Page 450 – RTO Insider

July 20, 2022June 14, 2023

NJ Adds $46.6 Million to Electric Truck Incentives

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.

Tim Sullivan 2022-07-18 (RTO Insider LLC) FI.jpg

Tim Sullivan, NJ EDA | © RTO Insider LLC

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.”

Victoria Carey 2022-07-18 (RTO Insider LLC) FI.jpg

Victoria Carey, NJ EDA | © RTO Insider LLC

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.

July 20, 2022

ERCOT, SPP Continue to Battle Extreme Heat

ERCOT demand Tuesday flirted with 80 GW for the first time as the Texas grid operator set yet another record, its 10th, for peak demand this year.

Demand averaged 79.6 GW during the hour ending at 5 p.m. CT. It averaged 79.2 GW during the previous hour.

ERCOT was able to meet demand without issuing a conservation appeal and deploying non-spinning reserves or emergency response service, all of which it did last week. (See ERCOT Demand Hits Record for 9th Time.)

The grid operator had as much as 87 GW of committed capacity at one point during the afternoon. Solar production was again near capacity Tuesday after setting a record Monday with 9.6 GW of generation; it combined with wind resources to account for more than 25% of ERCOT’s power near the peak.

The grid operator is projecting demand to reach 81.5 GW on Wednesday. Staff in May forecasted demand to peak at 77.3 GW in August.

Dallas recorded its hottest day of the year Monday, with a high of 109 degrees Fahrenheit, 1 degree off the all-time record for that date. Many parts of North Texas are under an excessive heat warnings, with highs expected to stay above triple digits into next week.

With the record heat exacerbating the state’s drought conditions, the National Weather Service issued a red flag warning until midnight Wednesday for counties in North and Central Texas because of an elevated risk of wildfires.

One such fire, the Chalk Mountain Fire southwest of Fort Worth, tripled in size from Monday to Tuesday. A Texas A&M Forest Service spokesperson said the fire posed no threat to the nearby Comanche Peak nuclear plant, as it is surrounded by enough asphalt that it would be protected from flames.

SPP Shatters Demand Mark

SPP shattered last week’s record for peak demand Tuesday when its load hit 53.2 GW at 4:59 p.m. CT. That met SPP’s projections of a 53-GW peak as triple-digit temperatures settled over the Southern Plains.

The demand was the RTO’s fourth record peak of the summer, toppling the most recent mark of 52.03 GW set Friday. That peak bettered the previous high of 51.5 GW set July 11, which, in turn, surpassed the peak of 51.1 GW on July 5.

SPP began the summer with a record of 51 GW, set last July.

The grid operator extended a conservative operations advisory through 10 p.m. Wednesday because of continued high loads and risks related to available generation resources. The advisory had been scheduled to end Tuesday.

SPP and its members are also operating under a resource advisory through Thursday because of the pervasive high temperatures, high regionwide energy use and uncertain wind forecasts.

Neither advisory requires public conservation.

July 20, 2022November 30, 2023

Senate Committee Holds First Hearing on Hydrogen Pipeline

Fears that FERC’s regulations — and those who use them to challenge gas pipelines — will stymie the development of a national hydrogen pipeline system pervaded a Senate Energy and Natural Resources Committee hearing Tuesday.

Chairman Joe Manchin, (D-W.Va.) set the tone in his opening remarks, saying the nation’s energy infrastructure is facing a “crisis.”

“We face huge challenges getting the energy infrastructure we absolutely need sited, permitted and built — challenges that weaken our energy security and jeopardize our ability to meet our climate goals,” he said. “We can’t be short-sighted here. We need to look to the future and play the long game. We must get the right regulatory structure in place now, at the ground floor, that will help us accelerate hydrogen to scale in this country.”

Noting that the nation now has only 1,600 miles of hydrogen pipeline, Manchin predicted new pipelines would have to be built, even if existing gas lines are used to move a blend of natural gas and hydrogen. And those pipeline expansions would likely come under the purview of FERC, he added.

“Clarity is important for hydrogen pipeline developers, producers, consumers and communities potentially affected by this development. It appears there’s uncertainty today around which federal laws to apply to interstate hydrogen infrastructure, and also about which federal agencies could or should be involved in siting, permitting and setting rates for using this infrastructure. If that is the case, our committee should take steps to ensure predictable and effective regulatory framework because regulatory uncertainty benefits no one. There’s a compelling argument for FERC to play a role for interstate hydrogen infrastructure similar to the responsibilities it has for natural gas and petroleum pipelines today for natural gas.”

Sen. John Barrasso, (R-Wyo.), the committee’s ranking Republican, said existing natural gas pipelines “are equipped to ship methane blends, which can include up to 20% hydrogen.” He said he does not believe there is a “regulatory gap that Congress needs to fill.”

He argued that environmentalists are working to make sure hydrogen pipelines are never built and that gas pipelines are not permitted to expand.

“Our country’s natural gas pipelines are under unprecedented attack. Well-funded environmental extremist activist groups are throwing the kitchen sink at every new project,” he said.

