QUEBEC CITY — Speaking at the first panel of the Electricity Information Sharing and Analysis Center’s annual GridSecCon security conference in Quebec City, NERC CEO Jim Robb said that the Cybersecurity and Infrastructure Security Agency’s (CISA) Shields Up initiative, implemented prior to Russia’s invasion of Ukraine in 2022, has done a lot “to make cybersecurity accessible” to workers in the electric industry.
However, he added that the initiative also had “created a real problem,” raising the question: How long can the industry be expected to maintain the vigilance that the name implies?
“This industry typically keeps its shields up at all times. And at some point you’ve got to ask yourself, ‘When can we lower them?’ Well, we’ve never lowered them, right?” Robb said. “So I think one of the real challenges here is, how do you sustain the intensity, dealing with the very real fatigue that results from that intensity, and keep your cyber defenses fresh?”
The challenge is exacerbated by the fact that the cyber struggle is “just not a fair fight,” with owners and operators of electric infrastructure — predominately private companies — having to stand against adversaries that include actors backed by nation-states like Russia and China, along with financially motivated criminals. For the industry to resist such opponents, Robb said, its members must be able to rely on “extraordinary collaboration” with their peers and the government.
Robb’s fellow panelists, representing the public and private sector in both the U.S. and Canada, agreed that mutual support is key to building cyber resilience. This also is true outside the power industry. Nitin Natarajan, CISA’s deputy director, described a symposium the agency recently held with emergency responders in the Northeast U.S. to educate them about introducing cybersecurity into their communications.
Adding to Robb’s point about the evolving cyber threat landscape, Natarajan pointed out that ransomware attacks have become easier than ever because of the rise of the ransomware-as-a-service model, in which a core group develops and operates a ransomware package while recruiting affiliates to hack into networks and deploy the app. Groups using this model include DarkSide, which federal officials believe was behind the attack on Colonial Pipeline in 2021. (See Colonial CEO Welcomes Federal Cyber Assistance.)
“You no longer need to start up your own cyber terrorist organization to attack somebody; you can hire somebody to do it for you,” Natarajan said. “If you have Bitcoin and you have an enemy, you can attack somebody today.”
Panelists agreed that because the Canadian and U.S. electric grids are fully integrated, collaboration also must extend across international borders. Rajiv Gupta, associate head of the Canadian Centre for Cyber Security, said Canada’s government is working hard to establish a tough regulatory regime around cybersecurity.
The Critical Cyber Systems Protection Act (CCSPA), part of a major bill making its way through Parliament, is an important step toward ensuring cybersecurity within critical industries, Gupta said. The bill would create a “comprehensive regulatory framework” governing cyber systems in Canada’s critical infrastructure, giving the government the power to review and intervene in cyber compliance and operational situations.
While Gupta and the other panelists applauded CCSPA, they also said it is only “a step in the [right] direction,” acknowledging that more effort will be needed to ensure smaller utilities as well as larger ones can respond to the new requirements.
“The organizations with more money have very different cybersecurity postures than the smaller ones,” Gupta said. “And we have to make sure to close that gap between large and small, because … getting that harmonization, not just across standards and countries and organizations, but also addressing disparities between well-funded organizations and lesser-funded [ones] is super important as well.”
A decision by Washington to link its cap-and-trade program to one shared by California and Quebec should benefit participants in both systems, according to a preliminary analysis the Washington Department of Ecology released last week.
“Linkage would likely improve the [Washington] cap-and-invest program’s economic durability, longevity and efficacy,” the analysis found. “In a larger, more liquid market with a greater number of participants, allowance prices would likely be lower and change more predictably. Predictable prices can foster greater investments in decarbonization.”
Participants in Washington’s program would be able to more effectively perform long-range planning, increasing their readiness to pursue expensive investments in decarbonization, the report said.
Washington’s carbon allowance market now is slightly bigger than Quebec’s alone, but only 18% the size of the combined California-Quebec program.
The preliminary analysis estimates Washington’s market by 2025 — the first possible year the two programs could combine — would be just 16% the size of the California-Quebec system.
In its analysis, Ecology set out to compare the difference in outcomes between Washington maintaining a standalone program or entering the combined market — referred to as “linkage” in the report.
“The cap-and-invest program is designed to address the current climate crisis on three critical fronts: by reducing GHG emissions economy-wide, by creating a growing market for cleaner technologies and energy sources, and by funding environmental justice and climate resilience efforts in our state. These goals would not change in a linked market,” the report said.
To assess the effects of linkage, Ecology reviewed the relative size of the carbon allowance budgets for 2023-2026 for the two programs. Because of the significant difference in size, prices of the newly linked market should track those in the California-Quebec market at the time of linkage.
