The CAISO Board of Governors approved a 10-year transmission plan Thursday that far exceeds the estimated cost of any similar plan in recent years, its price driven by the proliferation of renewable resources, predicted load growth and the state’s reliability concerns.
“The need for new generation over the next 10 years has escalated rapidly, driving an accelerated pace for new transmission development in this and future planning cycles,” Neil Millar, CAISO vice president of infrastructure and operations planning, wrote in a memo to the board.
CAISO identified the need for 23 transmission projects with an estimated cost of $2.96 billion — nearly 14 times more than the $217 million average over the past five years, Millar noted.
The next highest year, 2018/19, saw a need for $644 million in transmission projects. Other years were far less. CAISO found the state needed $5 million in transmission projects last year, $142 million of projects in 2019/20, $271 million in 2017/18 and $24 million in 2016/17.
The ISO adopts a 10-year transmission plan every year, but the forecasted need often varies dramatically based on circumstances. The 2020/21 transmission plan, for example, envisioned adding 1,000 MW of new resources per year. This year’s plan estimates a need for 2,700 MW per year, while next year’s plan could boost that figure to 4,000 MW, CAISO said.
To explain the increase, CAISO cited an “accelerated pace of resource development” based on decarbonization efforts and the planned electrification of the transportation sector, which state planners expect to drive up demand. California has a goal of 100% clean energy by 2045 and a mandate that all new passenger vehicles sold in the state be electric or zero-emission vehicles by 2035.
Reliability was also an issue. CAISO said the state will need generation and transmission development because of the potential for reduced imports from other Western states and high peak loads on hot summer evenings. Both factors contributed to the rolling blackouts of August 2020 and CAISO’s re-examination of its reliability risks.
CAISO also cited the need to replace several aging gas plants and Pacific Gas and Electric’s Diablo Canyon, the state’s last nuclear power plant. All are slated to retire in the next few years.
“The transmission system will need to be expanded, upgraded and reinforced to access and integrate these resources, as well accommodate the expected resurgence in electricity consumption as transportation and other industries electrify to reduce their carbon impact,” the plan said.
Sixteen projects, with an estimated price tag of $1.4 billion, are needed to meet load growth and the state fleet’s transition to renewable resources, CAISO said. They include two HVDC projects to serve Silicon Valley and the city of San Jose. Six policy-driven transmission projects, totaling $1.5 billion, are necessary to meet the generation requirements established by the California Public Utilities Commission’s renewable portfolio standards, the ISO said.
The plan will guide implementation, including initiating a competitive solicitation process for four high-voltage projects, the ISO said in a news release.
“Approval of the plan also sets in motion contractual agreements and cost recovery for transmission upgrades through ISO transmission rates,” it said.
The 10-year plan follows CAISO’s release on Jan. 31 of a first-of-its-kind 20-year transmission outlook. The outlook predicted a need for $30.5 billion of new high-voltage lines to transport wind power long distances across the West and to carry solar, offshore wind and geothermal power from in-state California generators to urban load pockets. (See CAISO Sees $30B Need for Tx Development.)
“While the 10-year plan is required by the ISO’s federal tariff and identifies specific projects for construction, the longer outlook is designed to provide a framework and longer-term vision for the system’s future transmission needs without recommending specific projects for approval,” CAISO said. “Together, the two documents will help map the short-term, intermediate and long-term milestones of the clean-energy transition, enabling rigorous and efficient planning coordination and creating the most cost-effective and durable transmission infrastructure to serve generations to come.”
NERC and the regional entities last week expressed support for “exploring ways in which market mechanisms can help ensure reliable operation” of the bulk power system and encouraged FERC and other stakeholders to take reliability into consideration when designing market enhancements.
The REs and NERC were responding to comments on the technical conferences held by FERC last September and October on energy and ancillary services markets in the electricity sector (AD21-10).
In the October conference, participants called for market participation rules to be revised to ease the entry of new and emerging resource types into wholesale electricity markets, while still incentivizing utilities to install the kind of energy products that can maintain grid reliability as the resource mix changes. (See Stakeholders Ask FERC to Support E&AS Market Changes.)
In their response, the ERO organizations acknowledged that while they play a direct role in reliability through the establishment and enforcement of reliability standards, assessing seasonal and long-term reliability, and training and certifying industry personnel, they do not take an active part in market design.
But while the ERO Enterprise declined to endorse specific market measures or incentives, its remarks pointed out that NERC’s “assessments over the past several years generally support policy enhancements which prioritize reliability under the transforming energy grid.” In particular, the groups highlighted last year’s State of Reliability Report, which laid out how “a rapidly transforming BPS has been impacted by a pandemic, extreme weather, cyber security, and supply chain issues.” (See NERC: Extreme Weather, Resource Changes Cause Mounting Concern.)
Reliability standards are not the only way to respond to these challenges, the ERO groups said; they function only as “part of a larger environment [comprising] overlapping energy regulation, markets, and jurisdictions.”
The ERO Enterprise reminded the Commission that NERC’s rules of procedure prohibit one of the organization’s standards from precluding market solutions as an approach to achieving compliance with it. As a result, reliability standards typically define only the desired result, rather than how to achieve it.
This does not mean that the methods for ensuring compliance must be left entirely to the utilities: NERC and the REs highlighted several comments that suggest ways that “market enhancements … may help address reliability concerns associated with the changing BPS.” Such market changes need not only involve NERC’s reliability standards but also can include proactive measures to promote reliability.
