AUSTIN, Texas — ERCOT has wasted no time in putting its new emergency communications system to use, issuing its first weather watch Tuesday ahead of triple-digit temperatures that are expected to smash existing demand records.
The watch, an early public notification of a weather forecast that signals high demand, begins Thursday and extends through June 21. The ISO says grid conditions are normal, but the weather conditions and expected demand will mean lower operating reserves.
The National Weather Service is forecasting triple-digit temperatures across much of the state during the waning days of spring, with highs of 103 F in Austin. Humid conditions Wednesday pushed the heat index to 112 F in Corpus Christi and 115 F in Brownsville.
ERCOT’s new six-day forecast projects demand will reach 81.3 GW on Friday and then hit 83.2 GW on June 20. Both marks would break the record of 80.14 GW set last July. The ISO set 11 peak records last year as it exceeded pre-summer expectations by more than 2.6 GW.
“Ah, it’s the summer crisis season,” cracked one attendee at the Edison Electric Institute’s annual meeting in Austin.
ERCOT expects to have about 90 GW of available seasonal capacity during much of the weather watch. Solar capacity has nearly doubled from last year, from 8.66 GW to 16.85 GW. Energy storage capacity has also grown since last summer, from 1.29 GW to 3.29 GW.
CEO Pablo Vegas said staff will closely monitor conditions and “deploy all available tools to manage the grid.”
The weather watch is part of a new communications strategy resulting from reliability concerns following the 2021 winter storm. (See “New Grid Notifications Added,” ERCOT Monitor Recommends New Market Design in Report.)
Meteorologists are predicting an El Niño climate pattern this year. El Niños are marked by warming surface water temperatures in the Pacific Ocean that tend to raise temperatures. They often also bring more rain to the southern U.S.
New Ancillary Service Product
The Texas grid operator last week added a new daily procured ancillary service to its suite of products for the first time in 20 years — the ERCOT contingency reserve service (ECRS).
ERCOT said it has procured an average of 2,073 MW of ECRS per hour at an average price of $25.26 MWh since June 10. It says the product is necessary because load and generation are constantly changing due to daily load patterns, instantaneous load variation, changes in intermittent generation output, and generators tripping offline.
ECRS offers capacity that can be sustained at a specified level for two consecutive hours. It will be deployed to restore frequency within 10 minutes of a significant deviation; to compensate for intra-hour net load forecast uncertainty when large amounts of online thermal ramping capability are not available; or when limited capacity is available for dispatch.
“As summer temperatures begin to rise across Texas and with high demand forecasted, we will continue to use all operational tools available, including implementation of new programs like ECRS,” Vegas said in a statement.
BOLTON LANDING, N.Y. — NYISO stakeholders will vote July 26 on whether a new study should be conducted to evaluate the cost allocation between transmission withdrawals and injections.
ISO officials previewed the vote on the Rate Schedule 1 cost-of-service study Tuesday at a joint Board of Directors and Management Committee meeting.
Rate Schedule 1 governs the charges made to market participants using NYISO’s open access transmission system and helps ensure that all participants are charged fairly for their services.
RS1 allocations were last changed in 2011 and are currently set at 72% for withdrawals and 28% for injections. Roughly 67% of the MC at the time supported the allocations, which were scheduled to be effective for a minimum of five years, with a Management Committee vote required in the third quarter of this year.
But the ISO told stakeholders Tuesday: “In recent years, discussions with market participants have indicated that a study is necessary in the future due to evolving market changes.”
The most recent RS1 allocation study, performed by Black and Veatch in 2011, cost about $215,000 and took six months to complete. The study included analysis of ISO data, staff interviews, and comparison of practices of other grid operators.
The ISO has steadily increased the allocation for injections since 1999, when withdrawals were allocated 100% of costs.
Should the MC vote to conduct a new study, NYISO anticipates new RS1 allocations would be effective by 2025.
Solicitation for MMU Evaluations
NYISO has opened its annual solicitation of stakeholder feedback on its market monitoring unit, Potomac Economics.
NYISO is asking for comments on the MMU’s performance, suggestions on how the MMU’s duties should change or improve, and opinions whether the ISO should search for a new MMU.
The ISO has worked with Potomac for more than a decade, and some attendees had questions about this ongoing relationship.
One attendee expressed concerns about the ISO’s reliance on Potomac’s proprietary software, asking if there could be issues should either the ISO decide to work with another MMU or the data gets compromised.
Shaun Johnson, director of market mitigation and analysis at NYISO, responded that Potomac has made significant upgrades to their cybersecurity and information technology systems and has an off-site datacenter that backs up their data to give them redundancy capabilities. Should the ISO hire another MMU, any transition would include considerations about how Potomac’s NYISO data would be shared and used, he said.
The same attendee asked whether NYISO’s relationship with the MMU has changed over the years, saying there is a perception that the ISO does not listen to Potomac’s recommendations as much as before.
“We have meetings and conversations with the MMU every day,” Johnson said. “So what you see at stakeholder meetings are maybe just the end results or beginning of those conversations.
“Just like within NYISO and within the stakeholder community, sometimes we agree with each other, sometimes we disagree with each other, but it’s really about collaborating to come up with the best results,” Johnson said.
NYISO requested that comments be sent to either sjohn@nyiso.com or deckels@nyiso.com by July 31. Submitted feedback will be confidential.
FERC Update
FERC staff updated the MC about what the agency has been doing for the past year and what plans NYISO should be aware of.
FERC energy industry analyst Emily Chen said FERC is reviewing NYISO’s third Order 2222 compliance filing to determine whether more revisions are needed (ER21-2460). (See “FERC Compliance Filings,” NYISO Business Issues Committee Briefs: May 24, 2023.)
