The New York Public Service Commission on Thursday approved construction of a scaled-back version of Consolidated Edison’s (NYSE:ED) proposed Clean Energy Hub in Brooklyn.
Con Ed originally proposed the hub in April 2022 (20-E-0197) as a $1 billion landing point for 6 GW of electricity generated by the wind farms New York wants to build off its coast.
In December 2022, the utility supplemented that proposal with a smaller alternative that it framed as a step needed by mid-2028 to maintain reliability in the area amid rapid electrification of buildings and transportation. The cost was significantly lower, at $810 million: $773 million for the hub itself, and $37 million to prepare the facility to serve as a make-ready point of interconnection for 1.5 GW of offshore wind power.
The PSC unanimously approved the supplement Thursday as necessary to maintain electric reliability.
The commission also rejected the original hub plan — which was still alive — because there was no evidence offered to show that routing 6 GW of power to the hub is feasible. There was demonstrated interest from developers in doing so but no indication it is physically possible.
The proposal was attractive because of the scarcity of real estate to build such a facility in New York City. Con Ed proposed to build it on a site occupied by an office building and three retired gas turbine generation units, adjacent to its Farragut substation.
But objections were raised during the public comment period. Many questioned the feasibility of running multiple HVDC cables beneath the East River to reach the hub. Others said the hub was not the product of a competitive solicitation process, such as NYISO’s Public Policy Transmission Planning process, and therefore might not result in the lowest price tag, or the price tag least likely to change.
But the PSC unanimously approved the scaled-down version of the hub proposal, agreeing that it is the only potential solution to the projected needs in the area as the city and state press forward with their clean energy transition.
The PSC denied New York City’s request to delay a decision to await further analysis, saying the proposal is time-sensitive. It also rejected the city’s contention that the hub would not be cost-effective and would not promote resilience.
The hub is only the first of several 345-kV substations that will be needed in the city, the PSC countered. Installed generation capacity statewide is expected to double from 43 GW in 2019 to 90 GW in 2040, with much of the load growth in New York City. The commission determined that the cost of building the hub will be borne by Con Ed ratepayers, as it is designed for purposes of reliability of service to them.
If the hub’s benefits expand beyond Con Ed territory into the larger realm of the state’s climate protection goals, such as through offshore wind, the utility can petition for an alternative cost-recovery mechanism to spread the costs beyond its rate base, the commission said, but it said it is skeptical at this point that it would agree to such a change.
Commissioner John Howard focused on the costs involved, and noted that Con Ed has estimated it will need to spend $60 billion to prepare its service area for the energy transition.
He applauded the inclusion of the word “skepticism” in the order and suggested also that the city should not be allowed to reap a property tax windfall from all the infrastructure that will be needed in the next few decades.
A Department of Public Service staff member estimated the smaller $810 million hub would have a $48 million annual property tax bill.
PSC Chair Rory Christian said Thursday that New York state’s energy landscape is in a period of fundamental change and that infrastructure investments must keep pace with proactive planning.
“Priority has shifted to ensuring increased levels of renewable, clean sources are integrated into the grid while polluting sources are being phased out,” he said. “To make sure the system continues to serve customers with the level of reliability that our modern economy demands, we know that additions and modifications to the utilities’ transmission and delivery infrastructure will be needed, as well as equitable methods for recovering the costs of such additions.”
HOUSTON — The Gulf Coast Power Association’s annual spring conference April 18-19 revolved around how Texas and its coastal region can become a hotspot for energy innovation.
Anne Choate, executive vice president for energy, environment and infrastructure with consulting firm ICF, said the Gulf Coast can “further cement its goal as the innovative energy epicenter” of the world.
She said the region can impel clean energy infrastructure and long-term change for climate stabilization “in the same way we’ve been successful at repairing the ozone layer.” Choate said the industrial-heavy Gulf Coast has “powerful” potential in geothermal energy, carbon capture and green hydrogen technologies.
“It’s going to be a lot of work. We’re going to look like we’re gliding across the water, but we’re going to be paddling furiously underneath,” she said, saying it has the potential to make Silicon Valley look “quaint.”
“I think the Gulf region will be one of the most active regions, not just in the U.S., but globally, in carbon capture and sequestration,” predicted Frederik Majkut, senior vice president of carbon solutions at SLB New Energy.
Brett Kerr, Calpine’s vice president of external affairs, said a healthy carbon capture industry will require a nexus of a young workforce, academics and financial capital.
“I truly believe that carbon capture can do for the Gulf Coast what tech did for the Bay Area,” he said.
Kerr said the Inflation Reduction Act’s passage means that carbon capture now makes financial sense.
