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June 17, 2024

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Calif. Clean Transportation Program Needs Equity Emphasis

California’s funding of zero-emission vehicle (ZEV) infrastructure must be more equitably allocated to disadvantaged communities, according to advisory committee members for the state Energy Commission’s (CEC) Clean Transportation Program Investment Plan.  

“We have the highest prevalence of asthma in Imperial County in comparison to the rest of the state of California and the rest of the nation. … From the moment we arrive here, we are persistently assaulted … with carcinogens and irritants that are causing respiratory problems and cancer,” committee member Luis Olmedo, executive director of the nonprofit Comite Civico del Valle, told NetZero Insider. “For that reason, it is extremely important that we transition to net-zero transportation and the net-zero economy as swiftly and as quickly as we possibly can.”  

Details of the Clean Transportation Program were discussed at a June 7 meeting hosted by the CEC, where industry experts grappled with how best to spend the almost $100 million available annually.  

“How do we spend our money wisely to accelerate zero-emission transportation and do it in a way that’s very attentive to equity?” CEC Commissioner Patty Monahan said at the meeting. “We need to ensure that Californians who are too often left behind in the transition to clean energy and left behind in terms of facing disproportionate burdens of air pollution, we need to make sure those communities benefit.” 

Established in 2008 and recently extended through July 2035 under Assembly Bill 126, the Clean Transportation Program promotes accelerated development and deployment of ZEVs and related infrastructure to meet California’s goal of electrifying 100% of passenger vehicles and drayage trucks by 2035 and 100% for medium- and heavy-duty trucks by 2045. It receives an annual investment of up to $100 million using funds collected from vehicle and vessel registration, license plate and smog abatement fees.  

Through 2023, the program was responsible for installing or planning more than 33,300 chargers for ZEVs, creating block grants to incentivize light-duty EV charging infrastructure projects, and allocating funding for 96 publicly available hydrogen fueling stations. It also awarded more than $107.4 million in ZEV infrastructure incentives to 190 projects through the nation’s first commercial vehicle fleet incentive project, called Energy Infrastructure Incentives for Zero-Emission Commercial Vehicles, and more.  

The CEC provides an annual investment plan update that guides the allocation of program funding for transportation solicitations for the upcoming fiscal year. Proposed investments for 2024/25 totaled $1.52 billion with the addition of National Electric Vehicle Infrastructure program funds, according to Benjamin Tuggy, Clean Transportation Program Investment Plan project manager at the CEC. Of that total, $656 million is allocated to light-duty charging infrastructure, $810 million to medium- and heavy-duty charging, $46 million to “emerging opportunities” and $3 million to ZEV workforce development.  

The CEC requires that more than 50% of funds go to projects that benefit low-income or disadvantaged communities. The Communities in Charge program, which is run by CALSTART and deploys Level 2 chargers, provided $68 million over two funding windows, all of which went to projects in disadvantaged communities, Marissa Williams, a supervisor in the CEC’s Fuels and Transportation Division, said during the meeting.  

Additionally, the CALeVIP 2.0 program, which is administered by the Center for Sustainable Energy and deploys DC fast chargers, also distributed $68 million, with a requirement that all projects be in disadvantaged communities.  

‘Equity Equals Capital’

But despite the emphasis on equity, some advisory committee members said disadvantaged communities still weren’t being adequately considered. Olmedo told NetZero Insider that while funding is being allocated to low-income communities, it often goes to those in metropolitan areas “where the market is,” creating EV deserts in rural communities like his own.  

“We have a lot of EV deserts in California. Companies aren’t going to go and invest there because the market isn’t there,” Olmedo said at the meeting. “The other thing that makes it even more challenging is when you have other state agencies like GO-Biz [Governor’s Office of Business and Economic Development] directing developers to go where the market is and specifically where they have adopted a streamlined permitting process. So, these programs are working against each other to continue to make it more difficult for these EV deserts to thrive.”  

