A California incentive program for zero-emission trucks that depleted $63 million of funding in nine minutes last year is set to reopen next week, and officials are hopeful the money will last longer this time.
The Hybrid and Zero-Emission Truck and Bus Voucher Incentive Project (HVIP) will open at 10 a.m. on March 30, with $430 million in funding available.
The funding includes $196.6 million for standard requests, plus funds set aside for specific categories: $65.5 million for public transit buses; $46 million for class 8 drayage trucks; and $122 million for public school bus funding in small and medium air districts.
Last year, vehicle buyers quickly snapped up incentives offered through HVIP, a program that the California Air Resources Board (CARB) launched in 2009.
In the first wave of HVIP funding for 2021, which opened in June 2021, all $84 million in incentives were requested within three hours. A second wave of funding in August offered $12 million in incentives. In the third and final wave of funding for 2021 in October, HVIP offered $63 million in incentives and all the money was requested within nine minutes.
Pent-up Demand
During a CARB workshop on Thursday, agency staff said “pent-up demand” for the incentives caused by a period of limited funding contributed to last year’s rapid depletion. With more funding this year, along with policy changes such as reduced incentive amounts and a limit on the annual number of incentives per fleet, CARB is hopeful the money will last longer.
“We have the most robust budget we’ve ever seen for the HVIP program,” Andrea Morgan of CARB’s Mobile Source Control Division said. “And we think that a number of the policy changes that we put into effect in previous years will also help with demand. So we’re optimistic that the funds will last longer throughout the year, if not the entire year.”
And CARB is considering another restriction on HVIP eligibility: a fleet-size limit of 100 vehicles or fewer starting in 2023, falling to 50 vehicles or fewer in 2024.
At least one workshop participant opposed the fleet-size limit.
“We are very concerned about the categorical exclusion of the large fleets from the program … given what we see as the really important role they play in driving scale and gaining experience with [zero-emission vehicles],” said Andrew Schwartz, senior managing policy adviser for Tesla (NASDAQ:TSLA). “We really see them as very critical early movers.”
As an alternative, Schwartz suggested setting aside incentive money specifically for smaller fleets, while still allowing larger fleets to apply for the main pool of funding.
Range of Incentives
Since its inception in 2009, the HVIP program has issued 9,200 incentive vouchers totaling $604 million. More than 140 makes and models of zero-emission vehicles from 35 manufacturers are currently eligible for incentives, according to CARB.
Incentives vary based on the type and model of zero-emission vehicle. For example, incentives range from $45,000 to $85,000 for shuttle buses; from $85,000 to $198,000 for school buses; and from $85,000 to $120,000 for garbage trucks.
Last week’s workshop focused on CARB’s fiscal year 2022/23 funding plan for clean transportation incentive programs, including HVIP. Development of the funding plan is just getting started, and CARB has scheduled a series of meetings on different incentive programs.
A March 22 workgroup meeting will include a discussion of fleet-size limits in the HVIP program, CARB staff said. And during a yet-to-be scheduled workshop in May, results from this month’s HVIP funding wave will be discussed.
In addition to the funding wave opening on March 30, CARB is launching a new “innovative small e-fleets” pilot program within HVIP. The program is expected to open by early summer with $25 million in funds. The program is intended to help small trucking fleets and independent owner-operators with mechanisms such as flexible leases or peer-to-peer truck sharing.
CARB hosted a work group meeting on the program on March 3.
Below is a summary of the consent agendas scheduled to be brought to a vote at the PJM Markets and Reliability Committee and Members Committee meetings Wednesday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
Consent Agenda (9:15-9:20)
B. Stakeholders will be asked to endorse proposed revisions to Manual 12: Balancing Operations resulting from a periodic review. The changes include attachment references and other minor revisions.
C. Stakeholders will be asked to endorse proposed revisions to Manual 13: Emergency Operations resulting from a periodic review. The changes include new columns with winter values for estimated peak load and estimated load reduction in the voltage reduction summary table.
