MISO’s second competitively-bid transmission project appears dead in the water because new generation in the region has evaporated the line’s benefits, according to the grid operator’s assessment.
During a special South Technical Studies Task Force meeting Wednesday, MISO planners said about 2.7 GW of planned capacity in southeast Texas negates the Hartburg-Sabine Junction project’s economic benefits. The transmission line was approved in 2017 as a market efficiency project.
“There’s more capacity planned in Entergy Texas that is going to contribute,” said Clayton Mayfield, senior engineer of economic studies.
MISO has not yet officially cancelled the $130 million, 500-kV project in East Texas. Brian Pedersen, senior manager of competitive transmission administration, said planners will share the study results with a MISO staff committee that focuses on competitive transmission. That committee will decide whether to cancel the project or reassign it to a new developer.
Pedersen said MISO will make a formal recommendation in August.
Tea leaves don’t need to be read to deduce which direction the RTO is leaning. The RTO said Hartburg-Sabine “no longer provides any meaningful production cost benefits based on the planning analysis performed and using the latest modeling information.” The grid operator said its analysis couldn’t find “substantive” congestion relief or adjusted production cost benefits.
In 2017, staff said Hartburg-Sabine would alleviate congestion, ease import limitations and allow access to lower cost generation for customers in the chronically congested West of the Atchafalaya Basin and Entergy load pockets in MISO South.
MISO in late April announced it would reassess the Hartburg-Sabine junction project under its variance analysis procedures. Depending on study results, the RTO said it has one of two options: cancel the project or confer the line to Entergy in accordance with Texas’s recent right of first refusal (ROFR) law for incumbent utilities. (See MISO Study to Decide Fate of Texas Competitive Project.)
MISO’s study accounted for last year’s addition of Entergy’s 993-MW Montgomery County Power Station in southeast Texas and assumed the utility builds its planned 1.2-GW natural gas and hydrogen-powered Orange County Advanced Power Station by 2026. The Orange County plant has a signed generator interconnection agreement in MISO.
The grid operator considered that Entergy pushed back retirement of its nearby 500-MW, gas-fired Lewis Creek plant from 2025 to 2034. It also factored in the addition of two small nearby baseline reliability projects, one rated at 138 kV and the other at 230 kV.
Mayfield added that the RTO’s long-range transmission plan will soon study congestion patterns in MISO South and possibly come up with new transmission solutions.
“The Hartburg-Sabine Junction just isn’t economically solving the congestion we’re seeing,” Mayfield told stakeholders.
The line would have been MISO South’s first market efficiency project.
Stakeholders pointed out that the Texas Public Utility Commission has not yet approved the Orange County plant.
“The plant is in a holding pattern,” said Andy Kowalczyk of activist group 350 New Orleans.
“It seems like it’d be an awful shame not to at least do a sensitivity case with regard to the generation addition, whether it changes the outcomes for Hartburg-Sabine,” the Coalition of Midwest Transmission Customers’ attorney Jim Dauphinais said.
He said MISO might find itself “bringing the project back to the table” a year from now if the plant is not approved.
Energy consultant Jennifer Vosburg said the Orange County plant is already a few hundred million above its original budget.
MISO planners said even if plant approvals fall through, it wouldn’t make the line economic or necessary.
But Dauphinais said MISO wasn’t presenting any study results showing that the line remains unnecessary without Orange County.
WEC Energy Group’s Chris Plante said the Hartburg-Sabine was a market efficiency project that overcame several analyses to show benefits.
“I think that just demonstrates that as we go forward, we need to ensure that we have robustness testing, that even with small changes in assumptions … we still have a project that’s beneficial,” he said.
“I do hope that this serves as a lesson for how MISO approaches congestion planning and how durable and defensible these projects are over time,” Kowalczyk said. “I am worried that the market efficiency project tariff doesn’t produce projects, and this one was undermined by the ROFR, by bottom-up [transmission] projects and by signed generator interconnection agreements.”