“The current majority of the FERC wants to make it impossible to upgrade pipelines or build new ones. …

“I’m concerned that some of the commission may seek to make the ability to ship higher blends of hydrogen a reason to impose new conditions on newer upgraded natural gas pipelines,” Barrasso said. “If that happens it’d be a disaster. Let’s not give these activists or the commission another weapon to use against natural gas pipelines.”

Witnesses

The committee listened to the comments of four expert witnesses who are involved in the production or distribution of natural gas or hydrogen, and knowledgeable about the current state of regulation.

Andy Marsh, president and CEO of Plug Power (NASDAQ:PLUG) and a hydrogen industry expert, said pipelines will be crucial.

“I think probably the most important items are the rights of ways. … To be able to use natural gas pipeline rights of way will help avoid unnecessary roadblocks,” he said. “I would suggest that the committee encourage FERC to lean on the industry experts,” he said.

The four expert witnesses from left: Andy Marsh, president and CEO of Plug Power(NASDAQ: PLUG); Holly Krutka, executive director of the School of Energy Resources at the University of Wyoming; Chad Zamarin, senior VP with Williams Companies, a natural gas processing and transportation company (NYSE: WMB); and Richard Powers, a partner and head of the Energy Practice Group at Venable, testified before the Senate Committee on Energy and Natural Resources Tuesday on the importance of pipelines for the development of hydrogen as a fuel. | Senate ENR Committee

Holly Krutka, executive director of the School of Energy Resources at the University of Wyoming, said she and others at the school see hydrogen as “an important component of the energy future.” But she warned that new regulations on hydrogen could impinge on the state and region’s robust natural gas industry

“It’s critical that hydrogen regulations do not negatively impact natural gas production, transportation and consumption. When it comes to standing up a hydrogen industry, Wyoming is standing on a strong foundation,” Krutka said.

“In addition to being a leading energy producer, the state hosts a robust and expansive rail system, and that rail system could be used to transport clean ammonia,” she said in a reference to converting hydrogen to ammonia, a liquid that is more easily transported.

“We also have an extensive natural gas pipeline network, and that offers the opportunity to transport clean hydrogen and blends of hydrogen and methane, which is probably the most likely opportunity in the near future,” she said.

But she added that the industry fears that federal mandates aimed at reducing methane leakage could upend hydrogen as well as natural gas development.

“If, for example, new natural gas infrastructure would also have to comply with new FERC-imposed mandates related to transporting blends of natural gas and hydrogen, I would worry that the infrastructure would never get built. Therefore, I and others in Wyoming are concerned about the imposition of new federal standards that could have unintended consequences on natural gas production and transportation.”

Chad Zamarin, senior vice president for Williams Co. (NYSE:WMB), said the only way to scale up hydrogen production and use is to “leverage” gas pipelines.

“FERC is, as has been mentioned, our primary regulator for interstate natural gas pipelines. And it does seem like that’s a likely venue for us to approach with respect to hydrogen. That said, we are concerned that we don’t want to create a traffic jam before the car even gets out of the garage,” he said. “The current FERC process has become an incredibly difficult process to facilitate the building of energy infrastructure. …

“We’ve proposed in our written testimony some very simple changes that if the Congress were to act, we think could streamline the FERC permitting process and ensure that we can bring the infrastructure needed to not only continue delivering the critical natural gas here and around the world, but the hydrogen that we believe we can bring to market through our infrastructure. These changes are relatively simple, and Congress has the power to implement them,” Zamarin said.

Richard Powers, partner and head of the energy practice group at the law firm Venable, said it is clear that FERC is the agency that has the authority to regulate hydrogen pipelines.

July 19, 2022June 14, 2023

ERCOT Demand Hits Record for 9th Time

Warnings that this week would include the highest temperatures yet this summer proved to be accurate Monday as ERCOT set yet another record for peak demand, its ninth of the year.

Demand averaged 79.038 GW during the hour ending at 6 p.m. CT. That shattered the previous mark of 78.4 GW set July 12 and marks the first time it broke 79 GW.

The record is likely to be short-lived, as ERCOT is projecting demand to break 80 GW today and Wednesday.

Dallas Forecast | WFAA-TV

Temperatures in Dallas were predicted to approach 110 degrees Fahrenheit early this week before cooling off into the low 100s. Texas has already suffered through its hottest May and June on record, and meteorologists expect more of the same through this month. Heat advisories remain in effect for much of the state.

The National Weather Service said widespread heat is highly predictable through Wednesday, and it has declared a moderate to high risk of excessive heat into August.

The record demand, 13 GW of thermal outages and reduced renewable production last week forced ERCOT to issue two conservation appeals to Texans and businesses. (See ERCOT Dances with Danger Again.)

“We want to be respectful of Texans, so we will only call for conservation if we need it,” staff said in an email to RTO Insider. They said the July 11 conservation appeal successfully reduced demand by about 500 MW.

Demand peaked above 77 GW from July 5 to 13 before dropping to just over 70 GW heading into the weekend.

The grid operator’s operations center has issued several watches in recent weeks because of projected reserve capacity shortages without a market solution that could lead to an energy emergency alert.