Olmedo pointed to legislation that requires permitting agencies to develop a streamlining mechanism, saying it is well intentioned but creates unintended barriers for low-income communities that may not have an internal permitting agency or the staff and resources required. GO-Biz created a map that shows which cities have streamlined permitting processes, signaling developers to “go there,” Olmedo said. 

“That communication is what we characterize as redlining in our communities, making it harder when you’re signaling to developers not to come here. You’re creating an EV desert” he said. “There’s a lot of times a misalignment in communication between the Energy Commission, who’s like ‘Hey, let’s build, build, build,’ and then GO-Biz … saying, ‘Yes, build, but build over there.’ So, that became very problematic.” 

In an interview with NetZero Insider, advisory committee member Rev. Dr. Charles Dorsey described how state efforts to distribute funding for clean transportation or other resources don’t adequately consider disadvantaged communities. In particular, he pointed to problems with the state’s processes around requests for proposals, which pit disadvantaged communities against bigger organizations that have won awards in the past.  

“The structure and the requirements of the proposal automatically create barriers for companies that are led by people of color,” he said. “You have a limited number of contractors who can actually equitably apply.”  

“They believe that just by putting the proposal out, that it is equal competition. It is not. Because they designed the proposal without considering the barriers that are already in place,” Dorsey said.   

Both Olmedo and Dorsey think the state should better address inequities built into its processes. Olmedo emphasized the importance of including more nonprofits in the process instead of prioritizing for-profit companies that can make money quicker. He noted at the meeting that Comite Civico Del Valle was one of the first nonprofits to receive funding from the CALeVIP 2.0 grant program, which says “a lot about how the state has been wrong in how it has prioritized its investment.”  

“If you go to rural communities, you’re not going to make a profit in the next three years,” he said. First, you [have to] create reliable EV infrastructure, and then disadvantaged, low-income communities can take the risk of buying an electric vehicle. Because you have less income, you can’t risk not having reliable infrastructure, because that might mean you don’t get to work on time. That might mean that by the end of the day, you don’t have a job.”  

Collaborating with nonprofits and investing in a three-to-five-year plan can create a market in rural communities that ultimately will help California meet its decarbonization goals, Olmedo said. He’s optimistic the Clean Transportation Program will bring EV infrastructure to rural, disadvantaged areas, as long as enough money is invested.   

“What we need is capital, and we need to make that a commonly used term whenever we talk about disadvantaged communities,” Olmedo said in the meeting. “Don’t give us more paper. Don’t give us more education. Yes, that is necessary, but equity equals capital, and these programs need to be designed to bring equity and capital into these rural clean transportation deserts.”  

While many advisory committee members at the meeting said the allocation of the $1.52 billion was appropriate, Dorsey emphasized he won’t know until there’s a formal process in place to overcome investment barriers for disadvantaged communities.  

“When you ask me if the spread is right, you’re also asking me if the process is right,” Dorsey said. “And I can’t answer that question.” 

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Stakeholder Soapbox: A New Twist on Capacity Markets in Japan

Reliability is a global problem that requires local solutions. For more than 15 years, PJM’s solution has been its forward-looking capacity market, the Reliability Pricing Model. Meanwhile, on the other side of the world, Japan recently enacted major reforms to its energy system. Those reforms have included a PJM-inspired capacity auction first held in 2020 for the 2024 delivery year and a related long-term decarbonized power resource auction inaugurated this year. 

Japan’s energy reforms are of increasing importance globally, including to U.S. companies and investors. A weak yen has spurred investment in Japanese energy projects, and foreign- and U.S.-owned energy companies have started winning major capacity contracts in Japan’s new system. Recent developments in Japan have revealed, however, that its market differs in significant ways from those in the U.S. — including from the very PJM capacity market on which Japan modeled its own. 

A Modified PJM Capacity Market in Japan

When Japan embarked on its energy reforms, it formed a study group to examine foreign capacity markets, including PJM’s, and to make a proposal for how best to ensure long- and midterm reliability in its energy markets. Ultimately, the study group concluded a capacity market similar to PJM’s model (and the model used in the U.K.) would work best. 