The D.C. Circuit Court of Appeals on Tuesday upheld FERC’s May 2020 rejection of Public Service Company of Colorado’s proposal to change its large generator interconnection procedures, agreeing that the changes could have given the utility an unfair advantage over competing generators (20-1295).
PSCo, an Xcel Energy (NASDAQ:XEL) company, had proposed a fast-track process for generators looking to replace an existing power plant with a new one on the same site, saying it would avoid wasteful grid-impact studies and would allow new generators to interconnect more quickly.
But while FERC had previously granted a virtually identical request by MISO, it said such procedures had different implications for vertically integrated monopolies such as PSCo. Because 60% of PSCo’s existing designated network resources are generators owned by itself or an affiliate, “we find that the proposed generator replacement process could give PSCo an undue preference,” FERC said (ER20-1153). (See FERC Rejects PSCo’s Interconnection Process.)
The D.C. Circuit’s July 19 ruling upholding the commission came more than a year after FERC approved PSCo’s modified fast-track plan.
Order 2003
Under FERC Order 2003, grid operators generally consider interconnection requests on a first-come, first-served basis. The commission said vertically integrated operators cannot deviate from the standard interconnection process unless they show that their proposed changes are “consistent with or superior to” the commission’s standard large generator interconnection procedures (LGIP).
Because they do not own generation, independent grid operators such as MISO can win FERC approval for more flexible rules under the “independent entity variation” standard.
In March 2019, FERC accepted MISO’s proposed generator replacement procedure, saying it “will avoid duplicative study costs and operational costs that otherwise would occur when the request to replace an existing generating facility must proceed through the interconnection study queue process” (ER19-1065).
In rejecting PSCo’s proposal, FERC noted that when an existing generator retires, its transmission capacity can be made available for a new generator. But under PSCo’s plan, the retiree’s transmission capacity would instead likely be locked up by incumbent generators, such as the company itself.
Unlike PSCo, MISO does not “have an incentive to obstruct independent generation from accessing the grid,” the commission said.
The D.C. Circuit said FERC had provided an adequate explanation of its rejection.
“There was nothing arbitrary or capricious about its decision to bar a vertically integrated grid operator from adopting a rule that could favor its own generators and so cement its dominant market position,” it said. “The commission’s holding is consonant with decades of agency policy reflected in orders upheld by the Supreme Court and our court.”
Decision Moot
The court noted that the impact of its ruling was moot, however.
Shortly after rejecting PSCo’s proposal, FERC in November 2020 accepted Dominion Energy’s (NYSE:D) plan for a streamlined replacement generator program administered by a neutral third party, which the commission said would protect “against discriminatory implementation” of the new process (ER20-1668-003).
“In 2021, while this case was pending here, [PSCo] filed a request with the commission to adopt a streamlined replacement generator program administered by an independent entity,” the court noted. “The agency approved that proposal for the same reasons it gave in Dominion Energy” (ER21-1287).
The North American bulk electric system faced “unprecedented challenges” in 2021 that resulted in significant hardships to customers even though grid operators were largely able to maintain reliability, NERC said in its 2022 State of Reliability Report issued Wednesday.
Unlike the ERO’s seasonal and long-term reliability assessments, the State of Reliability is meant to review the performance of the electric grid in the prior year, identify performance trends and emerging reliability risks, and measure the success of mitigation activities. NERC staff previewed the report in May for the organization’s Board of Trustees, which approved the report earlier this month. (See NERC Board Accepts State of Reliability Report.)
Winter Storms Lead Review
This year’s report identified six key findings, four of which had to do with severe weather and other impacts of climate change. First, the winter storms of February 2021 “demonstrated that a significant portion of the generation fleet in the impacted areas was unable to supply electrical energy during extreme cold weather.”