The Edison Electric Institute, for example, asserted that “market operators must be able to procure sufficient reserves and other ancillary services through the market,” even as the resources providing such services change. EEI urged FERC to ensure that RTOs and ISOs are working to make sure energy prices “reflect the full cost of the resources needed to reliably operate the system,” so that energy providers can accurately weight the costs and benefits of the resources they use.
MISO also got a mention from the ERO groups for asserting its efforts to ensure reliability through structuring the energy market, one of the pillars of the ISO’s “Reliability Imperative.” ISO-NE also noted in comments quoted by the ERO that “enhancements to the energy and ancillary services markets will be essential to [maintaining] reliable operations as the system transitions to … renewable resources whose uncertain output will need to be balanced using energy storage and a pipeline-constrained gas-fired generation fleet.”
“Well-designed ancillary service markets can help to ensure the system has all of the essential flexibility properties identified above — sufficient resources with dependable performance, sustainable output, and with the necessary response times to cover the increasing operational uncertainties and to provide a reliable system,” ISO-NE said.
As laid out in a report released Tuesday, Gov. Glenn Youngkin’s (R) main argument against Virginia’s participation in the Regional Greenhouse Gas Initiative (RGGI) appears to be that none of the $300 million the state has received to date from the 11-state cap-and-trade program is being used to provide rebates to customers.
Because the state’s main utility, Dominion Energy, is allowed to recover the cost of the carbon allowances it must buy to comply with the program from its “captive” customers, Virginia’s participation in RGGI has resulted in a “direct carbon tax” on residents and businesses, the report says.
Announcing the report, Youngkin reiterated his longstanding claim that RGGI is “a bad deal for Virginians,” invoking the added burdens that recent inflation is putting on residents “at the pump and at home.”
According to the report, Dominion’s recovery of its RGGI costs has added $2.39/month to residential utility bills and $1,554 to bills for industrial customers. According to figures supplied by Dominion to the State Corporation Commission, cited in the report, the utility expects that RGGI participation will cost customers a total of $3 billion through 2045.
These increases are framed as an “emergency situation” allowing the governor to issue an emergency regulation to take Virginia out of RGGI, according to a draft letter from Michael Rolband, director of the state’s Department of Environmental Quality (DEQ). The letter and a copy of the proposed regulation repeal accompanied the report.
Under Virginia law, an emergency regulation of this kind could stay in force for up to two years. A draft of a letter notifying RGGI of Virginia’s intent to withdraw is also included with the report.
Environmental and clean energy advocates were quick to criticize the report’s arguments and Youngkin’s plans for RGGI withdrawal.
“The report willfully ignores the massive benefits that come from our participation in RGGI,” said Chelsea Harnish, executive director of the Virginia Energy Efficiency Council, noting that half of the state’s RGGI funds go to energy efficiency projects for low-income residents. Another 45% goes to flood preparedness programs, with 5% allocated to cover administration costs.
Nate Benforado, a senior attorney with the Southern Environmental Law Center, slammed the report as “designed to support a partisan repeal effort rather than to provide an objective look at available information.”
The report actually finds that “RGGI is working very well,” Benforado said in an interview with NetZero Insider. While RGGI states have cut GHG emissions more than 30% over the past decade, the report shows that Virginia’s emissions have remained about the same, he said.
‘A Pretty Misleading Statistic’
Youngkin’s report counters that while Virginia’s emissions have not declined overall, the state’s “emission rate, which is the amount of CO2 emissions produced by a set amount of electricity, has steadily and significantly been reduced.”
But Benforado said such emission rates are “a pretty misleading statistic to look at” and can be attributed to the retirement of coal plants in the state and the increasing use of natural gas to generate electricity.
“When it comes to climate change, emissions rate doesn’t matter at all,” he said. “It’s all about the actual amount of CO2 you’re putting into the air. … Virginia has fallen behind the other RGGI states.”
Further, the report also acknowledges that without an emissions-reduction program like RGGI, Virginia will not be able to meet the clean energy goals of the state’s Clean Economy Act, which requires Dominion to decarbonize its system by 2045, Benforado said.
“It seems like the issue the governor really has is less about RGGI and more about the cost to customers,” Benforado said. “If the governor is sincere that that’s his concern, then we should address that; repealing RGGI doesn’t fix that problem.”
RGGI was founded in 2009 as a regional “cap-and-invest” program, according to its website. Participating states set annually decreasing caps on carbon emissions from power plants, which must then buy allowances issued by the states to offset their emissions. One allowance offsets 1 ton of carbon dioxide. States can invest their RGGI funds in clean energy, energy efficiency or GHG abatement programs or in rebates and bill credits to customers.
With allowance prices topping out at $13.50, the most recent RGGI auction netted Virginia $74.2 million. | RGGI
As noted in the report, four states in RGGI — Delaware, Maryland, Maine and New Hampshire — do use a portion of the money they receive from RGGI’s quarterly auctions to provide rebates to customers to offset any increase in rates that comes from the program. Virginia’s program was originally designed to include customer rebates, the report says, but was later changed to split the money between low-income energy efficiency and flood preparedness programs.
J.R. Tolbert, vice president of strategy and partnerships for Advanced Energy Economy (AEE), defended the legislature’s decision to split Virginia’s RGGI funds as it did. According to Youngkin’s report, to date, the flood preparedness program has received more than $150 million in funding, while low-income energy efficiency programs have received more than $135 million.