Leanne Khammal, deputy director of FERC’s Division of Electric Power – East, said the agency continues to work on improving interconnection queue backlogs via Notices of Proposed Rulemaking (RM22-14), develop more effective winter emergency and reliability plans with Northeastern RTOs, and host technical conferences that seek to improve transmission planning processes, such as the upcoming PJM Capacity Market Forum.
Staff also told the MC that FERC is searching for a new NYISO liaison, since the position’s previous holder recently retired. Staff said they are looking at ways to improve the role via stakeholder feedback.
FERC’s two Republican commissioners told members of Congress on Tuesday that the U.S. is heading toward a reliability crisis driven by the rapid retirements of dispatchable fossil fuel-fired generators.
Appearing before the House Energy and Commerce Subcommittee on Energy, Climate and Grid Security, each of the four sitting commissioners painted a different picture of the state of grid reliability in the country. While they gave different critiques of the resource mix, Commissioners James Danly and Mark Christie had ominous outlooks, harshly criticizing FERC-approved market designs in the RTOs and ISOs.
“The United States is heading towards a reliability crisis in our electric markets,” Danly said. He cited two primary factors: “the effect of subsidies” for intermittent renewable resources, “and the commission’s, let’s call it, ‘abandonment’ of its longstanding commitment to the rule of law.”
“I think we’re headed toward potentially very dire, potentially catastrophic consequences in the United States,” Christie said. “The basic reason is we’re facing a shortfall of power supply. … The problem is not the addition of wind and solar. The problem is the subtraction of coal and gas and other dispatchable resources.”
Republican members of the subcommittee agreed, though they were eager to blame the Biden administration, particularly EPA’s newest proposal to reduce power plant emissions, for the impending doom.
“The commission must do more to resist such regulations that run contrary to its core mission,” proclaimed subcommittee Chair Jeff Duncan (R-S.C.). “Electric reliability has significantly degraded over the past few years. Blackouts and energy rationing are now commonplace in wholesale electricity markets like California and Texas. The nation’s largest grid operator, the PJM Interconnection, issued a dire warning earlier this year that it may face significant capacity shortfalls because of, in large part, rules like the EPA has proposed.”
“It’s essential the commission return to its core mission of facilitating the delivery of abundant, affordable energy resources, like natural gas and electricity, to Americans,” said Cathy McMorris Rodgers (R-Wash.), chair of the full committee. “FERC must resist calls by the radical left to circumvent the commission’s mandated priorities.”
Acting FERC Chair Willie Phillips (D) sought to assure the subcommittee that “reliability is, and always must be, job No. 1.” He listed several actions the commission has taken related to reliability and grid resilience since he took the helm at the beginning of the year, including directing NERC to develop new cybersecurity standards.
Phillips also said his highest priority “in the near term is to finalize a proposed rule that will greatly improve our processes for interconnecting new electric generating resources, reducing the time it takes to bring those resources online.”
Neither side of the aisle of the subcommittee gave that statement much attention. For their part, Democrats used much of their time to question how, if at all, FERC accounts for environmental justice when approving natural gas infrastructure.
Ranking member Diana DeGette (D-Colo.) did ask Phillips whether the recently enacted Fiscal Responsibility Act, which ordered NERC to study interregional transfer capability, would delay FERC’s work on the issue. (See Debt Ceiling Bill Provides ‘Mini-deal’ on Permitting.)
“NERC is directed to do a study under the debt limit deal; we also have an ongoing proceeding at FERC,” Phillips responded. “It is my belief that those two proceedings can move forward in parallel. … It is not my intention to wait” for NERC to complete the study.
In what’s being called “breakthrough growth,” more than 3,500 zero-emission medium- and heavy-duty trucks were deployed in the U.S. in 2022, more vehicles than in the previous five years combined, according to a new report.
The 3,510 vehicles added in 2022 bring to 5,483 the number of zero-emission trucks (ZETs) purchased and placed into service in the U.S. from January 2017 through the end of 2022. The figures are in a report released by CALSTART, a national nonprofit focused on clean transportation technologies.
Zero-emission trucks are also becoming more widespread. Since mid-2022, seven states — Arkansas, Delaware, Montana, Nebraska, Oklahoma, Rhode Island and Wyoming — have seen their first ZET deployments, the report said.
The zero-emission vehicles tallied in the report include Class 2b to 8 trucks, classifications that are based on weight. The trucks range from larger pickups, cargo vans, and step vans to semis, garbage trucks, and on-road yard tractors.
The trucks include battery-electric and hydrogen fuel cell vehicles. Hybrids aren’t counted.
The 5,483 deployed ZETs are only a minute fraction of the 26.7 million trucks registered in the U.S. in 2022. But continued strong growth in ZET deployment is expected.
“This growth rate is expected to continue its aggressive upward trend as more OEMs enter the market, established OEMs expand their offerings, and fleets become more comfortable with the technology,” CALSTART said in its report.
As of December, more than 136 medium- and heavy-duty ZET models from more than 41 manufacturers were available for purchase.
Shifting Trends
As recently as March 2022, on-road yard tractors were the most-deployed type of zero-emission truck, according to a previous CALSTART report. Vehicles with low range requirements, such as yard tractors, were dominating ZET deployments, the previous report said. (See With Calif. in Lead, Clean Truck Sales Accelerate Nationwide.)
But now, smaller ZETs have taken the lead.
Cargo vans accounted for 2,565 deployments, or almost half of ZETs placed into service from 2017 through 2022. The price of the zero-emission vans compares favorably to that of their gas-fueled counterparts, the report said, and models such as Ford’s E-Transit van and BrightDrop’s Zevo 600 have become popular.
