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 Moore rescinded their nominations after taking office.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.
ALBANY, N.Y. — The State Legislature on Friday passed a bill that would require state agencies and utilities to identify electric grid improvements necessary to implement an electric vehicle highway and depot charging network (S4830C/A5052).
The New York State Energy Research and Development Authority, Department of Transportation, Department of Motor Vehicles, New York State Thruway Authority, New York Power Authority, Long Island Power Authority, Department of Environmental Conservation, and electric distribution and transmission utilities would be required to evaluate what it would take to comply with the state’s many clean transportation targets.
The bill would also seek to expedite transmission and distribution infrastructure and interconnection upgrades at public sites controlled by the Thruway, as well as identify charging station sites that should be prioritized for early deployment to ensure they are upgraded quickly.
The agencies would be required to develop an evaluation within nine months of the effective date and conduct another one every three years thereafter.
With bipartisan support, the bill passed easily: 59-3 in the State Senate and 140-5 in the State Assembly.
NYPA has been driving the state’s EV buildout via the EVolve NY program, while NYSERDA has several other EV programs, but more rigorous goals in the Climate Leadership and Community Protection Act, Advanced Clean Trucks and Advanced Clean Cars II rules, and Zero Emissions Vehicles policy necessitate greater state action and coordination. NYSERDA also partners with Atlas Public Policy to analyze and track EVs’ growth in the state via the EValuateNY program.
Establishing an EV network in New York that can support an electrified transportation sector by 2050 is expected to increase demand for electricity, potentially in many areas not well connected to existing generation infrastructure. National Grid released a study in November suggesting that states, such as New York, must move faster to support the needs required to meet the explosive growth of EVs. (See Study Projects Power Demands of Highway EV Charging Network.)
The bill would “reduce the cost of interconnection, electric distribution and local transmission upgrades while serving projected vehicle traffic volumes” by seeking to “optimize fast-charger deployment among the highway charging hubs and charging development among the fleet charging zones.”
“If the upgrade process fails to outpace the time when electric vehicle adoption reaches scale, we will not have a reliable and adequate electric supply to power all the new electric vehicles on New York’s roadways,” the bill says.
Advanced Energy United applauded the bill passing. “Analyses — and subsequent grid improvements — will ensure the grid is ready for the uptick in electricity demand that EVs will bring, and save money in the long run compared to the status quo of reactive and piecemeal grid upgrades.”
“New York’s transition to EVs is a critical undertaking, but that transition will be slower and more expensive without proactive strengthening of the electricity grid,” said Karlito Almeda, AEU’s New York lead. “The analysis this bill calls for is a critical first step toward making New York’s electricity grid ready for the full transition to EVs, but we also need to ensure that utilities move ahead with implementing the grid improvements recommended in the analysis.”
ALBANY, N.Y. — Justin Driscoll, the interim CEO of the New York Power Authority, remained in limbo as the state Senate finished its legislative session Friday without voting to confirm him.
Driscoll has been serving in an interim role since 2021, and the NYPA Board of Trustees voted to appoint him subject to Senate approval on July 26, 2022, after he was recommended as president and CEO by Gov. Kathy Hochul (D).
Driscoll had previously served as executive vice president and general counsel to NYPA, among other public roles, but environmental and labor groups mobilized to oppose him, citing his time in the private sector and recent comments on climate legislation.
Environmentalists and climate action groups claimed that Driscoll’s past legal work for fossil fuel companies, donations to Republicans, and opposition to the Build Public Renewables Act made him unqualified to lead an agency with an ever-expanding role in New York’s clean energy transition. The law makes the NYPA the sole provider of energy to all state owned and municipal properties and requires the authority to provide only renewable energy. The bill, which passed the legislature in May as part of the state budget, also requires that NYPA pay prevailing wages and use project labor agreements. (See “NYPA’s New Roles,” NY to Begin Banning Gas in New Construction in 2026.)
Meanwhile, Driscoll’s supporters credit him for his ability to work with everyone in the industry and for his extensive knowledge of how to achieve net-zero emissions without excessive costs or threats to reliability.