“It’s always been good policy, but for the first time it really makes good business sense to pursue these projects,” he said.
Kerr said when power generation has a carbon capture facility backfit, it becomes no different from a wind or solar resource, save for an “on/off switch.” He said firm delivery will make retrofitted gas plants attractive to buyers.
Mark O’Donnell, Occidental’s assistant vice president of power, said decarbonizing the region’s natural gas plants will undoubtedly take carbon capture and a conversion to green hydrogen. He warned that at ambient temperatures, it takes three times the amount of hydrogen to produce the same amount of energy generated by natural gas.
“It’s not like you can’t overcome hurdles, but carbon capture, you’ve seen it and it’s proven,” O’Donnell said.
Form Energy Senior Business Development Manager Molly Bales said long-duration storage can de-risk utilities’ increasingly renewable generation portfolios.
Bales said her company is pioneering a rechargeable iron-air battery capable of storing power for a little more than four days at costs on par with legacy power plants. She said the batteries cost about one-tenth of lithium-ion battery facilities. The iron-air batteries “breathe” in oxygen from the air and convert iron metal to rust when discharging; the process is reversed when charging, with an electrical current converting the rust back to iron while the battery expels oxygen.
Bales said Form Energy realized that the grid needs multiday storage to firm up renewables and navigate mounting multiday weather events.
“This is an opportunity to build a whole new ecosystem,” Bales said. Form is planning to build its first battery factory in Weirton, West Virginia, a former steel town.
Bales said Form could be eyeing Texas for such a factory as soon as 2025. “We’re really excited about what’s happening in the next few years,” she said.
Inflation, Interest Curbing New Assets?
Julien Dumoulin-Smith, head of U.S. power utilities and clean energy research at Bank of America Securities, said “rampant” inflation and increasing interest rates are complicating the outlook for new asset construction.
“It’s not over,” he said of stubborn inflation. “You heard it here first.”
Dumoulin-Smith, a frequent questioner during utility earnings conference calls, said investments in carbon capture and sequestration “should be taken seriously” while green hydrogen is “similarly quite real.”
“This stuff ain’t cheap, but $85 per ton does wonders on the cost,” he said, referring to the newly enacted tax credit for carbon capture and storage.
However, Dumoulin-Smith said capacity prices and resource adequacy’s costs “have gone from zero to 100” seemingly overnight.
“I think we’re heading materially higher,” he predicted.
Dumoulin-Smith said that he expects Texas, Oklahoma and Arkansas to be most affected by generation retirements as the Environmental Protection Agency ratchets up regulations.
“We see a litany of new EPA rules ahead that could impact the generation stack again,” he said. EPA’s proposed crackdown on coal ash through effluent-limitation guidelines stands to move the needle on retirements, Dumoulin-Smith said.
He said 2023 will be a “catch up” year for solar panel supply as it recovers from last year’s trade issues. He said interconnection queue wait times also remain a problem.
“Bottom line is, you need to be very skeptical about when these projects can get done,” Dumoulin-Smith said, stressing that companies must consider how much time and money it will take to get grid treatment versus situating resources on the distribution system.
Advances in Tx Capacity
LineVision CEO Hudson Gilmer said there is a “mismatch” between today’s grid needs and planned transmission that’s five-to 10 years away. He said even Texas, which typically gets lines built faster than the rest of country, lags on new transmission capacity.
Gilmer said LineVision uses non-contact sensors and analytics to employ dynamic line ratings that allow 30-40% more power to flow through lines. He said utilities don’t always have to use “disaster plan” line ratings.
Gilmer said bottlenecks in interconnection queues have led utilities to his company.
“While no one wants to be the first to deploy a new technology, when they see their peers adopting it … there’s a tipping point,” Gilmer said. He added that dynamic line ratings have had a perception problem, with fears they would “cannibalize” the need for new transmission lines. Gilmer said contrary to that belief, the grid needs new firm capacity, even with the assistance of dynamic line ratings.
“It’s not an either-or situation. It’s an ‘and’ situation,” he said.
Stephen Conant, vice president at startup VEIR, said his company focuses on overhead superconductors that can increase line capacity without expanding rights-of-way or increasing transmission tower heights. He said superconductors are at an “exponential” adoption stage, though he admitted the costs aren’t yet competitive with normal conductors.
“There’s a huge need to build transmission capacity, but it’s difficult to site, as some as you have experienced,” he told attendees.
Conant urged the audience to remember that at one point, it was difficult to imagine the development of 18-MW offshore wind turbines when compared to the 1.5-MW turbines that were once the standard.
