth?) 

EV sales also face new headwinds in New Jersey after Murphy on June 28 ended an exemption from sales tax for EV buyers, and the legislature added a fee that can add $1,000 to a purchase. 

Launched in 2020, the Charge Up program in recent years has offered incentives of up to $4,000 for buyers of vehicles priced less than $45,000, with up to $1,500 awarded for vehicles priced between $45,000 and $55,000. BPU officials developed the strategy after most of the incentives in the early years of the program went to buyers of Tesla models, the higher-priced vehicles on the market. 

In setting the $45,000 threshold for the maximum incentive, BPU officials said they wanted to target “incentive-essential” buyers, those with lesser economic means who opt for a cheaper vehicle and might not buy an EV without the subsidy. (See NJ Ramps up EV Purchase, Charger Installation Programs.) 

That level of incentive now will be open only to lower-income buyers. 

“We’ve restructured the program for vehicle incentives to help better ensure that incentives are going to support people who otherwise wouldn’t be able to switch to electric,” BPU President Christine Guhl-Sadovy said before the board approved the 2025 clean energy budget. 

Explaining the new program structure at a May 31 public hearing, Cathleen Lewis, e-mobility program manager for the BPU, said “incentives for EVs with an MSRP of $55,000 or less will have a fixed incentive of $2,000.” Income-qualified applicants then will be eligible for an additional incentive in the amount of $2,000.  

To be eligible, single tax filers who buy an EV must have incomes below $75,000, and joint tax filers must earn no more than $150,000, she said. The median household income for EV owners in New Jersey was $89,703 in December 2023, according to Atlas Public Policy. 

To date, Charge Up has awarded $120 million, supporting the purchase of more than 36,000 vehicles. Funding in the Charge Up program historically has been exhausted within months of its opening. In a June 14 letter to the board, the New Jersey Division of Rate Counsel argued that demand is so strong that a maximum incentive of $2,500 would stimulate sales and allow the funds to last longer.  

EV Sales Escalation

The shift comes after EV sales in New Jersey increased dramatically in 2023, even as some analysts say EV sales are slowing across the country. 

New Jersey added 62,426 new EVs on the road in 2023 – up 68% over the 2022 figure, based on figures from the Department of Environmental Protection, according to ChargEVC-NJ. ChargEVC called the increase the “largest year-over-year growth ever recorded based on DEP figures in the state,” and the organization, which promotes EV adoption, and other EV supporters say the figures show New Jersey is in reach of its goal of having 330,000 EVs on the road by the end of 2025.

Yet supporters say that trajectory may be undercut by several measures adopted by the state this year, which could slow the uptake of EVs.  

Murphy’s signing of the bill, A4702, that ended the exemption from state sales tax for EV buyers followed the enactment of a law, A4011, that added a $250-to-$290 fee to the price of an EV that was designed to help pay for road repairs the way the registration on gas-fueled vehicles does. Because the fee will be paid at purchase for four years at once, critics say it will add more than $1,000 to the price of an EV from July 1, the start of fiscal 2025. (See New Jersey Lawmakers Back $250 Annual EV Fee.) 

The two measures followed the state’s adoption of California’s Advanced Clean Cars II rule, which will require all new light-duty vehicles sold in the state to be zero emission by 2035. The rule requires manufacturers to make zero-emission vehicles (ZEVs) a steadily increasing portion of their car sales, starting with 35% for model year 2026, increasing to 68% in 2030 and reaching 100% in 2035. (See New Jersey to Adopt Advanced Clean Cars II Rule.) 

Aside from funding for the Charge Up program, the state budget adopted by the legislature on June 30 included $10 million to help local governments buy EVs and chargers, $9 million to help install chargers in multiunit dwellings and $15 million to help school districts buy electric buses. An additional $2 million will go to a pilot program to use EV school buses for vehicle-to-grid energy storage and $6 million for a pilot depot to provide chargers for medium- and heavy-duty vehicles. 

Consumer Charging Concerns

ChargEVC calls the EV fee and the phaseout of the sales tax exemption “unforced errors” that could slow the state’s upward trajectory of EV sales. The organization says the number of light-duty electric vehicles increased by 66% in 2023, to 151,827, and the number of plug-in hybrids grew by 91%. Still, EVs in 2023 made up only 2.2% of all vehicles in New Jersey, ChargEVC said in April. 

The state added roughly an additional 18,000 vehicles in the first three months of 2024, up 11%, according to figures compiled by the DEP. EVs accounted for about 2.6% of all vehicles in the state, the DEP figures show. 

“We certainly hope the $4,000 incentive for low-income buyers will help” boost sales, said James Appleton, president of the New Jersey Coalition of Automotive Retailers (NJCAR). “The sad truth is that the State of New Jersey is giving with one hand and taking away with the other.” 

He said he does not believe New Jersey’s EV demand is as robust as ChargEVC thinks, and added that the Advanced Clean Cars II rule requires car companies to sell 110,000 EVs in 2024, well above what the state achieved in 2023. 