The capacity market system Japan ultimately adopted shares the same basic structure as PJM’s. It is presided over by a private transmission organization called the Organization for Cross-Regional Coordination of Transmission Operators, (OCCTO). Like PJM, OCCTO runs a centralized capacity auction where generation resources offer to sell capacity for a price, and the auction’s clearing price is ultimately set at the point where supply and demand curves cross. 

There are, however, several key differences between Japan’s market and PJM’s. For example, unlike PJM’s system, participation in OCCTO’s capacity market is never required for participation in Japan’s wholesale electricity markets.  And unlike PJM, OCCTO does not administer the wholesale electricity market itself: Another organization, the Japan Electric Power Exchange, does. 

Perhaps most critically, OCCTO’s and PJM’s systems are different because they are governed by different legal frameworks. OCCTO is authorized and governed by Japan’s 2015 amended Electricity Business Act, while PJM (like other U.S. RTOs) is governed by the Federal Power Act. Those laws impose materially different restrictions, based on different national policies. The FPA, for example, embraces what U.S. courts have long called the filed-rate doctrine, which forbids retroactive rate changes. That prioritizes pricing predictability, even when doing so may result in higher-than-necessary consumer prices. Japan, by contrast, has not adopted the filed-rate doctrine; it has prioritized lowering consumer prices instead. 

A Focus on Reducing Prices

Japan’s focus on reducing prices has been especially clear in its management of its new capacity markets. Since the first capacity auction in 2020 yielded prices far higher than expected, Japan’s energy regulator — the Electricity and Gas Market Surveillance Commission (EGC) — has been on the lookout for ways to ensure that OCCTO’s capacity auction prices remain as low as possible. That has been especially clear in the EGC’s handling of the 2022 capacity auction for the 2026 delivery year. 

First, after the 2022 auction closed but before results were announced, the EGC discovered that one capacity supplier’s offer was too high because of a mistake. In consultation with OCCTO, the commission took the unprecedented step — one that no statute or auction rule permitted — of requiring that the offer be corrected and the resulting capacity price for all participants be changed accordingly. 

Second, this year, the EGC discovered another “misbidding” mistake — this time, after the 2022 auction results had been announced and the supplier had been awarded a contract. The commission and OCCTO promptly announced that they would amend the supplier’s contract to reduce the contracted capacity price. Recognizing that such a change was also unprecedented, the organizations emphasized that such an adjustment should be made only when the resulting capacity price would be lower, to protect consumers. 

Will Japan Adopt Something Like the Filed-rate Doctrine?

Japan’s energy and capacity markets are, in many ways, still in their infancy. Japan might still develop or adopt something akin to the filed-rate doctrine, or it might reject the doctrine expressly. Either way, Japan cannot help but recognize that market forces demand some degree of pricing predictability. Even in the recent misbidding investigations, for example, Japanese regulators showed they are sensitive to the same concerns that motivate the filed-rate doctrine. They could have undone the entire 2022 capacity auction this year after they discovered that misbidding affected the clearing price, but they did not. Instead, they amended only the responsible supplier’s contract while recognizing that amending such established contracts should be a rare event — one limited to situations where it will protect consumers without destabilizing market expectations. 

Even without a formal filed-rate doctrine, in other words, Japan’s capacity markets are not the Wild West. Japan cannot make reneging on capacity prices a habit, because participation in the capacity markets there is entirely voluntary. To incentivize participation and ensure reliability for consumers, if nothing else, Japan will need to safeguard the predictability of prices once they are set. Whether it will formally adopt the filed-rate doctrine, or something like it, in the years to come remains to be seen. 

 

Eri Akiyama is an attorney with Nagashima Ohno & Tsunematsu with a practice that includes energy and other complex civil litigation. She served as an international associate at MoloLamken LLP in New York from September 2023 to June 2024. 