“In the time it takes you to build your next transmission line, you’re going to be giving me a very serious look,” he said.
Speakers with Differing Market Views
Texas Public Utility Commissioner Kathleen Jackson said she believes the state’s energy future will come down to a blend of “a lot of little things,” not a singular technological solution. She urged attendees to focus on the “data, science and economics” when standing up new technologies.
Jackson urged Texas utilities to focus on energy efficiency and investing in new assets. She said the state’s growing population demands forward planning and making the most out of existing generation.
“We have 1,200 people coming to Texas each day,” she said. “Nobody is bringing power with them.”
Carrie Bivens, ERCOT’s Independent Market Monitor, said growing load uncertainty and renewables dominance in Texas means that ERCOT is currently making avoidable out-of-market commitments. She said she expects the energy-only market to effectively send price signals that stir respondents and said she doesn’t foresee a “fundamental” market breakdown on the horizon.
Former FERC chair Joseph Kelliher expressed disappointment during a keynote address over how RTO executives lead wholesale markets today.
“When I was at FERC, we expected RTO leadership to be more FERC-like. And I know that sounds obnoxious,” he said, explaining that grid operators should make unpopular decisions at times.
“I think some RTOs have become more dedicated to stakeholder consensus than they do toward market integrity,” he said. “I think some RTOs have lost their way, and that’s their current approach.”
Kelliher said capacity markets, especially those in the Northeast, are disappointing and producing suppressed prices that won’t support new generation entry. He said grid operators might consider scrapping the markets altogether and focus instead on long-term contracts.
GCPA Debuts ‘Power Pitch’
The GCPA conference featured a new concept in Power Pitch, where early-stage energy technology companies competed for a $5,000 award styled after the “Shark Tank” television show. Bodhi, a software app that offers real-time, personalized updates on homeowners’ residential solar projects, took the award home to Austin.
The judging panel consisted of three professional energy investors, with the audience weighing in via an interactive survey. Criteria included the presentation’s quality, potential impact on the industry, and the business model’s potential success. Judges asked about the comparative costs of new technologies, risks of being copied, ease of manufacturing and target customers.
Other contestants included:
Calwave Power Technologies, which plans to churn out submerged xWave boxes to harness the power of ocean waves and complement power output at existing offshore wind sites;
Criterion Energy Partners’ distributed geothermal system designed to be co-located on heavy industrial sites in Texas and Louisiana;
Revterra’s grid-synchronous, inverter-free kinetic flywheel battery that serves as a buffer between the grid and EV charging; and
Dash Clean Energy’s zero-emission hydrogen fuel cell storage facility, which is trying to ensure peaker plants can replace retiring older generation.
Houston-based energy startup incubator Greentown Labs vetted the contestants.
ISO-NE’s revised load forecast sees slower growth in the next few years because of economic turbulence, followed by accelerating growth from electrification.
The RTO’s draft 2023 Capacity, Energy, Loads, and Transmission (CELT) report, presented at the April 20 Planning Advisory Committee meeting, projects the RTO’s net winter 50/50 peak will hit 25,133 MW by 2031, a 10% increase over last year’s CELT projection for that year. The net forecast subtracts the impact of energy efficiency and behind-the-meter PV.
The RTO predicts a 2031 gross 50/50 winter peak — including BTM resources and passive demand resources that participate in the ISO-NE markets — of 27,646 MW, almost 7% above its 2022 forecast. For 2023, however, ISO-NE projects a gross winter peak of 22,053, almost 1% below the 2022 projection.
The summer forecasts for 2023 and 2024 also have been reduced from last year with the summer gross 50/50 forecast reduced by 1% in both 2023 and 2024.
New England’s projected economic growth (real gross state product) | ISO-NE draft 2023 Capacity, Energy, Loads, and Transmission report
The new report incorporates Moody’s February 2023 macroeconomic outlook, which projects the region’s economic output will be about 3% less than its previous forecast through 2032 because of the war in Ukraine, increased fossil fuel prices and the Federal Reserve’s interest rate increases to tame inflation. The final CELT report will be released May 1.
Lead data scientist Victoria Rojo told the PAC that the RTO expects winter loads to grow faster than summer loads over the next decade.
“In the outer years, you see a lot more growth [in winter] than you do in summer because now in our electrification forecast, we have both the heating and transportation components, which increased significantly over last year’s forecast,” she said.
By 2032, the 50/50 net load forecast shows the winter peak less than 800 MW below the summer peak. The 50/50 measure is a probabilistic forecast intended to be indicative of normal weather conditions in each season. “So if, for example, you had a summer with cooler than normal summer weather conditions, and in that same year, you have a winter with more extreme than normal winter weather, it’s possible that you can see a winter peaking system much sooner than our 50/50 forecast would dictate — possibly even by the end of the forecast horizon,” Rojo said.