“Consumers are kicking the tires on EVs, but dealers tell me that price and the absence of clear and consistent state and federal incentive programs make it hard to get and keep consumers interested in actually pulling the trigger to buy,” he said. One reason EVs are selling in New Jersey is that “car buyers in [New Jersey] are generally more affluent and the higher price for most EVs isn’t as serious a barrier in [New Jersey] as elsewhere.” 

But the state’s shortfall in charging stations is affecting sales, he said in an email. PHEVs are selling well because “consumers are going into dealerships looking for an EV and driving away with a PHEV because of price and because of concerns about publicly available, reliable charging infrastructure.” 

New Jersey ranked fifth in the nation by number of electric vehicles, not including PHEVs, according to figures for 2023, the latest figures compiled by the U.S. Department of Energy’s Alternative Fuels Data Center (AFDC). New Jersey had 125,317 all-electric vehicles, compared to 1.178 million for top-ranked California, 231,518 for second-place Florida and 210,433 for third-place Texas.  

But New Jersey lags in charging ports. The state is 14th in the nation, with 3,834 ports, compared to California with 46,501 ports, according to AFDC figures. New York is third, with 10,048 ports. New Jersey has one port for every 32 vehicles, compared to one for every 25 vehicles in California and one for every 10 vehicles in New York, the agency’s figures show. 

Doug O’Malley, director of Environment New Jersey, said the state policy is “schizophrenic.” 

“EV sales have been increasing tremendously over the course [of] the last two years. We’re really starting to see … the EV market take off,” he said. “And we’d expect to see that sales will continue to increase because of the lowering [of] prices and because of, you know, the expansion of charging infrastructure.” 

But the removal of the tax exemption and the addition of the EV fee “essentially cut the knees off that program unnecessarily,” he said. “You’re literally basically putting up a stop sign for people that are on the fence on whether they’re buying an EV.” 

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2 New California Bills Could Accelerate Decarbonization

The California Assembly Utilities and Energy Committee on July 2 advanced two new bills that could accelerate the state’s decarbonization goals by helping residents and multimeter customers transition to renewable energy.  

Senate Bill 1221, introduced by Sen. Dave Min (D), would advance efforts to retire gas-fired power plants, requiring gas companies to submit a map of all potential distribution line replacement projects by July 2025.  

The bill also directs the California Public Utilities Commission (CPUC) to designate priority neighborhood “decarbonization zones” that consider the concentration of gas distribution line replacement projects outlined in the maps by January 2026. The commission would then be required to establish a voluntary program to implement pilot projects within each zone to facilitate cost-effective decarbonization with an emphasis on equity.  

“The pilot projects enabled by SB 1221 will engage neighborhoods, support residences with zero-emissions appliances and create quality jobs, paving the way for disadvantaged communities to access clean homes and indoor air,” Edson Perez, policy lead at Advanced Energy United, said in a press release. “SB 1221 presents an opportunity to meaningfully and thoughtfully advance the state toward its climate goals and help residents transition away from a system destined for cost increases.”  

The legislation adds to the portfolio of other efforts led by the California Energy Commission and the CPUC to retire gas generation, including the CEC’s targeted electrification and strategic gas decommissioning, which involves transitioning whole neighborhoods to electric power instead of using a mix of services. (See Targeted Electrification ‘Promising but No Silver Bullet’ for Gas Cost Dilemma.) 

Additionally, SB 350, signed into law in 2020, requires the CPUC to focus utility energy procurement decisions on reducing greenhouse gas emissions by 40% by 2030. In January 2020, the commission opened the Long-Term Gas Planning Rulemaking procedure, which helps chart a course through the energy transition with an emphasis on gas infrastructure retirement.  

A second bill moving through the Legislature, SB 1374, focuses on rooftop solar and could reverse the CPUC’s controversial decision to block schools, farms and apartment buildings from using the solar power they generate to offset their utility bills. The legislation, written by Sen. Josh Becker (D), would amend the CPUC’s law, allowing schools and apartments in California to fully use the solar energy generated on their property.  

The first iteration of the bill included churches and farms, but following the committee’s recommendation, it was narrowed down to just schools and apartments. The amended legislation would require the CPUC to ensure that any contract or tariff related to customer-generators with a renewable electrical generation facility meets certain requirements, including allowing customers to elect to aggregate load.  

“Enabling more distributed energy resources like solar and storage will help grid reliability and affordability by keeping power close to consumers and making investments in transmission and distribution as efficient as possible,” Perez said in the press release. “By enabling schools and other multimeter customers to take full advantage of their solar and storage investments and save money on energy costs, SB 1374 saves everyone money. We must think about affordability at a systemwide level and with a long-term vision to ensure an energy transition that works for everyone.”  

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NYISO Studying How to Update IRM Calculation to Account for Offshore Wind

The New York State Reliability Council’s mathematical model for calculating the state’s installed reserve margin (IRM) every year will need to be updated as more offshore wind and major transmission lines come online, NYISO told stakeholders last week. 

“That would be a reasonable expectation as we get further along,” said Dylan Zhang, manager of resource adequacy for NYISO. “We’re seeing the curve dynamics fall apart, so the methodology isn’t maybe as robust.”  