D. Stakeholders will be asked to endorse proposed revisions to Manual 18: PJM Capacity Market to conform with several recent FERC orders, including those on the minimum offer price rule, the market seller offer cap and the removal of the 10% cost adder for the reference resource used to establish the variable resource requirement curve. (See “Manual 18 Revisions,” PJM MRC/MC Briefs: Feb. 24, 2022.)
E. Stakeholders will be asked to endorse proposed revisions to Manual 37: Reliability Coordination resulting from a periodic review. The language would properly label Silver Run Electric as a transmission owner in Attachment A of the manual.
Endorsements (9:20-10:15)
1. Pseudo-modeled Combined Cycle Minimum Run Time Guidance (9:20-9:40)
Members will be asked to endorse a proposal that includes adding language to Manual 11: Energy and Ancillary Services Market Operations to address pseudo-modeled combined cycle minimum run time guidance. The proposed solution calls for adding language to Manual 11 to require market sellers to update the minimum run time of a pseudo-modeled unit to remove associated steam turbine start-up time included in the parameter limit when it’s dispatched. (See “Minimum Run Time Guidance,” PJM MRC/MC Briefs: Feb. 24, 2022.)
2. Capacity Capability Senior Task Force Sunset (9:40-9:50)
The committee will be asked to endorse the sunset of the Capacity Capability Senior Task Force. The task force was originally created in March 2020 to consider using effective load-carrying capability to set the capacity value of limited-duration resources such as battery storage. (See “CCSTF Sunset,” PJM MRC/MC Briefs: Feb. 24, 2022.)
3. Max Emergency Changes (9:50-10:15)
Stakeholders will be asked to endorse an issue charge and proposed revisions to Manual 13: Emergency Operations addressing the extension of a temporary change to maximum emergency status for gas combustion turbines and steam generators. PJM made a temporary change to section 6.4 of Manual 13 in a “note” to modify the remaining hours under which a resource may be offered as maximum emergency generation. (See “Max Emergency Changes,” PJM MRC/MC Briefs: Feb. 24, 2022.)
Members Committee
Endorsements (1:30-2:30)
1. FTR Credit Requirement (1:30-2:30)
Members will be asked to vote on several motions regarding revisions to PJM’s tariff on financial transmission rights credit requirements stemming from FERC’s recent rejection of the proposal to modify the calculation. The commission directed PJM to make an informal filing within 60 days of the date of the order to either show why its FTR credit requirement remains just and reasonable and not unduly discriminatory or preferential, or explain what tariff changes will remedy the commission’s concerns. (See FERC Rejects PJM’s FTR Credit Requirement Proposal.)
MISO is collecting a final round of stakeholder feedback before making a compliance filing under FERC Order 2222’s directive requiring RTOs to open their wholesale markets to aggregations of distributed energy resources.
Stakeholders had until Monday to submit written comments. The compliance filing is due April 18.
MISO will lean on its electric storage participation plan for DER aggregations, limiting them to a single pricing node. The aggregations must self-commit in the RTO’s markets based on their own forecasts.
The grid operator last month set a 2030 completion date for DER aggregation’s participation in its wholesale markets. MISO envisions registration being available in late 2029, with participation in energy and ancillary service markets offered by the end of 2030’s first quarter. (See MISO: DER Aggregations Must Wait Until 2030 for Market Participation.)
Stakeholders have told MISO that eight years is too slow to comply with the order. Some of them have pointed out that substantial DER adoption could happen between now and 2030.
During a March 10 Market Subcommittee meeting, Deputy General Counsel Tim Caister said MISO must “get anchors in” before it’s ready for Order 2222 compliance. He said it’s not simply a matter of plugging DER participation into MISO’s new market platform, but that registration and settlement systems need to be overhauled as well.
Staff and stakeholders have extended the DER task force until July 2023 to discuss post-compliance filing issues and provide MISO guidance on other DER issues. The grid operator has long said that Order 2222 compliance will not be the only market offering for DERs.
Task force lead Tricia DeBleeckere, a Minnesota Public Utilities Commission staffer, said upcoming meetings will probably become more stakeholder led. She said like the Order 2222 edict, MISO facilitates DER technologies, but members are the driving force behind their participation.
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.”