“Because Washington’s allowance prices are higher than those in the California-Quebec linked market at the time of writing, it is likely that Washington’s allowance prices in a linked program will be lower than if Washington’s program remains separate. However, the extent of any allowance price decrease, and the level at which prices may stabilize, are difficult to predict,” the report said.
Washington carbon allowances (WCAs) cleared at $63.03 per metric ton in a quarterly auction in August, compared with $36.14 in California. Critics — particularly Republicans — have blamed Washington’s cap-and-trade program for the state having among the highest gasoline prices in the U.S. this past summer. Gov. Jay Inslee (D) and other state Democratic politicians have accused oil companies of exploiting cap-and-trade to take excessive profits above the cost of complying with the programs. (See Inslee Challenges Cap-and-trade Role in High Wash. Gas Prices.)
‘Linkage-ready’
Ecology acknowledges the price impact of the program in making its case for joining the bigger allowance market.
“We have seen that businesses may elect to pass through their regulatory compliance costs to consumers by increasing prices — on gas and diesel, energy bills and other daily necessities — so the positive impact of lower, more stable allowance prices on Washington residents is extremely important,” the report said.
Economic modeling done last year indicated the price for WCAs could rise to $100 by 2030 before leveling off and declining in subsequent years as the state reduces emissions through decarbonization investments. The “pass-through” costs from such high prices could strain household budgets, the report notes. Linkage with the larger market would mitigate the rise in WCA prices, according to the analysis.
“Reducing this impact between 2023 and 2030 on consumers benefits all Washingtonians, and particularly helps lower-income residents, who spend a larger percentage of their income on necessities like food, transportation and home heating. Linkage, therefore, may not only help mitigate overall consumer cost impacts, it may especially lessen the impact upon vulnerable populations,” the report said.
Washington officials expect to decide late this month or early next whether to join the joint market. Joel Creswell, Ecology’s climate pollution reduction program manager, recently briefed the state’s House Environment and Energy Committee about the upcoming decision. (See Wash. Weighs Joining California-Quebec Cap-and-trade Program.)
If Washington decides to join the joint cap-and-trade market, the governments of California and Quebec will need to approve its membership. Although the Washington law authorizing the state’s cap-and-trade program required it to be “linkage-ready,” meaning key aspects of the two programs already are aligned, the linkage process still could necessitate regulatory changes in each area, the Ecology analysis said.
“If all three jurisdictions decide to link, California and Quebec would need to add amendments to their respective regulations to implement any potential linkage agreement. All three programs would need to complete their processes to adopt policy changes before our carbon markets could actually be linked,” the report said.
If the three jurisdictions agree to linkage, a final agreement likely would be signed in 2025, Creswell told legislators.
Transmission upgrades that are needed to avoid overloads in a fully electrified New England by 2050 could cumulatively cost between $22 billion and $26 billion, ISO-NE told its Planning Advisory Committee on Wednesday.
The RTO emphasized that limiting the 2050 winter peak from the anticipated 57 GW to 51 GW would save the region about $8 billion in avoided transmission costs.
The projections were part of the results of ISO-NE’s 2050 Transmission Study, which was requested by the New England States Committee on Electricity in 2020. ISO-NE is now developing a process to better facilitate transmission infrastructure projects based on the findings.
The study focused strictly on thermal overloads on the system during peak load and did not include costs associated with interconnection, distribution, transient stability and other system needs. “The total transmission and distribution costs are anticipated to be much higher,” it said.
“Reducing the peak load can significantly reduce the transmission costs,” Reid Collins of ISO-NE told the PAC. The region could reduce this peak by either investing heavily in demand response, building insulation and heat pump efficiency, or by reducing the levels of electrification during the times of peak load, he said.
As a part of the study, ISO-NE identified a set of “high-likelihood concerns” that will need transmission investment. These include the need to increase transfer capability from Maine and New Hampshire into the Boston area, and to boost import capability into the regions of Burlington, Vt., and southwestern Connecticut.
ISO-NE outlined a set of potential solutions for each of these concerns, including the potential of an offshore grid to address Boston imports. The study also found that the region will likely need many new transformers no matter where the new loads appear.
“It may be worth looking into ordering some of these up front, not knowing exactly where they’re going,” Collins said, noting the long lead times associated with acquiring new transformers.
Some stakeholders expressed concern about the study’s assumptions about the amount of energy storage on the grid in 2050. The study projected that the region would have just over 5,000 MW of nameplate capacity by then, which Collins acknowledged seems to be a low-end estimate. He added that most of the new storage assessed was of four-hour duration.
“There is already more battery storage expected to be online by 2033 than the 2050 Transmission Study’s input assumption for 2040,” Collins said.
While the study assumed that all oil, coal, diesel and municipal solid waste resources would be retired by 2035, it also assumed a significant remaining role for natural gas, with almost 17,000 MW of nameplate capacity expected for 2050.