During the June 26 meeting of the NYSRC’s Installed Capacity Subcommittee, members discussed the breakdown of the model in possible future scenarios where 9,000 MW of offshore wind, with accompanying transmission, would be available to New York City and Long Island.  

The IRM is the minimum amount of capacity beyond the forecasted peak demand that must be procured to satisfy the loss-of-load expectation. For the 2024/25 capability year, which began May 1, the council set the IRM at 22%. 

The rather complex method for setting the IRM is known as “Tan45.” Hypothetical IRMs are plotted against possible minimum locational capacity requirements (LCRs) for New York City (zone J) and Long Island (zone K), based on how much generation from upstate zones is “shifted” into them. The low point of the curve (representing the lowest possible IRM and highest possible LCR) for each zone is determined by simply excluding generation from certain upstate zones from the total amount of statewide capacity. 

An anchor point of each curve is then selected by applying a tangent of 45 degrees at its sharpest bend, and then another formula using the values where the tangents intersect the curves determine the Tan45 inflection points. The final IRM is calculated by averaging both curves’ Tan45 points and rounding up to meet the LOLE.

OSW Tan45 curve comparison | NYISO

But in future scenarios with the addition of significant amounts of generation flowing into the city, NYISO “observed that the current process to establish the low point no longer appears to operate as intended,” the ISO’s Lucas Carr told the subcommittee. 

With less generation needing to be shifted over to zones J and K, the curves flatten. Under one scenario studied, the “low point” of the IRM on the curves reached as high as 39.99%. 

“In the older system, when we had more transmission limitations, if you had capacity down in New York City load centers, that provided more reliability than a given megawatt in Buffalo,” said Mark Younger, president of Hudson Energy Economics. “Not surprisingly, it has problems when you start to add a whole bunch of transmission because now the reliability value of an additional megawatt in New York City is not nearly as much as it was before.” 

Members of the Installed Capacity Subcommittee said they would need to develop an alternative model before the current methodology breaks down. “Rather than waiting to drive off the edge of the cliff to figure out what to do next, let’s figure it out now,” one member said. “This is trying to do some forward planning. … But we’re good, for now.” 

“When the subject was first brought up about [dropping Tan45], that was not well received,” another committee member said. “But it’s not a matter of, ‘Oh we don’t like Tan45.’ It’s a matter of there are issues … coming up.” 

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Wildfire Prompts CAISO’s 1st Transmission Emergency of Summer

CAISO declared its first transmission emergency of the summer July 2 as a fast-spreading Northern California wildfire forced Pacific Gas and Electric to de-energize transmission lines near one of the state’s key hydroelectric facilities.

By the morning of July 3, the Thompson Fire had burned more than 3,000 acres in Butte County, prompting the California Department of Forestry and Fire Protection (Cal Fire) to request PG&E de-energize circuits from the Wyandotte Substation that were in or near the fire, as well as several transmission lines, leaving about 4,200 residents without power.

Paul Moreno, a spokesperson for PG&E, told RTO Insider the utility was able to repair a few transmission lines, including one serving Lassen Municipal Utility District. The remaining three were expected to be restored July 4, but Moreno was unsure when staff will be able to re-energize the Wyandotte circuits.

“We’ve been closely tracking the weather forecasts and have geared up on staffing and are ready to respond to any heat-caused power outages,” Moreno said.

PG&E also announced a public safety power shutoff (PSPS) that went into effect the morning of July 2, leaving 2,200 Northern California residents across eight counties without power. While the utility hoped to restore power July 4, it was unsure of the timeline because of wildfire danger and dry winds.

The transmission emergency, which the ISO extended into July 3, comes at the start of an extended heat wave that will bring soaring temperatures to cities across much of the West, including Sacramento, Portland, Las Vegas and Phoenix.

While the ISO assured its power grid is stable and supply shortfalls weren’t forecast through July 3, high heat in the interior of the state could set temperature records.

“We are continuing to closely monitor long-duration extreme heat in California, with triple-digit temperatures forecast in the valley over the next several days,” an ISO spokesperson said. “We are also watching wildfire activity across the state. While fires are not currently affecting the bulk electricity system, wind direction can change quickly and impact generation and our transmission system.”

CAISO also issued a restricted maintenance operation (RMO) alert effective midnight July 3 through midnight July 10 to caution utilities and transmission operators to avoid taking equipment offline for routine maintenance. The RMO can help assure all generators and transmission lines are available to supply higher loads, according to the ISO spokesperson.

Hyatt Hydro Plant Taken Offline

The Thompson Fire started outside Oroville the morning of July 2. By late afternoon on July 3, the fire had grown to more than 3,500 acres and was 0% contained, according to Cal Fire. The agency has issued mandatory evacuation orders for many zones in Butte County and evacuation warnings were in place for others. The cause of the fire remains unknown, and there have been no reports of fatalities.