RTO system planners have made no major changes to the specification of the summer/winter demand forecast models since CELT 2020, Rojo said. However, methodologies for both the heating and transportation electrification forecasts have been updated since CELT 2022.
“On the heating side, we’ve completely overhauled our methodology. And on the transportation side, we’ve made some more targeted updates to pieces of the methodology,” Rojo said.
For heating, the RTO changed how it performs demand modeling, as well as how it forecasts the adoption of electrification. It includes a greater variety of building types and technologies through use of the National Renewable Energy Laboratory’s residential and commercial real estate stock data sets.
Planners are now including the impacts on commercial real estate “whereas in the past forecasts, we focused exclusively on the residential sector,” Rojo said.
Residential properties are forecast to adopt electrification at different rates depending on their current heat source, with oil-heated homes transitioning faster than propane and natural gas properties lagging both.
The RTO’s forecast shows faster adoption of full heating electrification in the commercial sector while the residential buildings are expected to see more partial heating electrification.
“It’s easier to install a ductless mini-split heat pump … especially when you have buildings that have [hot water] systems that have no ductwork [for heating or air conditioning],” Rojo said. “It’s easier to just do the partial application, which can be a room or zone in the house.
“The expectation is that when a business … chooses to electrify a building, they’re doing it as more of a business decision versus just kind of taking advantage of certain incentives [available to residential homeowners]. It’s more of a business choice, and it’s more likely to be a whole business transition,” she added.
FERC on Thursday approved revised rate schedules for two American Electric Power (NASDAQ:AEP) affiliates in Ohio to remove their RTO participation adders (ER23-855).
The order stems from a complaint filed last year by the Ohio Consumers’ Counsel (OCC) arguing that because state law mandates that transmission owners in the state participate in an RTO, the utilities should not be eligible for the adder. The commission agreed in December, requiring AEP to make a compliance filing recalculating its returns on equity for the affiliates without the RTO adder. (See FERC Orders Two Ohio Utilities Ineligible for RTO Adder.)
Under the new language, AEP affiliates Ohio Power and AEP Ohio Transmission would lower their ROE from 10.35% to 9.85% under the filing and revise the PJM tariff to specify that the adder does not apply to those companies.
The commission also approved a proposal in AEP’s filing to add language to the tariff stating that the companies have the right to receive refunds should federal courts invalidate the Ohio law, noting that there are pending lawsuits challenging the legislation on the grounds that it may pre-empt the Federal Power Act.
The OCC protested the filing, arguing that the notice provision asserting the right to collect refunds should not be approved, arguing it is out of scope, premature, and a violation of the filed-rate doctrine and rule against retroactive ratemaking.
AEP countered that the provision does not violate the filed-rate doctrine because it provides notice of a potential future rate change, which has been upheld by past court rulings. The commission agreed.
“If the commission’s determination in the December order is overturned, the inclusion of the notice provision provides sufficient notice under the filed-rate doctrine to permit Ohio Power and AEP Ohio Transmission to surcharge customers,” FERC wrote.
NextEra Energy (NYSE: NEE) is continuing its efforts to salvage the only competitive regional transmission project MISO has recommended in its South region, filing a request last week at FERC to stay the commission’s recent order that formally terminated the project.
NextEra Energy Transmission Midwest (NEET) requested on Monday both a rehearing and a stay of FERC’s March order that allowed MISO to abandon the $115 million, 500-kV Hartburg-Sabine Junction project in East Texas (ER23-865). MISO approved the project in 2017 but determined last year that the project’s benefits faded after recent generation additions in the region. (See FERC Rejects Last-ditch Effort to Save Tx Project.)
NEET said the stay is necessary while it “fully exercises its right to judicial review” of not only the March order but also its pending appeal of Texas right of first refusal legislation that prompted MISO’s re-evaluation of the project.
The 5th U.S. Circuit Court of Appeals last year ruled that the state’s 2019 law giving incumbent transmission companies the first rights to build new power lines is unconstitutional. Texas has petitioned the U.S. Supreme Court to review that decision. (See Texas Petitions SCOTUS to Review ROFR Ruling.)
NEET said it is likely to succeed in the case and maintains that FERC’s cancellation of the project was premature.
“Absent a stay of the commission’s order, the project will be removed from MISO’s regional transmission planning models and cannot easily be reinstated, regardless of whether NEET Midwest prevails on rehearing or on appeal,” NEET argued. “Granting a stay will avoid imposing these substantial and irreversible consequences on NEET Midwest and will not unduly harm third parties.”