Jennifer Fischell is a partner at MoloLamken with a practice focusing on energy and complex civil litigation, administrative law and appeals. She has clerked for judges at all levels of the federal judiciary, most recently for U.S. Supreme Court Justice Elena Kagan. 

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Clements Says Order 1920 Will Help States, not Usurp Authority

WASHINGTON — FERC Commissioner Allison Clements said last week that Order 1920 will make it easier for states to address the changes facing the industry. 

Rehearing requests have come into FERC, and some states are argue the commission cannot impose the new transmission planning and cost allocation rules on them, Clements said at the annual meeting of the Energy Bar Association’s Northeast Chapter. The issue of states’ rights drove Commissioner Mark Christie to dissent from the order, which Clements and Chair Willie Phillips responded to in a concurrence. (See FERC Issues Transmission Rule Without ROFR Changes, Christie’s Vote.) 

“Good luck to the states who think they’d be better off going at this alone. Good luck to the economic development opportunities that your state faces. Good luck to the health and safety of your citizens in extreme weather,” Clements said. “I mean, I don’t know that there’s any other way to get there besides all the solution sets, and regional transmission and inter-regional transmission has to be at the top of that list, at least in the FERC-jurisdictional bucket.” 

The changes ultimately are an incremental step from what FERC did more than a decade ago in Order 1000, and it rests on a firm legal framework, Clements said. It should stand up in court in the face of any appeals. 

“The reality is that this money is getting spent every year anyways, $20 [billion] to $40 billion a year on annual spending on transmission,” Clements said. “It has to be the commission’s responsibility to try and direct that money towards more cost-beneficial outcomes for customers.” 

Along with Order 1977 implementing the commission’s rules on National Interest Electricity Transmission Corridors, and Order 2023 that revised interconnection queue rules, 1920 is meant to help address the rapid changes the industry is facing from new demand to a changing resource mix, Clements said. 

“I think the whole time I’ve been here, I’ve been focused on what I set out to do in this role, which is to facilitate affordable and reliable electricity as the world around us changes,” Clements said. “It’s not our job to dictate where the world goes; it’s our job to facilitate affordable and reliable electricity service in light of where it’s going.” 

Until this year, load growth in most of the country had been flat, but that has changed with new demand from data centers, reshoring manufacturing and ongoing efforts at electrification. It’s unclear how much demand will grow, even in the near future, she said. 

“I don’t think we know that it’s going to be a 5% increase in U.S. consumption in the next five years,” Clements said. “We can estimate that; we can model that; we’re sure to be wrong.” 

The new demand is cropping up in specific areas, and potential shortages are going to occur only part of the year, but investments to bolster the grid are likely to be “low regrets” for the near future, she added. 

“I think we’re not yet at the point where we need to start worrying about the ‘no one’s going to show up,’” Clements said. “The top thing I hear from companies, whether it’s tech companies or advanced manufacturing companies, is that we are shopping for location, with the No. 1 priority being, ‘where is there available capacity on the grid?’” 

The low-regrets case is bolstered by the fact the grid has plenty of room for improvement with advanced grid-enhancing technologies (GETs) that can affordably make the existing system more efficient, she said. The Brattle Group estimates such technologies could double the amount of renewables online now absent major investment in new transmission, but even if the reality is half that, GETs are a worthy investment, Clements said. 

Clements will step down this month after the open meeting June 27, having served three and a half years. Her replacement, Judy Chang, was confirmed by the U.S. Senate the same day she spoke. 

“It has flown by for me, personally. I’m not sad for it to be over for my sake and my family’s sake,” Clements said. “But … all of the work we’re doing is pretty important. You know, I’m really proud of helping to establish our first Office of Public Participation. I think it’s a really long row to hoe to think that you’re going to actually engage members of the public in our esoteric, technocratic conversations, but we’re on our way.” 

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Texas Supreme Court Rules for ERCOT, PUC During Uri

The Texas Supreme Court has ruled ERCOT and the Public Utility Commission were within the law when they raised wholesale prices to more than 300 times above normal during the deadly February 2021 winter storm that came within minutes of bringing down the grid.