The storm resulted in more than 23,000 MW of manual firm load shed across Texas and the South Central U.S., the largest controlled firm load shed event in U.S. history, according to FERC and NERC’s joint report on the event released last year. (See FERC, NERC Release Final Texas Storm Report.) Solely because of this one event, the ERO recorded 70.5 hours of operator-initiated firm load shed in 2021, higher than any other year since 2017.
At the other extreme was the Northwest Heat Dome, which affected the Pacific Northwest in June and July and caused temperatures to hit record highs — for example, 108 degrees Fahrenheit in Seattle and 116 in Portland. During the heat wave, which resulted in more than 1,000 deaths, “utilities across the region [set] new all-time summer peak demand records [and] several substation distribution transformers reached internal hotspot levels causing outages in some areas.”
Along with the severe weather events themselves — which also included the California wildfires, Hurricane Ida’s impact on Louisiana and Mississippi, and the storm system that spawned tornadoes in eight states in December — NERC’s report singled out electricity and natural gas interdependencies as another key finding. The vulnerability of the BES to disruptions in the natural gas supply has been a topic of concern for years, but it was highlighted in the February storms, when multiple gas generation plants were unable to perform because of freezing temperatures, resulting in a knock-on effect in which other gas generators could not function because of lack of electricity.
“It is now evident that these risks are no longer emerging; they are certain and expected to increase. Natural gas-fired generators are now necessary balancing resources for reliable integration of … renewable energy resources and can be expected to remain so until new storage technologies are fully developed and deployed at scale,” the report said.
While the direct effects of climate change are visible in the growth of severe weather events, the efforts of grid planners to prevent such impacts by adding wind and solar plants has also created reliability risks.
Left: AC circuit outages initiated by human error since 2017; right: Transformer outages initiated by human error since 2017. | NERC
NERC’s report cited the Odessa Disturbance — in which nearly 20 solar and wind facilities suffered reduced voltage as a result of a fault in a combined cycle plant in Odessa, Texas — as well as four disruptions in California as evidence of “continued BES reliability risks associated with inadequately interconnected” inverter-based resources (IBRs). (See Texas RE, WECC Call For Coordination on DER Issues.) In addition, NERC noted that in several areas, “peak demand could not be met without renewable generation,” suggesting that future disruptions to IBRs could lead to larger outages.
Cybersecurity Still Poses Problems
Among non-weather-related challenges, the threat of cyberattacks loomed large in 2021, with NERC noting “a series of attacks on the digital supply chain” and suspicious incidents across the industry such as phishing, malware and denial-of-service attacks. Threats came from both cyber criminals and nation-state adversaries such as China, Iran, North Korea and Russia.
In a media call introducing the report, John Moura, NERC’s director of reliability assessment and performance analysis, declined to specify how many of last year’s cyber incidents involved attacks against the industrial control systems that directly control the grid, as opposed to utilities’ information technology networks. He did, however, emphasize the “increased sophistication” displayed by the attackers and the need for ongoing vigilance by the industry, NERC and the Electricity Information Sharing and Analysis Center.
Finally, the report noted that despite frequent calls for new metrics to “evaluate the resilience of the [bulk power system] to the changing resource mix,” such measurements have not yet emerged. While NERC acknowledged that various stakeholders are working to develop new metrics, it will be difficult to properly evaluate the resilience of the grid until the task is completed.
ERCOT demand came within 12 MW of breaking the 80-GW barrier Wednesday afternoon, but the Texas grid operator was still able to set a record, its 11th of the year, as load averaged 79.8 GW during the hour ending at 5 p.m. CT.
Temperatures have reached up to 115 degrees Fahrenheit in Texas and Oklahoma, as the Southern Plains continue to bake under a heat dome that is diverting the jet stream northward. Oklahoma City hit 110 F on Tuesday, breaking a record that stood since 1936, while Wichita Falls to the south reached 115, a July record.