In a statement posted on X on July 2, the California Department of Water Resources (CDWR) said the fire ignited just north of its Oroville Field Division facilities and that “several” state water project facilities were under evacuation orders from the Butte County sheriff.

Among those was the Hyatt Powerplant, a 645-MW hydroelectric facility near Oroville Dam that CDWR temporarily shut down because of de-energized PG&E transmission lines. Plant staff were relocated to the nearby Thermalito Pumping-Generating Plant, the agency said.

The department was able to resume Hyatt’s operations on July 3, it said in a follow-up post. Staff found minor damage to nonessential infrastructure at the dam, but “there was no damage to the dam or spillway structure, and Oroville Dam remains safe,” it said.

No Alarms on West Coast, but EEA 2 Declared Inland

Despite the forecast for extended heat, utilities across the region have not expressed alarm about energy shortages, likely in part because of the lower demand seen during holiday weekends.

The Sacramento Municipal Utilities District, which is not part of CAISO but participates in the ISO’s Western Energy Imbalance Market, said this week it was prepared to meet electricity demand, “barring a grid or other emergency such as wildfire or unexpected significant power shortfall.”

Portland General Electric noted on its website that it too is prepared for “high temperatures and high electric use.” Portland-based Pacific Power urged its customers to take steps to conserve power during peak periods between 3 and 7 p.m. to reduce strain on the grid.

Nevada-based NV Energy hasn’t issued calls for conservation, but the utility did alert customers about its newly implemented PSPS policy in the event of high fire danger.

But in New Mexico, according to a source, the El Paso Electric balancing authority area in the SPP reliability coordinator footprint on July 2 was placed into an Energy Emergency Alert 2, in which the RTO requests emergency energy from available resources, activates emergency energy programs and calls for conservation from consumers.

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PURPA Case Offers FERC Early Glimpse of Post-Chevron World

FERC is getting an early taste of life without Chevron deference after the Supreme Court remanded a case involving the Public Utility Regulatory Policies Act (PURPA) back to an appeals court. 

In a brief order issued July 2, the Supreme Court granted a petition for writ of certiorari in Edison Electric Institute v. FERC, remanding it to the D.C. Circuit Court of Appeals for further consideration in light of Loper Bright Enterprises v. Raimondo. (See Supreme Court Ends Chevron Deference to Administrative Agencies.) 

The case involves a solar plant Broadview Solar developed in Montana that FERC certified as a “qualifying facility” under PURPA, which are supposed to be rated at 80 MW or less. The power plant can produce up to 160 MW, but it can only deliver up to 80 MW to the grid. 

FERC certified the facility as a QF under PURPA over the protests of EEI and its member NorthWestern Energy, the utility required to buy its output. The complainants argued that a plain reading of PURPA indicates that any resource that generates more than 80 MW cannot be a QF and that FERC exceeded its authority in the approval. 

The D.C. Circuit previously upheld the decision, finding that PURPA was unclear on the exact meaning of “power production,” so it deferred to FERC’s interpretation. (See DC Circuit Upholds FERC on Montana PURPA Project.) 

In their petition to the Supreme Court, EEI and NorthWestern argued that the lower court misapplied Chevron by rushing to agency deference while ignoring the plain language of PURPA. 

“But if Chevron is properly understood to condone the result reached here, then this case is further evidence that the time has come to reconsider Chevron by, at the very least, clarifying its limits,” they said in the petition filed last June. 

FERC based its approval on its “sendout approach” for PURPA qualifying facilities that measures how much power they can ship out to the grid, it said in a response filed with the Supreme Court in September. The commission has been using the sendout approach since 1981. 

“The net power that a qualifying facility sends out to the grid is also the amount of power that is ‘capable of being avoided on the [purchasing utility’s] system,’ i.e., the amount of power that the purchasing utility need not get from elsewhere,” FERC said. 

While the solar array at the Broadview facility can produce up to 160 MW, and a co-located battery can discharge up to 50 MW for four hours, it has to convert that direct current electricity into alternative current through an inverter connected to NorthWestern’s grid that is just 80 MW. 

The facility as a whole can supply no more than 80 GW of grid-usable alternating current to the grid at any one time. 

“The battery does not permit the facility to supply more than 80 MW to the grid at any time,” FERC said. “But the array-and-battery design does mean that the Broadview facility can more consistently deliver 80 MW of power to the grid than the facility would be able to deliver using only a 160-MW solar array with the same inverters.” 

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Vandals Smash Solar Array with Construction Equipment

Maine police are looking for the people who plowed a construction vehicle through a nearly completed community solar farm, causing hundreds of thousands of dollars in damage. 

The incident happened late June 30 at the Novel Energy Solutions community solar farm in New Gloucester, the Cumberland County Sheriff’s Office reported. It was discovered around 7 a.m. the next day. 

Community news page NGXchange described the facility as a 975-kW array and reported it was approved by the town Planning Board in 2022. It sits on 10 acres in a rural area of fields, woods and houses, north of Portland and just east of the Maine Turnpike. 

Minnesota-based Novel Energy Solutions could not be reached for comment. 