The transmission developer said MISO will likely remove the project from planning models for its interconnection queue and 2024 Transmission Expansion Plan (MTEP) cycle, which will begin later this year.
“Once removed from MISO’s MTEP and generator interconnection planning models, it will be difficult, if not impossible, to reinstate the project, particularly given the disruptions and delays to MISO’s annual transmission planning and interconnection studies that reinstatement will likely cause,” NEET said.
The NextEra subsidiary added that interconnection customers are unlikely to be harmed if the project is kept in planning models because no generation projects currently rely on it for grid access. NEET said scrubbing the project from MISO “prior to final resolution of the legal issues surrounding it” may require customers to pay abandonment costs.
The developer said it’s at a point where it has spent significant money to participate in MISO’s competitive bidding process and to develop the project, but that it may be unable to recover even a portion of its costs.
NEET argued that FERC simply took MISO at its word that keeping the project on its books would distort transmission planning. It said the grid operator’s tariff language triggering a project’s re-examination is more prescriptive and includes “reliability- or service-related issues that may ‘be jeopardized as a result of the delay.’” The developer pointed out that MISO continues to incorporate the unfinished Cardinal-Hickory Creek line in the Midwest that was first recommended in 2011 in its models.
It also said FERC should have more seriously weighed not taking immediate action on the project while the Texas ROFR litigation is pending.
Opponents of a natural gas compressor station made a long-shot bid to close the facility in oral arguments Thursday at the D.C. Circuit Court of Appeals that focused on FERC’s handling of environmental justice concerns.
The compressor is part of Algonquin Gas Transmission’s $627 million Atlantic Bridge Pipeline Project, which expanded capacity into the area.
The commission approved the pipeline expansion, including the compressor, on a peninsula in the city of Weymouth, Mass., in early 2017. In September 2020, the compressor station had two unplanned releases of natural gas, leading a number of groups to ask FERC to reconsider the project.
The commission then took the rare step of asking for briefings on the environmental justice impacts of the compressor after the certificate had been granted and upheld on appeal to the D.C. Circuit.
In an order dealing with those briefings issued in January 2022, FERC let the project keep its certificate. However, then-Chair Richard Glick said he thought the earlier order was likely a mistake, though it could not legally be overturned as the time for rehearing had passed and the D.C. Circuit had upheld that initial decision.
“Although it is cold comfort for the residents near the compressor station, I hope that this proceeding will serve as a turning point for the commission as we work to better consider, address and act on issues of environmental justice,” Glick said during the 2022 briefings.
The attorney for Fore River Residents Against the Compressor Station, Michael Hayden of Morrison Mahoney LLP, told the three-judge panel Thursday that FERC’s decision on the briefings was a “Pyrrhic victory.”
Since then, Glick was denied a nomination hearing before the Senate, which means FERC is more prone to deadlock on such cases with two members from each party, he added.
“I recognize it is a mountainous uphill climb for my clients [to] expect any change to occur before FERC,” Hayden said. “So we don’t expect it to happen voluntarily. It is only going to happen through the influence of the courts.”
The judges asked questions focusing on the same procedural issues that FERC said tied its hands in reviewing the environmental justice concerns. Chief Judge Sri Srinivasan noted that Hayden and his clients were not challenging the 2020 order that authorized an extension of the project’s certificate, but only the order on briefs that also dealt with the rehearing on the extension request.
FERC granted an extension request to the Atlantic Bridge project just 34 minutes after receiving it in the days following Christmas 2018, through an order issued by a staffer. Hayden complained that stopped his clients and others from even having a chance to challenge the firm’s request for an extension.
FERC attorney Jared Fish noted that the staff was in a position to act because it had been monitoring the project’s efforts to get state permits, which were also heavily litigated and delayed. The entire commission later confirmed that order, giving opponents a chance to weigh in on the merits of the extension. But they did not seek rehearing of that order, instead challenging the 2022 order on the briefings.
That 2022 order was an “unusual animal” that constituted a rare third round before the commission, Judge Patricia Millet said.
“I feel like it’s … a little unfair to put on them not to know how to challenge it,” she said.
FERC effectively asked the towns and residents to make their case; the commission seemed to agree with them; but then nothing was changed, Millet said.
“I credit FERC for having done the work and professed its need to change going forward,” Millet said. “But … real people are getting lost in the technicalities of all of this.”
Fish said the problem was that the petitioners asked FERC to reopen its decision granting a certificate, which is not something that it was legally able to do as the 60-day rehearing period had long ended and the court had already upheld the decision.