ERCOT said the forced thermal outages exceeded its forecasts. It was expecting only 67 of its 80 GW of installed thermal capacity to be available July 13 during the afternoon’s tightest hour (3-4 p.m.). Wind generation was again below its historical usage, dropping to 750 MW, about 2% of capacity, after the conservation period passed. Cloud cover in West Texas initially reduced the amount of available solar generation by almost 2 GW.

Operating reserves stayed below 3 GW during much of the afternoon.

Interim ERCOT CEO Brad Jones reminded the Houston Chronicle on July 12 that the grid operator is now calling for conservation earlier to help the grid avoid emergency conditions.

ERCOT deployed 927 MW of non-spinning reserves at 12:39 p.m. and then called on emergency response service (ERS) at 2:55 p.m. shortly before physical responsive capability fell below 3 GW. That forced dispatchers to issue another advisory.

During its open meeting Thursday, the Texas Public Utility Commission approved an order that increases ERCOT’s annual ERS budget to $75 million and allows the grid operator to broach this amount by up to $25 million for contract term renewals. ERCOT will be able to access the additional $25 million immediately upon the effective date of this rule (53493).

The grid operator said Monday morning that the Texas Commission on Environmental Quality (TCEQ) will allow resources to exceed their air-permit limits to ensure all possible generation is available to serve system demand. The TCEQ’s enforcement discretion began at noon and was expected to end at 9 p.m. Monday.

The commission allowed similar exceedances July 8-14. Prices exceeded the $5,000/MWh offer cap for four hours Wednesday, reaching as high as $5,500/MWh. Monday’s prices settled at a high of $1,419/MWh during the interval ending at 4:45.

July 19, 2022

PJM Orders Dominion ‘Immediate Need’ Projects to Serve Load Jump in ‘Data Center Alley’

VALLEY FORGE, Pa. — PJM officials said last week that “Data Center Alley” in Northern Virginia will require further transmission upgrades in addition to the previously identified $230 million in baseline and supplemental transmission upgrades to support a 4-GW increase in load.

The RTO said it has assigned incumbent Dominion Energy to construct the “immediate need” reinforcements. Dominion is already in the process of constructing 11 “supplemental” transmission upgrades estimated at $197 million and two “baseline” transmission upgrades totaling more than $32 million to address the “unprecedented load growth” caused by the continued growth of power-hungry data centers near Dulles Airport.

PJM’s Sami Abdulsalam gave the Transmission Expansion Advisory Committee a presentation on the issue July 12, showing that Dominion’s load is growing by 3% per year for 2022-2027, all of it from data centers.

Since 2018, Dominion has submitted to PJM 44 supplemental projects to serve more than 2 GW of increased load through the summer of 2025. All told, the RTO expects 4 GW of additional load in the area between 2021 and 2027.

Data center additions listed in the 2022 load forecasts provided by Dominion and Northern Virginia Electric Cooperative (NOVEC) were “noticeably higher” than in their 2021 forecasts, PJM said.

The updated load forecast for the 2027 Regional Transmission Expansion Plan showed that the area would face reliability violations even with the 13 projects in service, with four flowgate violations leading to load drop of more than 300 MW.

“Because the area is constrained on all 230-kV inlet transmission segments to serve the size of load, and data center load has a flat profile throughout the day, power flow control or non-wires solutions are not applicable to solve the identified transmission needs,” PJM said.

As a result, PJM declared an immediate need to address reliability violations expected through 2025 and assigned construction responsibility to Dominion, saying a shortened competitive window would result in “delays of about six months.”

The immediate-need reinforcements will address violations in the area through 2025. PJM plans to solicit competitive proposals for further reinforcements that may be required beyond 2025. Once a proposed transmission solution is identified, PJM and Dominion will present it to the August 2022 TEAC meeting for first read.

July 19, 2022December 10, 2023

PJM Sees Wide Range of Costs in New Jersey OSW Transmission Proposals

Delivering power from New Jersey’s planned offshore wind projects will cost at least $1.2 billion and could total more than $7 billion, PJM officials said Monday.

The RTO released a 64-page analysis of the 26 point-of-injection (POI) scenarios it received in response to its transmission solicitation, which the New Jersey Board of Public Utilities (BPU) requested under FERC Order 1000’s State Agreement Approach.

PJM conducted analyses on reliability, impact on LMPs, constructability and legal risks, officials told a special meeting of the Transmission Expansion Advisory Committee. PJM planners are seeking feedback on the analyses by the end of July to allow the BPU to select its preferred projects by October, said Sami Abdulsalam, a senior manager for transmission planning.

PJM received 45 proposals for Option 1a, for onshore upgrades to address reliability violations on existing facilities, with capital costs totaling about $100 million or less. Proposals for Option 3, for an offshore transmission network, came in with similar price tags.

More expensive were Option 1b (new onshore transmission connection facilities) and Option 2 (new offshore transmission connection facilities), each of which ranged between $500 million and $7 billion, PJM said.

“Offshore wind is expected to be a major driver of green job growth in New Jersey for decades to come and has demonstrated clean energy benefits,” the BPU told RTO Insider in a statement. “The board, along with PJM, is pioneering the use of a highly competitive bidding process to select new transmission facilities to ensure that the power from the offshore wind turbines is delivered to New Jersey customers in an affordable and environmentally friendly way. The board will carefully review PJM’s findings and take them into consideration as we continue the offshore wind transmission application review process. The board anticipates making a final decision on whether to select one or more transmission projects later in the year.”