The Senate’s refusal to act on Driscoll’s appointment points to the state’s current dynamics. Democrats, who hold a supermajority in the legislature, recently torpedoed a Hochul judicial nominee whom they felt was too conservative.
Driscoll expressed support for NYPA’s expanded role in New York’s energy market in February.
“Government can play a role. Nobody is suggesting that government be the only tool. But just given the enormity of what we’re looking to achieve here, we think that NYPA and government can play an ancillary role in the energy transition,” he testified to the Senate Energy and Telecommunications Committee. (See NYPA Leader Says Expansion not Threat to Private Sector.)
But Driscoll was challenged in a joint legislative hearing, with Assemblyperson Zohran Kwame Mamdani, a New York City Democrat, pressing him on whether labor unions have been involved in NYPA’s work. (See “NYPA Boost,” NY Legislators Press Hochul Officials on Energy Transition.)
Organized labor has split over Driscoll’s nomination, with the Communications Workers of America District 1 tweeting, “NYPA is in good hands with Justin.”
United Auto Workers Region 9A, however, wrote they “were proud to support the #BuildPublicRenewables Act to turn the New York Power Authority into a national renewable energy leader,” adding that “New York needs a NYPA CEO who can lead with that vision” but “Justin Driscoll is not that person.”
At a confirmation hearing last week, Driscoll also had to respond to a report in The Buffalo News quoting allegations that he refused as NYPA’s general counsel to investigate allegations of racial discrimination at the authority. “Anyone who knows me knows that’s not me, that’s not how I operate,” Driscoll testified, according to the News. “I would never try to minimize complaints.”
Opposition
After learning that Driscoll would not be put up for a vote, Sen. Jabari Brisport, a Democrat representing parts of Northern Brooklyn, wrote, “New Yorkers spoke out so loudly against Justin Driscoll because he is quite clearly not an acceptable option to lead the historic transition mandated in the Build Public Renewables Act.
“NYPA needs a president who cares about environmental justice and labor rights, but Gov. Hochul has so far failed to put forward someone who meets that bare minimum,” he added.
The left-leaning New York Working Families Party tweeted that “Driscoll’s close ties to fossil fuel lobbyists, contributions to climate-denying candidates and parties, and stated opposition to expanding green energy production through the BPRA makes him a poor fit to lead the NYPA into the future.”
Public Power NY, a collection of New York grassroot organizations focused on clean energy, wrote in an email sent after reports confirmed Driscoll would not receive a vote, that “thousands of New Yorkers mobilized this past week to ‘Dump Driscoll.’
“We look forward to collaborating with stakeholders to ensure we find the most qualified person to lead NYPA,” the group added.
Supporters
The Municipal Electric Utilities Association of New York State, had earlier shared its support, writing “that Mr. Driscoll is well qualified and the right choice to lead NYPA into its next chapter.”
The New York Association of Public Power (NYAPP), a group of municipal utilities and rural electric cooperatives, also supported the nomination, tweeting, “Justin is the right person to lead NYPA.”
NYPA forwarded an email inquiry from NetZero Insider to the governor’s office, which responded with a statement from a spokesperson: “Following a national search last year, Gov. Hochul recommended Justin Driscoll for president and CEO of the New York Power Authority because he has the expertise to lead the nation’s largest state-owned utility, helping New York to achieve its ambitious climate goals using both NYPA’s existing authorities and its expanded mandate to build renewable energy secured in the FY24 State Budget.”
The spokesperson also confirmed that Driscoll would remain in his acting position.
FRAMINGHAM, Mass. — Eversource broke ground on the first utility-led networked geothermal demonstration project in the country last week, launching an alternative to fossil fuel heating that climate advocates hope will eventually be able to replace much of the state’s natural gas network.
The project is a collaboration between Eversource and climate nonprofit HEET and is one of two ongoing networked geothermal projects being developed by utilities in the state. Projected to begin operating this fall, the geothermal system will provide heating and cooling to about 140 customers, including homes, low-to-moderate income apartments, businesses and a fire station.