Economic Planning for the Clean Energy Transition
Also at the PAC, ISO-NE’s Patrick Boughan and Benjamin Wilson presented additional “sensitivity results” of the RTO’s Economic Planning for the Clean Energy Transition pilot study, modeling different scenarios following requests from stakeholders.
ISO-NE found that added demand from transportation and heating would increase the cost to load by 114% compared to the no-electrification base model.
“Because the additional heating and electrification load peaks in colder conditions, the additional load likely requires more stored fuel generation,” Wilson said, noting these additional loads would greatly increase the expected need for oil generation, from 11 GWh to 834 GWh.
While ISO-NE anticipates that heating and transportation electrification would drive a 67% increase in electricity-sector emissions compared to the no-electrification scenario, Wilson noted that these emissions “are expected to be offset by emission reductions in other sectors.”
In the scenario modeling nuclear retirements, ISO-NE found they would drive increased solar and wind generation but also increase emitting generation, especially during the interim years of 2030 and 2040. During these years, the model showed that nuclear retirements would lead to “a significant increase in gas generation and emissions.”
In the biodiesel scenario, the RTO found that biodiesel — along with synthetic natural gas — would be a useful but expensive fuel for generation.
“Higher carbon prices or [renewable energy certificates] would be needed to allow carbon-neutral fuels to be utilized if they had to compete with existing emitting fuels,” Wilson said.
Asset Condition Projects
Kyra Lagunilla of Rhode Island Energy presented to the PAC on three proposed asset condition projects totaling about $88 million. Lagunilla said the projects are necessary because of deteriorating and out-of-date transmission infrastructure that has led to poor performance on the lines.
The proposed line rebuilds are:
the Rhode Island portions of the 115-kV M13 Pottersville-Jepson and L14 Bell Rock-Jepson lines, with a projected cost of $56.5 million and an in-service date of Q4 2025;
the 115-kV S-171N Woonsocket-Hartford Ave and T-172N Woonsocket-Hartford Ave lines, with a projected cost of $22.3 million and an in-service date of Q3 2026; and
the 115-kV E-183W Franklin Sq-Wampanoag line, with a projected cost of $10.6 million and an in-service date of Q4 2025.
A coalition of natural gas companies, homebuilders and unions have filed a lawsuit asking a federal court to overturn New York State’s ban on natural gas hookups in new construction. (See NY to Begin Banning Gas in New Construction in 2026.)
The New York State Builders Association, National Association of Home Builders, New York Propane Gas Association, locals of the International Brotherhood of Electric Workers, Mulhern Gas Co. and others filed the suit in the U.S. District Court for the Northern District of New York. It seeks to apply the same logic as a successful challenge of a ban in Berkeley, Calif. The Ninth U.S. Circuit Court of Appeals said such bans are preempted by the federal Energy Policy and Conservation Act (EPCA). (See Impact of Berkeley Gas Ruling Debated.)
“As the only federal appellate court to have addressed this issue recognized, EPCA preempts state and local laws relating to the use of energy, such as gas, by covered appliances and equipment,” the suit said.
The suit alleges the prohibition is inconsistent with the public interest and consumer choice and would shift energy demand to the power grid.
The ban applies only to buildings of seven stories or less in height and also exempts commercial or industrial buildings above 100,000 square feet in “conditioned floor area.” But those exemptions go away starting in 2029, when it will apply to all new buildings.
“Plaintiffs support achieving the state’s climate goals, but with the majority of New York’s electric generating capacity coming from gas-fired power plants, banning gas in homes will do little if anything to advance those goals — and in all events, the state must comply with federal law,” the lawsuit said.
Although the ban doesn’t take effect until 2026, the plaintiffs said it already is chilling and undermining their businesses.
The EPCA was born out of the oil crisis in the 1970s and covers energy independence, domestic energy supplies and national security. It requires a practical approach to energy regulation, maintaining neutrality on energy sources and recognizing the need for a diverse supply of energy. The law includes regulations on appliances’ energy efficiency, which are meant to be uniform across the country. EPCA expressly preempts state and local regulations on the efficiency and energy use of products for which it sets standards, leaving narrow room for concurrent state and local regulations.
New York announced its ban just weeks after the Ninth Circuit overturned Berkeley’s ban, and the lawsuit argues the state’s rules do “exactly” what that court preempted.
EPCA has been changed a few times since the 1970s, including a 1987 amendment that specifically covers the preemption issue.
That change sought to reduce the regulatory and economic burdens on the appliance manufacturing industry through the establishment of national energy conservation standards for major residential appliances. Congress recognized that varying state standards would complicate design, production and marketing plans.
States can seek permission to establish their own standards, but that requires a showing of an unusual and compelling local interest and cannot be granted if the state regulation would lead to the unavailability of a product type or products of a particular performance class, the lawsuit said.
