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.
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.
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.
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.
“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.
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.
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.