Other cities in the region could face the same dangerous conditions in the next few days. The National Weather Service has issued heat advisories and excessive heat warnings in 28 states.
“Another day of exceptional heat lies ahead with triple-digit highs forecast for all of North and Central Texas,” wrote the National Weather Service in Fort Worth in an online technical discussion.
SPP, which set its latest record for peak demand Tuesday, again extended the conservative operations advisory for its 14-state balancing authority area by 24 hours because of continued high loads and generation availability. The advisory is now effective through 10 p.m. Thursday.
The RTO’s grid is also operating under a resource advisory through Thursday.
The global energy crisis has created the potential for the U.S. to clean up its electricity supply while providing energy security to the world through LNG exports, a panel of energy experts said Wednesday.
Current global LNG market conditions place the “burden” of fulfilling new LNG demand from Europe and Asia Pacific on the U.S., Renee Pirrong, director of research and analysis at Tellurian, said during the Energy Dialogues webinar.
“The market is going to be quite tight for years to come, and the U.S. is the only place where you can get scalable, additional liquefaction supply in the context of Europe potentially needing 150 [million] to 170 million tons of LNG imports per year,” she said.
That level of demand could allow the U.S. to displace natural gas from its power market for liquefaction and exportation, according to Gabriel Collins, a fellow at Rice University’s Baker Institute for Public Policy.
There is also case for “accelerating the small modular nuclear revolution in the U.S., and that allows you to scale low-carbon power without having to think about nuclear nonproliferation,” he said. “It’s a domestic opportunity that captures the best of both worlds.”
Kevin Book, managing director of ClearView Energy Partners, agreed that providing global energy security while also greening the U.S. grid is an “incredible opportunity,” but it will require new gas transmission infrastructure.
“For us to be able to push our molecules out into the water, we need to have connection from the production site to the coasts,” Book said.
Market Status
The global LNG market has seen “huge” supply and demand shocks this year, according to Pirrong.
New demand levels for LNG in Europe that stem from Russia’s invasion of Ukraine can be seen in the region’s usage in 2022 alone. Historically, European demand was between 35 million and 65 million tons per year, but so far this year the continent has consumed 63 million tons, on track to 125 million tons by year-end, Pirrong said.
Europe has reached the top spot on the “willingness to pay scale” for the foreseeable future, she said.
On the supply side, Russia will no longer be among the top LNG exporters in the world. About 140 million tons of Russian LNG exports are either in jeopardy or “completely wiped off the table,” she said.
Those market shifts will create what Pirrong calls “demand destruction” in the long-term LNG market.
“It’s ironic and a little bit sad that Europe, which has been to some degree lecturing the rest of the world against investing in gas, is now diverting LNG away from the markets that needed it the most in the midst of this crisis to shore up its own supply,” she said.
If that trend persists, she added, many countries that were transitioning to LNG will return to coal. As a result, the International Energy Agency expects coal investments to trend up this year and reverse a decade of declining investment.
“This points to a long-lasting period of high gas and energy prices as a whole,” Pirrong said. “The only antidote to this is more investments in traditional energy projects, including LNG, but it is also important that those projects are in regions that support global energy security aims.”
Global energy decisions that are made in 2023-2024 are likely to be the most “consequential” for the climate, according to Collins.
“If there’s not an expectation of abundant, affordable and secure gas supplies at some point reasonably near in the future, we’re likely to see additional coal locked in,” he said.
The extension of coal as a resource will go beyond simply adding a few years of operation to plants that heretofore were headed for decommissioning. Instead, Collins said, coal plants in China, India or Southeast Asia that were potentially “on the fence” will come online and run for up to 50 years.
“There’s a lot at stake here, and gas is right at the center of that conversation,” he said.
That was one of the big takeaways for ISO-NE after last year’s GridEx VI, the biennial grid security exercise put on by NERC.