“New York’s gas ban falls within the heart of EPCA’s express preemption provisions,” the lawsuit said. “The gas ban is a regulation concerning the energy use of appliances covered by EPCA in that it ‘prevent[s] such appliances from using’ fossil fuels, such as propane or natural gas.”
The New York ban goes further into preempted territory than Berkeley’s because in addition to banning gas piping it also bans gas appliances from being installed in new buildings.
A new report finds that the impact of offshore wind development on an endangered whale species in a key ecosystem will be hard to distinguish from the ongoing impacts of climate change.
The report looks at the Nantucket Shoals, a unique shallow area southeast of Massachusetts that supports an aggregation of the zooplankton consumed by the ton by the North Atlantic Right Whale, which migrates there to feed.
Nine federal wind lease areas are clustered in 900,000 acres just west of the shoals; two utility-scale wind farms are being built there now, and several others are in varying stages of development.
Full buildout would entail up to 700 turbines in a grid pattern across the area.
One of the regular talking points of offshore wind opponents is the effect of offshore wind power on the rare leviathans, roughly 340 of which are believed to remain in the world. Offshore wind opponents often focus on the risk of whales being struck by ships or harmed by construction noise, but the new report focuses instead on a more subtle effect: hydrodynamics — the structure and movement of ocean water — and how it would affect the ecosystem there.
“Potential Hydrodynamic Impacts of Offshore Wind Energy on Nantucket Shoals Regional Ecology: An Evaluation from Wind to Whales” was sponsored by the Bureau of Ocean Energy Management and compiled by the National Academies of Sciences, Engineering and Medicine.
Offshore wind development is new to the United States, so there is no domestic data from which to estimate its impacts on the shoals. Modeling limited data from North Sea wind farms suggests offshore wind can modify water circulation and ecology, the authors write, and the impacts can extend beyond the region of the wind farm.
But the North Sea is different from the U.S. Outer Continental Shelf.
The shallow area south of Nantucket already is known for its complex hydrodynamics and ecology, even before the first wind turbines start spinning: It can contain warm eddies that break off the Gulf Stream, bottom friction, tidal mixing and stratification.
It is the site of numerous shipwrecks, as well. For decades, lightships were stationed on the south edge of the shoals.
Copepods thrive there. A cubic meter of water can contain more than 100 of each of several of the tiny zooplankton species during the springtime peak. The North Atlantic Right Whale eats a few thousand pounds of zooplankton per day, and nothing else.
A decade of surveys found the whales’ presence increasing in both the shoals and the wind energy areas, but this may be due to the zooplankton concentration increasing there or decreasing in other feeding areas.
Precautions are in place to protect whales and other large sea mammals from injury during construction of the Vineyard and South Fork wind projects, and they would presumably be imposed during future projects not yet approved.
When construction is complete, the more subtle effects addressed in the report would begin: Dozens of monopile foundations would create underwater wakes and dozens of rotors up to 900 feet in diameter would create concentrated wind wakes above the water.
Zooplankton could increase or decrease in productivity or concentration as a result, to the benefit or detriment to the whales that eat it. Or there might be no effect at all.
The complicating factor is that the baseline against which these effects will be measured is itself moving, because of the naturally shifting character of the shoals from one decade to the next and the effects of human-induced climate change.
The fishing industry and others concerned about ocean ecology have been unhappy that offshore wind development is progressing so ambitiously with such large gaps in knowledge about its impacts.
“The studies available about the effects and implications of wind farms on local ecosystems are not sufficient to say with absolute certainty whether the turbines would have effects on specific parts of the Nantucket Shoals ecology,” said Eileen Hofmann, a professor and eminent scholar in the department of ocean and earth sciences at Old Dominion University who chaired the report committee.
“But with everything we do know at this time, we conclude that those effects are difficult to compare to the impacts of all the other forces changing the hydrology in the region already, especially with the existing and future effects of climate change. Research and monitoring will be essential as these projects move forward in the Nantucket Shoals and other areas around the globe.”
The report recommended further observation during construction and continuing all the way through the operation and decommissioning phases.
A consortium has begun working to anticipate the charging infrastructure needed in the next 20 years for heavy-duty electric trucks across nine Northeast states.
National Grid is leading the effort, which benefits from a $1.2 million grant from the Department of Energy. It will result in a road map predicting the supporting infrastructure needed for electrified transport of goods in one of the nation’s busiest areas.
Nearly 3,000 miles of interstate highway corridors in New York, New Jersey, Pennsylvania and New England will be examined, with major commercial zones such as the Port of New York and New Jersey folded in because of their traffic density.
National Grid will coordinate its efforts with CALSTART, which received a similar DOE grant to map out truck-charging needs across a smaller area running south to Georgia.
Combined, the two analyses will span 3,700 miles across 15 states and movement of more than 300 million tons of freight through East Coast ports.