The high court on June 14 reversed a state appeals court’s ruling that the PUC’s order to raise wholesale prices to their $9,000/MWh cap during Winter Storm Uri violated state law.

The Supreme Court said the commission met the requirements of the Public Utility Regulatory Act’s (PURA) Chapter 39 — added when ERCOT was opened to retail competition — when it issued the emergency orders in a desperate effort to bring generation back online to meet demand. It also found that the commission “substantially complied” with the Administrative Procedure Act’s procedural rulemaking requirements (23-0231).

“The [PUC] has the expertise to manage the electric utility industry; the courts do not,” Chief Justice Nathan Hecht said, writing for the 7-0 majority. (Two justices recused themselves.) “The Court of Appeals thus strayed from its lane by inquiring whether the orders could have used ‘competitive rather than regulatory methods’ to any greater extent than they did.”

The Texas 3rd Court of Appeals in March 2023 reversed the PUC’s emergency orders and raised the issue of repricing the market transactions during the storm. The court found the commission’s actions “entirely” eliminated competition and were contrary to state law. (See Texas Court Reverses PUC’s Uri Market Orders.)

Luminant initiated the proceeding after it incurred $1.6 billion in losses when forced to buy backup power at the system cap and gas supplies at equally exorbitant prices. (See Vistra’s Winter Storm Loss Deepens to $1.6B.)

The PUC argued that Luminant’s ability to recoup its losses in the administrative proceeding was speculative because ERCOT does not maintain a fund of money.

ERCOT “just facilitates market transactions — and any payment would come out of the pocket of other market participants,” the high court said. “Essentially, the commission’s argument is that the egg cannot be unscrambled.”

The court noted that Chapter 39 directs the PUC to establish protections entitling customers “to safe, reliable and reasonably priced electricity, including protection against service disconnections in an extreme weather emergency.”

It said the law also “expressly” directs ERCOT to “ensure the reliability and adequacy of the regional electrical network” and gives the commission “complete authority” to ensure that ERCOT adequately performs that duty, including rulemaking related to the grid’s reliability.

The Supreme Court heard oral arguments in January. (See Texas Supremes Hear Arguments Over Uri’s Prices.)

When the PUC issued its directive to ERCOT on Feb. 15, 2021, the grid operator’s algorithm was setting prices as low as $1,200/MWh, even though generation was dropping offline. Under ERCOT’s market construct, prices are designed to increase during scarce conditions to incentivize more generation to come online.

The problem was there wasn’t enough generation during the first two days of the storm because of frozen equipment or lack of fuel supplies. ERCOT kept prices at the $9,000 cap — since reduced to $5,000 — until Feb. 19, resorting to rolling blackouts to keep the grid stabilized.

The emergency order resulted in $16 billion of market transactions that ERCOT’s Independent Market Monitor said were incorrectly priced during the 33 hours that followed the end of firm load shed. The PUC declined to reprice the transactions. (See “Monitor: $16B ERCOT Overcharge,” ERCOT Board Cuts Ties with Magness.)

Some of the $16 billion balance has since been securitized. Other transactions have been settled outside ERCOT and can’t be undone, according to legal experts.

The court also dismissed a lawsuit by RWE Renewables Americans and an RWE wind farm, finding that the 3rd Court of Appeals did not have jurisdiction over the proceeding (23-0555).

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SPP’s REAL Team Approves Base PRMs, Sufficiency Value Curve

SPP’s Resource and Energy Adequacy Leadership (REAL) Team approved a proposed tariff change June 13 that would codify its work and some votes over the past six months.

The revision request (RR622) would set separate base planning reserve margins (PRM) at 36% and 16% for the winter and summer seasons, respectively, effective with the 2026 summer. It would also clarify that the sufficiency valuation curve is effective for three years, beginning at the same time.

“I think it dawned on us, and probably a number of you in the room, that it wasn’t exactly clear,” Casey Cathey, SPP vice president of engineering, told the REAL Team.