In a presentation to the NEPOOL Reliability Committee on Tuesday, ISO-NE’s manager of control room operations, Jonathan Gravelin, laid out some of the grid operator’s lessons learned from the November 2021 exercise.
The two-day exercise, a smaller affair than in past years because of the COVID-19 pandemic, incorporated elements of some of the major cyberattacks from around the world in the past year. (See GridEx VI Incorporates Recent Cyber Lessons.)
It also threw a Nor’easter into the mix of hypotheticals, adding extra strain to the simulated grid in New England, as well as some additional offshore wind to get an accurate picture of the future energy mix.
In New England, the scenario resulted in 12,000 MW of lost generation from cyber and physical attacks on transmission and natural gas infrastructure, according to Gravelin’s presentation. The events and manual load shedding led to, at its peak, 3.5 million customer outages in the region.
Among the strengths of ISO-NE’s simulated response, Gravelin said, was that the region maintained communication effectively, in part because of technology that’s been introduced since the pandemic.
The system also effectively started shedding load, he said, using process improvements from previous exercises. And emergency reporting from ISO-NE provided “valuable data and information in a consolidated format for timely decision-making.”
The response wasn’t all rosy though.
ISO-NE will be looking to find ways to improve its 21-day forecast of expected energy deficiencies, which could be more flexible.
There were also some aspects of communication that should be improved, Gravelin said, like presenting a “unified message” for coordinating requests for government help.
And finally, ISO-NE needs to go deeper in exploring how the modeling and operation of renewable resources would play into major events like those simulated.
“The recommendations suggest a task-force type approach to collaborate and gather information and knowledge across impacted parties,” he said.
New York regulators on Tuesday issued an order approving Consolidated Edison’s (NYSE:ED) emergency response plan (ERP) after the utility restored language related to communications (21-E-0567).
The Public Service Commission in May approved such plans from all the other investor-owned utilities in the state, but rejected Con Ed’s filing “due to concerns regarding Con Edison’s removal of certain language from its existing approved ERP and the lack of additional improvements reflected in other utilities’ amended ERPs.”
The commission determined that without such language, there was a potential that Con Ed’s emergency responsiveness might suffer detrimental impacts during future events.
Unlike the other utilities, Con Ed did not file an amended ERP, even after several meetings with Department of Public Service staff to discuss possible resolutions. It initially had proposed notable changes to how it classifies certain events and had removed specific language in several sections of its ERP filed in compliance with an earlier commission order.
Much of the deleted language reflected existing practices or processes that should continue to be used, such as language regarding its meteorologist and storm classifications, the commission said.
Con Ed negotiated with DPS staff to include a small set of modest amendments to augment its ERP, which now also incorporates language on proper communication with customers, emergency management officials and government representatives. The added language includes clarifications related to contacting life-support customers who are without power because of an event.
Implementing the supply chain security requirements in NERC’s CIP-013-1 reliability standard has required an unexpected level of outreach across the industry, cybersecurity specialists at several utilities said in a webinar hosted by SERC Reliability on Tuesday.
CIP-013-1 took effect in October 2020, the first NERC security requirements for bulk electric system cybersystems. The new requirements received considerable industry attention in the lead-up to their release, with Chuck Abell, the supervising engineer of technical support for transmission operations at Ameren, calling the standard “the most publicized, socialized CIP [Critical Infrastructure Protection] standard so far.”
Participating in an industry panel during SERC’s “The Scoop on Supply Chain” webinar, Abell observed that implementation was more complicated than with most of NERC’s standards because CIP-013-1 applies to utilities’ processes for sourcing and acquiring new equipment. This requires the participation of significantly larger numbers of people internally than is normally the case, which has spurred a variety of approaches from utilities.
“There’s a lot of different players who get involved with CIP-013 that don’t get involved with the other standards. It’s not just cybersecurity and compliance; it’s sourcing, it’s legal, it’s contract administration,” Abell said. He added that utilities have even begun to include vendors in the process, in hopes of ensuring their equipment is built to the standard’s specifications.