“You ask for new evidence, new briefing arguments about events that post-date the facility coming online, but it’s not a reopening?” said Millet. “How is it not a reopening?”
Fish answered that FERC was looking for information to determine whether Algonquin was still in compliance with its certificate based on the unintentional releases of natural gas and other new information such as COVID’s impact on environmental justice communities. The commission ultimately found no credible allegation that Algonquin was out of compliance with its certificate order or other permits, he added.
A bill that would require all new electric vehicles to have bidirectional charging capabilities for vehicle-to-grid (V2G) or vehicle-to-home uses by 2027 cleared the California State Senate Energy, Utilities and Communications Committee on Tuesday despite opposition from large utilities and automakers.
Senate Bill 233 “will ensure that new EVs are equipped with bidirectional charging so that EV batteries have the ability to power homes or other facilities when electricity demand is at its peak and prices are high,” the bill’s author, Sen. Nancy Skinner, wrote in a statement on the need for the bill. “With bidirectional charging, EVs also have the potential to help power the grid.”
California has a requirement that 100% of new passenger vehicles sold in-state must be zero-emission by 2035, with interim goals of 35% by 2026 and 68% by 2030.
The California Electric Transportation Coalition (CalETC) — a group whose members include Pacific Gas and Electric, Southern California Edison and the Los Angeles Department of Water and Power — said Skinner’s bill could hinder EV adoption and undermine the state’s efforts.
“The ramifications of setting a mandatory deadline requiring EVs and chargers to be bidirectional-capable will be detrimental to the EV market and risks increasing costs at a time when zero-emission technology needs to be more accessible to consumers, especially equity communities,” the group wrote in a letter opposing the measure.
“The V2G and bidirectional charging technology market is still nascent, and it is unclear which use cases justify the costs,” it said. “Further, the lion’s share of benefits to grid stability and resiliency are expected to be realized with managed charging through V1G [unidirectional smart charging] technology in the near to medium term and at much lower cost.”
At Tuesday’s hearing, Skinner noted that all Nissan Leafs have been bidirectional since 2013 and remain among the most affordable on the market. All Tesla models will be bidirectional starting with the next model year, she said.
“We’re already moving in this direction, but we need all of our vehicle manufacturers to move their EVs to bidirectional, so that we have that capability,” she said. Doing so could save ratepayers money and promote grid reliability during times of high demand, she said.
“With the expectation that 8 million EVs will be on the road by 2030, if less than 10% of those EVs were utilized in this way, it would have more gigawatt capacity than Diablo Canyon has today,” she said.
Diablo Canyon, the state’s last operating nuclear power plant and its single largest power source, has a 2.2-GW generating capacity.
Supporters of the bill include the Sierra Club, the Union of Concerned Scientists and community choice aggregator Marin Clean Energy.
In their analysis of the bill, committee staff suggested lawmakers might want to amend the bill to remove its mandates and instead direct the California Energy Commission and Air Resources Board to study the availability of bidirectional EVs and chargers, as well as the costs and benefits of bidirectional EV charging and discharging to the grid.
The Alliance for Automotive Innovation — a group whose members include Ford, General Motors and Toyota — said it would oppose the bill unless the mandates were removed and urged the committee to follow its staff’s suggestions.
Skinner accepted an amendment to remove a mandate that EV charging equipment be bidirectional by 2027 but did not remove the vehicle mandate.
Curt Augustine, head of state affairs for the auto alliance, said he was “perplexed” by the move.
“She is exempting all the utilities, the service providers [and] the charging units but requiring a mandate on the automakers,” he said.
Some committee members expressed concerns with the measure, including its potential effects on EV affordability for low-income residents, but they passed it 12-1. It goes next to the Senate Transportation Committee.
FERC on Tuesday approved a PJM proposal to overhaul how generators can represent variable operating and maintenance (VOM) costs in their energy market offers (ER23-1138).
The proposal sought to divide generators’ maintenance adders into “major” and “minor” buckets and allow the owners to opt for newly created default values for minor maintenance. The proposal also would create default values for operating expenses, which — like minor maintenance — have a tendency to be fairly uniform year-over-year, PJM said. (See “MRC Approves VOM Package,” PJM MRC Briefs: Nov. 16, 2022.)
The April 18 order said the proposal streamlines the process for approving maintenance and operating costs, while retaining market power protections. The order granted PJM’s requested June 1 effective date.
“PJM’s proposal offers market sellers flexibility while maintaining essential safeguards to mitigate opportunities for market sellers to exercise market power,” the commission said.