“This is what fighting climate change on a local level looks like,” an Eversource spokesperson told the attendees of the groundbreaking ceremony.
Eversource said it expects to significantly reduce energy use and emissions in the area, projecting an approximately 75% reduction in energy use for Framingham Housing Authority renters. The U.S. Department of Energy recently awarded the project $715,000 to expand to an additional neighborhood.
“This project has been a source of envy across the state,” said Rep. Priscila Sousa of Framingham.
To improve understanding of the challenges and potential for future projects, HEET is leading a team of researchers to study and model the technology used in the geothermal system, funded by a $5 million grant from the Massachusetts Clean Energy Center and to be conducted independent of industry oversight.
Zeyneb Magavi, co-executive director of HEET, said this project will provide valuable insight on the logistical and cost constraints to scaling up the technology.
“There’s a lot of potential savings that have already been identified if we get this going to scale,” Magavi told RTO Insider.
Magavi said drilling is one major component of networked geothermal projects that will need extra attention to deploy the technology across the state.
“Drilling, drills, drillers — that aspect of the cost is really a significant portion, and the price per linear foot varies widely across the country,” Magavi said, adding that ordering a drill for a networked geothermal project currently takes about a year and a half.
“Having identified that supply chain problem — and that is a core driver of cost — we’ve actually gone ahead and submitted an effort to the Department of Energy for the Defense Production Act on heat pumps to try to open up that supply chain and bring a drill assembly and driller training center for excellence to New England.”
Magavi emphasized the potential of networked geothermal to help low-income gas customers transition away from fossil fuels.
“If we do a house-by-house transition, we are absolutely going to end up with an equity challenge whereby renters and low-income customers are going to be left on a gas system with rising prices,” Magavi said, noting that both pilot projects are being developed in neighborhoods with significant populations of low-income residents.
William Akley, president of gas business at Eversource, called the demonstration project “a great platform for the workforce transition,” which he said is critical to the company, though no representatives from organized labor groups spoke at the event.
“Operating, constructing and maintaining an underground geothermal network has a lot of parallels to what our industry and what our employees do every day,” Akley said.
A recent price drop for Tesla’s Model 3 and Model Y electric vehicles have made the cars eligible again for a California EV rebate, and now the incentive program is quickly running out of money.
The potential funding depletion leaves in limbo California’s popular Clean Vehicle Rebate Project (CVRP), which has issued more than 500,000 rebates totaling more than $1.1 billion since its launch in 2010.
CVRP funding that was intended to last through June 2024 is now projected to run out as soon as November.
“At this point in time, there is no [additional] allocation for CVRP and as such, we plan to close the program once funding is out and not hold the waitlist,” Raquel Cardenas with the California Air Resources Board (CARB) said during a CVRP workshop last month. Cardenas is manager of CARB’s innovative light-duty strategies section.
The status of CVRP was also discussed Thursday during a CARB workshop on the agency’s overall funding strategy for clean vehicle incentives.
CARB is expecting to receive $441 million for all of its clean vehicle incentives in the next fiscal year — a steep drop from the $2.6 billion for incentive programs that the CARB board approved last year. The programs apply to vehicles ranging from e-bikes and cars to heavy-duty trucks, as well as clean mobility options such as bike or car sharing. (See CARB Approves $2.6B in Clean Vehicle Incentives.)
Last year’s $2.6 billion in incentive funding, which CARB called historic,was part of the state’s five-year, $10 billion multi-agency package to promote zero-emission vehicle adoption. California will ban the sale of gas-powered cars in 2035.
The $2.6 billion in funding followed a $1.5 billion allocation the previous year. The proposed $441 million for clean vehicle incentives in the next fiscal year is more in line with annual funding levels in 2016 through 2020, which ranged from $391 million to $588 million.