“Last year we sent about 250 people through [our annual supply chain security training], and that was not just internal [staff], but also vendors that do similar contract prep for us,” he said.
Tony Hall, the manager of LG&E and KU’s CIP program and moderator of the panel discussion, agreed with Abell on the importance both of including vendors in the CIP-013-1 compliance process and of coordinating a utility’s internal response to the standard. Instituting a supply chain security standard turned out to be a much bigger job than anyone at his utility expected, he said.
“We found out at LG&E that we [didn’t have just] one department that was responsible for procurement, but we actually had three. They were trying to cross-functionally work together, but they were separate departments,” he said. “So having a cross-functional team develop our program is probably one of the best things that we did.”
Tony Eddleman, director of NERC reliability compliance at the Nebraska Public Power District (NPPD), said his company has implemented a yearly independent risk assessment for components that are subject to the standard, along with the vendors that supply them. The assessment looks for any vulnerabilities that have been announced for the component and any negative news about the supplier, the discovery of which could spur further review and mitigation activities.
Along with his colleagues, Eddleman emphasized that NPPD considers its CIP-013 compliance process a work in progress, with a complete solution likely to remain out of reach.
“I think supply chain [security] is a journey,” he said. “There’s always things that we can learn, that we can tweak, [to] make our processes better.”
The Western Area Power Administration has approved interconnection of the proposed 504-MW Rail Tie Wind Project in southern Wyoming, completing the last step necessary for the developer to go forward with construction.
Developer ConnectGEN had requested to hook the project up to WAPA’s 345-kV Ault-Craig transmission line. WAPA Administrator Tracey LeBeau signed the record of decision on July 11.
“Connecting more renewable energy projects to the grid is a critical step in modernizing America’s energy infrastructure and meeting our nation’s growing energy needs,” LeBeau said in a statement.
Rail Tie will consist of 84 to 149 wind turbine generators, according to WAPA’s decision. The project site is about 26,000 acres of private and state land in Albany County, Wyo.
The project will have two stages, each approximately 252 MW and divided by U.S. Highway 287. The company received approval from the Albany County Board of County Commissioners in July 2021, the Wyoming State Board of Land Commissioners in January 2021 and the Wyoming Industrial Siting Council in November 2021.
With the main permits needed for the project now in place, the company is focusing on final engineering and pre-construction planning, Mark Lawlor, ConnectGEN’s vice president of development, said through a publicist on Tuesday. The company expects construction to begin in spring 2023, with operations starting by the end of 2024.
Lawlor said the company is in conversations with several potential customers but has not yet finalized a power purchase agreement for the project.
ConnectGEN is a renewable energy company that private equity firm Quantum Energy Partners launched in 2018. According to its website, the company has 139 MW in operation and more than 20,000 MW of wind, solar and energy storage projects in development across the U.S.
According to WAPA’s decision, technical analyses found the project would not reduce the transmission system’s reliability and that system upgrades wouldn’t be needed to support the interconnection.
An environmental impact statement, finalized in November, identified significant impacts from turbine operations on visual resources, certain historic properties and eagles. But there are still opportunities for those impacts to be mitigated, WAPA noted.
For example, ConnectGEN is seeking Federal Aviation Administration approval to install an aircraft detection lighting system, in which flashing red lights on the turbines would only turn on when an aircraft is in the area.
ConnectGEN is also preparing an eagle conservation plan. In addition, the company is applying for an eagle incidental take permit from the U.S. Fish and Wildlife Service, a process that could lead to other mitigation measures, WAPA said.
New Jersey is for the first time offering incentives for the purchase of electric heavy-duty trucks and has committed $46.6 million to expand a two-year-old program that has already funded the purchase of nearly 150 light- and medium-duty trucks with Regional Greenhouse Gas Initiative funds.