Under the status quo rules, generators are required to submit documentation of any maintenance and operating expenses they’re seeking to include in their cost-based offers, which the filing said causes “significant administrative burdens for both market sellers and PJM.”
The maintenance history used to calculate corresponding adders includes costs going back 10 to 20 years, which results in time spent reviewing and approving those costs each year, PJM said. The proposal allows expenses for major maintenance to be approved with an “expiration date,” after which costs must be resubmitted.
Major maintenance expenses would also be required to be resubmitted if they are no longer accurate due to expenses rolling off the 10- or 20-year historical period.
Generators would still have the option to submit unit specific costs for minor maintenance and operating expenses. However, PJM argued that the process of submitting, reviewing and approving expenses typically takes several months on behalf of sellers, RTO staff and the Independent Market Monitor.
Default adders would not be created for nuclear and hydroelectric resources, which PJM said lack the historical data being used to create the adders for other resource types, nor for wind and solar, which the filing said typically don’t submit maintenance adders. PJM may seek to create those adders in the future.
The proposal defines major maintenance as “overhauls, repairs, or refurbishments that require disassembly to complete of boiler, reactor, heat recovery steam generator, steam turbine, gas turbine, hydro turbine, generator, or engine.” Minor maintenance is described as “typically performed when there is a component failure or prior to a component failure due to limited remaining component life” and that can be completed while the generator is operating or during short shutdowns.
Monitor Protests Inclusion of Avoidable Costs
The Monitor argued that PJM’s proposal incorrectly allows maintenance costs that are avoidable costs and should be included in capacity offers to be instead submitted as short-run marginal costs in the energy market.
The issue arises from a vague definition of maintenance costs, the protest states, allowing all costs “directly related to electricity production” to be included in energy offers.
To support its position that maintenance costs should be included in capacity offers, the Monitor pointed to a filing to allow the Indian River 4 coal-fired unit to provide service after its deactivation request, in which it seeks to receive a lump-sum payment for its maintenance-related investments rather than recovering those expenses through the energy market. The protest also states that 53% of marginal units in the energy market included maintenance costs in their 2022 energy market offers.
PJM responded that its proposal doesn’t seek to change the existing requirement that maintenance adders can only be recovered in the energy market and through the avoidable cost rate (ACR) in the energy market. It also argues that the Monitor’s objections have been raised in past dockets and constitutes a collateral attack on the commission’s 2019 order approving PJM’s maintenance adders revisions (EL19-8).
In this week’s order, the commission noted that it had addressed the concerns raised by the Monitor in 2019.
“The wear and tear of operating a resource is typically based on the number of starts or run hours, and the maintenance intervals can be influenced by resource output levels. As such, it is reasonable to assume that some maintenance costs are incurred as the result of operating the resource, even if such costs are not incurred immediately at the time of production,” the commission said in its 2019 order, cited in the recent finding.
FERC took the final step on Thursday in fulfilling its obligation to encourage voluntary investments in cybersecurity by electric utilities, as directed by Congress two years ago (RM22-19).
Congress ordered FERC to develop its cyber incentive plan in the Infrastructure Investment and Jobs Act of 2021, which mandated that the commission establish financial incentives for public utilities to invest in “advanced cybersecurity technology” and participate in cybersecurity threat information-sharing programs.
FERC Chair Willie Phillips | FERC
“In today’s highly interconnected world, our nation’s security and economic wellbeing depend on reliable and cyber-resilient energy infrastructure,” FERC Chair Willie Phillips said in a statement. “We must continue to build upon the mandatory framework of our cybersecurity reliability standards with efforts such as this to encourage utilities to proactively make additional cybersecurity investments in their systems.”
The final rule approved Thursday is largely similar to the Notice of Proposed Rulemaking that FERC issued last September. (See FERC Reluctantly Proposes Cybersecurity Incentives.) It sets three ways utilities may qualify for the incentives:
any investment included in a prequalified list of cybersecurity expenditures with a rebuttable presumption of eligibility;
investments needed to establish compliance with NERC’s mandatory Critical Infrastructure Protection (CIP) standards that are not yet enforceable; and
investments not included in either of these categories but “tailored to their specific situations” and approved by FERC on a case-by-case basis.
The first qualification was already given in last year’s NOPR; the latter two were added for the final rule. Eligible investments must be for technology that “materially improves” a utility’s cybersecurity posture and is not already mandated by law or the CIP standards. Expenses for participating in threat information-sharing programs would also qualify for reimbursement.
Also included from the NOPR is the proposal to allow deferred cost recovery for eligible investments, through which utilities may add the unamortized portion of the expenses to their rate base.