“This market is expected to grow quickly, thanks in part to the new federal Commercial Clean Vehicle Credit, which provides up to $7,500 in tax credits to mitigate the incremental cost,” the report said.
The second-most deployed ZET in the report was yard tractors, with 912 vehicles placed into service.
But pickup trucks scooted into third place, accounting for 831 of ZETs deployed. Zero-emission pickup trucks in the Class 2b weight category became available last year, the report noted.
Deployments by State
Among the 5,483 ZETs placed into service since 2017, CALSTART was able to identify locations for 3,107 of the vehicles.
Among those ZETs, California led the way, with 1,472 deployments. New York followed with 186 ZETs, while Florida and Texas had 137 and 131 deployments, respectively.
Fifty-nine percent of ZET deployments were in states that had adopted California’s Advanced Clean Trucks rule. As of December 2022, those include California, Oregon, Washington, Massachusetts, New York, New Jersey and Vermont. Advanced Clean Trucks requires manufacturers of medium- and heavy-duty trucks to sell an increasing percentage of zero-emission vehicles each year.
California is also home to the Hybrid and Zero-Emission Truck and Bus Voucher Incentive Project (HVIP) for medium- and heavy-duty trucks. From 2011 to 2022, HVIP issued vouchers for 3,149 ZETs totaling $315 million, or roughly $100,000 per vehicle on average, according to CALSTART, which administers HVIP on behalf of the California Air Resources Board (CARB).
California ZET deployment may also get a boost from the Advanced Clean Fleets regulation that CARB adopted in April. (See CARB Adopts Clean Fleets Rule Despite Broad Skepticism.) The regulation requires truck fleet operators to start transitioning to zero-emission vehicles starting in January 2024, and all new medium- and heavy-duty trucks sold in the state must be zero-emission beginning in 2036.
The Biden administration’s goal to achieve net zero emissions from transportation by 2050 will require an increase in the generation and delivery of an additional 1,800 terawatt-hours per year, estimates the Electric Power Research Institute.
Watson Collins, an engineer and senior technical executive at EPRI, offered the estimate Tuesday during a webinar organized by the North American Council for Freight Efficiency, a trucking industry initiative sponsored in cooperation with the Rocky Mountain Institute, an environmental organization.
“The grid today [carries] about 4,000 terawatt-hours,” Collins said, estimating the additional power needed to electrify transportation as roughly “about a 50% increase in throughput on the grid.”
“This is going to take 20 years,” he said, adding he’s not concerned since utilities made a similar increase in the past few decades to electrify heating, air conditioning and myriad other electrical functions.
In the meantime, Collins said trucking companies considering the cost of running electric trucks instead of diesels must keep in mind that “the slower you charge is better, [and] is cheaper. The infrastructure is less expensive. And it’s better for the batteries.”
When an EV is charged is just as much a price determining factor as how much power the charge uses. | Electric Power Research Institute
The faster a trucking company must charge its vehicles, the less likely those rigs will be cheaper to operate than traditional diesel vehicles, he explained, at least at today’s fuel and power prices. Slower charging during the night or off-peak hours during the day also will make the electric truck more cost-competitive compared to diesel, he added.
“There’s a huge savings potential if you’re charging the vehicles in the off-peak period. That’s part of why I’m mentioning that off-peak is usually the slow-charging, longer-duration charges, because you can save a lot of money.” Local utility infrastructure also is significant, he said.
An EPRI survey of utilities found that 60% would not have to immediately build costly and time-consuming upgrades to accommodate trucking company depots increasing their demand by no more than 1 MW.
By contrast, 60% of the utilities surveyed said they would need to build upgrades to handle a load increase of 20 MW, he said.
Robert Graff, a senior technical adviser at RMI and adviser to NACFE, said most commercial electric vehicles in use today are limited to 350 kW, “with many operations getting by with 50 kilowatts or less.”
“Charging at this level meets the needs of many fleets, particularly single-shift return-to-base operations.
“As the use of commercial battery electric vehicle expands … there will be use cases that will benefit from higher-power charging, such as adding hundreds of miles of range to heavy-duty trucking during around-the-clock operations,” he added.
Ted Bohn, an engineer with Argonne National Laboratory, said work now is concentrated on standardizing components and voltages. He said the lab has been experimenting with 350-kW units “tied in parallel to come up with 3,000 amps … at 1,000 volts and 300 amps.” That combination figures to 3 MW, he said.
By comparison, most home 240-volt EV chargers draw no more than 7,200 watts — less than 10 kW — according to the Department of Energy.
Emil Youssefzadeh, an engineer and chairman of WattEV, a California firm that leases Class 8 trucks and builds the charging stations to electrify them, said what his company has encountered is “a level of slowness” from utilities building upgrades to supply the company’s growing demand from the expansion of charging depots.
WattEV rents drayage trucks to companies working at the Port of Los Angeles, where diesel exhaust emissions had become a major problem.
But relying solely on a local utility for power may not always be necessary, Youssefzadeh said. “Is there a solution other than grid power? The answer is that we’re looking at different alternatives, putting in microgrids, solar with distributed energy resources, [to offer] higher capabilities, to go to 20 megawatts,” he said.
Ryan Menze, an engineer managing charging hardware and software engineering at Daimler Trucks North America, said the company has analyzed the situation in a process similar to balancing a series of mathematical equations.
“If any of these three things — technology, cost parity or infrastructure — is zero, we will not be successful as an industry. We will not be successful as an organization in pushing zero-emission technologies,” he said.
