The Virginia State Corporation Commission on Friday approved Dominion Energy’s (NYSE:D) 2022 Renewable Energy Portfolio Standard plan, which includes more than 800 MW of carbon-free electricity.
The utility has to file such a plan every year in compliance with the Virginia Clean Economy Act. The SCC approved Dominion’s $89.154 million revenue requirement for VCEA-related costs in the rate year of May 2023 through April 2024.
“This is another big step forward in delivering reliable, affordable and cleaner energy to our customers,” Dominion Energy Virginia President Ed Baine said in a statement. “These projects will bring jobs and economic opportunity to our communities, and they will deliver fuel savings for our customers. That’s a win-win for Virginia.”
The projects approved on Friday are expected to lead to $250 million in fuel savings for customers over their first decade of operation. They include nine solar facilities and one energy storage project, which total nearly 500 MW and will be owned by Dominion itself. Kings Creek Solar and Ivy Landfill Solar are being built on previously developed land, with the latter being the first solar plant Dominion has built on a former landfill.
The commission also approved power purchase agreements with 13 solar and energy storage projects, which total more than 300 MW and are owned by independent developers.
Construction of the projects is projected to support thousands of jobs and more than $920 million in economic benefits across Virginia. The projects will cost the average residential customer an extra 38 cents on their monthly bill, with construction of the new renewable projects expected to be complete by 2025.
The SCC directed Dominion to provide additional analysis with its next RPS plan due later this year, including an assessment of the impacts of the federal Inflation Reduction Act and modeling that shows Virginia both inside and outside the Regional Greenhouse Gas Initiative’s cap-and-trade system for power plants.
The commission sided with the utility and against its own hearing examiner’s report, which recommended the rejection of cost recovery for the Shands Storage project. The project will be the largest storage facility in Virginia at nearly 16 MW once completed, but the report found it would cost consumers $36.8 million without corresponding benefits, especially given the so-far light development of renewables in PJM, though Dominion argued that was changing.
“The extent to which Shands Storage can take advantage of any such market evolution would depend in part on both the actual market design changes (which cannot be known at this time) and timing,” the examiner said in their report filed in early March. “As Shands Storage degrades over time, each year this project is operational under PJM’s current market design seemingly means it will have less product to sell in PJM if and when a market redesign occurs.”
The SCC disagreed, noting that the VCEA includes targets for storage and that Dominion will benefit from starting to roll out the resource in Virginia.
Offshore wind isn’t the only clean energy technology that got a boost in the Maryland General Assembly this year.
In addition to the Promoting Offshore Wind Energy Resources (POWER) Act (S.B. 781), raising the state’s goal for offshore projects to 8.5 GW by 2031, the state legislature also approved bills aimed at growing markets for energy storage, community solar and zero-emission heavy-duty trucks. (See Md. Legislature Sends POWER Act to Governor’s Desk.)
All told, at least 12 clean energy and transportation bills were passed in the final days of the session and are now sitting on Gov. Wes Moore’s (D) desk. Moore has signaled strong support for the POWER Act but has yet to make statements on some of the other legislation.
House Bill 910, for example, would require the Maryland Public Service Commission to establish an energy storage program, with the goal of putting 750 MW of storage capacity online by 2027, 1,500 MW by 2030 and 3,000 MW by 2033.
Evan Vaughan, deputy director of renewable energy trade group MAREC Action, said the bill would help Maryland leverage the new 30% investment tax credit for standalone storage in the Inflation Reduction Act.
“You often need complementary state policies to work in tandem with most federal policies to really encourage a new market to take off,” Vaughan said in an interview with NetZero Insider. “That’s exactly what this legislation … will do. It’s a huge step forward.”
The Climate Solutions Now Act of 2022 (S.B. 528) commits the state to reducing its greenhouse gas emissions 60% by 2031 and to net zero by 2045, which means “there’s going to be a lot of clean energy capacity needed,” Vaughan said. “As you get to those really high grid penetrations of renewables in Maryland, it’s important to have a storage industry that’s there, that’s established, that’s ready to ensure the grid continues to operate reliably and affordably.”
However, according to the bill’s fiscal and policy note, “if a target cannot be met cost effectively, the target must be reduced to the maximum cost-effective amount for the relevant delivery year.”
Another key provision calls for the program to be implemented by July 1, 2025. The PSC only recently finalized rules for an energy storage pilot program that was established by the legislature in 2019.
Community Solar
H.B. 908, which would make the state’s community solar pilot program permanent, was another bill that was closely tracked by clean energy advocates. The seven-year pilot program was set to expire in 2024, said Rebecca Rehr, director of climate policy and justice for the Maryland League of Conservation Voters, “so, it was really important that the program was made permanent this year so that there wasn’t market disruption.”
Other key changes in the bill includes an increase to the amount of power from the projects required to go to low- and moderate-income (LMI) households from 30% to 40%, and a provision allowing customers subscribing to a community solar project to receive a single, consolidated bill. Under the pilot, subscribers have received two bills, one for the community solar project and one from their utility, which can be confusing for some customers, said Stephanie Johnson, executive director of the Chesapeake Solar and Storage Association.