“The governor seems to have picked a boogeyman in RGGI versus actually providing solutions on big issues, whether it be a rebate [or] how he would replace the money that’s going to communities all over the commonwealth dealing with rising water levels and how he would help low-income Virginians address energy efficiency needs in their homes,” Tolbert said.
‘The Courts Will Rule’
Advocates and Virginia Democrats have also argued that Virginia joined RGGI as the result of a 2020 legislative mandate (SB 1027), and therefore Youngkin does not have the unilateral authority to take the state out of the initiative.
“The legislature codified Virginia’s participation in RGGI, and in order for the state to withdraw from RGGI, the legislature would have to make that decision,” Tolbert said.
While Tolbert said AEE is not planning to take the governor to court, he expects that others will. “I think the way this plays out is that the courts will rule that we continue to stay in RGGI until the legislature decides otherwise,” he said.
However, an analysis from industry analysts ClearView Energy Partners suggests that the law may not codify RGGI, creating a fine point for the courts to decide. The language in the 2020 law “authorizes” the DEQ to design and implement Virginia’s RGGI program, ClearView said. Such language could be read as giving the DEQ permission for a RGGI program but not necessarily a mandate.
Tolbert, who advocated for the bill at the time, disputes that interpretation. “The legislative intent was that this was a mandate,” he said. “The reason they passed the law in the first place was because they wanted to take that extra step.”
Air Pollution Control Board
After his victory over Democrat Terry McAuliffe in the November election, Youngkin came into office vowing to take Virginia out of RGGI and signed an executive order to begin the process just hours after his Jan. 15 inauguration. (See Youngkin Takes 1st Steps Toward Va. RGGI Withdrawal.)
The order directed the Department of Natural Resources and DEQ to conduct a new cost-benefit study of Virginia’s RGGI participation and draft the letters and emergency regulations that would allow Youngkin to circumvent the legislature in taking the state out of the initiative.
With a Democratic majority in the state Senate opposing any effort to repeal the RGGI mandate, Youngkin’s strategy depends on the State Air Pollution Control Board. At the time of his inauguration, the board had a solid majority of members who had been appointed by former Gov. Ralph Northam (D). It had approved the regulations setting up Virginia’s participation in RGGI by a 5-2 vote and appeared unlikely to reverse that decision.
In the interim, however, the Senate rejected Andrew Wheeler, the former EPA chief under President Donald Trump, as Youngkin’s secretary of natural and historic resources. Wheeler, along with Rolband, was responsible for leading the RGGI withdrawal efforts. Youngkin has since made Wheeler a senior adviser, a post that does not need confirmation. (See Va. Senate Committee Rejects Wheeler Nomination.)
At the same time, the General Assembly rejected two members of the Air Pollution Control Board — Joshua Behr and Richard Langford — who had been nominated by Northam but not yet confirmed, leaving two vacant seats, according to DEQ spokesperson Anissa Rafeh. Two other members, Vice Chair Kajal Kapur and Gail Moore, term out in June.
New Jersey will spend $3.425 million on three initiatives to research the impact on wildlife and fisheries of the state’s two planned offshore wind projects, which commercial fishermen believes could be severe enough to damage the industry.
The New Jersey Department of Environmental Protection (DEP) and New Jersey Board of Public Utilities (BPU) said they will coordinate two projects funded through the state by the developers of the state’s two most recently awarded offshore wind projects: Ocean Wind II and Atlantic Shores.
The awards include $865,440 for a project led by Rutgers University to develop a “specialized surf clam dredge to conduct research in areas where harvesting” of clams takes place in what will soon become wind-turbine lease areas, according to a release by the two departments. The study will be conducted in partnership with Northeast Fisheries and Surfside Seafood Products and the National Oceanic and the Atmospheric Administration.
The second study, costing $2.5 million, will focus on gathering data to assess the turbines’ impact on physical oceanographic conditions such as seafloor topography, sunlight availability and water temperature. The study will be conducted by Rutgers using an underwater glider.
Financial support for the projects will come from the state’s Offshore Wind Research and Monitoring Initiative (RMI), which is funded by the developers of the two most recent of the three projects backed by the BPU. Denmark-based Ørsted is developing the 1,148-MW Ocean Wind II wind farm, and the developer of the 1,510-MW Atlantic Shores is a joint venture between EDF Renewables North America and Shell New Energies US.
The RMI also will provide $60,000 for the state to join the Regional Wildlife Science Entity, which supports research and monitoring on wildlife and offshore wind. That will support regional cooperation and sharing of research in the development of offshore wind energy, the DEP and BPU said.
In addition, the BPU and DEP will soon release a request for proposals for a “passive acoustic monitoring project to better understand the movements and behaviors of baleen whale species,” the two agencies said.
BPU President Joseph Fiordaliso said the funding will enable the state to collect “critical baseline data on whales and their movements along New Jersey’s coastline, as well as contributing to regional collaboration to study the impact of offshore wind development on recreational and commercial fisheries and our rich and diverse wildlife.”
“We are committed to developing New Jersey’s offshore wind resources in an environmentally sensitive and cost-effective way,” he said.
The two developers in their project leases committed $10,000/MW of project-size-awarded capacity — or about $26 million — to fund research and ecological monitoring of offshore wind, according to the BPU-DEP release.