Brian Wilkie, National Grid’s director of transportation electrification in New York, said 100 charging sites will be analyzed initially but their ranks will be winnowed down to about 30 as the “Northeast Freight Corridors Charging Plan” takes shape.
The final product will be offered as a starting point for decisions on how to prepare for electrification of heavy trucks, as is mandated in some states. Given the rapid technological evolution of vehicles, storage and charging, Wilkie said, the report will not be a final action plan but a road map for drawing up action plans.
The speed of transportation electrification is almost certain to exceed the speed of transmission development, he said, so it’s imperative to build infrastructure before the need arises — a concept traditionally anathema to transmission planners because of risk of overbuilt or stranded assets.
“Our infrastructure won’t be able to keep pace if we don’t start building ahead of the need,” Wilkie told NetZero Insider on Tuesday. “Given what we see in the [building] heating electrification space and the transportation electrification space, we’re not going to have much in the way of stranded assets.”
CALSTART President John Boesel pointed out the policy benefits of the study, as well. He said in a news release: “The I-95 Corridor project, once completed, will put into practice the integration of zero-emission vehicles, infrastructure and addressing climate-change issues that has been carried out in other areas of the country. The successful implementation of this project will put to rest the unfounded concerns of zero-emission opponents by demonstrating that this technology is both economically feasible and a benefit to all.”
There is no estimate at this point how many plugs and gigawatts would be needed for a Northeast truck charging network.
But in 2022, the first-in the nation “Electric Highways Study,” also led by National Grid, concluded a network of about six dozen fast-charging plazas would be needed for light- and heavy-duty vehicles just in New York and Massachusetts, each able to meet 2045 peak demand of 15 to 40 MW, perhaps even more.
That is like adding a mix of 72 athletic stadiums, small towns and large factories to the grid. With the associated upgrades in generation and transmission, it’s a major undertaking.
Add seven more states and include heavy-duty fast chargers drawing up to 1 MW each and the challenge of electrifying trucking becomes clearer, even if it cannot be quantified yet.
The new study builds on its predecessor but will take a broader perspective.
National Grid is joined in the effort by Clean Communities of Central New York, the National Renewable Energy Laboratory, the Northeast States for Coordinated Air Use Management and RMI.
The effort is technology-neutral, and it must be, given that emissions-free transportation will evolve to a significant degree but in unknown directions over the next 20 years. The assumption is that hydrogen will account for only a small fraction of the heavy-duty fleet and that new wireless charging concepts will not be part of the mix.
Generation and transmission capacity are not part of the study because they are the purview of the RTOs in the nine-state region, but the RTOs’ input will be sought.
The study is focused instead on point of delivery. National Grid is working with industry and other utilities to better estimate the need for chargers and the need for local infrastructure to support them, such as substations.
“One of the things that makes this transformational, one we’re very proud of, is traditionally, transportation planning has happened in one silo and utility planning has happened in another, and they’ve never really spoken to each another,” Wilkie said.
But now they are working together on an integrated structure, and this will be central to the success of the effort.
“It hasn’t been easy. We speak different languages, but here we’re trying to get all the right stakeholders in the room to have that conversation,” he said.
When the study wraps up, the report goes to DOE for consideration.
“We’re trying to make this plan as actionable as possible,” Wilkie said. “So, not just identifying the power needs but the utilities that we partner with will all be looking at, ‘How would you serve a load like that in that particular place in our territory?’”
That’s the underlying question the study seeks to address, if not completely answer.
“There’s a lot of unknowns about where all this charging will take place and what the power needs are,” he said. “We don’t know the exact number, but we know the numbers are pretty big.”
Just three of MISO’s 11 member sectors voted to support the RTO’s nearly $9 billion 2023 Transmission Expansion Plan (MTEP 23).
The Environmental, Transmission Owners and Transmission-Dependent Utilities sectors voted in favor of recommending MTEP proceed to the MISO Board of Directors for approval. Other sectors either abstained from voting or did not cast votes. No sectors registered opposition to the portfolio, so the motion to move MTEP 23 forward is considered passed. (See MISO PAC Considers Lower, $9B MTEP 23 Transmission Package.)
MTEP 23 now contains 572 new projects totaling almost $9 billion; 47% of that spending is destined for MISO South.
The low MTEP approval continues a trend of diminishing sector support for MTEP portfolios. In 2022, four sectors voted in favor of the $4 billion MTEP 22. In 2021, six sectors supported the $3 billion MTEP 21.
At an Oct. 18 Advisory Committee teleconference, WEC Energy Group’s Chris Plante asked why so many sectors didn’t register votes this year.
“For a sector to not submit a vote and not explain why, that’s concerning,” Plante said.
Three MISO sectors — the End-Use Customers Sector, Public Consumer Sector and the State Regulatory Sector — regularly abstain from voting on MTEP packages. This year, the Competitive Transmission Developers sector again joined in the abstentions.