The tariff change would also implement the 2023 loss-of-load expectation study that determined the appropriate PRMs for both seasons.

The Market Monitoring Unit (MMU) offered cautious support for the change, saying it supported the 36% and 16% PRMs and the sufficiency valuation curve’s extension. However, it also recommended that SPP continue to monitor generation’s performance during the next winter storm “and the one after that.”

“We see those as a minimum that should be approved,” the MMU’s John Luallen said, referring to the PRMs. “But with that said, I want to point out that in the last three winter storms, SPP found [itself] in a situation where they could not serve their load with accredited capacity. They had to rely on non-accredited capacity and on imports.”

The Monitor’s concern is what’s not in RR622, Luallen said. He said the sufficiency valuation curve lowers the deficiency payment, which, combined with a cost-of-new-entry value that the MMU believes is not quite accurate, could be sending the wrong market signals.

“If [the CONE]’s not updated for another four years, it will be even further from accurate,” Luallen said. “In our mind, it discounts an already discounted number, which is fine except that if the deficiency penalty gets low enough, then it could not have the signal that it needs for [load-responsible] entities to get the capacity. They could choose to just pay the penalty instead. So, we’re concerned about the signal this could be sending.”

The REAL Team approved the package 9-4. American Electric Power, Arkansas Electric Cooperative Corp., the Oklahoma Corporation Commission and the Oklahoma Municipal Power Authority provided the opposing votes, mirroring their votes on the related policies.

Looking ahead, the team’s workload includes ramping resource adequacy, an issue heightened by the increasing addition of intermittent renewable resources.

“What is ramping capacity?” SPP’s Charles Hendrix asked by way of explanation. “As load is increasing or decreasing, can your resources follow that load?”

“There’s a lot of data out there, but here’s what’s happening in real time,” Cathey said, using a graph of forecasted wind and solar resources to make his point. “We’re trying to figure out ways to incent and better value ramp.

“It should not be alarming to LREs in terms of what the system needs today. We have enough rampable capacity today. The question is, how long can we sustain it? Does it send a strong signal around dispatchable resources?” Cathey added. “That’s part of the reason we’re trying to add this requirement.”

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Survey to Begin for Planned Calif. Floating Wind Farm

An autonomous underwater vehicle will soon slip out of sight off the north California coast, mapping thousands of acres of seabed as a first step toward construction of the floating wind farm envisioned there. 

The data gathered in the coming months will give a better picture of the ecosystem in the lease area and any obstacles, hazards or sensitive sites that lurk a half mile or more below the surface. And it will inform RWE when it puts together a construction and operation plan for the 1.6-GW project it has named Canopy Offshore Wind Farm. 

The site characterization surveys are similar to the early-stage work the German company has done for its 19 existing offshore wind facilities with one key exception: Lease Area OCS-P 0561 is 1,760 to 3,400 feet deep.  

RWE has contracted with Norwegian firm Argeo to survey the depths with one of the fluorescent-painted uncrewed micro-submarines that it also uses for offshore oil, gas and mineral applications. It will arrive on site this month. 

A third of a century after the first commercial offshore wind farm came online, more than 70 GW of capacity is installed worldwide, almost all of it firmly affixed to the seabed with a rigid foundation in shallow water.  

RWE is one of many companies and governments trying to extend the success of fixed-bottom wind to floating wind in deeper water — it launched a 3.6-GW tubular steel demonstrator off Norway in 2021 and a 2-GW twin-hull concrete demonstrator off Spain in 2023. 

RWE is preparing proposals in France, Norway and the United Kingdom, but it expects Canopy Wind to become its first operational floating farm sometime in the mid-2030s. 

Project Director Rob Mastria spoke to NetZero Insider on June 13 with a look at what is ahead.  

The underwater work starts this month with the geophysical survey. 

The autonomous underwater vessel glides about 130 feet above the seabed, using sonar to avoid obstacles and using a digital camera to make a photographic mosaic of the environment where the turbines would be moored and where the export cables would run. 