Portland news station WMTW TV interviewed assistant construction manager Cody Ellich, who said a skid steer was used to smash panels, damage frames and flip over a trailer. 

Two skid steers are visible in the WMTW footage, one of them sitting frozen mid-crunch amid a row of panels, wrapped in a tangle of wires from the solar array. 

“Luckily the skid steer malfunctioned on them. It looks like they were in the middle of causing absolute [mayhem] and it just shut down on them,” Ellich said. 

There were no security cameras on site. 

The Sheriff’s Department said preliminary estimates placed damages at several hundred thousand dollars. 

Solar farms are not universally popular, and NGXchange reported some local opposition to the Novel Energy proposal. 

Online, there was no shortage of opinions in comments on Facebook posts by the Sheriff’s Office and WMTW. 

Some who commented criticized the destruction of property, while others seemed not upset by the news, and some came right out and cheered.  

One commenter even compared the perpetrators to Marvin “Killdozer” Heemeyer, who attained folk hero status in some circles by building an armor-plated bulldozer and using it to level 13 buildings associated with people he held a grudge against in a small Colorado town 20 years ago. 

While some people hold a similar dislike for solar farms, the damage wrought upon them most commonly is the result of severe weather rather than vandalism. 

A 2020 NREL report based on 15,128 property-casualty insurance claims over the preceding six years showed theft and vandalism at the root of not quite 1% of claims, while hailstones accounted for nearly 53%. 

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Mass. Announces Priorities, Advisers for Office of Energy Transformation

Massachusetts’ new Office of Energy Transformation (OET) will focus on cutting peaker plant emissions, eliminating the state’s reliance on the Everett Marine Terminal LNG import facility, and financing distribution grid upgrades in a way that minimizes costs to ratepayers. 

Gov. Maura Healey (D) created the office in March as a subset of the Executive Office of Energy and Environmental Affairs (EEA). The OET is led by Melissa Lavinson, former head of corporate affairs in New England for National Grid, one of the major gas and electric utilities in the state. 

The Healey administration’s July 3 announcement about priorities also described an advisory board for the OET, which features more than 60 members representing a wide range of interests, including utilities, generators, state and local government, climate and environmental organizations, labor, and tribes. 

In a press release, Healey called the new office “an invitation to everyone impacted to come to the table, bring solutions, and make real commitments to move us forward.” 

EEA Secretary Rebecca Tepper noted that the Department of Public Utilities’ recent order on the future of natural gas in the state “set the stage for the transition from gas to electricity, making Massachusetts the first state in the country to require its utilities to prioritize electrification. … We launched the Office of Energy Transformation and Advisory Board to take on this big challenge.” (See Massachusetts Moves to Limit New Gas Infrastructure.) 

Tepper said the office’s three key priorities represent “tangible next steps in ending our reliance on some of the most costly and dirty fossil fuel infrastructure and ensuring that our ratepayers and environmental justice communities are kept at the heart of this transition.” 

The OET and its advisory board will be tasked with charting a course through some of the state’s most pressing challenges of the clean energy transition: how to meet increasing electric demand without increasing reliance on natural gas, and how to electrify heating without dramatically increasing electric rates. 

The power grid’s reliance on generation from natural gas has increased substantially over the past couple of decades, rising from 15% of New England’s electricity in 2000 to 55% of generation in 2023. Overall, natural gas is responsible for more than three-quarters of power-sector emissions in New England. 

This increase has continued in recent years despite the proliferation of renewables, with natural gas generation emissions increasing in 2023 relative to 2022 and on track for another year-over-year increase in 2024. (See NEPOOL Holds Summer PC Meeting amid New England Heat Wave, Climate Protests.)  

This year, the DPU authorized contracts between Constellation and the state’s gas utilities to keep the Everett LNG import facility operating into 2030 to preserve the winter reliability of the state’s gas network. In its approval, DPU also required the utilities to make annual reports on their efforts to reduce their reliance on Everett. (See Massachusetts DPU Approves Everett LNG Contracts.) 

Dan Dolan, president of the New England Power Generators Association, told NetZero Insider the administration “rightfully” is focusing on the issue of Everett “immediately, and not letting it linger.” 

Regarding the OET’s priority of cutting peaking emissions, Dolan applauded the administration’s collaborative approach to considering a range of potential solutions, including battery storage, hydrogen or renewable natural gas. 

“I give the administration a lot of credit for how they have at least initially set this up, and it’s certainly something we’re excited to work on with them,” Dolan said. 

Mireille Bejjani, co-executive director of the New England environmental justice organization Slingshot, said she is “excited about the focus on the Everett Marine Terminal and peaker plants.” 

“We can’t just be continually kicking the can down the road, we have to make a plan for how we’re going to get off of gas,” Bejjani said, expressing hope the OET and its advisory board will provide a forum for charting this path.  

Activists in the state have been vocalizing concerns that Everett ultimately will be replaced by a gas capacity expansion to the region; Enbridge has a capacity expansion proposal — dubbed “Project Maple” — that could come in service around the end of the decade. (See Enbridge Announces Project to Increase Northeast Pipeline Capacity.) 