The company’s Freightliner division has designed a series of heavy-duty trucks marketed under the eCascadia model.
“From a technology perspective, on the vehicle side [of the equation], we need to ensure that we have the charging capabilities and can meet the range demands of our customers,” Menze said.
“One of the big technology analogies I like to use is [that] it’s kind of a balance. We need to have the right amount of charge speed which enables enough range and the time that our customers have using their 30-minute required breaks that they have to take every day and opportunity charging, when possible, but also having the necessary range on a single charge in order to complete their missions throughout the day,” he said.
The webinar was one of a series planned by NACFE and RMI in preparation for a three-week event in September designed to measure and record the charging, resilience and local distribution grid capacity at eight trucking depots operating fleets of at least 15 electric trucks. Seven of the depots are in California; the eighth is in Queens, N.Y.
Maryland Gov. Wes Moore (D) submitted his third nomination for the state’s Public Service Commission on Wednesday, naming energy attorney Bonnie Suchman to take the seat currently held by Commissioner Odogwu Obi Linton.
Suchman will join incoming Chair Fred Hoover, an attorney in the Office of People’s Counsel, and Commissioner Kumar Barve, a long-time state delegate from Montgomery County. Hoover will begin his term July 1, following the expiration of current Chair Jason Stanek’s term.
Barve replaced Commissioner Patrice Bubar, attending his first commission meeting on June 7, according to Tori Leonard, PSC communications director. Exactly when Suchman will attend her first commission meeting is uncertain, Leonard said. She will need to be sworn in at a state district court at a time of her choosing.
Suchman’s resume includes stints as special counsel for electric utility restructuring at the U.S. Department of Energy during the Clinton administration and as a senior attorney focusing on transmission issues for the Edison Electric Institute. She also led the energy practice at Troutman Pepper, where she worked on both state and federal energy policy issues. She has continued working on energy issues with her own practice, Suchman LLC.
Barve was first elected to the Maryland House of Delegates in 1991. Before Moore tapped him for the PSC, he had been chair of the House Environment and Transportation Committee since 2015. He was also majority leader in the House from 2003 to 2014.
He is also the CFO for EMSI, a small environmental services company located in Rockville.
Bubar, Linton and Stanek were appointed to the PSC by former Gov. Larry Hogan (R), but Bubar and Linton were not confirmed by the Senate. Moore rescinded their nominations after taking office.
Hoover, Barve and Suchman will also have to be confirmed by the General Assembly when it is back in session in January 2024. They join Commissioners Michael T. Richard and Anthony O’Donnell, both reappointed by Hogan for second terms in 2020 and 2021, respectively.
Kim Coble, executive director of the Maryland League of Conservation Voters, applauded Suchman’s appointment and “the Moore administration for putting forward somebody that has extensive experience in utilities and electricity.”
“The thing that I think is important here is to understand in Maryland … the PSC plays a really significant role, and a unique role in advancing the … electricity agenda,” Coble said. “The Moore administration has made their commitment to climate change very clear … and so to have somebody with [Suchman’s] background helping to advance [this] agenda, I think it’d be a strong asset to the state.”
Moore ran afoul of Coble and other energy advocates earlier this year when he nominated Juan Alvarado, senior director of energy analysis for the American Gas Association, to the commission. As opposition mounted, Alvarado withdrew his nomination. (See Alvarado Withdraws from Md. PSC Nomination.)
As more clean energy comes online and extreme weather accelerates, states need to work together to unlock the reliability benefits of increased interregional transmission, said a panel of experts convened by the American Council on Renewable Energy to discuss NERC’s Summer Reliability Assessment.
The assessment found that while all regions have adequate supply to cover peak load under normal conditions, most regions face elevated risk of shortfall during extreme weather conditions. NERC said this elevated risk is due largely to retirements of fossil fuel generators and above-average projected summer temperatures across most of North America, consistent with long-term climate trends. (See NERC Warns of Summer Reliability Risks Across North America.)
“My review of the NERC summer assessment is there’s nothing particularly surprising,” said Commissioner Andrew French of the Kansas Corporation Commission. “I think it continues to highlight trends and concerns that we’ve seen crop up over the last several years. I definitely don’t view it as a specific indication that anything will happen, or anything won’t happen.”
French said the loss of dispatchable fossil fuel generators has reduced the state’s safety cushion of excess generating capacity, which is driving reliability risks. He said that in the short term, policymakers should focus on retaining resources that provide reliability benefits, while focusing in the long term on the reliability attributes of expanding demand response programs and interregional transmission.
To put a better value on the reliability benefits of transmission investments, French said planning processes should incorporate a calculation related to the value of lost load, along with potentially valuing “large-scale interregional transmission as a generating capacity resource.”
Simon Mahan, executive director of the Southern Renewable Energy Association, said the summer outlook looks manageable for the Southeast but cautioned against settling into a false sense of security. “There are extreme weather events that could come in and radically change your plans quickly. When that happens, it’s important that we have the regional and the interregional transmission capability available to us so that we can import power if we need it, or we can export power to our neighbors if they need it.”
Danielle Mills, principal of infrastructure policy development at CAISO, said California is in a better position than last year because of improved hydro conditions and the addition of 3,000 MW of battery storage in the state.
“We still do see some risk associated with those periods after 8 p.m. when the solar generation is declining if we have high loads and a lack of availability of imports” Mills said.
Mills said the state is “looking at opportunities to improve transmission planning across the West and look at interregional transmission planning projects, as well as projects that can provide power to California from out of state.”
Nicole Hughes, executive director of Renewable Northwest, said nothing in the report was too concerning, but instead “more of an indication of risk to come.”