Cost Caps

Several of the POI scenarios offered additional capacity beyond the 6,400 MW desired, but they were not dispatched in the initial reliability analyses.

While 1A proposals had little to no cost-containment promises, eight of the proposers offered some sort of cost-capping mechanism on the other options, including an overall cost cap, a cap on return on equity and a cap on equity-debt mixes.

“Well capped proposals tend to have significantly lower cost overrun and other downside risks, such as high financing cost, compared to uncapped proposals,” PJM said. “However, depending on the magnitude of project cost and base case revenue requirement, there may be a tradeoff between cost and risk levels.”

Option 1a proposals included conventional transmission solutions such as rebuilding or reconductoring existing transmission lines, as well as proposals for power flow-controlling devices. But PJM said it will “generally prioritize consideration of conventional solutions over power flow-controlling devices depending on the overall transmission capacity provided by and cost associated with the devices.”

The 1a proposals would address only about half of the reliability violations identified. Incumbent transmission owner upgrades would address violations from injections that were not previously identified, Abdulsalam said.

Economic Analyses

PJM’s Nick Dumitriu said the RTO and the BPU created offshore transmission scenarios involving various combinations of the Option 1b and 2 proposals and, after an initial reliability screening, selected a subset for economic analysis.

That analysis looked at estimated load LMPs and gross load payments for load-serving entities in New Jersey and also computed PJM-wide production costs and cost impacts on Pennsylvania zones.

For Options 1b alone and 1b combined with Option 2, PJM said the difference between the proposals were “not significant,” with the largest difference in New Jersey load payments less than 1% and differences in POI annual average LMPs 4.2% or less. Some scenarios resulted in curtailment of OSW, but that was limited to 0.4% of total annual generation.

PJM plans to expand the analysis of energy market impacts with capacity market simulations, Dumitriu said.

An analysis to determine incremental auction revenue rights (IARRs) identified “no available IARRs.”

Construction Risks

PJM’s Augustine Caven said the RTO’s constructability evaluation found more risk in projects that impact the New Jersey Pinelands National Reserve or parcels in New Jersey’s Green Acres program, which are managed for recreation and pother public purposes.

Proposals with underground cabling were found to have higher engineering risks but lower environmental impacts.

Projects that made landfall in the busy Raritan Bay were seen as having a higher risk of conflicts than proposals to connect at the Seagirt National Guard Training Center.

Among those who made proposals were three New Jersey utilities: Exelon’s Atlantic City Electric, FirstEnergy’s Jersey Central Power & Light and Public Service Enterprise Group’s Public Service Electric and Gas. PSEG Renewable Transmission also teamed up with OSW developer Ørsted.

Con Edison Transmission and PPL Electric Utilities also made proposals, along with Anbaric Development Partners; Atlantic Power Transmission, a Blackstone Infrastructure Partners company; LS Power; Mid Atlantic Offshore Development, a joint venture of EDF Renewables North America and Shell New Energies US; NextEra Energy Transmission MidAtlantic Holdings; and Transource Energy.

Given the stakes involved, PJM’s analyses are likely to be subjected to heavy scrutiny. The RTO’s analysis surfaced one early disagreement: NextEra projected a cost of $4.68 million to reconductor the 230-kV Deans-Brunswick line, but PJM said PSEG estimated the cost at $73.3 million.

Additional reliability studies will be completed in July and August.

July 19, 2022November 15, 2023

TAE: Fusion Reactor Controls 135M-degree Plasma

California-based TAE Technologies on Tuesday said its research reactor had achieved and maintained control of plasma in the heart of a fusion reactor at a temperature of 75 million degrees Celsius (135 million degrees Fahrenheit) in a self-created magnetic field.

The company’s target temperature is 100 million C (180 million F), which it believes it can control to initiate sustained fusion and build a commercial reactor by the end of the decade.

TAE is among a half dozen startup research companies, including one in Seattle, working to develop a working fusion reactor to create energy by fusing atoms rather than splitting them as conventional nuclear power plants do. (See Fusion Company Gets $500 million.) Fission creates radiation in the process and leaves behind radioactive waste, some of which will be dangerous for millions of years. Fusion reactors do not produce long-term radioactive waste.

Unlike competing fusion research companies that have been working to fuse hydrogen from heavy elements and can be slightly radioactive while operating, TAE has been working since 1998 with hydrogen and boron, a common element found in cleaning products.

TAE’s rector creates enormous amounts of heat by fusing the nuclei of hydrogen atoms with those of boron atoms in a radiation-free process that also creates helium, an inert gas. Boron is ubiquitous on Earth, and the company estimates a 100,000-year global supply.

The research reactor is a fifth-generation test machine, dubbed “Norman” in honor of TAE co-founder Norman Rostoker, a Canadian plasma physicist who died in 2014. The reactor began operating in 2017.

The company credited Norman’s success to sophisticated control technologies it developed with Google since partnering with it in 2014.