The New Jersey Economic Development Authority (NJEDA) on July 13 approved the funding for the second phase of the New Jersey Zero Emission Incentive Program (NJ ZIP), in an expansion that would also increase the geographic area in which incentives are available.
Initially, the program only funded the purchase of trucks to be based in or around Newark in northern Jersey, and Camden, in the south. The EDA later expanded the program to include Central Jersey and the Jersey Shore. Under the latest phase, EDA will provide incentives for the purchase of electric trucks to be used anywhere in the state.
The strong demand in the first phase, in a relatively limited area of the state, drove the decision to open a second phase, agency CEO Tim Sullivan said at a press conference Monday in Lyndhurst, to tout the expansion of the program.
“Hopefully, finally, lots of small businesses are thinking about what’s next and how they make the long-term capital upgrades to get ahead of, not just rising gas prices, but long-term energy costs,” Sullivan said. He sees the high interest in the program as reflecting a mindset of “how you participate in the green and clean economy.”
NJ ZIP at present awards vouchers for electric truck purchases, starting with $25,000 for a Class 2B truck up to $100,000 for a Class 6 truck. The incentives are designed to encourage potential truck buyers to go electric by covering the added cost of an electric vehicle over a traditional gas- or diesel-powered vehicle.
The second phase incentives, set at $20,000 for a Class 2b truck and $90,000 for a Class 6 truck, will cover 75% to 110% of the extra cost of an electric vehicle, Sullivan said in a memo to the board outlining the expansion. The new program also adds incentives of $135,000 for a Class 7 truck and $175,000 for a Class 8 truck.
The EDA expects the program to be up and running by the end of the year, and it will continue until the funds are exhausted, which Sullivan expects to be about the middle of 2023. The agency’s goal is to follow the first and second phases, both pilot programs, with a permanent program if the funding is available.
Chance to Go Green
The generous incentive package, and the chance to make good on their commitment to creating a greener world, persuaded ENAT Transportation and Logistics of Ridgefield Park to submit an application last year, said Vanessa Abad, the company’s executive administrator. She co-founded ENAT with her husband Luis Abad, the company CEO, and his brother Ernesto Abad, the company logistics manager.
“We really are green people, so we like going green. We like recycling; we like to make sure we’re not wasting food.” Vanessa Abad said. “So, we thought this was a good opportunity for our business to go green.”
ENAT, a contract delivery company, applied for incentives to purchase four Class 4 trucks ― a 2021 EV Star Cargo Plus box truck and three 2022 EV Star Cargo vans, all manufactured by GreenPower Motor ― to add to their four diesel trucks. The vehicles were the real stars of the press conference, and the Abads expect to use them for deliveries of about 30 to 40 miles in distance, with recharging every couple of days.
The trucks have also spurred the Abads to go even greener by installing a charger and solar panels at their home, where the trucks will be charged.
Because the company is minority- and woman-owned — the Abads are immigrants from Ecuador — it qualified for one of the highest incentive levels, Vanessa Abad said. She estimated that the company paid about $12,000 of the total $115,000 purchase price for the vans. Luis Abad said a similar diesel vehicle would cost about $70,000, and he anticipates that the electric trucks will also cut his fuel costs, which used to be about $80 a tank and are now about $140 due to the rise in diesel prices.
Moises Luque, CEO at transportation company Supreme Green Team, of East Brunswick, said the financial package persuaded him to apply for six vehicles under NJ ZIP. He has been approved for three 22-foot vans and three 26-foot vans that will be used to move freight to and from warehouses, he said, adding that he will pay about $13,000 for each of the vans, which cost about $110,000.
“The numbers are the first things that attract you,” Luque said. “You know that you’re going to get an incentive that’s going to pay for about 80% of your vehicle.”
He also is planning to start a charging hub that will be open to the public because, “there’s no charging stations for vehicles this size here in the state of New Jersey,” he said, speaking at the EDA conference.