Hughes agreed with the assessment that expanding the grid will be essential to mitigating reliability risks in the future. She said the inadequate transmission infrastructure has made it difficult to bring renewable energy generation online to meet the region’s clean energy goals.
With CAISO being the only ISO on the West Coast, Hughes touted the benefits of a potential Northwest RTO.
“Pretty much it’s across-the-board accepted in our region that we need … more of an RTO that can bring us all together and limit the number of balancing areas, and I think the Western Resource Adequacy Program is going to be a good test model for that,” Hughes said.
Led by the Western Power Pool and approved by FERC this year, the Western Resource Adequacy Program will coordinate resource adequacy efforts across 10 Western states and British Columbia. (See FERC Approves Western Resource Adequacy Program.)
Mahan also highlighted potential benefits of an RTO for the Southeast to limit the number of balancing areas and improve reliability. He noted that a Brattle Group report released this year for South Carolina found that the state would generate about $300 million in net benefits by integrating with PJM.
Warren Lasher, former senior director of system planning at ERCOT, said that growing electricity demand poses a significant challenge for Texas. He added that increasing frequency of extreme weather events can make it difficult to project reliability based on historical data.
Hughes said the impacts of climate change on both wildfire risks and the capability of hydroelectric resources in the Northwest will be difficult but essential factors to model in the future.
“We rely significantly on the hydropower system, and there’s a lot of questions about what that’s going to look like going forward,” Hughes said. “What is average seems to be changing, and that’s why diversity of resources across a larger grid is so important.”
Public financial support for New Jersey’s offshore wind projects has come under scrutiny from lawmakers as Danish developer Ørsted seeks to obtain access to federal tax credits to help offset rising supply chain and materials costs on its Ocean Wind 1 project.
A think-tank report published June 5 on the state’s rapidly growing OSW sector said the developer has been “locked in negotiations for months” with state officials in an effort to use federal offshore wind tax credits created under the 2020 Stimulus Act and the Inflation Reduction Act (IRA).
“Ørsted’s argument is that material, labor and borrowing costs have soared in the runaway global inflation that followed the COVID-19 pandemic,” pushing up costs to higher levels than when the developer bid on the project, according to the report, which was compiled by the Sweeney Center for Public Policy at Rowan University.
New Jersey law, however, requires tax benefits from offshore wind projects to be returned to ratepayers. That contrasts with other states, among them New York, which allows developers to use the federal tax credits, the report says. It added that the administration of Gov. Phil Murphy and legislators “have been in discussions on a bill to authorize Ørsted to retain the full federal tax credits.”
The New Jersey Board of Public Utilities approved the 1.1 GW Ocean Wind in 2019, in the state’s first solicitation, and in 2021 approved the 1.148 GW Ocean Wind 2, also an Ørsted project, and the 1.51 GW Atlantic Shores. The state in March launched a third solicitation.
Stephanie Francoeur, a spokeswoman for Ørsted, said it and other developers are in discussions with the state and the BPU “to address the macroeconomic challenges facing early stage offshore wind projects, including opportunities made available by federal tax incentives.”
“We continue to assess existing federal tax credits to support our local investments, create jobs,” she said. “We remain committed to Ocean Wind 1 and look forward to continuing our conversations with New Jersey policymakers to help address these unforeseen challenges.”
Atlantic Shores, the developer of the project of the same name, declined to comment.
The prospect of an increase in assistance to offshore wind developers, however, stoked bipartisan resistance at a May 23 hearing of New Jersey’s Senate Budget and Appropriations Committee. Two committee members expressed concern that the state would provide additional financial assistance to developers under pressure from inflation and rising costs, and pressed Joseph L. Fiordaliso, the BPU president, on the agency’s plans.
Sen. Paul Sarlo (D), the committee’s chairman, said it “has been hearing some rumors that there is going to be a request from this body to subsidize the wind projects that are currently under construction,” and asked if that was true. When Fiordaliso responded, “Not that I am aware of,” Sarlo made clear his antipathy to giving extra help to offshore wind developers.
“I’m probably one of the most pro-business, pro-development legislators,” Sarlo said. “I’m going to have a very difficult time supporting any type of future subsidies.”
“These are large players, international players who knew what they were getting into when they built these facilities,” he said. “They’re going to have to step up their game. We don’t bail out every developer in the state of New Jersey who gets himself into a new adventure, a new endeavor.”
Rising Headwinds
The flap was one of several recent gusts of headwind against the offshore wind sector. Last week, the BPU postponed an item from its agenda that would modify the scope — seemingly due to cost increases — of the state’s $1.1 billion offshore transmission project to tie offshore wind projects to the grid. The agency also put back by five weeks the deadline for the state’s third offshore wind solicitation, to Aug. 4, to give developers more time to put together their submissions. (See NJ BPU Pulls Offshore Tx Project Mod from Agenda After Complaint.)
In addition, the county of Cape May, through which a cable for Ocean Wind 1 will pass, on May 26 passed a resolution opposing the Ørsted projects and has filed an appeal against a BPU decision to grant an easement across county land for the cable. The sector also has faced a steady drumbeat of concern over the death of several whales on the Jersey Shore that project opponents say might be due to preliminary work on the wind projects, despite state and federal officials saying they’ve found nothing linking the deaths to the projects, which have yet to start construction.
Fiordaliso, at the BPU’s meeting last Wednesday, expressed frustration at the offshore developers, although it was unclear what triggered the outburst.
“We have had, almost since Day 1, delay after delay after delay,” he said. “All one developer in particular has done is delay this process for one reason or another.”
He did not identify the developer, although Ørsted is the only one involved since Day 1.