“Through successful training of Norman’s state-of-the-art control system, paired with proprietary power-management technology and extensive optimization of our machine-learning algorithms, we have achieved a scale of control at an unparalleled level of integrated complexity,” TAE CEO Michl Binderbauer said in a statement.

The success of the Norman reactor has enabled TAE to secure $250 million in new funding for a larger test reactor, which it has named Copernicus. Since its founding it has received $1.2 billion in private investment and received more than 1,100 patents related to its technology.

The most recent investors include Chevron, Google, Reimagined Ventures, Sumitomo and Tiff Investment Management, as well as a large pension fund and a mutual fund manager, both unidentified.

“The caliber and interest of our investors validates our significant technical progress and supports our goal to begin commercialization of fusion by the end of this decade,” Binderbauer said. “Global electricity demand is growing exponentially, and we have a moral obligation to do our utmost to develop a baseload power solution that is safe, carbon-free and economically viable.”

The company characterized its hydrogen-boron technology as “the cleanest, safest, most economical terrestrial fuel cycle for fusion, with no geopolitical concerns or proliferation risks.”

The company’s announcement includes little detail on the “balance of plant” technologies that it will need to harness the enormous amounts of energy created by the fusion. In a FAQ document accompanying the announcement, there is a reference to a “steam generator.”

“Just as you feel warmth when sunlight hits your skin, in a power plant, the containment vessel wall will heat up from energetic light emanating from the plasma. The wall will be cooled through a network of pipes, which have working fluid streaming through them to pick up the heat and transport it to a steam generator,” the FAQ explains.

“The steam spins a turbine that then drives an electric generator, similar to what happens in operating power plants today. TAE’s unique fusion core supplies a superior and environmentally benign heat source for future power plants.”

July 19, 2022December 5, 2023

Oregon Regulators Grapple with Gas Sector Role in Decarbonization

Oregon officials are grappling with how the natural gas sector will fit into the state’s decarbonization strategy, with industry players seeing a clear role in a clean energy future and skeptics seeking a sharply reduced position for gas companies.

The two sides pitched their perspectives at a virtual public hearing hosted by the Oregon Public Utility Commission (OPUC) on July 12. The commission called the hearing to solicit input on its draft Natural Gas Fact Finding report, issued in April. A final version of the report is due to be released Aug. 12.

The hearing also cast light on the uncertainty utility regulators in Oregon — and elsewhere — face as they’re forced to balance their roles as economic supervisors with the growing need to factor environmental mandates and the decisions of sister agencies into their own decision-making and long-term planning.

According to the draft report, Oregon’s three natural gas utilities in 2019 earned $810 million in revenues while delivering about 1.6 billion therms of gas. Residential customers accounted for about 59% of those revenues, followed by “firm” commercial and industrial customers at 33%. Pipeline transport customers — who acquire their gas from other sources — accounted for just under 5% of revenues but more than 40% gas utility deliveries.

The Climate Protection Program (CPP) adopted last year by Oregon’s Department of Environmental Quality requires gas utilities to reduce greenhouse gas emissions by 50% by 2035 and 90% by 2050. All gas deliveries will be subject to the declining caps, including those for transport-only customers.

The fact-finding is intended to serve two purposes, the PUC said: to analyze the ratepayer impact of limiting gas utility GHG emissions under the CPP; and to “identify appropriate regulatory tools to mitigate potential customer impacts and accommodate utility action.”

At last week’s hearing, OPUC Utility Strategy and Planning Manager Kim Herb told hearing participants that the draft report points to the “strong and divergent opinions about how the natural gas industry decarbonization will come about.”

Even so, Herb acknowledged, some groups complained the draft report failed to capture their input. Environmental, community groups and “grassroots” commenters contended that the report focused on the financial costs of complying with the CPP while downplaying the societal benefits of climate-related policies and investments.

Those commenters advocated for a policy of halting the further expansion of the gas system in Oregon, which would entail prohibiting new gas hookups for new construction in favor of building electrification. Builders would instead be steered to heat pump technology for space heating, which would provide the added benefit of cooling in the warmer months.

Greer Ryan, Oregon clean buildings policy manager for Climate Solutions, said the organization was “extremely concerned” by the draft report.

“We’d like to see more benefits captured. When we’re talking about programs that are meant to address the climate crisis in Oregon, it’s not just about short-term costs, but we think about longer-term costs of inaction and the benefits that communities receive from these kinds of investments,” Greer said. The draft also “failed to incorporate the bulk of community groups’ feedback, and in some cases misrepresents alignment between nonprofit and community-based organizations and the utility and industry groups.”

Climate Solutions is calling for the PUC to immediately discontinue gas companies’ “line extension allowances,” ratepayer-based subsidies that permit the connection of new customers at no cost. Any subsidies should be directed to support “a clean and renewable energy economy,” especially for low-income and environmental justice communities, Greer said.

She also said the PUC’s final report should “not give credence” to gas industry arguments that the system must be expanded “to protect communities.”

“This argument is reflective of the gas industry co-opting legitimate community concerns without taking into account actual community-based organizations and ratepayer advocate feedback,” she said.