In some cases, “subscribers thought that they owed much more money than they did,” Johnson said. “So, including the consolidated billing, it makes it easier for subscribers to see what they’re actually paying.”
Solar advocates also pushed hard for H.B. 692, which aims to resolve a bottleneck in local permitting of renewable energy projects and related transmission or distribution lines. While the PSC issues certificates of public convenience and necessity (CPCNs) for new energy projects, local jurisdictions must still issue certain “nondiscretionary” permits, like site plan or storm water permits.
Some counties were uncertain if they had the authority under a CPCN to issue these permits, causing delays, Vaughan said. “This bill just clarifies that they do in fact have that authority, and that the counties should grant those permits or deny those permits in a timely fashion … [to] prevent a potential inadvertent delay to project permitting.”
But the bill may only provide limited help in counties where local officials are generally opposed to solar, he said. “If a county was intentionally trying to slow-walk a permitting process based on an argument that they didn’t have the authority, that would be a narrow instance where this would help,” he said.
Other solar-friendly bills include:
S.B. 143, which would allow solar owners to accrue net metering credits indefinitely, rather than on a year-by-year basis, as currently required under state law. Community solar subscribers receiving virtual net metering credits would also be able to accrue them indefinitely, and the PSC would be required to establish a method for valuing these credits. Utilities would be required to pay customers the value of the accrued net metering credits within 15 days of an account being closed.
S.B. 469, which would establish a task force to study the state’s solar incentives and make recommendations for improving them to help the state meet its clean energy and emission-reduction goals. The task force would be required to deliver a report with its findings and recommendations to the General Assembly by Dec. 15.
Revving up Clean Transportation
Building on the Moore administration’s adoption of California’s Advanced Clean Cars II rule in March, the Clean Trucks Act (H.B. 230) would also move ahead with the adoption of California’s Advanced Clean Trucks regulation, which requires an increasing percentage of new medium- and heavy-duty trucks sold in the state to be zero-emission vehicles. (See Maryland to Adopt California’s Advanced Clean Cars II Rule.)
The Advanced Clean Cars II rule sets 2035 as the deadline for all new passenger cars, SUVs and light-duty pickups in the state to be ZEVs. With the adoption of the Clean Trucks targets in Maryland, 55% of all new class 2b and 3 vehicle sales, 40% of truck tractor sales and 75% of new class 4 through 8 truck sales would have to be zero-emission by 2035.
The Maryland Department of the Environment would be required to establish the program and also to “prepare a related needs assessment and deployment plan in consultation with specified state agencies and submit the plan to the General Assembly by Dec. 1, 2024,” according to a fiscal and policy note.
The bill would also increase funding for a state grant program to support medium- and heavy-duty truck sales from its current level of $1 million per year to $10 million per year.
An analysis from the Maryland League of Conservation Voters said the bill “is of particular importance because communities of color and low-wealth communities often face disproportionate burdens from traffic and transportation pollution.”
Rehr is hoping the needs assessment will not slow implementation of the law, but rather help to “identify priorities for implementation.”
“We’re hoping that what it does is actually show the need and show where we can invest in charging stations … and invest in [other] infrastructure needed to implement the bill,” she said.
Other clean transportation bills include:
H.B. 123, which would allow electric vehicles registered with the state to use HOV lanes regardless of how many passengers are in the vehicle. EV drivers would need a permit, which will cost no more than $20. The program would end Sept. 30, 2025.
H.B. 830, which would require all new residential construction with a garage, driveway or carport to include an EV charger or be wired for charger installation. The bill would also require that the Maryland Energy Administration conduct a study on the costs and other considerations for installing EV chargers in multifamily housing, for example, how many chargers would be needed per number of apartments in a building.
H.B. 834, which would allow electric utilities to install EV chargers at multifamily housing in underserved communities. The program would continue through Dec. 31, 2025, and utilities would have to ensure the chargers have an average annual uptime of 97%.
ERCOTsaid Wednesday that it will pay Austin Energy a $2.86 million to settle an alternative dispute resolution (ADR) stemming from the February 2021 winter storm.
The settlement covers 15 pricing intervals over Feb. 14-15, when ERCOT issued high-dispatch limit override (HDLO) instructions for Austin Energy’s Fayette Power Plant, reducing its power output during the storm’s first two days. At the time, the grid operator was desperately cutting load to help keep the system afloat after more than 50 GW of generation was knocked offline by the frigid weather from Winter Storm Uri.
The utility said in its ADR claim that Fayette’s power reduction kept it from fully serving Austin Energy’s native load and it incurred financial losses by purchasing power in the real-time market to cover contractual obligations.
Under ERCOT protocols, Austin Energy and other qualified scheduling entities (QSEs) are eligible for real-time HDLO payments if a resource’s power output is reduced by a manual dispatch override and it can show a “demonstrable” financial loss.
To be eligible, QSEs must have complied with the grid operator’s dispatch instructions to reduce power, received an economic dispatch base point equal to the resource’s HDLO during the 15-minute interval, and filed a timely dispute.
ERCOT found Austin Energy met its obligations. However, it denied compensation for eight other intervals on Feb. 14, saying the utility’s total generation and trade energy purchases were higher than its total load obligations during that period.