Asked about Fiordaliso’s comments, Madeline Urbish, Ørsted’s head of government affairs in New Jersey, said they were “unexpected,” and added that the company is committed to completing Ocean Wind 1.
She said the developer is working closely with the BPU, the New Jersey Department of Environmental Protection and federal agencies, “despite early delays in federal permitting” and cited the “unprecedented macroeconomic challenges [that] have led to significant cost increases for capital-intensive industries across New Jersey and the U.S., including the offshore wind energy industry.”
“The available federal programs, including the Inflation Reduction Act, present an opportunity to address inflationary costs without increasing costs for ratepayers,” she said in an email to NetZero Insider, but added that they won’t “entirely cover the increased costs the project has faced due to inflation, supply chain constraints, and interest rate hikes.
Francoeur, noting that projects in other states can receive the tax credits, said that without these, New Jersey runs the risk of threatening early stage supply chain investments, manufacturing and jobs.
Escalating Costs
At the committee hearing, Tim Sullivan, CEO of the New Jersey Economic Development Authority (EDA), which has provided much of the funding for the state’s OSW projects, sought to distinguish between federal and state subsidies. He said the IRA would provide a “tremendous amount of resources” to support offshore wind projects, but “that is not at the expense of ratepayers.”
But Sen. Steve Oroho (R), echoed Sarlo’s concern, saying that the state’s Office of Legislative Services had calculated that the “amount of taxpayer subsidies already committed to the wind port and related projects alone totals more than $1 billion.” The funds include a $350 million loan program to support offshore wind related businesses and funds to support the construction of the New Jersey Wind Port, which will provide space for marshaling OSW projects and manufacturing turbine parts. (See NJ $1 Billion OSW Port and Marshaling Hub 60% Finished.)
“And despite this $1 billion already in taxpayer subsidies, wind port project costs are rapidly escalating to the point where Ørsted and vendors are threatening the project could stall without massive additional subsidies,” he said. “That is where the concern comes.”
Disappearing Promises
The issue has added to an already-simmering debate over the cost of the state’s clean energy program and efforts to position itself as a regional player that can provide wind port, marshaling and manufacturing services to projects along the East Coast. Republicans and some business groups have expressed concern at the cost of the projects, and the lack of a concrete estimate of how much they will cost ratepayers.
Speaking at a March 6 BPU meeting, then-Commissioner Dianne Solomon — who left the board last month, after Murphy replaced her — said she had been concerned “from the outset” at the cost of the OSW projects. She spoke before voting in support of the BPU’s launch of its third solicitation of OSW projects.
“It appears that with every solicitation, promises are made that somehow disappear or we learn of increases in costs,” said Solomon, who was first nominated to the board by Republican Gov. Chris Christie.
“For instance, with the first [OSW] solicitation, we were assured that any federal funds or investment tax credits would be used to offset the cost of the OREC,” she said. “But we now learn that legislators are poised to give the funds back to the developer.”
Fiordaliso responded, as he did at the budget hearing, by citing the example of the subsidies for the state’s now strong solar sector. “Initially, is it going to cost more money, yes,” he said of the wind sector. “But the prices will continue to come down just as they have in the solar industry.”
Monopile Factory Phase “in doubt”
The Sweeney Center report said the state’s inability to reach an agreement over the use of federal tax credits would put “in doubt” a key element of another part of the state’s OSW plan — a manufacturing plant at the Paulsboro Marine Terminal that makes monopiles, the massive steel poles that support a wind turbine.
The first phase of the project, a joint venture between EEW, a German monopile manufacturer, and Ørsted, is up and running, with the help of a $160 million investment from the Danish developer, the report said. But the second phase of the project is “already more than a year behind schedule,’ the report said.
Both Ocean Wind 1 and Atlantic Shores agreed in their bid solicitation to use monopiles made at the Paulsboro plant. But completing phase two of the plant is dependent on the two plants moving forward, and that is “contingent on legislative action,” the report said.
That in turn is holding up manufacturing and means the factory may not be able to meet its delivery deadlines with the two projects, the report said.
Francoeur said that EEW’s Paulsboro facility has the “potential to be a premier supplier for U.S. offshore wind projects and that continued capital investments made possible by the federal government, along with a steady stream of demand for monopiles, are critical to its long-term success, as they are for all domestic supply chain initiatives.”
WASHINGTON ― Patti Gunderson, a building science engineer at the Pacific Northwest National Laboratory, is passionate about windows, so when Housing and Urban Development (HUD) Secretary Marcia Fudge stopped by the PNNL exhibit at the Innovative Housing Showcase on the National Mall on Friday, she got an earful.
Double-pane windows may be the standard, but PNNL is now pushing triple-pane windows that provide even more energy efficiency and savings, Gunderson told Fudge. But the first triple-panes were heavy and wider than standard window frames, and “it’s been very difficult to get industry to accept them,” she said.
PNNL has been working with a consortium of researchers and builders, “so what happened with triple-pane technology is they are now narrow enough … that they could fit into a standard frame that has always been used for doubles,” Gunderson said, “So all of a sudden, regular manufacturers can build them, make them available to the public, and the public can have a much better window.”
Triple- and even double-panes are expensive, so for a cheaper alternative, Gunderson showed Fudge a thermal window insert — an acrylic pane with a flexible frame — that creates “an excellent seal,” she said. “We’ll put in a pane like this over an existing window that actually operates and … all of a sudden you’ve got almost double-pane performance.”
Fudge spent Friday morning at the HUD-sponsored showcase, talking with exhibitors like Gunderson and visiting model houses that are super energy efficient and, in some cases, already on the market and expanding options for affordable, high-quality housing that can be brought in quickly in emergencies.