The geotechnical survey gets right down to the bottom, using equipment that collects sediment samples and biological information. 

Subsequent research and design work will build on the results of these two surveys. 

Back on land, different work is being done. 

“We need to really have two major focus areas,” Mastria said. “The first is building relationships and collaborating with the local community in the Humboldt area and tribal nations, trying to make sure we develop those points of connections and relationships so that we can share information back and forth. The second pillar is really working on the market development in California.” 

As elsewhere, there has been pushback against offshore wind on the West Coast because of feared impacts on the scenery and fishing industry, and developers are working to overcome this. They also need to help create a supporting industrial and infrastructure ecosystem that does not now exist. (See West Coast OSW Will Require Robust Supply Chain.) 

RWE, which bid $158 million for its 63,338-acre California lease in a 2022 auction, looks internally and externally to build the confidence to make these investments, Mastria said. 

“It’s a combination of believing in floating, knowing that there’s vast opportunity in the future for it because there’s only so much area in shallow water depths that can be used, but it also comes down to what I’ll call market signals,” he said. 

“We have a federal policy of wanting to have 30 GW of offshore wind by 2030. California has its own state targets for offshore wind, 25 GW by 2045.” 

He added: “California has always been a leader in the climate change space and wanting to really incorporate renewable energy into the grid there. This is a technology that can play a major role in helping California meet its clean energy goals.” 

The long development timelines for Canopy and wind farms in the four other lease areas along the California coast give some room to prepare the transmission, manufacturing, workforce and port facilities needed for the new industry, Mastria said.  

The company has already taken steps in that direction: The protected species observer training program it put together graduated a class of 19 area residents in April. These people or others certified in the task will be on duty on vessels around the clock while underwater survey work is in progress, watching for marine mammals in the vicinity. 

RWE is the only wind power developer to hold leases off all three mainland U.S. coasts: Atlantic, Pacific and Gulf of Mexico. The underwater, political and market conditions are different in each, just as fixed-bottom and floating wind are different from one another, creating three distinct sets of hurdles to clear. 

But RWE frames the question as how to build a wind farm, Mastria said, not whether it is possible. 

“We have a ton of experience, and we know that this works,” he said. “We have, in addition to our projects, a global floating team. So that’s a team that focuses on advancing floating technology, doing assessments to monitor the state of the market and how the technology solutions are developing.” 

Mastria has worked 16 years in the renewable energy industry, the past four of them in offshore wind. Notably, he was project development director for New York’s South Fork Wind, which this year became the first utility-scale offshore wind farm completed in U.S. waters. 

South Fork is a bright spot in the Northeast offshore wind industry, where most projects have canceled contracts or been canceled altogether since early 2023 due to rising costs and supply chain constraints. 

Most of the affected Northeast proposals remain in active development, but advancing to construction will take longer and cost more, in most cases. 

Among the casualties has been Community Offshore Wind, RWE’s two-phase joint venture with National Grid Ventures.  

In the past 12 months: 

Community’s 1.3-GW Phase 1 contract with New York had to be spiked when General Electric halted development of an 18-MW turbine. (See NY Offshore Wind Plans Implode Again.) 

New York “waitlisted” the 1.3-GW Phase 2 proposal so the state could concentrate on getting two mature projects back into the pipeline after they balked. (See Sunrise Wind, Empire Wind Tapped for New OSW Contracts.) 

The partners withdrew a 1.3-GW proposal in New Jersey when the financials did not pencil out. (See NJ Awards Contracts for 3.7 GW of OSW Projects.) 

A recurring theme in the early stages of West Coast offshore wind development has been the need to avoid the setbacks seen on the East Coast. (See Strategy Offered for Success of Future West Coast OSW Sector.) 

Mastria offers the same message. 

“One of the things that I try to do is bring the experience from what has been done on the East Coast to try to make sure that the way we set up how offshore wind will work on the West Coast learns from those experiences on the East Coast and smooths the way based on the experiences that the industry has had,” he said. 