Austin Energy is an ERCOT non-opt-in entity (meaning it has not opted into the competitive retail market) that meets its load obligations through its own generation fleet, day-ahead market purchases and bilateral trades. The utility uses 600 MW of Fayette, which it jointly owns with the Lower Colorado River Authority.
ERCOT declined comment beyond its market notice.
The grid operator last year denied a settlement and billing dispute by Engie Energy Marketing after the company failed to meet a responsive reserve service obligation during the height of the winter storm. ERCOT said Engie was unable to demonstrate that ERCOT staff violated any obligations under the protocols.
Engie was seeking $48.7 million in damages.
Calpine: Time to Build Plants
Calpine said Tuesday that it is relaunching its Texas development program following the Public Utility Commission’s embrace of market-based incentives under its performance credit mechanism (PCM) design.
“We are encouraged that the PUC has laid the foundation to ensure Texas maintains a reliable power supply through market-based mechanisms, and we are excited to move forward with projects that will deliver on that mission,” Caleb Stephenson, Calpine’s executive vice president of commercial operations, said in a statement. “Our hope is that the legislature will respect the regulatory certainty offered by the PUC and avoid discriminatory programs or direct government procurement that would undermine competition in Texas.”
Stephenson said the PUC has “sent a clear signal that Texas is ready to support ambitious investments in a more reliable grid based on the principles of competition, not government mandates.”
Texas lawmakers have responded to the PCM proposal by coalescing around a bill that would build 10 GW of gas generation to sit on the sidelines, for use only to prevent load shed. That plan was originally estimated to cost $10 billion, but recently uncovered documents indicate it may cost as much as $18 billion. (See Texas Legislature Moves Bills Remaking the ERCOT Market.)
Calpine said it plans to complete a new 425-MW gas-fired plant before the summer of 2026 at its existing Freestone Energy Center north of its headquarters. It also said it will develop another 425-MW gas unit near Austin and a large-scale combined cycle gas plant to support co-located industrial load.
70-MW Unit to Stay Offline
BHER Power Resources on Tuesday notified ERCOT that it will indefinitely suspend operations at one of three gas-fired units near Abilene in West Texas.
The company said the unit suffered a forced outage last summer. Unit 3 went commercial in 1988 and has a summer seasonal rating of 70 MW.
VALLEY FORGE, Pa. — PJM has assessed more than $1.8 billion in performance penalties on generators that underperformed during the December 2022 winter storm, the RTO told the Market Implementation Committee on Wednesday.
The penalties are being levied against 187 members through PJM’s Capacity Performance (CP) system, which charges generators that underperform during performance assessment intervals (PAIs) and allocates those funds to generators that overperformed. (See PJM Weighs Options for Winter Storm Elliott Follow-up.)
A significant share of companies assessed with nonperformance charges during the storm, also known as Winter Storm Elliott, are also receiving bonuses, leaving a net total of $1,296,628,015 in penalties allocated among 116 members whose penalties outweigh their bonuses. PJM Director of Market Settlements Initiatives Lisa Morelli told the MIC that 260 members are set to receive bonuses, 182 of whom will be receiving payments that outweigh any penalties they’ve been assessed.
The net figures assume that every generator pays their penalties, but two companies have already filed for bankruptcy because of their inability to pay: Lincoln Power and Heritage Power Marketing. PJM is holding back 25% of monthly bonus payments to account for the possibility of nonpayment; any penalty payments made above that in a given month will be trued-up in the following payment. (See “Lincoln Power Declares Bankruptcy Because of Penalties,” Complaints to FERC over PJM Performance Penalties Multiply.)
FERC Approves Alternative Billing Schedule
About 70% of members facing nonperformance charges have elected to make their payments under the standard three-month billing schedule. The remaining companies — which account for the bulk of the gross penalties — have elected for a longer nine-month payment period approved by FERC last week.
In an April 7 order, the commission said that allowing the payments to be spread out could reduce the number of defaults as a result of the penalties. The approval, effective April 4, was conditioned on PJM making a compliance filing within 30 days aligning the proposed tariff revisions to reflect language in the filing stating that when extensions in the billing period are approved by PJM, the longer period will be applied to all resources — rather than being granted on a unit-specific basis (ER23-1038).
The filing allows those saddled with penalties stemming from Elliott to opt for a nine-month alternative, with the tradeoff of being subject to interest charges. For future PAIs, the proposal allows PJM to spread all payments over nine months, with no interest, when an emergency event occurs near the end of the delivery year, resulting in a shortened billing schedule. Under the status quo rules, nonperformance charges must be paid by the end of the relevant delivery year.
“Allowing members to pay their nonperformance charges over nine months instead of three should reduce the immediate risk of defaults, especially given that the tariff requires members to pay their monthly bills within one week and the first bill will be invoiced on April 7,” the commission said. “Although overperformers during Winter Storm Elliott may have their bonus payments delayed, we find reasonable PJM’s assessment that the transitional rule will maximize the total bonus pool by reducing the probability of defaults.”
In comments supporting the proposal, the PJM Power Providers said that extending the payment period nine months will allow generators that incur charges over the winter to make payments through the summer, allowing those that run more frequently in those months to earn revenue to put toward the penalties.