Some activists have sounded alarm bells about several near-term upgrade projects along Enbridge’s pipeline network, alleging they could help the company expand its gas capacity into the region. Enbridge has said the upgrades are needed to preserve gas reliability (CP24-49 and CP24-21).

“My hope is that, through having this advisory board and intentionally and proactively planning for the transition away from Everett, we’re closing the door to Project Maple,” Bejjani said. 

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Study: Significant Benefits for Merchant Tx Line

ARLINGTON, Va. — High-voltage transmission developer Grid United says its proposed North Plains Connector would provide significant reliability capacity benefits to interregional transmission, according to a study. 

The study, conducted by Astrapé Consulting, modeled the North Plains Connector as two 1,500-MW HVDC lines connecting SPP and MISO to the Western Interconnection and quantified the project’s ability to increase power system reliability. 

Loss-of-load analyses like those performed for new generating facilities indicated a capacity value can be credited to the line. According to the study, when the project’s bi-directional nature and the seasonal diversity among the three regions are considered, it would unlock 3,550 MW of capacity across the three systems, more than the line’s physical capacity. 

“You’re probably wondering, ‘Well, how can it be more than what the line is?’” Grid United President Kris Zadlo asked his audience June 26 during an Infocast conference on transmission and interconnection issues.  

Kris Zadlo, Grid United | © RTO Insider LLC

“It’s due to the bi-directional nature of the lines, so they will provide about 1,750 MW of reliable capacity to pass through the Eastern grid and then it would provide 1,800 MW of capacity for the Western grid,” Zadlo explained.  

The study identified the benefits from connecting meteorologically diverse regions whose demand peaks occur at different times of the day or in different seasons. Using the difference in generation and load profiles improves the grid’s reliability on both sides of the project without adding any new capacity and allows it to add an outsized amount of reliability benefit relative to its physical capacity, Grid United said. 

Zadlo said the study’s findings were similar to an analysis the developer conducted for MISO of a 2-GW interconnection between MISO South and North. 

“They found that a similar interregional line like that would create 3 GW of capacity, 1,500 MW each way,” he said. “When you start building these interregional lines and connect diverse loads and in diverse generation shapes, then we can start sharing energy across the grids. The two areas peak at different times, not only times of the year but during the day because there’s a two-hour time zone.” 

As Zadlo told RTO Insider, “The simple way to say it is the grid has to be bigger than the weather.” 

Grid United and utility ALLETE announced the project in February 2023. The 415-mile HVDC transmission line, capable of up to 525 kV, would connect the western and eastern grids in Montana and North Dakota. It would be the first HVDC connection among three regional markets: MISO, SPP and WECC. (See Transmission Project Would Span Across Interconnection Divide.) 

The developer’s staff are engaging with the various regulatory bodies that will be pivotal before construction can begin. Zadlo huddled during the Infocast conference with Sheri Haugen-Hoffart, a member of the North Dakota Public Service Commission that is among those who must approve the project. 

A Grid United spokesperson said North Plains will have to go through a U.S. Department of Energy environmental review related to its funding and routing process across federal lands. FERC approval also is required, as is that of MISO and SPP, for the merchant project.  

SPP said NERC’s planning coordinator responsibilities define its roles related to merchant HVDC lines. The RTO must identify any reliability needs that arise from a facility interconnecting to the system under its functional control, with the developer providing a solution to address those needs before the project goes into service. 

MISO said any merchant HVDC project that wants to connect to its system must follow its tariff’s procedures.  

Grid United officials said the North Plains project would be paid for by subscribers to the line, which would dead-end into the 1,480-MW coal-fired Colstrip plant in Montana. Western utilities have existing transmission rights from the plant but in the East, the developer would have to rely on bilateral contracts with utilities. 

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NY Expects to Miss 2030 Renewable Energy Target

The architects of New York’s clean energy transition predict the state will fall short of its 70%-by-2030 renewable energy target, perhaps far short, and suggest ways to catch up in the early 2030s. 

On July 1, the Department of Public Service (DPS) and the New York State Energy Research and Development Authority (NYSERDA) issued a draft of the 2024 Clean Energy Standard Biennial Review (Case 15-E-0302). 

It indicates that in the two years since the last review, the projected electric load growth is significantly greater and there are significantly fewer renewable energy projects contracted to meet that need. 

Considering how long it takes to develop and build a renewable energy generation facility and connect it to the grid, some revisions are in order, the review suggests: “The amounts of Tier 1 project deployment that would be needed … in order to achieve the 70% goal in 2030 may far exceed what the renewables industry could be expected to develop in this time frame.” 

The review suggests more than a dozen possible changes in New York’s approach to clean energy development in response, including allowing regulated utilities to own and operate renewable energy projects, awarding longer-term purchase contracts for renewable energy certificates and placing less emphasis on bid price when choosing proposals for contract awards. 

After a 60-day comment period, the Public Service Commission will consider actions in response. 

Alliance for Clean Energy New York Executive Director Marguerite Wells told NetZero Insider that the report did not contain a lot of new information for ACE NY and its members, many of whom have been working for years to build New York’s clean energy portfolio. 