LS Power’s Brenda Prokop said the volume of “other” category projects and baseline reliability projects this year was cause for concern among the Competitive Transmission Developers. She also said there’s little transparency into transmission owners’ cost estimates for the sector to confidently back the slate of projects.
Energy consultant Jim Dauphinais said the End-Use Customers Sector doesn’t weigh in on projects because it doesn’t have the resources to conduct a thorough vetting of all MTEP projects. He said his members’ positions on projects are best handled individually in state regulatory processes.
MISO and its System Planning Committee of the Board of Directors held the first of two meetings Oct. 17 to devote more review and discussion to MTEP 23 and the stakeholder comments attached to the draft report this year. MISO’s System Planning Committee typically holds just one meeting in November to consider the annual MTEP.
Senior Director of Transmission Planning Laura Rauch said, “given the magnitude of the projects,” directors needed more time to consider the most expensive MTEP in MISO’s history.
Rauch said most MTEP 23 projects are meant to solve reliability issues caused by localized load additions, especially in MISO South. She said MISO is not experiencing a regional, across-the-board increase in load that would justify regional project identification. She said MISO analyzed the largest MTEP 23 projects for potential as regionally cost-shared, market efficiency projects, but none could meet MISO’s minimum 1.25:1 benefit-to-cost requirement.
Rauch told directors that members’ comments this year on MTEP 23 likely will push MISO to consider HVDC and battery storage in future MTEP and long-range transmission plan (LRTP) portfolios.
She also touched on MISO delaying recommendation of the $260 million third phase of Entergy Louisiana’s Amite South reliability project into 2024 so it can better scrutinize the project.
“Certainly, we don’t think this is a bad project, but we need additional time for analysis,” Rauch said. She said MISO will bring the project back to board members once it completes its alternatives study on the project.
Rauch said the slew of large, reliability-driven projects in MISO South won’t impede MISO’s plans to focus on the South region for the third portfolio of its LRTP. MISO remains committed to discussing the scope of the third LRTP in 2024, Rauch said.
MTEP 23 will go before the full MISO Board of Directors for approval at their quarterly meeting on Dec. 7 in Orlando, Fla.
Relatedly, MISO this week launched a new MTEP Planning Portal, the nonpublic platform members use to submit and update MTEP project proposals.
FERC issued an order Friday giving itself more time to review the proposed $6.3 billion purchase of Energy Harbor by Vistra, saying it will now rule on the application by April 11, 2024 (EC23-74).
Commissioner James Danly said he would file a dissent on the order “tolling time for action” at a later date.
FERC issued a deficiency notice on the initial application in August.
The application had faced opposition from the Office of the Ohio Consumers’ Counsel, who argued it would impact the retail market in the state. PJM’s Independent Market Monitor and the U.S. Department of Justice urged FERC to ensure it did not lead to market power issues in the RTO. (See Vistra’s Deal for Energy Harbor Runs into Opposition at FERC.)
Vistra owns 9,200 MW of fossil fuel generation in PJM’s territory, including in Ohio and Pennsylvania, the two states where Energy Harbor’s 4,000 MW (largely three nuclear plants) are located.
In comments filed in August, the Justice Department said FERC should focus on the interaction of Vistra’s Richland plant, a 369-MW gas-fired combustion turbine in Ohio, with Energy Harbor’s three nuclear plants. The plant runs 10 to 15% of the time, and Vistra often offers it near the clearing price, it said. Combined with the nuclear assets, which run all the time and are price takers, the Richland plant gives Vistra the ability and incentive to withhold power to raise the prices that the much larger nuclear plants get, the department said.
Both DOJ and the Monitor have argued FERC must look at smaller geographic markets because the nuclear plants and some of Vistra’s existing generation are not able to sell to the entire PJM footprint because of transmission constraints.
Vistra has said that no local market power concerns exist because there are no frequently binding transmission constraints that would limit its ability to sell power from the plants far and wide in PJM.
DOJ wants FERC to use a supply curve analysis in its review of the application, which is something the department argued for when the commission issued a Notice of Inquiry on its merger reviews in 2016. That NOI was never acted upon by FERC, and Vistra argued it would be unfair and lead to regulatory uncertainty to change the rules for its specific merger case.
In comments filed earlier last week, the IMM said that FERC’s own deficiency notice recognized that the local market power issues “cannot be ignored.”
Vistra has proposed selling off the Richland plant and a much smaller Stryker plant (a 16-MW oil-fired plant) to ease market power concerns, but the IMM said last week that the divestitures — even to a firm that owns no capacity in PJM — would do little to quell them. The sales would cut market power in some local markets created by transmission constraints, but the combined firm would still fail the three-pivotal-supplier (TPS) test too often.