Invenergy protested that imposing interest on nonperformance charges for generators that choose the longer payment period for penalties stemming from Elliott is unreasonable and goes against the purpose of the filing: to reduce the risk of defaults and therefore maximize bonus payments.
The commission pointed to PJM’s argument that interest is necessary to balance the settled expectations of generators that based their operations on the tariff language in place at the time of the storm.
Commission OKs New Bankruptcy Provisions
FERC also approved two PJM filings modifying its provisions for market participant bankruptcies, providing flexibility to allow members to continue operating in the markets while in default and requiring members filing for bankruptcy to clarify the RTO’s rights in a first-day motion (ER23-1058, ER23-892).
PJM’s proposal to allow continued market participation for members in default is limited to a handful of circumstances: when that participation supports reliability; the member is a net market seller; the market participant has demonstrated the ability to post collateral; and when participation cannot be terminated without regulatory approval. (See “Deficiency Notice Interrupts Timeline on CP Penalty Payments,” PJM MRC/MC Briefs: March. 22, 2023.)
PJM argued that the proposal would allow it to maintain resource adequacy and generators with characteristics required by the grid, such as black start, while providing generators an opportunity to pay any obligations while earning revenue.
In an April 7 order approving the RTO’s filing, the commission agreed that it could “minimize relative risk to the PJM markets and provide PJM an opportunity to recover funds on behalf of the PJM membership.”
In response to comments on the filing, PJM committed to notifying the Risk Management Committee when these provisions are exercised and codifying that practice in the Credit Overview supplement. The RTO also stated it would work with the Independent Market Monitor and stakeholders to consider additional clarifications and changes.
New Jersey regulators agreed Wednesday to search for a consultant to help develop a new strategic plan to guide the state’s effort to install 11 GW of offshore wind by 2040.
The four members of the state’s Board of Public Utilities (BPU) voted unanimously to issue a “request for quotation” from consultants interested in compiling the plan, which would “guide New Jersey in achieving its offshore wind energy objectives and future solicitations,” said Jim Ferris, BPU’s deputy director of the Division of Clean Energy.
The move comes more than two years after the state released its first strategic plan, Navigating Our Future, which preceded the state’s aggressive pursuit of offshore wind capacity. The state has approved three projects totaling about 3.8 GW in two solicitations. And on March 4 the state opened a third solicitation that could add another 4 GW of capacity. (See NJ Opens Third OSW Solicitation Seeking 4 GW+)
In September, Gov. Phil Murphy increased the state’s OSW target capacity from 7.5 GW by 2035 to 11 GW by 2040.
Ferris said the aim of the new plan is not to duplicate past work but to “update [and] enhance based on the many changes in offshore wind since the first strategic plan was issued.”
The plan would likely be released before the third quarter of 2024, when the state expects to open a fourth solicitation, he said.
Learning Process
The board approved the consultant search after Commissioner Dianne Solomon, who has expressed concern about the costs of New Jersey’s renewable energy program, questioned whether the plan would “duplicate” work that has already been done.
Solomon said she was “glad to see that we’re looking at … different market forces and activity to give us some insight as to what these actual costs to ratepayers will actually be.
“In the past, we really have not had an opportunity to look at the all-in costs,” she said. “And this may give us maybe a little bit more insight, even though it’s not really a cost valuation.”
The board’s decision to create a second strategic plan comes as New Jersey’s first OSW project is moving ahead and the state is looking to position itself as a key player in providing services and supply chain support for wind projects along the East Coast. That includes developing the New Jersey Wind Port, with manufacturing and staging capacity designed to serve the industry. But the sector also has faced opposition from shore residents, tourism businesses and the commercial fishing sector, which all fear negative impacts from the OSW projects.
Most recently, a series of whale deaths along the New Jersey shore has raised concerns about the impact of the growing wind sector on marine life, sparking protests and a public hearing held by two of the state’s Republican congressmen, Reps. Jeff Van Drew and Christopher Smith, who have called for a halt to the projects. Federal marine authorities have said they see no connection between OSW developments and whale deaths.
BPU President Joseph L. Fiordaliso acknowledged that there had been “potholes,” unexpected developments in the process that turned into learning events, including the fact that some details should have been included in the early solicitations that were not. But he said the agency and state are trying to figure out how best to create a new industry.
In addition, he said, “a lot has changed from the first solicitation to where we are today.
“We just don’t throw mud up against the wall and hope something sticks,” Fiordaliso said. “That’s not how the approach goes. Your approach involves detailed research and information from wherever we can get it. And some of the price tags for this are certainly a little higher than was initially thought of.
“But we can’t stop. And I know, the next statement I’m going to make has been criticized by some. But can we afford not to do it? And the answer to that, in my opinion, is ‘no’,” he said.
Fiordaliso also dismissed claims that preliminary offshore studies conducted by OSW developers may have led to the whale death.
“As I’ve said many times before, there are very powerful forces out there that don’t want us to succeed,” he said. “And then we also say there is no evidence that what’s going on as far as offshore wind is concerned is in any way affecting the whales or the dolphins. There’s no scientific evidence to that.”