She said focusing on 70-by-30 or other arbitrary numerical goals is misguided — everyone working on the clean energy transition, public sector or private, is working as hard as they can to make it happen as quickly as they can.  

Fixes largely are in place or in process for three of the largest hurdles for renewable development — procurement, permitting and interconnection — but there is no easy way to bring down costs, Wells said. “There are a lot of factors that make it expensive to build things in New York and I don’t think any of them can be swept away with a pen.” 

By the Numbers

The 70-by-30 target was mandated in July 2019 as part of New York’s landmark Climate Leadership and Community Protection Act (CLCPA), which also calls for 100% emissions-free power by 2040 and greenhouse gas emissions at least 85% lower than 1990 levels by 2050. 

The legislation was a collection of visions and directives, not a plan. The complicated and politically delicate task of making and implementing the plans fell to agencies such as NYSERDA and DPS, which typically work at a deliberate pace. 

In the following years, the world moved faster, with costs soaring for contracted renewable projects as they moved through one review after another. 

This culminated in the collapse of the state’s portfolio of contracted renewable projects in late 2023, when developers canceled more than 11 GW of contracts that had become economically untenable to advance to construction. 

So, in the draft review published July 1, 2024, there is a gaping hole in the numbers. 

The review projects a 2030 base load of 164,910 GWh, up from the 151,678 GWh estimated in 2020. (Most of this increase is due to increased demand anticipated from industrial users and electric vehicle charging.) 

To provide 70% of the 2030 base load, New York would need 115,437 GWh of renewables. Its current trajectory, assuming robust response to future contract solicitations and a 30% attrition rate for awarded contracts, yields 73,292 GWh from renewable sources in 2030. 

New York generated just 38,061 GWh of renewable power within its borders in 2022, 80% of it hydropower.  

The review lays out a potential scenario by which renewable energy generation could hit 70% of base load by 2033. That is 120,673 GWh, and reaching it would require procurement of 5,600 GWh of large-scale renewables per year, assuming 30% attrition. 

Progress has been tepid since 2022. In the 17 months from Jan. 1, 2023, to June 1, 2024, the renewables that have come online are estimated to total only about 2,250 GWh annual output. 

There also was 31,865 GWh of nuclear generation in New York in 2022, but that is classified as zero-emissions energy, not renewable energy. It would help the state reach its 2040 goal, but not its 2030 goal. 

Possible Solutions

The review suggests adjustments that could be made to improve the state’s procurement of renewable energy development.

The first suggestion is revising the methodology by which it awards contracts to buy renewable energy certificates and placing less emphasis on a proposed REC price, because recent history shows the cheapest proposals are not necessarily the best value, and perhaps more likely to be unable to proceed into development. 

Other options include: 

    • Create carve-outs for onshore wind in large-scale onshore solicitations (Tier 1) or create separate solicitations, so that wind proposals are not competing with less-expensive solar. 
    • Add strike price adjustment mechanisms for black swan events beyond a developer’s control. 
    • Increase maximum contract length to 25 years for Tier 1 projects and 30 years for offshore wind in recognition of the potential operating lives of these projects. 
    • Allow adjustments to commercial operation milestone deadlines and the consequences of missing them. 
    • Allow regulated utilities in New York to own and operate renewables. 
    • Divide the state into zones and align generation development in each zone with its planned transmission expansion and economic development. 
    • Help small-scale hydropower owners undertake needed maintenance and repairs. 

Headwinds and Tailwinds

Interest rates, inflation, supply chain constraints and black swan events — such as the COVID pandemic and war in Ukraine — are blamed in part for past shortfalls in New York’s renewable energy portfolio. 

The length and cost of the interconnection process continues to limit the pace of renewable development, the review states, despite efforts by NYISO at least as far back as 2019 to mitigate delays. The authors predict that even after NYISO integrates all the FERC Order 2023 requirements into its tariff, interconnection likely will remain a lengthy and costly process. 

The review predicts the already-complex generation siting process will become even more difficult in New York as the easy sites are exhausted and resource protection laws become more stringent. There are obstacles to placing renewables on farmland and forests, which constitute approximately 85% of New York’s total land area. 

Looking forward, the review sees shortages of key components potentially continuing and sees domestic manufacturing expansion as a possible counterweight.  

It also sees a need for large numbers of skilled workers trained to work in the clean energy sector, and details some of the efforts to build such a workforce. And it sees Biden-era financial incentives as a key boost to renewable energy development. 

Response to Report

That renewable energy development is slow, expensive and complicated in New York is news to no one, though state officials do not often say it in so many words or issue a hundred-page report about it. 

It also is frustratingly ironic. New York is among the bluest of states, firmly committed to climate protection in its policies, budget decisions and actions. 

But it is among the most expensive of states, and its home-rule tradition gives its many local governments outsized control over execution of state renewable energy policy. 

Clean-energy advocates have been frustrated at times at how slow and hard-fought progress has been in the five years since the CLCPA was signed into law and celebrated by its supporters as a nation-leading example. 