But Tesla’s Model 3 and Model Y regained eligibility as of Feb. 13 after the automaker lowered the MSRP. Since then, Tesla vehicles have accounted for about 80% of all CVRP rebates.
Other factors are contributing to the rapid depletion of incentive funds. CVRP rebate amounts increased in February for low-income buyers, who can now receive $7,500 for a battery-electric vehicle, up from $4,500. The rebate for a low-income buyer of a plug-in hybrid increased to $6,500 from $3,500.
And starting this summer, low-income CVRP participants will also be able to receive a $2,000 prepaid card for use at public charging stations.
Last year’s $2.6 billion for clean vehicle incentivesdidn’t include money for the CVRP. That’s because in FY20/21, CARB allocated $515 million to the program, an amount intended to last through June 2024.
As of May 22, $281 million in CVRP funding remained. To keep the program running through next June, another $256 million to $837 million would be needed, according to the Center for Sustainable Energy, which administers CVRP on behalf of CARB.
Other Incentive Programs
CARB’s workshop last week was the first in a series of meetings on the FY23/24 funding plan for clean vehicle incentive programs.
The agency expects to release a draft of the plan in August ahead of a second workshop on Aug. 31. In addition, a series of community and work group meetings are planned through October.
The CARB board is expected to vote on the plan in November.
During Thursday’s workshop, CARB staff gave brief updates on other clean vehicle incentive programs.
An electric bicycle incentive program is set for a “soft launch” this month followed by a statewide launch later this year. The program will provide incentives of up to $2,000 to low-income buyers of e-bikes. A total of $13 million has been allocated to the program.
The Clean Cars for All (CC4A) program provides rebates to low-income residents who are scrapping an old car and buying an EV. The program has been administered through four regional air districts, and the San Diego Air Pollution Control District intends to launch its program this year.
CARB is in the process of expanding CC4A statewide. The agency expects to announce an administrator for the statewide program this summer.
Stakeholders Endorse Discussion on Deactivating Generators’ CIRs
VALLEY FORGE, Pa. — The PJM Planning Committee on June 6 approved a problem statement and issue charge to explore possible improvements to the existing process of transferring capacity interconnection rights (CIRs) from a retiring generator to a replacement resource at the same interconnection point.
Proposed by East Kentucky Power Cooperative and Elevate Renewables, the problem statement says transfer requests currently have to go through the same backlogged interconnection study queue as new generators to determine if any grid upgrades are required, which can result in replacements for retired facilities taking years to begin construction.
The companies said the long turnaround increases the commercial risk for generation owners seeking replacements; incentivizes speculative projects being submitted in the queue in anticipation of retirements; and contributes to PJM’s concerns about the balance between retiring resources and new entry over the next decade. The problem statement pointed to a February white paper PJM published finding that the pace of renewable development has been slower than anticipated while legislation and economics are leading to more deactivations.
The scope of the issue charge includes only discussion of transfer requests for the same point of interconnection, which EKPC’s Denise Foster Cronin said can often use existing infrastructure and should require no material transmission upgrades. The current process is envisioned to remain for transfers involving different points of interconnection, as those are more likely to require transmission upgrades. The issue charge also aims to develop a solution that specifies that the CIR transfer process applies for all energy-injecting resources, including thermal, renewable and storage.
Responding to stakeholders questioning how a system that allows replacement resources to go through the interconnection process faster would not be skipping other projects in the queue, Paul Sotkiewicz, president of E-Cubed Policy Associates, said the CIRs the replacing resource is seeking are held by the generation owner and are already being modeled as existing on the grid.
“Why can’t those projects be moved forward, because again they’re already being modeled; it doesn’t change anything for anyone else; … it’s not jumping the queue for anyone else; those CIRs are being modeled for everyone else,” he said.
Other PC Business
Stakeholders endorsed PJM’s plan for how it will conduct the 2023 reserve requirement study, the annual process for determining the forecast pool requirement and the installed reserve margin for the following three delivery years and establish the figures for the fourth year out. The study will also set the winter weekly reserve target for the 2023/24 delivery year. (See “Reliability Requirement Study to Use New Software,” PJM PC/TEAC Briefs: May. 9, 2023.)