Reducing Barriers to Grid-scale Solar
In a separate proceeding, the board modified several requirements in the Competitive Solar Incentive (CSI) program, loosening some parts of the program to make it easier for developers to comply with rules.
The program — approved in June 2021 under the Successor Solar Incentive programs (SuSi) with the specifics being approved last December — created the state’s first grid supply program. It covers basic grid supply; grid supply projects located on the built environment; grid supply projects on contaminated sites and landfills; and net metered non-residential projects greater than 5 MW.
The board approved the removal of two elements that, according to the presentation by BPU research scientist Diane Watson, “create barriers to participation in the CSI program that considerably outweigh the intended benefit of ensuring project maturity.”
One removed element required a developer to “provide electrical and building permits, or documentation that applications for electrical and building permits have been submitted to the relevant municipality,” according to the order approved by the board. The board concluded that was detrimental because it “forces the registrants to make design and procurement decisions at too early a point in the development process.”
The board also removed a requirement that registrants “supply a contract between the primary installer or the third-party owner, and the bidder or customer of record, within 30 days after receiving an award.” The board found that the requirement “conflicts with the timelines of internal and external review for many of those entities,” according to the order.
The U.S. Bureau of Ocean Energy Management on Thursday debuted its effort to better engage fisheries and their related stakeholders in the country’s offshore wind development process.
Liz Klein, director of the U.S. Bureau of Energy Management, speaks during Thursday’s webcast. | National Academies of Science, Engineering and Medicine
BOEM Director Liz Klein told the first meeting of the Standing Committee on Offshore Wind Energy and Fisheries that its input would be critical to informing the regulatory process, in which the agency plays a central role.
Potential impact on fisheries and ocean ecosystems has been one of the most contentious points in the drive to install thousands of towering wind turbines off the Atlantic, Gulf and Pacific coasts of the U.S.
Offshore wind is an emissions-free source of power, but its construction and operation will alter the marine environment to an unknown degree, as illustrated in a recent analysis by BOEM, the National Ocean and Atmospheric Administration and the Responsible Offshore Development Alliance. (See Report Flags Gaps in Scientific Knowledge of OSW Effects.)
That uncertainty has led to fear, resentment and litigation by the fishing industry and its advocates.
In an attempt to improve its engagement with the fishing community on offshore wind, BOEM earlier this year announced formation of the committee, established by the National Academies of Sciences, Engineering and Medicine.
Nearly 300 people signed up to watch the committee’s first meeting via webcast Thursday.
“We expect this committee to be an independent and credible forum to discuss pressing stakeholder concerns and relevant science knowledge,” Klein said.
The committee will seek a range of scientific expertise from a variety of disciplines, she said, as well as input from stakeholders such as tribal nations, commercial and recreational fisheries, non-governmental organizations, communities and the offshore wind industry.
“We know that fishing communities and other fisheries stakeholders are really critical to informing our offshore energy development process,” Klein said.
Offshore wind is an important part of the nation’s clean energy transition, she said, with President Biden having set a goal of 30 GW online by 2030.
“At the same time,” Klein said, “fishing is a crucial part of many of our nation’s coastal communities. It contributes to our food security, jobs and economic opportunity. And for many, it’s much more — it’s a way of life and national heritage.”
Fishing, she said, must not just co-exist with offshore wind but thrive alongside it.
Cumulative Impacts
The discourse during the meeting was polite but at times pointed.
Committee member Eric Kingma, executive director of the Hawaii Longline Association, asked whether BOEM would be seeking advice from the committee on individual OSW projects or be seeking more broad-stroke insight.
Klein said BOEM is seeking broad insight across multiple projects in a given region because “the goal is always to get to some level of consistency in how you’re treating projects.”
Committee Member Steve Joner, a fisheries consultant to the Makah Tribe in Washington, touched on a different aspect of the larger picture, saying: “One question that we really haven’t had answered from BOEM yet is the cumulative impact of all the potential wind area sites on the West Coast. What happens in California can and likely will impact fisheries all the way up into northern Washington and into Canada. I’m hopeful that BOEM will be open to our recommendations on [ecosystem impacts] and will address this very critical question.”
Klein said, “I think that’s certainly something that’s top-of-mind for us when we think about the potential leasing that might take place on the West Coast.”
Committee Chair Jim Sanchirico said the cumulative impact, which could be quite different between the West Coast and East Coast, would be a great discussion topic for the committee.
Committee member Daniel Doolittle, principal environmental scientist with the geo-data firm Fugro, asked if BOEM’s approach in the New York Bight — a single programmatic review of the several leases in the area — is a result of the agency listening to critical input from stakeholders and evolving the rule making.
Karen Baker, chief of BOEM’s Office of Renewable Energy Programs, said it was.
“New York Bight has been a pilot that we’re moving forward with in terms of looking at that whole lease area and looking at it collectively first,” she said.
“We do believe that’s more the wave of the future,” Klein said, though it may turn out that individual lease areas will require specific environmental impact statements, depending on what the collective review shows.
Regional review of impacts has its own challenges, but it’s probably more productive than single-project review, she said.