The two projects followed the earlier BPU award of a lease to Ørsted for the 1,100-MW Ocean Wind I project. The state plans to hold at least three more solicitations to give the state a total of 7,500 MW of offshore wind capacity.
Fishery Concerns
Clam industry representatives have in the past expressed concern that the weight of clam dredges, which can weigh 5 to 7 tons when empty, and other nets, combined with unpredictable winds and currents through the turbines will make it difficult and dangerous for fishing boats to maneuver around them. Some tourist businesses fear the sight of turbines on the horizon and the potential damage to marine life during turbine construction could deter recreational fishermen from visiting the New Jersey Shore. (See Fishermen Fear the Impact of NJ Wind Farms.)
Fishing sector representatives were not impressed with research initiatives announced by the DEP and BPU.
Ronald Smolowitz, a technical adviser to the Fisheries Survival Fund, which represents scallop fishermen, called the initiatives “monitoring programs that may or may not benefit fisheries.”
“It reminds me of the TV commercial where the company monitors theft but doesn’t do anything about the theft,” he said. “I think the research needs to focus on seafood security [and] developing new methods and fisheries that are sustainable in this new environment of climate change and industrializing the ocean with wind farms.”
David Wallace, who represents several food processors along the East Coast that also own fishing boats, said he had “no problem” with the state’s initiatives to monitor the impact of the turbines.
“The problem is this should have been started 10 years ago,” he said. If it had, the state would have already built up a “long-term baseline study” of what was happening before the turbines arrived that can in the future be used as a comparison with changes resulting from the arrival of the wind farms, he said.
“We cannot resolve some negative impacts on habitat and whales after thousands of turbines are placed in the ocean,” he said. “The alteration of the ecosystem will be done and protection will be too late.”
Promoting Offshore Wind Research
The announcement of the studies came about a week after the New Jersey Economic Development Authority (EDA) approved agreements with four universities in the state to award grants totaling $1,080,000 to create fellowships “to advance academic research and investment in offshore wind learning.”
The funding is in line with the state’s effort to build an industry around its offshore wind projects that will position the state as a hub of investment, manufacturing, labor and logistics that can serve not only the state’s projects but others on the East Coast too. (See New Jersey Shoots for Key East Coast Wind Role.)
The fellowships will be created at Rutgers, Rowan University, Montclair State University and New Jersey Institute of Technology. The fellowships and related programs are intended to “strengthen linkages to offshore wind research by formally engaging New Jersey’s top public research universities and expanding the number of individuals with expertise in offshore wind in the state,” according to an EDA memorandum given to its board about the project.
The fellowships will support 24 undergraduate research fellows, and the funding is designed to help the universities build “long-term institutional expertise in offshore wind” and create a faculty that is “engaged in offshore wind-related research and learning,” according to the memo. Undergraduate fellows will receive a $15,000 stipend, and graduate fellows will receive $30,000, with the courses expected to begin in the fall of this year.
As part of the agreement with the universities, the EDA will organize a NJ Wind Institute Fellowship Symposium to review the research in April 2023.
MISO this week said it intends to sunset its longstanding stakeholder group dedicated to the grid operator’s loss-of-load expectation calculations.
The RTO would like to retire the stakeholder-led Loss of Load Expectation Working Group (LOLEWG) at the end of the year and fold its work into the Resource Adequacy Subcommittee (RASC), MISO’s Lynn Hecker told stakeholders during a LOLEWG teleconference Wednesday.
The LOLEWG is more than a decade old and helps prepare MISO’s annual loss-of-load expectation study, which generates planning reserve margin requirements for load-serving entities, zonal reliability requirements, and zonal import and export capabilities. Those limits are used in MISO’s capacity auction.
The sunset news comes as MISO is pursuing seasonal reliability targets as the footprint faces a more pronounced wintertime loss-of-load risk that could eventually top summertime risk. MISO’s internal analysis shows that renewable penetration and electrification adoption will push the region to become exclusively winter peaking by 2035.
Clean Grid Alliance’s Natalie McIntire said she was worried stakeholders might lose their forum to provide detailed input on such technical studies. She said she hoped loss-of-load topics wouldn’t be glossed over in RASC meetings with MISO’s new “post-only” agenda item format, in which the RTO publishes information but doesn’t prepare a presentation.
“I think the idea of a technical work group is helpful, and I don’t want to lose the … dialogue and discussion,” McIntire said.
Hecker said that by sunsetting the working group, MISO would end duplicate loss-of-load conversations in both the LOLEWG and the RASC. MISO will reserve time for loss-of-load discussion in the RASC only if the subjects are deemed noteworthy, he said.
“The short answer is, ‘it depends on the importance of the topic,’” Hecker said.
LOLEWG Chair James Peters asked if stakeholders could reconvene the working group if they think the RASC isn’t adequately covering loss-of-load topics.
MISO customer relations said stakeholders, with approval from the stakeholder-led Steering Committee, could always create a new task team, working group or task force devoted to loss-of-load expectations.
The RTO will hold another discussion in July on possibly sunsetting the group by the end of 2022.
Because many of the technologies key to decarbonizing the nation’s industries by midcentury don’t exist on a commercial scale yet, the Biden administration is trying something previous peacetime governments may not have dared: organizing industries and their prospective customers to create demand for carbon-free energy and services.