Las Vegas-based Boxabl has developed a 361-square-foot “casita” that folds up into an 8½-by-19-foot cube so “we can put it on a trailer and ship it without [needing] a wide load,” said Jennifer Katz, vice president of strategic investments. “And it comes with all the appliances for you,” including a combo washer-dryer.
Katz sees a wide market for houses like the casita in workforce and military housing. The house can be unfolded and assembled in a couple of hours, although a local contractor has to complete the electric and water hookups onsite, she said. Inside, the cube has a full kitchen with significant cabinet space, a decent-sized bathroom — with yet more cabinets — and a bed alcove and living room. In other words, it’s small, but it doesn’t feel constricted, and Katz said the company can stack or connect the units for a larger residence.
The homes can be folded up, moved and reassembled up to 10 times without affecting structural integrity, Katz said. So far, the company has built and sold 400 of the homes — including one for Tesla CEO Elon Musk — and it is rapidly expanding its manufacturing capacity.
Fudge was impressed. “For us to do something like this … says that we can start to solve our housing problems if we but want to do it,” she said. “We have to build more density.”
On the Mall
The message from Boxabl and other companies exhibiting model homes on the Mall during the three-day showcase is that well-designed green housing is breaking out of its customized, high-priced niche but still has a way to go to become the standard rather than the exception.
In Phoenix, Ariz., Steel + Spark has developed off-grid housing, the Sparkbox, using shipping containers insulated 20% above international building codes and powered by solar panels and battery energy storage. Working with the city, the company will soon be constructing a project it is calling X-wing, which will demonstrate the use of shipping containers for off-grid emergency housing.
Each X-wing unit will consist of four containers connected by two custom core modules, said Steel + Spark founder Brian Stark. Four of the units will be installed on a city-owned lot.
In Pittsburgh, Pa., Module is targeting the urban infill market — putting new homes on small urban lots — built to the U.S. Department of Energy’s Zero Energy Ready Home (ZERH) standard. ZERH homes are so energy efficient that adding rooftop solar could offset the household’s energy use, and they may be eligible for a $5,000 tax credit under the Inflation Reduction Act.
In dollars and cents, savings on electric bills come out to about 80% under a standard home, said Drew Brisley, Module’s chief product officer.
One of Module’s first projects was a three-house infill site in Pittsburgh, and the company is now preparing for a 10-unit project, Brisley said. The company’s designs are modular, so “what is coming from our factory is a full volumetric box,” which can be stacked one on top of the other “like Lego blocks,” he said.
Module’s Black Street project of three infill houses in Pittsburgh | Module Design
The cost per home out of the factory is $200,000, appliances included, Brisley said. The company is fielding inquiries from across the country, he said, “but we feel like the opportunity that makes the most sense is the Mid-Atlantic,” in cities like Pittsburgh, Washington, D.C., and Baltimore.
Florida-based BlockEnergy has still another approach to energy-efficient, resilient housing: utility-owned, front of the meter, direct current solar and storage community microgrids. Each home in a community has solar and storage and “can operate on its own … but it’s more powerful if it can participate with its neighbors,” said Gary Oppedahl, the company’s vice president of emerging technologies, “All the storage in this system is shared, as is the solar generation, because it’s all on the front side of the meter.”
A “BlockBox” combines storage, an inverter and system management, so if a homeowner wants energy, “the inverter switches into split-phase AC and [electricity] goes in through the meter to the home,” Oppedahl said at a pre-showcase conference at the National Building Museum on Thursday.
Such microgrids could provide future proofing for homes as they electrify, he said. EV chargers and some HVAC systems run on DC, so the system could provide power to them directly rather than first converting to AC and then back to DC, with the associated power loss. The homeowner pays nothing up front, and the utility buys and manages the system “instead of buying capacity at a local coal-fired or gas-fired plant,” Oppedahl said.
With a group of microgrids, the systems could provide ancillary services and even black start capability for the distribution grid, he said. Partnering with a local utility, BlockEnergy has piloted the system for over a year in a community of 37 homes in Florida, where residents were able to ride out Hurricane Ian in 2022 without even having “to reset their microwave clocks,” Oppedahl said. “Each home is like a cell phone: It’s running off the battery all the time.”
A second project in Prince George’s County, Md., will break ground this summer, he said.
The Retrofit Market
While the houses on the Mall provided a glimpse of the cool, energy-efficient housing now on the horizon, a major challenge for Fudge, Gunderson and other participants at the event is how to bring the same level of energy efficiency to the nation’s existing, often inefficient housing stock.
Close to half of all homes in the U.S. were built before 1980, and more than a third were built before 1970, according to the National Association of Home Builders. In addition, many states have yet to adopt the latest, most energy-efficient building codes.
The impact on home comfort and energy bills can be significant. For example, Gunderson noted that while windows constitute only about 7% of a home’s exterior, older windows may account for as much as 48% of the building’s heat loss.
Eric Werling, director of the ZERH program, said the home building sector is poised for transformation but the process of change is uneven due to tricky market dynamics.
“The theory of change was that if we can help early adopters to be profitable on selling a better product — and by better, what we meant was adding efficiency and comfort and health protections — then the rest of the market would copy that,” he said. “The bad news is … that the top performers are never emulated by the bottom performers in the market.”
Policies and incentives are needed to encourage the adoption of higher standards, he said, along with industry-supported building codes to ensure bottom performers don’t undercut the rest of the field. Many cities are adopting building performance standards for their commercial buildings, but not for residential, he said.