“I think we’re already learning lessons from New York Bight [that] we’re going to apply elsewhere.”
Committee member Dave Wallace, a fisheries consultant who represents members of the shell fishing industry, was skeptical about assumptions being made around the erection of up to 2,500 turbine towers on the Outer Continental Shelf from southern New England to the Mid-Atlantic states.
He specifically cited wind wake from turbine blades that might stretch nearly 900 feet above the water’s surface, with unknown effects on the water below.
“They are all going to be much bigger than anything that has ever been built in — the world? What are you going to do when all of the sudden some of the assumptions you have made end up not being true, and they’re going to have a much larger negative impact than originally planned?”
BOEM Chief Environmental Officer William Brown replied, “We’re very interested in the potential effects on ocean circulation, but we don’t know; we don’t have good information — we BOEM or we the world really — on what those impacts are. That’s why we’ve asked the Academy to help us answer that question.”
U.S. commercial aviation is charting an ambitious flight plan to net-zero emissions by the year 2050 using synthetic liquid fuels rather than batteries or fuel cells envisioned for trucking and consumer automobiles.
“Those [electric] technologies do not work across the entire space of what we know as aviation,” said Steve Csonka, executive director of the Commercial Aviation Alternative Fuels Initiative (CAAFI), an industry effort that began in 2006.
Appearing Thursday in a webinar presented by the Washington-based Environmental and Energy Study Institute, Csonka said electrification may be fine for “some very modestly sized vehicles.”
“Electrification, however, does not offer the energy density per weight compared to synthetic liquid aviation fuels already available in limited volumes but with the potential to ramp up production in the coming years,” he said.
Steve Csonka, CAAFI | EESI
Synthetic aviation fuels (SAFs) are already available and offer an 80% reduction in emissions compared to jet fuels produced from petroleum, he said. The industry’s long-term goals are now achievable, he said, given the federal “grand challenge” targeting the production of 3 billion gallons annually by 2030 and ongoing research by several federal agencies working with the industry.
“We have offtake agreements [to purchase SAF] for between five and 15 years from the airlines … before any concrete is put in the ground. This is a fundamental, unique thing that the aviation enterprise is offering to potential producers to have that level of offtake commitment,” Csonka said.
“Aviation understands how some of the other technologies that spin around this space like power, liquids, biomass, energy, carbon capture and sequestration, [and] direct air capture and sequestration sort of fit into the rubric of the things that aviation is interested in.”
Csonka said that original equipment manufacturers, including the Department of Defense, are continuing to help fund fundamental research and development. The Pentagon funded initial research nearly 20 years ago.
“We’re talking about being able to continue to make aviation turbine fuel [jet fuel]. Why is that important? Because it allows us to have a drop-in approach with no changes required to infrastructure equipment.
“I don’t have to rebuild every airport in the world to bring in a new type of fuel. I don’t have to replace every airplane in the world. … I can get my carbon reduction by using a drop in fuel that has a lower greenhouse gas impact. We also want to do this sustainably.
“How do we do that? Instead of pulling hydrocarbon molecules out of the ground in the form of petroleum and then refining those to fuel products, we’re reaching into our own biosphere and picking up hydrocarbon molecules from things that nature hands us or using recycled components from the things that we do as a natural course,” he said.
Those sources include municipal solid waste, forestry residues, agricultural waste, food processing waste and cellulosic crops.
As the 2022 Atlantic hurricane season entered its fourth month, Florida Power & Light’s (NYSE:NEE) customers were starting to feel they could relax.
Storm activity had been unusually light, with just four named storms since the season started on June 5, and only the first — Tropical Storm Alex — directly impacted Florida. The season’s first hurricane, Danielle, didn’t form until Sept. 1, making 2022 the first season to have its first hurricane develop so late since 2013.
“The Atlantic was very quiet; a lot of folks out there … were saying they thought hurricane season may be over,” Andy Pankratz, FPL’s senior director of emergency preparedness, said at SERC Reliability’s Extreme Weather Webinar on Thursday. “We’ve got onsite meteorologists that were definitely not believing that, and to their credit [they] were giving us a heads-up that the Atlantic looked like it was going to be getting more active very soon. And that’s exactly what happened at the very beginning of September.”
Andy Pankratz, Florida Power & Light | SERC
Storm activity began to pick up after Danielle, but Hurricane Ian finally blew away the relative lull when it made landfall in southwest Florida as a Category 5 storm on Sept. 28, having already caused a nationwide power outage in Cuba. With 150-mph winds, the storm tied for the fifth-strongest hurricane ever to hit the contiguous U.S. And with 149 fatalities it was the deadliest storm to hit Florida since 1935.
Hurricanes are a fact of life for Florida’s utilities, but Ian took things to another level. Recalling that he “was around for” 2004’s Category 4 Hurricane Charley, Pankratz shared a graphic showing that the storm could have fit entirely within the eye of Ian, saying “it really put things into perspective.”
Ian cut power to more than 2 million of FPL’s customers, although recovery was rapid compared with earlier storms. As an executive from the company explained at SERC’s December board of directors meeting, two-thirds of affected customers were restored by the day after landfall, and restoration was complete within eight days. (See FPL Credits Grid Hardening for Fast Ian Restoration.)