“But the reduction in the number of hours that Vistra fails the TPS test is not large enough to conclude that the proposed divestiture of the Richland and Stryker units would resolve the market power concerns,” the Monitor said. “Even with the divestiture, Vistra would have market power with respect to local constraints in the PJM market. Exercise of that market power to raise prices would raise energy market revenues for the Energy Harbor nuclear units.”
Vistra also argued that its ownership of the three nuclear plants will put them in a better financial position, ensuring their continued operation and the local jobs and tax benefits they bring. Ohio Senate Majority Leader Rob McColley (R) wrote FERC a letter early this month extolling those economic benefits.
“All of Ohio will benefit from the operations and preservation of these plants by a capable and responsible owner like Vistra, which successfully operates other electric generation plants, including nuclear, across Ohio and the country,” McColley wrote.
FERC on Friday granted NextEra Energy Transmission (NEET) Southwest’s request to recover 100% of “prudently incurred costs” to construct a competitive transmission project in New Mexico, should the project be abandoned or cancelled for reasons beyond its control (ER23-2630).
The commission agreed with NEET Southwest’s contention that the project faces certain regulatory, environmental and siting risks beyond the developer’s control that could lead to its abandonment. FERC said its abandoned plant incentive will address those risks by protecting NEET Southwest.
“Thus, we find that NEET Southwest has demonstrated a nexus between its requested incentive and its planned investment and that NEET Southwest has tailored its incentive rate request to its identification of risks and challenges associated with the project,” the commission said.
SPP awarded the NextEra subsidiary the Crossroad-Hobbs-Roadrunner 345-kV project in July. The project, 135 miles of double-circuit 345-kV lines at either end of the Hobbs generating substation, is estimated to cost $291.6 million and has a proposed in-service date of May 2026. (See SPP Awards NextEra 3rd Competitive Project.)
In August, NEET Southwest filed a request with FERC under Section 205 of the Federal Power Act and the commission’s 2012 policy statement on transmission incentives for incentive rate treatment.
The commission previously accepted the developer’s 2017 filing for a formula rate designed to be incorporated into SPP’s tariff. In its order, FERC also granted NEET Southwest’s request for several incentive rate treatments: a 50 basis point return on equity incentive for participating in an RTO or ISO; a regulatory asset for prudently incurred pre-commercial and formation costs for later recovery; and a hypothetical capital structure of 60% equity and 40% debt until its first transmission project is commercialized.
Commissioner Mark Christie concurred in a separate statement, but also called for FERC to revisit “the array of incentives offered to transmission developers.” Those include construction-work-in-progress and hypothetical capital structure incentives, and RTO participation adders.
“A core principle of utility law and regulation for decades is that consumers can only be forced to pay costs for assets that are ‘used and useful’ to them,” he wrote, noting that under Order 679, the commission may have to overlook that principle to address the “substantial challenges and risks” in building transmission facilities.
Christie said he previously questioned the commission’s determination of “whether ‘substantial challenges and risks’ exist when granting the abandoned plant incentive and other incentives has become nothing more than a check-the-box exercise.”
Consumers shy away from buying electric vehicles in New Jersey because of the high price and lack of charging infrastructure, and they’ll still be reluctant even if the state adopts California’s Advanced Clean Cars II (ACC II) rules, representatives of the vehicle sales and manufacturing sectors said at an energy conference last week.
Car manufacturers and dealers said they’re committed to the transition from gas to electric vehicles. But the ACC II rules don’t consider consumer attitudes.
Executives from the New Jersey Coalition of Automotive Retailers (NJ CAR) and North American Subaru voiced their concerns at a conference organized by New Jersey Business and Industry Association (NJBIA).
The ACC II rules require manufacturers to make EVs a steadily increasing portion of their car sales in New Jersey until all new vehicles sales are EVs in 2035. The New Jersey Department of Environmental Protection (DEP), which is accepting public comment on the rules until Oct. 20, is moving to adopt ACC II by the end of the year so they affect the 2027 car model year. The NJBIA is leading a coalition of businesses that oppose the rules. (See NJ’s Push Toward Clean Cars Rule Sparks Vigorous Debate.)
“When a consumer comes into the showroom, and they start shopping for a new car, and they are an ‘EV Intender,’ what winds up happening in the process is that they typically drive out with a hybrid or a plug-in,” said Jim Appleton, president of NJ CAR, referring to a hybrid gas-electric vehicle or a plug-in battery vehicle that also operates with gas.
One reason is that an EV can be $10,000 to $15,000 above the price of a gasoline vehicle, he said. Another reason is the lack of public chargers.
“If they are in a dealership, if they’re a multiple unit dwelling person, if they don’t live in a house with a garage where they can charge their vehicle every night, most consumers are walking out the door because they just don’t trust that the infrastructure is there,” he said.