The administration announced the First Movers Coalition in November 2021, at the start of the U.N. Climate Change Conference in Glasgow.
Described by the Atlantic Council as a partnership between the U.S. departments of State, Commerce and Energy and the World Economic Forum, the effort drew immediate support from 34 founding member companies focusing on aviation, shipping, steel and trucking.
On Tuesday, the Atlantic Council hosted representatives of two of those companies, Ørsted and United Airlines (NASDAQ:UAL), for a discussion about their goals and how they see First Movers enabling them to meet those targets. Also in the forum was a State Department representative key to keeping the overall goals in view.
“You’re trying to bring these decarbonization technologies to market by creating market demand. How is it working? Are you pleased with the progress so far?” asked moderator David Goldwyn, an Atlantic Council senior fellow.
Pamela Venzke, head of corporate affairs for Ørsted North American Offshore, said the company quickly realized the coalition “could lead to the clean energy future we wanted to build.”
“We’re well on our way, internally, for our portfolio being net zero by 2025. We can do that; we can make that decision ourselves. Decarbonizing our supply chain? That is a really big challenge, and it’s not something that we can do alone,” she said.
Calling First Movers “a roadmap,” Venzke said 50% of the “life cycle emissions of a wind farm come from steel. That’s a substantial number.
“What can we do to correct that? We are working right now with our supply chain partners to look at near-term incremental changes … greater efficiency in production [and] recycled steel,” she explained. “But what doesn’t exist today is net-zero or even near-zero steel for the steel plate market that we need for the offshore wind industry.”
That led the company to begin investing in green fuels, an entirely new business for Ørsted. “We have created a new business around e-fuels. We have announced a partnership with Maersk to do green fuels for the shipping industry. That also plays with an opportunity with the steel industry.”
She explained that the company has a tentative agreement with a European steel producer, which she did not name, to provide it with power generated with a low-carbon or carbon-free e-fuel.
“Then we do a green steel purchase from them. So, it’s kind of a circular approach that we feel really good about,” she said.
Asked how much the green steel would add to the price of power produced by the company’s offshore wind farms, Venzke said the price differential would be about 5% more compared to using steel produced by conventionally produced energy.
“But first there is a huge investment that needs to happen to build out these product lines,” she added. And that’s one area that the Department of Energy’s Loan Programs Office is already looking at.
“You know, if we want a U.S. supply chain in this area, we do need assistance in getting that started. And we have had [talked to] people within this administration that are ready to go and ready to help. It’s going to be really important, not just for steel, but across the board,” she said.
Lauren Riley, managing director of global environmental affairs and sustainability for United, said that in aviation, clean fuels such as biofuels, which the company is already testing, are two to four times the cost of fossil fuels.
“We spend a lot of time talking with our corporate customers. They are staring at their emissions, which are by and large from business travel, or were prior to the pandemic; and they don’t know how to partner with us to really effect permanent change. They have been true advocates to really push the industry forward faster,” she said.
“We recognize that we have a crisis looming. We do impact the temperature rise on this planet. We are a hard-to-abate industry. We take responsibility for that. We are going to continue to invest so that one day we can fly hopefully no-carbon, but certainly low-carbon,” she said.
Moderator Goldwyn noted that there are many steelmakers and many airline companies.
“How do First Movers propagate this information about developments that are happening in one space around the world? What’s next, in terms of the coalition, for driving this, driving all these industries forward toward decarbonization?”
Varun Sivaram, senior director for clean energy and innovation for U.S. Special Presidential Envoy for Climate John Kerry, explained a little of what the administration is doing to foster greater communication among First Mover companies in the U.S. and globally.
“We try and keep an open line of communication. We’re now going to launch the sectoral-focused workshops so that companies that have made the aviation commitment [like] United can talk to your customers.
“Apple has also made the commitment, and you guys can share both lessons and strategize on how you’re going to get the cost of these premium products down a little bit,” he added.
“We’ve tried to set up an infrastructure that allows for information sharing within the U.S. but also with our global set of companies.
“The hope is that we’ll keep this cadence up. We’ll have annual reporting that comes out at the end of this year and going forward, and our companies will form a community committed to realizing the advanced market commitment,” he said.
U.S. critical infrastructure entities will soon be required to report significant cyber incidents to the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA), under the omnibus spending bill signed into law by President Joe Biden on Tuesday.
Congress passed HR 2471, the Consolidated Appropriations Act 2022, last week. Division Y of the bill is the Cyber Incident Reporting for Critical Infrastructure Act of 2022. A similar law was proposed in the House of Representatives last year but failed to make it past committee.
The new bill requires covered entities — those “in a critical infrastructure sector, as defined in Presidential Policy Directive 21” and further defined through rulemaking by CISA’s director — to report relevant cyber incidents to CISA within 72 hours after the entity “reasonably believes that the covered cyber incident has occurred.” Authority for defining which incidents are subject to reporting is delegated to the CISA director.
Entities are also required to report to CISA when they have made a ransom payment to the perpetrators of a ransomware attack. The report must be made within 24 hours after the payment takes place. This requirement applies even if the ransomware attack is not otherwise subject to the reporting mandate found elsewhere in the law.
If the entity does have to report the ransomware attack, it may submit a single report for both the attack and the ransom payment. In addition, entities already required to report cyber incidents to another federal agency will not be required to do so to CISA as well, provided the agency has agreed to share such reports with CISA and they meet the requirements set by the director.