Despite the fast recovery, Ian left weakened soil that proved a liability when Hurricane Nicole, the 14th and last named storm of the season, made landfall in November. Nicole, a Category 1 at its peak, was the third storm of 2022 to make landfall in Florida after Alex and Ian, and only the third November hurricane on record to do so. It was also the first hurricane to make landfall on Florida’s east coast since 2005’s Hurricane Katrina.
The unstable ground after Ian “really created some challenging conditions” for crews from FPL and other utilities assisting in recovery efforts, Pankratz said, and workers “had to really get creative” when entering affected areas. Their solutions included using barges to bring trucks into areas they could not access from land; one employee even used a kayak to reach a substation surrounded by floodwaters.
Pankratz said that although FPL sees its response to Ian and Nicole as “arguably … two of our best performances from a restoration perspective ever,” the utility is still looking for areas to improve.
“We have pages and pages and pages of lessons learned and things that we want to do better — and things that we’ve already implemented this year and are continuing to implement prior to storm season,” Pankratz said. “We’re really, really focused on lessons learned and getting better each and every time we have an event — or support an event.”
Most of the cuts from the proposed standards are for light- and medium-duty vehicles, which produce a greater volume of emissions and have more readily available alternatives to the internal combustion engine, but EPA also proposed new standards for heavy-duty vehicles.
“Today’s actions will accelerate our ongoing transition to a clean vehicles future, tackle the climate crisis head on, and improve air quality for communities all across the country,” EPA Administrator Michael Regan said at an event announcing the standards outside the agency’s headquarters.
EPA expects the rules for light- and medium-duty vehicles will cut 7.3 billion MT of CO2 between 2027 and 2055 and projects net benefits of $1.6 trillion. The heavy-duty vehicle rules would save 1.8 billion MT of CO2 and yield $320 billion in benefits.
The proposed standards for light-duty vehicles start in 2027 and ramp up to an 82 grams of CO2 per mile standard by model year 2032, while the medium duty standard ramps up to 275 grams per mile by 2032. Those represent cuts in fleet average CO2 emissions of 56% and 44%, respectively, compared to the model year 2026 standards, EPA said.
Heavy-duty vehicles have different standards depending on the type of vehicle covered, with EPA updating existing standards for 2027 and extending more stringent cuts out to model year 2032.
The standards are expected to drive significant increases in the EV share of the vehicle market, although the fact that they are technology-neutral should also drive improvements to internal combustion engines and benefit other technologies such as fuel cells.
In light of the rules, EVs are forecast to make up to 67% of light-duty sales by 2032 and 44% of medium-duty sales by that year. EVs are expected to account for 8.4% of light-duty sales this year, up from just 2.2% in 2020.
Automobile manufacturers have already said they plan to switch to producing larger volumes of EVs in the coming decades. Based on those pledges and current market shares among automakers, EVs should make up 48.6% of sales by 2030. Regan said that the agency was following the market trends, which shows the standards are achievable.
“I believe that because when I look at the projections that many in the automobile industry have made — his is the future,” Regan said. “The consumer demand is there. The markets are enabling it. The technologies are enabling it.”
The EPA’s standards provide a regulatory compliment to federal incentives from recent legislation, including the Inflation Reduction Act, Infrastructure Investment and Jobs Act and the CHIPS and Science Act, which include tax credit and other funding for electrification, Regan said.
The Alliance for Automotive Innovation, which includes major automakers such as Ford and General Motors, agreed that the industry was electrifying but called EPA’s plan “aggressive by any measure.” Reaching the target depends on factors outside of automakers’ control, the group said.
“Factors outside the vehicle, like charging infrastructure, supply chains, grid resiliency, the availability of low carbon fuels and critical minerals will determine whether EPA standards at these levels are achievable,” it said.
Impacts to the Grid
EPA’s modeling predicts non-hydroelectric renewables becoming the largest overall source of electric generation by 2035, at about 46% of total generation, rising to 70% by 2050.
“As [power plant] emissions continue to decrease between 2028 and 2050 due to increasing use of renewables, and as vehicles increasingly electrify, the power sector GHG and criteria pollutant emissions associated with light- and medium-duty vehicle operation will continue to decrease,” the agency said in its light- and medium-duty rulemaking.
Light- and medium-duty vehicle rule’s impact on power generation | EPA
The additional electric vehicles will not increase electricity demand significantly, according to EPA, ranging from an increase of less than 0.4% in 2030 to about 4% in 2050. The heavy-duty rule would add another 0.1% of demand in 2027 and 2.8% in 2050. That demand growth is much smaller than what the industry dealt with as air conditioning grew in popularity, or more recent demand growth associated with the digital revolution.
“The U.S. electricity end use between the years 1992 and 2021 increased by around 25% without any adverse effects on electric grid reliability or electricity generation capacity shortages,” EPA said.
The light-duty rule highlighted analysis in California, which has found that 20% of charging loads at any time in the day can be shifted to another hour in a process that benefits car owners, other customers and the grid at large.