Zach Kravitz, director of rates and regulatory affairs at NW Natural, Oregon’s largest gas provider, said the company “respectfully” disagreed with “some stakeholders’ approaches, which we view as morphing this fact-finding around the CPP into a binary policy choice about the future of natural gas.”

Kravitz said NW Natural believes that it can decarbonize its system and comply with the CPP at a “reasonable cost.” The energy delivered by the company’s gas system cannot be easily replaced, he said, adding that during a cold winter morning, it delivers about twice as much energy as the electric system.

“Our modeling indicates that our compliance with the CPP carbon-reduction targets is achievable through a combination of increased energy efficiency, conservation [and] installation of low-use appliances like dual-fuel or hybrid heating systems or gas heat pumps; reduced intensity of our gas supply; and the use of community climate investments [CCIs],” Kravitz said. Under the CPP, energy providers will be allowed to offset a portion of their emissions with CCIs.

The company wants the PUC to implement a process of joint system planning among gas and electric utilities, he said.

“We can’t look at gas and electric in silos anymore. And we can really leverage each other going forward, whether it’s hydrogen, where we can utilize excess renewables and store it on the gas system, or even hybrid heating, which NW Natural is open to and wants to explore further and which can really help address resource adequacy on the power grid [by] having gas utilities meet space heating demand during those peak periods,” Kravitz said.

Lori Blattner, director of regulatory affairs for Cascade Natural Gas, voiced concern that the fact-finding is moving in an “anti-gas direction.”

“Cascade encourages the commission to instead continue to encourage innovation throughout the natural gas distribution system that will allow natural gas utilities to make carbon-reduction goals, while still providing customers all the benefits of energy diversity, including reliability and affordability,” Blattner said.

‘Unique Opportunity’

Commissioner Mark Thompson mused that PUC might be confronting two competing paradigms. In the first, the agency must fulfill its duty to protect utility customers financially as an economic regulator amid sweeping change. In the second, the commission would have to expand the notion of protecting customers to considering the most cost-effective way to decarbonize the gas system — and the energy industry — as a whole.

“How do you think we ought to balance and understand that our role in this environment?” Thompson asked Climate Solutions’ Greer.

“I think that as economic regulators being tasked with having the least-cost and reduced-risk criteria in mind, you can absolutely take into account costs and risks of inaction on climate. And there’s more and more precedent for this and other state commissions,” Greer said.

Commissioner Letha Tawney ticked off some of the lingering uncertainties that come with decarbonizing an electricity sector expected to replace gas. She named the impact of transportation electrification, the difficulty in siting new transmission, offshore wind controversy and the reliability concerns that come with fossil fuel plant retirements.

“I’m curious how you’re thinking about sort of the large-scale risks of the vision you’re putting forward,” Tawney asked Greer.

“My two cents, right now, is that this transition is not happening overnight. I think gas utilities and other fossil fuel companies try to use the tactic of spreading fear by saying, ‘If you do this transition, we won’t be able to afford it. People will be without power because we have reliability issues.’ But the fact of the matter is, it’s going to take some time to curb the gas system. We can have strategic planning conversations.”

Thompson wondered whether the PUC was facing a “Y” in the road, in which one path led to gas companies achieving decarbonization through use of renewable gas and hydrogen without having to worry about depreciation and a shrinking system — and actually investing in new assets — while the other path leads to gas companies shrinking, the elimination of the line-extension policy and a push for electrification.

“I don’t actually agree that it’s a ‘Y,’ and you’ve got a choice to either go down one path or the other,” said Bob Jenks, executive director of the Oregon Citizens’ Utility Board.

Jenks said it won’t come down to the PUC deciding which path to choose. Rather, different government agencies and hundreds of individual customers will be deciding whether they want fossil fuel coming into their homes.

“Do they want the most efficient cooling system that they can get — an electric heat pump? And with that comes efficient heat,” he said.

Mark Gamba — mayor of Milwaukie, a suburb of Portland — said “rational people” must confront the fact that the world is confronting “climate chaos.”

“Methane, greenwashed as natural gas, is one of the most powerful greenhouse gases in the world; it’s 86 times more powerful than CO₂,” Gamba said, adding that burning natural gas inside a home also impacts human health.

“You have a unique opportunity to start to make actual changes so that … when it becomes abundantly clear to everyone that we need to be moving away from methane, it’s not a sudden and catastrophic switch,” he said.

July 19, 2022November 15, 2023

Gen2 Formula E Race Cars Hit the Streets in NYC E-Prix; Crash Shakes up Race

NEW YORK — The ABB FIA Formula E World Championship’s New York City E-Prix returned to Brooklyn on Saturday with a race that started in sunshine and ended abruptly with a rainout and a dramatic multicar crash.

Twenty-two of the championship’s second-generation (Gen2) open-wheeled, single seater electric cars took to the track in the lead up to the Season 8 finale in Seoul, South Korea, in August. The Gen2 cars will retire officially after this season’s championship, and the next generation (Gen3) will debut for the 2023 season.

The Formula E race cars are not as loud as their fossil-fueled counterparts, but they still quicken the pulse up close with a high-pitch whine and top speeds of 200 mph. The 45-minute race Saturday came to a halt with seven minutes remaining when the cars entered a sudden downpour, which caused the two lead cars to hydroplane in quick succession into a wall followed by the fourth-place car.