Entities will have to supplement their reports if “substantial new or different information” comes to light, and they will also be required to preserve any data that bears on their disclosures.
CISA is to issue a notice of proposed rulemaking regarding the matters left to the director’s discretion within the next two years, with a final rule to follow within 18 months after the NOPR. The final rule will also specify what content entities must include in their cyber incident and ransom payment reports, as well as the data preservation requirements.
Once the rule is in place, CISA must provide monthly briefings to congressional leadership on the national cyber threat landscape based on reports it has received. The agency may also share incident and ransom payment reports with other federal agencies, though the data may only be used:
for cybersecurity purposes;
to identify a cyber threat or security vulnerability;
to respond to, prevent or mitigate a specific threat of death or serious bodily or economic harm;
to respond to, investigate, prosecute, prevent or mitigate a serious threat to a minor; or
to prevent, investigate, disrupt or prosecute an offense arising out of a reported cyber incident or ransomware attack.
CISA may also compel entities to release information on suspected cyber incidents or payments through subpoenas and civil lawsuits. Entities that do not provide information voluntarily are not eligible for provisions in the law that provide anonymity for reports.
NERC, CISA Applaud Requirements
NERC praised the new legislation in a statement to ERO Insider, calling it “an important measure to protect critical infrastructure from persistent cyber threats” and a “further enhancement” to the information-sharing operations of NERC and the Electricity Information Sharing and Analysis Center (E-ISAC). The organization said it will continue to “monitor the rulemaking process … particularly the requirements for reporting incidents to ISACs and any other provisions which further our coordination efforts with our federal government partners.”
In a statement issued after the bill’s passage last week, CISA director Jen Easterly called the legislation “a game-changer [and] a critical step forward in the collective cybersecurity of our nation.”
“CISA will use these reports from our private sector partners to build a common understanding of how our adversaries are targeting U.S. networks and critical infrastructure,” Easterly said. “This information will fill critical information gaps and allow us to rapidly deploy resources and render assistance to victims suffering attacks, analyze incoming reporting across sectors to spot trends, and quickly share that information with network defenders to warn other potential victims.”
Two renewable energy industry groups are asking federal regulators to address what they say are unfair preferences given to gas-powered generators in ISO-NE.
In a Section 206 complaint filed with FERC this week, RENEW Northeast and the American Clean Power Association wrote that ISO-NE’s rules and practices around capacity accreditation and operating reserve designation don’t adequately take into account the uncertainty of natural gas supply in the region, particularly in winter.
The undue preference, they say, harms almost every other type of generation resource in the region.
The complaint says that ISO-NE’s capacity accreditation for gas-only resources is an “outlier,” in that the grid operator treats them as equivalent to resources with dedicated, on-site fuel supplies despite “known uncertainties with fuel availability for gas-only resources in winter peak conditions” — the well-established pipeline constraints that have been in play in New England for years.
ISO-NE’s qualified capacity rating for a gas generator is based on a test that only confirms the physical ability of the resource to convert fuel into energy, and not its access to that fuel.
“Gas-only resources receive an undue preference by being treated the same way for capacity accreditation as generators with known, dedicated fuel supplies, in spite of uncertainties about the ability of gas-only generators to obtain gas supply in peak winter conditions,” the complaint says.
The groups also contend that the grid operator’s operating reserve designation involves similar undue preferences, because gas-only resources are again unique in that they’re not required to prove the availability of fuel.
“A gas-only resource that cannot find gas is the same as a wind resource without wind or a solar resource without sun,” said RENEW executive director Francis Pullaro. “There is no justification to treat gas-only resources in a different manner.”
ISO-NE spokesperson Matt Kakley said the grid operator is reviewing the filing, noting that the RTO has already started a stakeholder process to improve its capacity accreditation. In its 2022 work plan, the RTO says it is aiming to find methodologies to “appropriately accredit resource contributions to resource adequacy as the resource mix transforms,” with a tentative plan to have a filing to FERC by the end of the year.
The primary method under discussion for doing so is effective load carrying capability (ELCC).
“A commitment by ISO-NE to timely take steps through ELCC implementation to set winter capacity ratings for gas-only resources consistent with the level that could be fueled on a cold winter day would be a positive step,” the renewable groups wrote in their complaint.
By 2035, zero-emission medium- and heavy-duty vehicles (MHDVs) — from delivery vans to 18-wheelers — should be no more expensive to buy and operate than those that run on diesel, according to a new study from the National Renewable Energy Laboratory (NREL).
With that kind of price parity on the horizon, electric trucks could make up 42% of new MHDV sales by 2030 and close to 100% by 2045, the report says.
Those timelines map out “a clear pathway for trucking companies to make the switch from diesel to electric that will help them cut costs and pollution for their customers, while combating climate change,” Energy Secretary Jennifer Granholm said in the March 7 press release announcing the study.
Based on 2019 figures, MHDVs produce about 445 million metric tons of carbon dioxide per year, 21% of the U.S. transportation sector’s total emissions, the report says. While California and other states are attempting to reduce those emissions with rules requiring that increasing percentages of new truck sales be electric, the NREL report builds on the assumption that adoption of these zero-emission vehicles (ZEVs) will be driven by economics by comparing total cost of ownership (TCO).
By 2050, zero-emission vehicles will make up 80% of all trucks on the road, but the 20% of older ICE trucks will use 50% of the energy needed to power the U.S. fleet.