The planned deactivation of the coal-fired Brandon Shores Generating Station, near Baltimore, will require an estimated $786 million to resolve several voltage and thermal violations, PJM’s Phil Yum told the Transmission Expansion Advisory Committee last week.
The violations would spread from the BGE zone to also impact PEPCO, Dominion, PECO, APS, PPL and Met-Ed. The work to the 500-kV grid is estimated at $333 million and includes two new lines between the Peach Bottom and Graceton substations, as well as additional projects throughout the BGE, PECO and PEPCO zones. The 230- and 115-kV upgrades are estimated at $453 million and include three new substations and additional work throughout the BGE and APS zones.
The deactivation is scheduled for June 1, 2025, but Yum said the work is unlikely to be complete before that date. PJM Director of Operations Dave Souder said it will likely be necessary to seek to continue operating the generator under a reliability-must-run contract while the transmission work is ongoing.
“There’s a significant need to import to serve the load,” Souder said, adding that new high-voltage lines will be required into Baltimore to avoid voltage collapse under outage conditions.
Dominion Proposes Substations and New Lines Throughout Northern Va.
Dominion Energy has proposed several line extensions and installations to serve new substations in Northern Virginia, in part fueled by data center growth.
Two new substations in Louisa County requested by Rappahannock Electric Cooperative would be served by a $55 million project to extend the North Anna-Desper line.
Meanwhile, Northern Virginia Electric Cooperative requested a new substation to serve a new data center complex with more than 100 MW of load in Bristow. The 230-kV Gainesville-Wheeler line would be extended at a $15.75 million cost.
Another substation in the area, Daves Store, would be served by extending a 230-kV line terminating at the existing Heathcote substation to the new facility at a $40 million cost. The new lines would connect to a GIS 230-kV four-breaker arrangement.
Dominion has also proposed a $33.5 million project to address a 300-MW load drop violation related to the Daves Store, Youngs Branch and Catharpin substations. The work would extend a 1.7-mile, double-circuit 230-kV line from the new Trident substation to Daves Store and install associated 230-kV equipment at both. The bulk of the cost is to acquire rights of way for the new line at $18.5 million.
Two additional substations, Gemini and Atlas, would be constructed in Gainesville to serve data center loads exceeding 100 MW. Dominion estimates each project would cost just over $15 million to construct, including 230-kV lines to interconnect them.
Other Supplemental Projects
Exelon proposed the replacement of a circuit breaker on its 500-kV Conastone line, northeast of Baltimore near the Maryland-Pennsylvania border, at a $2.3 million cost. The company said the equipment was installed in 1992 and is now deteriorating, causing higher maintenance costs. The projected in-service date is Nov. 14, 2023.
Dominion provided an update on its proposed $40 million project to install new equipment at its Goose Creek substation in Loudoun County, Va. Because of an inability to procure a 1,440-MVA transformer to address real-time constraints, it plans to instead install an 840-MVA transformer and move up the in-service date from Dec. 15, 2026, to Dec. 15, 2023.
Dominion also proposed 230-kV projects to connect to its proposed Twin Creeks substation in Loudoun County, with a requested in-service date of Dec. 31, 2024. A line linking the new substation with the existing Pleasant View and Edwards Ferry stations comes with an estimated $20 million cost, while two lines to the Sycolin Creek substation have an estimated $28 million expense.
PJM Proposes New Standard for RTEP Window Submissions
PJM presented a new format for how projects being submitted to address needs identified in its Regional Transmission Expansion Plan (RTEP) should be organized.
The RTO’s Sami Abdulsalam said the change will be required for future RTEP windows and is expected to simplify the process for both staff and stakeholders.
The change asks submissions to eliminate the inclusion of existing infrastructure that is not relevant to the project being submitted and identify facilities that will be removed when submitting single-line diagrams. It also creates a standard format for how contingency files should be named to streamline compiling all the files PJM receives.