An alternative means of compensation that would have provided a return on equity adder of 200 basis points was not adopted in the final rule. Commissioner Mark Christie criticized the idea as “FERC candy” when it was brought up in September, saying it was “pretty sour for consumers” who would end up paying utilities significantly more for doing what they “ought to do anyway.”
Incentives will remain in effect for up to five years from the date the expenses are incurred, with some exceptions, as long as the investments remain voluntary.
The only dissenting vote on the measure came from Commissioner James Danly, who said at Thursday’s meeting that despite the “unambiguous declarations of Congress and [their] clear purpose [of] directing us to incentivize certain types of investments,” FERC had chosen an “insufficient” path for fulfilling its mandate.
“We can quibble all we like about whether or not [the law] was the right way to do it; it doesn’t matter,” Danly said. “We’ve been given our marching orders by Congress, and it has been a matter of continuous interest to any number of policymakers that we take more aggressive stances on cybersecurity. This rule fails to encompass a sufficient quantity of the entire electric system, and it demands certain levels of materiality that I think are simply not appropriate given the statutory language.”
Danly tempered his criticism with praise for Phillips’ “enthusiastic and unflagging … support for ensuring that the NERC reliability standards are up to scratch.”
The final rule will take effect 60 days following its publication in the Federal Register. FERC had not published its order approving the rule as of press time.
More than 1.5 million light-duty electric vehicles have now been sold in California, beating by two years the target set by a governor’s executive order in 2012.
The state reached the 1.5-million EV milestone during the first quarter of this year, according to data released Thursday by the California Energy Commission. And 21% of new cars sold in California in the first quarter were electric. The EV data include battery electric vehicles, plug-in hybrids and hydrogen fuel cell EVs.
In March 2012, Gov. Jerry Brown issued executive order B-16-2012, calling for 1.5 million zero-emission vehicles on California roads by 2025.
At the time, many viewed the target as a “moonshot,” or aspirational goal, state officials said during a media briefing on Thursday. At the end of 2011, only 6,743 EVs had been sold in the state.
“When Gov. Brown set this goal, people across the state and around the nation said it couldn’t be done,” said Lauren Sanchez, senior climate adviser to Gov. Gavin Newsom. “But here in California, we make the future happen. We don’t just set goals, we achieve them.”
California Air Resources Board Chair Liane Randolph credited the state’s zero-emission vehicle (ZEV) regulations for spurring ZEV technology and manufacturing.
“The industry has responded incredibly rapidly to the confluence of market pressures, consumer demands and regulatory requirements,” Randolph said during the briefing.
In 2012, CARB adopted its initial Advanced Clean Cars regulation, which requires an increasing percentage of zero-emission cars to be sold each year. In August, the agency adopted Advanced Clean Cars II, which requires all new cars sold in the state to be zero-emission or plug-in hybrid by 2035. (See Calif. Adopts Rule Banning Gas-powered Car Sales in 2035.)
ZEV adoption in California also has been boosted by nearly $2 billion in purchase incentives, officials said.
“California is setting the bar for climate action,” Newsom said in a statement. “And we’re achieving our goals years ahead of schedule thanks to unprecedented investments secured in partnership with the Legislature.”
The 1.52 million light-duty EVs sold in California through the end of the first quarter of 2023 represent 42% of the 3.61 million EVs sold in the U.S.
“The transition to ZEVs is here, and it’s happening quickly,” California Energy Commission member Patty Monahan said during Thursday’s media briefing.
The CEC is playing a lead role in ensuring enough charging infrastructure and hydrogen-fueling stations are built to support the growing number of EVs. A 2021 analysis found that the state will need 1.2 million public and shared private charging ports to support 8 million plug-in electric passenger vehicles in 2030, Monahan said. The CEC expects to release this year an updated analysis of EV charger demand.
According to figures released Thursday, California had 87,707 EV chargers and 63 hydrogen-fueling stations at the end of the first quarter.
Monahan said efforts are also underway to improve the reliability of public chargers. Drivers often find that chargers don’t work at the public stations, or there’s a glitch in using their credit cards, she said. CEC is developing reporting requirements for the reliability of publicly funded chargers and will publish a report on the reliability of the state’s EV charging network.
In addition, Monahan said, EVs must be “good citizens of the grid.” An analysis found that EVs will account for less than 5% of peak load in 2030. But that demand must be managed wisely, she added.
“With the right incentives, vehicles could shift charging from peak times to the middle of the day,” Monahan said. “You could literally run your vehicle on sunshine, and we wouldn’t have to curtail renewable energy.”