Sven Mumme, DOE’s acting manager for emerging technologies, said that beyond price, the technologies for home retrofits must be made more accessible and easier to use. While the White House and DOE are heavily promoting heat pumps, Mumme said, many models require an electrical panel upgrade to 240 volts, as opposed to a home’s standard 120-volt plugs. Having 120-volt heat pumps will reduce upfront costs and speed deployment, he said.
Mumme and Werling also spoke about the challenges of training contractors to combine energy efficiency with other home improvements.
“There are 1 to 2 million re-siding projects that are done each year in the residential sector,” Mumme said. “So, 99% of the time they just add … [new] siding back on,” missing a key opportunity to improve a home’s insulation.
“If we had a low-cost, high-performing, insulated siding product … that would be a game changer if we can utilize the greater workforce to basically convert siding projects to efficiency,” he said.
VALLEY FORGE, Pa. — PJM’s Operating Committee endorsed a joint proposal by PJM, Public Service Enterprise Group (NYSE:PEG) and DC Energy for the RTO, transmission owners and market participants to increase information sharing ahead of extended transmission outages.
The package received unanimous support Thursday, while a competing proposal from the Independent Market Monitor (IMM) received 17% support. (See “Discussion Continues on Transmission Outage Coordination Proposals,” PJM OC Briefs: May 11, 2023.)
The joint proposal would add coordination between utilities and PJM to identify any required extended outages, evaluate the impact of those outages and expand outage information shared by the RTO.
Monitor Joseph Bowring said his proposal was designed to increase transparency about late outages and impacts on transmission congestion. He said the status quo rules have strong provisions around late outages that transmission owners (TOs) can bypass by instead reporting them as rescheduled projects.
“Our point is to increase clarity, transparency — particularly about late outages and congestion,” he said.
The IMM proposal would label outages as rescheduled when the start date is moved, adding a third category to current “on time” and “late” labels. It would also recommend that PJM identify the “congestion analysis required for transmission outage requests and associated triggers, including both the extent of overloaded facilities and the level of economic congestion,” the package’s matrix entry says. Bowring modified the proposal during the meeting to incorporate stakeholder feedback about a desire for more clarity.
Exelon’s Alex Stern argued that Bowring’s proposal was out of the scope of the outage coordination issue charge and would be inconsistent with the Consolidated Transmission Owners Agreement, which doesn’t give PJM the authority to place conditions on TO scheduling based on congestion analysis, associated triggers or whether an outage or rescheduled outage occurs before or after FTR auction bid opening dates. He cautioned against conditioning any outage requests needed to address grid reliability on market criteria.
Bowring said his proposal was focused on reporting, not changing how projects are scheduled or any TO behavior.
After Bowring modified the language of his proposal, OC Chair Anita Patel ruled the change was within the scope of the discussion.
PJM Plans to Open Stakeholder Process on RMR
PJM Senior Vice President of Operations Mike Bryson told the OC that RTO staff is working with the Monitor to draft a problem statement and issue charge to start a discussion on the reliability must-run (RMR) process, which allows PJM to contract with a deactivating generator to continue operations to maintain reliability.
During recent discussions on reliability and resource adequacy, PJM has warned of risk that deactivations will outpace new resource development, creating increased reliance on RMRs to maintain resource adequacy. (See “Panel Discusses Future Reliability Landscape,” PJM CEO, Panelists Address Reliability During Annual Meeting.)
Bryson said PJM is considering the timing of when to bring the subject before stakeholders and which committee should take up the issue, adding that it would likely be the OC.
Stern advocated for having a working group or special sessions examine the issue more deeply and increase visibility for stakeholders.
PJM Seeks Information on Expected Impact of EPA Rules
PJM’s Gary Helm presented on recently proposed EPA rule changes, including the “good neighbor” plan to cut nitrogen oxide emissions. He recommended that market participants provide the RTO information on how the regulations could impact their operations as it considers what comments to submit to the EPA. (See EPA Good Neighbor Plan Expected to Accelerate Coal Plant Retirements.)
The proposed rule changes include a stricter fine particulate standard, carbon capture and sequestration (CCS) for coal-fired resources and hydrogen fuel requirements for combustion turbines (CT) over the next decade. The EPA is also considering changes to the mercury and toxic air standards to more strictly target mercury emissions through electrostatic precipitators, Helm said.
The requirements for gas and coal units would have a sliding scale for when those units must either retire, install CCS to reduce CO2 emissions by 90%, or — for CT units — blend an increasing amount of hydrogen into their fuel. Helm said there are currently no commercially operating generators blending hydrogen into their fuel at the minimum 30% standard the EPA plans to require for larger resources by 2032. That rule would affect most of the combined cycle generators in PJM’s fleet.
Paul Sotkiewicz, president of E-Cubed Policy Associates, questioned whether the EPA is considering the infrastructure that would be required for generators to procure the amount of hydrogen required. Helm said at this point the EPA is focused on the viability of the technology.
“No one is doing that of their own volition, just running for the market with 30% hydrogen,” Helm said. “What I would say when you talk about infrastructure [is] that’s not addressed in the proposal because that’s something the administration feels is being addressed through actions being taken by the Department of Energy, the [Inflation Reduction Act] and the [Infrastructure Investment and Jobs Act].”
America’s Power CEO Michelle Bloodworth said generators will have to decide which avenue to pursue much sooner than laid out in the EPA’s rules, because states will have two years to write their implementation plans and will likely require utilities to make a determination ahead of that timeline. She added that no commercially operating power plants have 90% carbon capture and she doesn’t think the EPA has demonstrated that the technology is viable yet for coal-fired power plants or that the supporting infrastructure exists.