Matt Forman, director of government and regulatory affairs for Camden, N.J.-based Subaru, said that although New Jersey is reasonably highly ranked in the nation by raw numbers of EVs, its charging infrastructure is lagging. The state is about sixth in the nation by the number of registered EVs, but has only about one charger per 40 EVs, when it needs one per seven EVs, he said.
“That’s the, I’d say, the biggest challenge,” Forman said. “That gap is growing. So for this to succeed, we need to see investment in charging, which traditionally is not the role of an OEM. But you’re starting to see OEMs actually putting money in charging.”
New Jersey had about 123,000 EVs in June, according to ChargeEVC, a pro-EV lobbying organization. But that’s a tiny proportion of the estimated 6 million light-duty vehicles registered in the state.
There are about 1,645 Level 2 chargers and 755 Direct Current Fast Chargers in the state, according to the DEP’s Drive Green website. And the state added another $12.7 million to incentive programs designed to encourage developers to install chargers at tourist sites, in multi-unit dwellings and in other locations. (See NJ to Add 400 EV Chargers with $12.7M Investment.)
Although New Jersey has a strong EV purchase incentive program, the weakness in the ACC II is that it focuses on sales to stimulate EV buyers, Appleton said. The regulation starts with a 35% ZEV sales requirement for model year 2026, increasing to 68% in 2030 before reaching 100% in 2035.
“The rule requires manufacturers to send cars, but unfortunately, it doesn’t require consumers to buy them,” he said. “Manufacturers will build what government mandates and they will ship them to dealers who’d be happy to sell them. But the flaw in this program has always been that it lacks a mechanism to require consumers to buy them.”
However, proponents of the rules — including government officials and environmental groups — say climate change requires an urgent, rapid uptake in EV adoption and the ACC II rules will trigger a much faster uptake than the state otherwise would see. Transportation is New Jersey’s biggest emissions source, generating about 40% of greenhouse gases.
Appleton said one impact of the ACC II is that it “corrupts the marketplace,” so that manufacturers will respond to the diminishing number of gas vehicles that can be sold in the state by focusing only on selling higher priced vehicles that give them a larger profit margin. He predicted the state’s dealers nevertheless would suffer as buyers seek gas vehicles out of state.
“I’m sure there’ll be dealers in Idaho, who will be trying to unload their inventory here in New Jersey, and they’ll be reaching out to you and you’ll be able to go online and buy a car in Idaho and they’ll flatbed it here in the state of New Jersey,” he said. “And the dealerships that do business here will lose business.”
OSW Developers Unbowed
In a separate panel, offshore wind (OSW) developers acknowledged the sector faces tougher opposition than in the past, but say they have no intention to back away from a key piece of the state’s energy future.
“I’m not going to sugarcoat it — it is really rough out there on the ground level,” said Crystal Pruitt, external affairs lead for Atlantic Shores Offshore Wind, one of three projects approved by the state. She said it’s difficult “having conversations with communities, having conversations with elected (officials) and policymakers and just seeing the turn of faith away from the policy goals that they were so supportive of.”
The conference followed the release on Sept. 28 of a poll by Stockton University that showed that 50% of those polled support the installation of wind turbines off the New Jersey coast, down from 80% in 2019. The poll was the second to show dramatically diminished support. A Monmouth University Polling Institute poll released on Aug. 29 showed support for offshore wind had dropped from more than 82% in the early 1980s to 54% now. (See Poll Shows Drop in Support for Offshore Wind in NJ.)
New Jersey is in the middle of its third offshore wind solicitation, having backed the 1,100-MW Ocean Wind 1 project in the first, in 2019, and the 1,148-MW Ocean Wind 2 and the 1,510-MW Atlantic Shores projects in 2021.
The polls follow months of growing opposition from Jersey Shore residents and representatives of the tourism and fishing industries who fear the turbines will harm business. Some opponents have seized on a series of whale deaths to boost opposition to the projects, depicting the deaths as potentially tied to the preliminary undersea work underway in preparation for the OSW projects.
State and federal investigators looking into the deaths say there’s no evidence the deaths are linked to the offshore work.
The developers also have faced challenges from rising costs and supply chain difficulties, which have raised questions about the economic feasibility of some projects.
Janice Fuller, mid-Atlantic president of Anbaric, a transmission development company, acknowledged the sector has faced some “negative attention, not just in New Jersey” but in multiple states in recent months. But she cast the downturn as “rationalization” from the unduly high support and expectations early on.
“We were very aggressive, set some really aggressive targets,” she said. “And right now the industry and the world, because of things that are outside of New Jersey’s control, are adjusting. Timelines are being adjusted, prices are being adjusted and a realistic schedule is going to emerge from that.”
“This is a little bit of a bump in the road, unfortunately,” she said, and blamed “misinformation about the industry and its impacts.”