Environmental Advocates NY Executive Director Vanessa Fajans-Turner said via email: “New York must use every tool at its disposal to meet the 70% renewable electricity target by 2030. This is a legal mandate and a moral imperative for our future. The [Gov. Kathy] Hochul administration holds significant power to act. They should. Today.” 

The Independent Power Producers of New York said via email: 

“The lack of progress towards the state’s climate mandates is disappointing and this report further demonstrates how issues regarding reliability and affordability need to be taken seriously. While progress has certainly been affected by global concerns, such as supply chain issues, inflation, etc., the state has not moved quickly enough to determine the future technologies that are needed to help achieve these targets.” 

IPPNY added: “There can be opportunities for businesses to invest in New York, but the state needs to identify what will be considered a zero-emission source to create these opportunities. Appropriate market signals must be given so that the retirement of reliable generation stops outpacing new generation being added to the grid.” 

Wells of ACE NY said there are some problems beyond New York’s reach (war, the pandemic, inflation, interest rates) and there are problems New York is trying to solve. 

“The industry has known about the challenges and has been advocating for the fixes that are now largely in place for quite a while,” she said. 

Wells is particularly optimistic about interconnection process changes NYISO is making, including measures to discourage speculative requests from developers. 

“I think they have shown incredible willingness to work with the renewables side of the house to make a process that works for both them and will maintain the reliability of the grid,” she said, “so that things can speed up there, and I think that’s really exciting.” 

That began in advance of FERC Order 2023, Wells said, “because NYISO was sort of at the bleeding edge of this problem and they wanted to fix it … in part because of the size and speed at which New York is trying to change over to renewables.” 

Wells flagged an issue not raised in the report — state agencies working individually rather than together, or attaching a low priority to renewable energy if it is not among their traditional duties. 

“I think helping align those agencies to pull all in the same direction is something that that the governor can help direct, but I don’t think there’s any structural changes or new laws that are required at all.” 

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FBI Warns Power Sector of IBR Cyber Vulnerabilities

The FBI warned utilities this week that operators of inverter-based resources will likely see their risk of malicious cyber activity grow along with their increased presence on the grid and issued a set of recommendations to improve their security posture.

The FBI’s private industry notification (PIN), issued July 1, focused on renewable energy resources, particularly residential and grid-connected solar panels. It warned that malicious actors may target these facilities “to disrupt power-generating operations, steal intellectual property or ransom information critical for normal functionality to advance geopolitical motives or financial gain.”

NERC has warned about the potential cyber vulnerability of IBRs before. At FERC’s annual Reliability Technical Conference last year, NERC CEO Jim Robb said that solar and wind plants are “incredibly exciting technologies” that nonetheless come “with real issues.” (See FERC Conference Highlights Challenges of Evolving Grid.) Among these issues is their reliance on digital communications for remote control, broadening the attack surface for threatening entities.

This week’s PIN took these warnings further, noting the FBI’s concern that cyber threats against IBRs are likely to increase because “with federal and local [legislatures] advocating for renewable energies, the [power] industry will expand to keep pace, providing more opportunities and targets for malicious cyber actors.” Examples of government advocacy cited in the report include the Inflation Reduction Act’s incentives for renewable energy and state targets for solar power capacity.

Residential and commercial solar projects are both vulnerable to attacks targeting their inverters, the FBI said, particularly if those inverters use internet-connected monitoring systems. Attackers that gain control of a residential unit’s inverter could use their access to reduce the system’s power output or damage the home’s battery system, if one is present. In addition, cyber criminals or nation-states could target microgrids used to maintain power during an electrical outage.

The notification cited only one actual cyberattack against IBRs in the U.S. This 2019 incident involved “a private company which operates [wind and] solar assets” in California, Utah and Wyoming with a total capacity of about 500 MW into which the company lost visibility after an attacker launched a denial-of-service attack exploiting an unpatched firewall.

“While it was unclear if this specific incident was a deliberate cyberattack targeting this specific company, the incident highlighted the risks posed by a security posture that relies on outdated software,” the document said.

Recommendations provided in the report include establishing and maintaining strong relationships with local FBI field offices, and proactively addressing cyber espionage and interference by:

    • monitoring network activity for suspicious traffic;
    • updating company networks, firewalls and antivirus software to patch security vulnerabilities; and
    • reporting unexpected visits to company facilities or suspicious solicitations of employees.

The FBI also urged utilities to assume they will be the victim of a cyber incident and prepare accordingly. Suggested preparations include maintaining offline, encrypted data backups; reviewing the security posture of third-party vendors; documenting and monitoring external remote connections; and implementing a plan for recovering sensitive or proprietary data.

Identity and access management are also important preparedness steps and can be addressed by implementing strict password controls (such as requiring long passwords, using industry-recognized password managers and locking out accounts after multiple failed logins) and requiring multifactor authentication. Entity cybersecurity staff may also regularly review servers, workstations and active directories for new and/or unrecognized accounts, and segment networks to prevent the spread of ransomware.