Moving to Heavy-duty Trucks
In line with the New Jersey Energy Master Plan, the EDA is seeking to transition 75% of the state’s medium-duty trucks and half of the heavy-duty trucks to EVs by 2050.
“The state has ambitious goals,” Sullivan said in his memo, which called the incentive program “a critical step in this direction to support the ZEV marketplace and rapidly deploy electric MHDVs on the road.”
Heavy-duty trucks had always been a target for the program, said Victoria Carey, EDA’s clean energy manager, who oversees the NJ ZIP program.
“The vast majority of the demand, and pollutants, come from the heavy-duty sector,” she said. But the agency wanted the first phase of the program to be up and running quickly, and the lengthy delivery time for heavy-duty trucks would hinder that, she said. The EDA has also heard strong stakeholder demand for electric buses, which are included in the program’s heavy-duty truck category, as well as demand from large trucking fleets, whose “hub and spoke” delivery systems require trucks to go relatively short distances and are not restricted by the limited range of some electric trucks.
“We have the port right here; there’s just so much density to go from the port to the warehouse, out and back,” Carey said. “New Jersey, because of our density, is set up really well for the heavy-duty vehicle space.”
The change enables the program to target a heavy-duty trucking sector that has been slow to embrace large EV trucks. A recent report from CALSTART, a national nonprofit focused on clean transportation technologies, found that 65 medium- and heavy-duty electric trucks are deployed in New Jersey, a state that has 567,000 registered trucks of all sizes.
Few vehicles in the state’s electric trucking fleet are heavy-duty vehicles, according to trucking sources, and many of them are light- to medium-duty trucks purchased through the NJ ZIP program. At the Port of New York and New Jersey, the electric truck fleet consists mainly of yard tractors, which move containers inside port terminals and inside the port. (See Port of NY-NJ Unveils Fleet of 10 EV Trucks.)
Trucker Concerns
Truckers in New Jersey, like those around the nation, cite the lack of heavy-duty charging sites as a key obstacle to greater use of electric trucks. Other barriers cited by truckers in the past include the limited number of truck models available, the short range of existing electric trucks — which for larger trucks is about up to 250 miles — and the high cost of the vehicles. Their use at the port is also complicated by the fact many truckers are independent owner-operators with few resources for clean energy investment, according to the Port Authority of New York and New Jersey. (See Port NY-NJ Cites ‘Hurdles’ to Employing EV Trucks.)
But the CALSTART report said that nationwide the deployment of electric trucks of all sizes is growing, with a 155% increase in sales in 2021 over the previous year. And several studies have predicted that, in time, electric trucks will be more cost effective than diesel trucks. A report released in October by the Natural Resources Defense Council (NRDC) projected that an average medium- or heavy-duty electric truck purchased in New Jersey in 2040 will cost $25,000 less over its lifetime than a comparable diesel vehicle, due to reduced fuel and maintenance costs. (See NRDC Report Predicts a Decline in NJ’s EV Truck Costs.)
In New Jersey, sales could be boosted by the New Jersey’s Department of Environmental Protection’s adoption in December of California’s Advanced Clean Truck regulations, which require truck manufacturers to meet increasing electric vehicle sales targets. (See NJ Adopts EV Truck Sales Mandate.)
Sullivan’s memo said the NJ ZIP program, which began in 2021 and works on a first-come, first-served basis, has so far drawn 228 purchaser applications, totaling $43.6 million. Of these the EDA has approved 144, totaling $32.2 million.
The memo also said 90% of the program applicants are small businesses and 57% are either minority or women owned.
Carey said the program to date has funded the purchase of all sizes of trucks, but Class 4 vans for deliveries have been popular, as have Class 6 box trucks, which have so far commanded the highest incentives. The program has also funded the purchase of many passenger shuttles by the Atlantic City Jitney Association, an association of shuttle bus operators, she said.