“Integration of electric vehicle charging into the power grid, by means of vehicle-to-grid software and systems that allow management of vehicle charging time and rate, has been found to create value for electric vehicle drivers, electric grid operators and ratepayers,” the rule said. “Management of PEV charging can reduce overall costs to utility ratepayers by delaying electric utility customer rate increases associated with equipment upgrades and may allow utilities to use electric vehicle charging as a resource to manage intermittent renewables.”
The new cars will require new charging infrastructure, with 12 million home chargers expected in 2027, increasing to more than 75 million in 2055, while workplace chargers will grow from 400,000 to 12.7 million, and public chargers will grow from 110,000 ports to more than 1.9 million.
Other infrastructure will be needed to integrate the new demands, such as upgrades to local distribution systems. But EPA found significant uncertainty on exactly what would be needed and asked for comments to weigh in on the subject.
Reactions
The rules elicited opposite reactions from the country’s two main political parties, as seen from statements from the leadership of the Senate Environment and Public Works (EPW) Committee that oversees the EPA.
“In addition to providing regulatory support to where the market is already heading, EPA’s proposed vehicle emissions standards would make significant progress in our fight against climate change,” EPW Chair Tom Carper (D-Del.) said.
“They will also save Americans money at the pump and better insulate our country from the volatility of the global oil market. I am encouraged by the Biden Administration’s step toward cleaner, more efficient cars, trucks and vans, and I hope to see a final rule by the end of the year.”
Ranking member Rep. Shelley Moore Capito (R-W. Va.) blasted the rule and said it made little sense when coupled with other actions that are shutting down “baseload” coal and natural gas plants.
“Today, the Biden administration made clear it wants to decide for Americans what kinds of cars and trucks we are allowed to buy, lease and drive,” Capito said. “These misguided emissions standards were made without considering the supply chain challenges American automakers are still facing, the lack of sufficiently operational electric vehicle charging infrastructure, or the fact that it takes nearly a decade to permit a mine to extract the minerals needed to make electric vehicles, forcing businesses to look to China for these raw materials.”
Likewise, reactions among clean energy groups were largely positive, while the American Petroleum Institute lambasted the rule.
“This deeply flawed proposal is a major step toward a ban on the vehicles Americans rely on,” API CEO Mike Sommers said. “As proposed, this rule will hurt consumers with higher costs and greater reliance on unstable foreign supply chains.”
The American Council for an Energy Efficient Economy argued that EPA should have gone even further than it did.
“These are strong proposals, yet they do not give us as much progress as climate circumstances demand,” ACEEE Transportation Program Director Shruti Vaidyanathan said. “We need to move to electrified vehicles as rapidly as possible while continuing to reduce emissions from conventional vehicles, and these proposals need to be improved to get us there.”
The cost of transmission congestion doubled in the organized electricity markets between 2020 and 2021, rising by billions of dollars, according to a report released Thursday by Grid Strategies.
All of the ISOs and RTOs except for CAISO publish their congestion costs; they were up $7.7 billion on the year, which, extrapolated to the rest of the country, leads to a national cost of $13.4 billion, according to “Transmission Congestion Costs in the U.S. RTOs.”
Congestion costs rebounded in 2021 after reduced demand from the height of the COVID-19 pandemic in 2020 led to lower costs that year, but other factors helped fuel that increase.
“The price transparency and generally more favorable transmission expansion policies in the RTO regions tend to reduce congestion in those areas relative to non-RTO regions,” the paper said. “However, RTO regions have experienced more renewable deployment in recent years than non-RTO areas, which may somewhat offset those factors as renewable expansion tends to increase transmission congestion when it outpaces transmission expansion.”
The best way to cut congestion is to build new transmission, the report said, citing a PJM analysis that found that transmission enhancements approved in the past decade have cut costs to serve consumers by $280 million annually.
No similar numbers exist for how interregional lines would benefit consumers by cutting congestion, but Lawrence Berkeley National Laboratory found that interregional transmission links can have just as much, if not more, value than intraregional links.
While the bounce back from the pandemic was a national trend, different regions had different factors impacting the rise of congestion.
ISO-NE continues to deal with increased congestion as transmission development has lagged the development of renewable energy.
“A new wind generator in coastal Maine went online in late 2020, and along with other abundant wind generation, and in the absence of proactive transmission additions, congestion increased,” the report said.
Higher natural gas prices, especially on the coldest days of winter, helped to push up congestion in NYISO. MISO saw congestion costs nearly triple in 2021 to $2.8 billion, with roughly $730 million of that total alone from the February storm, also known as Winter Storm Uri, that knocked out power in Texas and surrounding states.
“This is consistent with the general pattern nationally that much of the congestion (and value of transmission) occurs in a relatively small percentage of the hours,” the report said.
SPP saw congestion prices more than double to $1.2 billion, with its market monitor attributing the increase to the distance between generation and load centers, outages of key transmission lines, volatile fuel prices and Uri.
Texas was also obviously heavily impacted by Uri, with congestion costs representing 33% of total costs in February 2021, compared to 15% in February 2020. The growth of renewables also helped push up congestion.
“In 2021, 3 GW of wind output and 3.6 GW of solar came online [in ERCOT] without concomitant transmission development, which contributed to a real-time congestion cost increase of 46%,” the report said.