The crash led to a red flag, stopping the race. While drivers were on standby, officials determined that the race would not continue because of safety concerns and called the winners based on the drivers’ standing in the lap prior to the red flag. Nick Cassidy (No. 37) of Envision Racing, the winner of the race, and second-place winner Lucas di Grassi (No. 11) of ROKiT Venturi Racing, had crashed, while third-place winner Robin Frijns (#4) of Envision survived the slick conditions without incident and took over the lead.

Nick Cassidy of Envision Racing (center), winner of the NYC E-Prix Round 11, sitting after the race with second place winner Lucas Di Grassi of ROKiT Venturi Racing (left) and third place winner Robin Frijns of Envision Racing. | © RTO Insider LLC

None of the drivers was hurt.

“We had a really nice fight,” Cassidy said at a press conference after the race. “It got slippery; it got fun; and then ultimately, it was a bit too much.”

Di Grassi expressed gratitude for the cars’ safety features.

“This was the biggest crash of my Formula career,” he said. “I’m without any problems, but the car is pretty much destroyed, and that shows how safe these cars are.”

Di Grassi was going about 62 mph when it crashed, he said.

Frijns said visibility was low coming up on the crash site, but he managed to break early enough to make the turn that the lead cars in front of him had missed.

“When the rain came, I saw Lucas in a 90-degree angle in front of me, which is never good,” Frijns said. He added that although he had thought he won the race, he believed the final ruling was “a good one.”

Gen3

The International Automobile Federation (FIA) and Formula E introduced the Gen3 car in April, calling it the “pinnacle of high performance, efficiency and sustainability.”

Seven auto manufacturers have agreed to race under the Gen3 standards next year. They include DS Automobiles, Jaguar, Mahindra Racing, Maserati, NIO 333 Racing, Nissan and Porsche.

The new standards call for a top speed of about 200 mph, which will push the vehicles closer to the traditional Formula One car’s top speed of about 230 mph. On the charging front, the cars will produce about 40% of the energy used in a race through regenerative braking. And it will have ultra-high speed charging capability of 600 kW, or almost double most current commercial chargers, according to FIA.

Among the updated sustainability standards for Gen3 will be the first ever use of linen along with recycled carbon fiber from the Gen2 cars for the new car bodies. FIA said the recycled materials will reduce the carbon footprint of the Gen3 body construction by 10%.

Tires for the new season will include 26% natural rubber and recycled fibers, and all tires will be recycled after use.

In designing the Gen3 car, FIA tracked all the carbon-reduction measures that will reduce the cars’ impact, while carbon offsets will address all remaining emissions.

July 19, 2022November 30, 2023

SPP Markets and Operations Policy Committee Briefs: July 11-12, 2022

RCAR III Shows Dramatic Improvements in all Tx Zones

WESTMINSTER, Colo. — SPP’s third Regional Cost Allocation Review (RCAR) of the regional and zonal allocation methodology’s reasonableness left several members dinged by the first two reports in a cautious, yet celebratory mood during last week’s Markets and Operations Policy Committee meeting.

“We’re not popping the champagne yet,” said Jeff Knottek, director of system planning and compliance for City Utilities of Springfield (Mo.). He was among several members who have requested meetings with the RTO’s staff to better understand how the new numbers were derived.

CUS was the only utility below a benefit-to-cost ratio threshold of 0.80 in its transmission zone after the first RCAR in 2012. It was joined by five other utilities who failed to meet the 40-year present values of the estimated benefit metrics and costs in 2016’s RCAR II.

However, the preliminary RCAR III review pegged CUS’ ratio at 10.65, third among all pricing zones.

“It feels pretty good to be a winner,” said Empire District Electric’s Aaron Doll, whose zone went from a 0.60 to a 6.04 in the last two RCARs. “Empire would be interested in meeting with SPP staff to understand how our B/C ratio increased tenfold with little to no investment. … We’re a little bit skeptical the increase was so substantial without the investments commensurate with that.”

SPP General Counsel Paul Suskie said the Regional Allocation Review Task Force, comprising SPP regulators and members, took a hybrid approach to RCAR III. Staff used actual market runs with and without highway/byway transmission and took a planning-based approach for approved upgrades not in service for at least two years.

The review’s preliminary operational results show significant B/C results for the region and all pricing zones. Staff used 538 of 741 highway/byway upgrades, totaling $4.6 billion of $6.4 billion in upgrade costs. They said it is unlikely any remedies will be needed.

Suskie said the real-life models were a contrast to the first two RCARs, which were more “theoretical, what we thought the system would look like.” That resulted in lower B/C ratios for CUS, Empire and others.

“For instance, we said in 2020 [that] we would have 17 GW of wind in 2022. Today, we have 31 GW,” Suskie said. He pointed out that the recent run-up in natural gas prices also created higher ratios.

MOPC endorsed the RARTF’s recommendation to direct staff to finalize the report based solely on operational results. When the report is brought back to the committee in October, members can then determine if the full planning process is needed to supplement the operational result.