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NREL
A key metric for fleet owners and drivers, TCO includes not only the upfront costs to buy a vehicle, but also its fuel, maintenance and resale value. The report plots the time frames for when battery electric or fuel cell electric vehicles (FCEVs) will reach price parity with comparable diesel vehicles.
The upfront purchase price for an electric MHDV is generally higher than a traditional diesel-powered vehicle with an internal combustion engine (ICE) at present, while fuel and maintenance costs are lower. A 2021 study from the Lawrence Berkeley National Laboratory estimated maintenance for a heavy-duty diesel truck at $12,000 to $13,000 per year versus $6,500 per year for a comparable electric truck.
The NREL report projects that battery and fuel cell prices will trend down between 2035 and 2050, which will lower the overall costs for electric MHDVs.
Electric trucks may be two to three times more expensive than ICE vehicles, according to Fred Ligouri, a spokesperson for Daimler Trucks North America. The company’s Freightliner division has been working with customers to test out a small, preproduction fleet of electric MHDVs and will begin production on its heavy-duty model in late 2022, he said.
Drive More, Save More
The timelines for when ZEVs ― both battery electric vehicles and FCEVs ― will reach price parity with ICE vehicles depends on the vehicle type — medium or heavy duty — and the distances they travel.
For example, the study finds that a heavy-duty battery electric truck with a range of 300 miles and traveling 100 to 500 miles per trip will reach price parity with a similar diesel vehicle around 2033. But if the truck is used for shorter trips, the break-even point is pushed back to 2041.
The correlation between these short distances and later break-even points holds true across different classes. “It’s not a technical problem; it’s mostly a matter of cost,” said Matteo Muratori, team leader for integrated transportation and energy systems analysis at NREL.
With EVs, “you spend more money when you buy the vehicle, but the more you drive it, the more money you save,” Muratori said in an interview with NetZero Insider. “Vehicles that are driven more save more and reduce emissions more; vehicles driven less save less. It takes longer to recover the initial capital cost.”
At the same time, he said, range matters; an electric truck with a range of 150 miles could reach price parity sooner than one with a range of 300 to 500 miles. “Shorter-range vehicles make more economic sense in the near term, and the longer-range vehicles start making economic sense when you get closer to 2030 or 2035,” he said.
Price parity for FCEVs also varies. For medium-duty vehicles, price parity with diesel is expected in 2031, while for heavy-duty FCEVs, the break-even point comes in 2033 or 2034.
Based on these projections, the report estimates that by 2045, 80% of all medium- and heavy-duty trucks on the road could be ZEVs, cutting emissions 69% from 2019 levels.
The report also notes that electric buses have become the leading edge in this transition, as they are already cost-competitive with diesel vehicles “in certain contexts … depending on vehicle and fuel prices and driving requirements.” The TCO for battery electric buses is anticipated to be “well below” that of diesel buses by 2032, the report says.
The Caveats
The NREL report comes with caveats, the most significant of which is the volatile nature of diesel prices. With the war in Ukraine and ban on Russian oil imports driving record spikes in prices, ZEVs could attract a wider range of buyers.
“Diesel is never the cheapest solution anymore because it is priced higher,” Muratori said.
Megawatt chargers will also be needed to keep EVs competitive, he said, and in some instances, FCEVs may be more time- and cost-efficient than battery electric vehicles because fuel cells run on hydrogen, which allows quicker refueling.
“If hydrogen is really cheap and electricity is really expensive, fuel cell vehicles make a lot more sense and vice versa,” Muratori said.
The report’s focus on bottom-line economics also leaves out key variables that may affect the speed and scope of electric truck adoption, such as the time and cost of building out the charging and refueling networks and the supply chains that will be needed to transition the U.S. MHDV fleet. The potential impact of increasingly rigorous federal and state emission reduction and fuel efficiency standards are also not discussed.
For example, California’s clean truck rules have been adopted by five other states: Massachusetts, New Jersey, New York, Oregon and Washington. The rules require that 55% of light-duty truck sales be ZEVs by 2035; for MHD trucks, the requirement is 75% by 2035, goals that will likely affect adoption rates and market growth in those states.
Muratori said the impacts of infrastructure, supply chain and regulatory issues will be important to track as the market evolves. But echoing the report, he argues that economics will drive ZEV adoption in the commercial truck and freight sectors, and demand could rise quickly once cost parity is reached.
More IIJA Funds
Underlining to the feasibility of widespread adoption of electric MHDVs, the NREL report was released alongside a series of White House announcements intended “to advance clean heavy-duty vehicles, as part of our electric, zero-emissions transportation future,” according to a March 7 fact sheet.
While not directly related to price parity, EPA’s new proposed regulations to cut tailpipe emissions of nitrogen oxides from heavy-duty trucks were framed as a stimulus to “jump-start the transition to zero-emission vehicles in the heavy-duty fleet,” the fact sheet said. The target for 2045 is a 60% emissions reduction.
The proposed regulations would also set stricter standards for greenhouse gas emissions for trucking sectors that are already seeing faster adoption of EVs, such as school and public transit buses and commercial delivery trucks.
Other funding announcements rolled out with the NREL report include $17 million from EPA for electric buses to replace diesel vehicles in underserved communities, and $450 million from the Infrastructure Investment and Jobs Act (IIJA) for projects that will cut greenhouse gas emissions at U.S. ports.
The White House continued to push forward on heavy-duty vehicle electrification with Monday’s announcement of another round of grants for 70 projects to improve and electrify public transportation in 39 states. The $409.3 million in funding from the IIJA will be used to “modernize and electrify America’s buses, make bus systems and routes more reliable, and improve their safety,” according to a Department of Transportation press release.
“These grants will help people in communities large and small get to work, get to school, and access the services they need,” Transportation Secretary Pete Buttigieg said in the release. “Everyone deserves access to safe, reliable, clean public transportation.”
Among the grantees, the Connecticut Department of Transportation is getting $11.4 million to buy electric buses, while the Regional Transportation Commission of Southern Nevada will receive close to $5 million for new hydrogen fuel cell buses, according to the release. Still more projects will be funded over the next five years with $5.1 billion in IIJA dollars, the release said.
The New York Public Service Commission on Wednesday heard updates on how the state’s utilities are responding to the PSC chair’s pleas to improve billing practices and customer outreach in the light of this winter’s electric and gas bill surges on higher natural gas prices.
NYPSC Chair Rory Christian | NYDPS
“It bears pointing out that the price spikes we’ve recently seen are not something limited just to New Yorkers. This is a global issue, a national issue, and it’s affecting everyone from Maine to California,” PSC Chair Rory Christian said. “Customers already struggling with a global pandemic are now faced with rising inflation, rising energy costs, and concerns that the war in Ukraine could have far greater impacts in the near term and long term.”
Christian said the PSC has instructed utilities to increase their outreach on the issue, adding that he’s “optimistic” about the results of outreach efforts.
Christian wrote to Consolidated Edison (NYSE: ED) on Feb. 11, directing the state’s largest utility to increase communications and improve its billing mechanisms to reduce dramatic changes in commodity prices from month to month, an issue that exacerbated price volatility for their customers, some of whom saw their monthly bills go up by as much as 67% this winter (Case No. 22-00346).
Revenue Strategies
The other major utilities — Con Ed subsidiary Orange and Rockland; National Grid; Avangrid subsidiaries NYSEG and RG&E; National Fuel; PSEG Long Island; and Central Hudson Gas and Electric — are reviewing their power purchasing to mitigate the risk of severe price volatility, retooling their consumer communications regarding anticipated bill increases, payment assistance plans and programs to reduce energy usage.
Aric Rider and Tammy Mitchell, NYDPS | NYDPS
Con Edison filed an emergency tariff to fix its billing by the summer and said that its hedging practices include reconciling benefits in a future bill, which resulted in a bill credit for its customers beginning with Feb 11 bills and continuing through March 14, said Tammy Mitchell, director of the Department of Public Service’s Office of Electric, Gas and Water.
“While Con Edison customers experienced commodity price and bill volatility, the hedges that Con Edison entered into saved full-service mass market customers over $120 million this winter through the end of February compared to if they were simply subject to market prices,” Mitchell said.
Due to the increases, the supply portion of a Con Ed customer bill jumped from 24% of the total bill in January to about 45% of the total bill in February, she said.
Additional state directives on better outreach are not really the solution to price volatility, Commissioner Diane X. Burman said.
“We need to call out some other state officials who may not fully understand we can’t just say that we have to educate consumers,” Burman said. “I can tell you if I was a consumer who had my checking account or savings account getting an auto withdrawal, and I have overdraft, and then all of a sudden money was coming out that I didn’t expect, I would be devastated. … We have to do better as a commission in understanding that in real time and responding to that.”
Nearly 25% of a Con Ed customer’s bill goes to the city of New York as general revenue, said Commissioner John B. Howard. He said that no one at the state or city level is addressing the issue.
NYPSC Commissioner John B. Howard | NYDPS
“The state of New York today and the city council could do things immediately to provide immediate rate relief to customers,” Howard said. “I believe they could even provide retroactive relief to customers if they take their own revenue requirements and deal with them appropriately.”
Addressing advocates for converting Con Ed to a publicly owned company, Howard said such a change would not alter the fact that $0.25 on every dollar it collects goes to taxes, not to providing service.
“It’s not just Con Ed, although it’s the most gross example across our state,” Howard said. “There are a variety of taxing jurisdictions — school districts, counties, cities — that put on extra taxes to their utility customers. They could take immediate action on their level to reduce bills.”
New Billing System Woes
The PSC also approved a third-party independent consulting company to audit the management and operations of Central Hudson’s electric and gas operations and grid modernization efforts (Case No. 21-M-0541).
For large electric and natural gas utilities such as Central Hudson, the law requires such audits at least once every five years.
In addition, state officials are reviewing the utility’s response to a February storm that left more than 67,000 homes and businesses without power, and are investigating billing problems related to the company’s recent upgrade to a new IT system that resulted in many customers not receiving timely monthly bills (Case No. 22-00497)
Poughkeepsie-based Central Hudson serves about 309,000 electric customers and 84,000 natural gas customers in the mid-Hudson region.
The utility tripled its complaint resolution staffing relative to normal operations, stated it has identified the problems within its new customer information system and is working with its implementation vendor and software engineers to resolve the problems by early next month, said Aric Rider, deputy director of the Office of Consumer Services.
“Central Hudson acknowledges that approximately 7% of its customers, or 21,000 customers, mostly customers that are specially billed, are still facing billing difficulties,” Rider said.