MOPC Keeps SPS’ Tx Alternatives Alive

Committee members endorsed two projects as potential solutions for a 345-kV double-circuit transmission line in eastern New Mexico’s Permian Basin region.

They sided with staff’s recommendation to issue a notification to construct following further evaluation of Southwestern Public Service’s proposed Crossroads-Phantom project, a 150-mile line estimated to cost $410 million.

MOPC also endorsed a NextEra Energy Resources’ motion that Crossroads-Phantom would be a viable alternative to another proposed project line in the same region, the 143-mile, 345-kV double-circuit Crossroads-Hobbs-Roadrunner line. The $395 million project was approved as an alternative by both the Transmission and Economic Studies working groups over its operational flexibility and lower cost to SPS.

Comparisons between the Crossroads-Phantom and Crossroads-Hobbs-Roadrunner projects. | SPP

The votes served as a compromise following a discussion over whether to vote on the two different projects separately or together, and whether to even conduct the vote. That left some members frustrated enough to suggest MOPC should just tell the Board of Directors to decide for it.

“We’re abdicating our responsibility,” Midwest Energy’s Bill Dowling said.

The original proposal received 80% support, while NextEra’s suggestion barely cleared the 67% threshold.

“At the end of the day, NextEra and other want to see steel in the ground,” NextEra’s Matt Pawlowski said.

Jarred Cooley, SPS’ director of strategic planning, called in to the meeting to throw his company’s support behind the Crossroads-Roadrunner option. He said adding a substation at Hobbs gives direct access to reactive reserves for the load pocket and offers voltage support on the pocket’s north and south sides.

“Apples to apples, it has slightly better economics; it’s a slightly cheaper line; and routing the line through the Hobbs substation breaks up an extremely long, 150 mile transmission line that would span pretty much the entire New Mexico territory,” he said. “This will help our area operationally grow as the system continues to grow in that area.”

The Crossroads-Phantom project was originally part of the 2021 Integrated Transmission Planning (ITP) report that was approved in January. However, MOPC pulled the project out of the portfolio when two stakeholder groups said load-projection errors had been discovered late in the planning process. (See SPP Markets and Operations Policy Committee Briefs: Jan. 10-11, 2022.)

Questions to Engineers Require Care

Golden Spread Electric Cooperative’s Natasha Henderson learned the hard way not to ask a group of engineers a question with a literal answer.

Fresh off a Hawaiian vacation that was sandwiched between SPP meetings and focused on the three presentations she was about to deliver to MOPC, Henderson entered the meeting room looking for her seat. She walked up to a group of fellow stakeholders and jokingly asked where she was.

The group was more than happy to help.

“You’re right here!” responded one. “You’re with us!” another said.

Henderson eventually found her seat on her own.

NRDC Becomes SPP’s 113th Member

MOPC welcomed to the table Natural Resources Defense Council’s Christy Walsh, director of federal energy markets, who represented the organization as it became SPP’s 113th member. The RTO eliminated its exit fee for non-transmission owners several years ago, opening the door to environmental groups and other nonprofit organizations. (See FERC Tells SPP to End Exit Fee for Non-TOs.)

Walsh, a FERC staffer for almost 20 years, is only serving until the environmental advocacy group can hire a fulltime staffer to represent it before RTOs.

Changes for Tx Evaluations

MOPC endorsed a revision request (RR452) from the Transmission Working Group that adds a standardized process for evaluating projects proposed by TOs for reasons other than meeting SPP regional criteria or meeting a limited subset of local planning criteria evaluated in the ITP.

The change will allow TOs to perform their own analysis and provide it to staff for review. If SPP performs the studies, TOs must sign an agreement, pay a deposit and cover all study costs.

The more “robust” process also includes the implementation of zonal planning criteria recently approved by FERC. The revision establishes an annual process for each transmission pricing zone to develop a single set of uniform zonal criteria to evaluate zonal reliability upgrades in regional planning. (See FERC Accepts SPP’s 2nd Try at Zonal Planning Criteria.)

Members also unanimously approved a consent agenda included three RRs:

- - RR484: includes surety bonds as a form of “financial security” within the tariff to secure all types of financial transactions, including transmission congestion rights and virtual energy. Surety bonds can provide a lower cost entry point for creditworthy customers as compared to a letter of credit.
  - RR489: identifies business practice and ITP manual changes to ensure that transmission service and ITP base reliability models’ dispatch are accounting for the granted amount of interconnection service or surplus interconnection service to multiple resources behind the same point of interconnection. The RR also identifies an ITP base reliability dispatch approach for batteries that have been granted transmission service for charging purposes.
  - RR496: adds minor and non-substantive missing language, primarily modifying settlements, that are necessary to accurately implement RR449.

The committee also approved four sponsored upgrade studies. SPP reliability assessments found no system impacts on:

- - NextEra Energy Resources’ upgrade of terminal equipment on two 161-kV lines near Warrensburg, Mo.;
  - Invenergy’s proposal to build a 345-kV line between two substations in West Texas;
  - Invenergy’s upgrade of two 345/230-kV transformers in South Dakota to a 581-MVA rating; and
  - Oklahoma Gas & Electric’s reconductoring of a transmission line to increase their normal and emergency ratings of the lines while replacing aging assets.