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FERC Issues Show Cause Order on TO Self-funding in 4 RTOs

FERC on June 13 initiated show cause proceedings into the practice by four RTOs of allowing transmission owners to self-fund network upgrades needed to bring generation online, saying the practice may amount to favoring TOs over interconnection customers.

The commission directed MISO, PJM, SPP and ISO-NE to explain within 90 days how their tariff language on the initial funding is fair or, alternatively, to propose changes to make their policies impartial (EL24-80). All four grid operators currently allow TOs the first shot at funding and earning a return on the capital cost of network upgrades required for generators to connect to their systems.

FERC said that approach might be biased against interconnection customers, who could see their interconnection service costs rise when compared with having the ability to finance their own upgrades. It said TO self-funding might “increase the costs of interconnection service without corresponding improvements to that service, may unjustifiably increase costs such that it results in barriers to interconnection and may result in undue discrimination among interconnection customers.”

The commission added that the grid operators’ current practice may amount to barriers to interconnection. It also seeks to “consistently and comprehensively” address the RTOs/ISOs that maintain a TO self-fund option.

Started with MISO

The show cause order is the latest in a string of seesawing decisions between the commission and the D.C. Circuit Court of Appeals that originated with disputes in MISO.

MISO restored TOs’ rights to self-fund in 2019 at FERC’s direction. The commission originally issued an order in 2015 preventing TOs from providing initial funding for network upgrades, but that decision was remanded by the D.C. Circuit. At the time, the court said the commission didn’t consider complaints from Ameren and five other TOs who claimed the policy forced them to accept “risk-bearing additions to their network with zero return” and essentially act as “nonprofit managers” of network “appendages.”

However, the court ruled in late 2022 that FERC did not adequately explain why it reinstated TOs’ option to finance network upgrades before the interconnection customers owning generation projects were given the chance to do the same. (See FERC Must Clarify MISO Tx Funding Decision, DC Circuit Finds.)

Since 2019, MISO interconnection customers have taken to filing unexecuted network upgrade agreements to protest the RTO reinstating TOs’ rights to self-fund. (See FERC Accepts Unexecuted Agreements Filed in Protest.)

Other affected grid operators have made filings regarding TOs’ right to self-fund upgrades.

PJM in 2021 filed on behalf of its TOs to replace its existing method of generator upfront funding of upgrades with a TO self-funding provision. The RTO also specified that interconnection customers must provide security either to PJM or the transmission owner in question to protect against non-payment. FERC accepted the switch but placed PJM’s new rules in a paper hearing and subjected payments to possible refund.

SPP allows either TO initial funding or generator upfront funding. However, FERC last year rejected an SPP proposal regarding its initial funding option, saying SPP’s plan to allow TOs a non-binding decision to elect initial funding could create uncertainties for interconnection customers because a TO could reverse course at the end of interconnection studies, leaving customers with different network upgrade costs.

ISO-NE allows a transmission owner to unilaterally elect TO initial funding. However, FERC said the practice of initial funding by TOs is rare in ISO-NE, where no TO has ever pursued the option. SPP in 2021 saw its first FERC-approved network upgrade agreement in which the TO elected initial funding.

In 2021, New York transmission owners filed a complaint against NYISO, which does not have a TO initial funding option, contending it was unfair the ISO wouldn’t allow them to be compensated for “the risks and costs associated with owning, operating, and maintaining system upgrades.” FERC denied the complaint, reasoning the TOs didn’t demonstrate that NYISO’s current funding mechanism was inequitable.

‘Replacement Rate’

In its show cause order, FERC singled out testimony from RWE Renewables, NextEra Energy and EDF Renewables, who argued that their costs “double or increase exponentially” when TOs take the reins on funding network upgrades. EDF claimed MISO’s use of TO initial funding has stymied development of new generation development in MISO and SPP, with larger MISO TOs hiking the cost of network upgrades.

FERC said it was concerned that unilateral TO initial funding might force an interconnection customer to pay a higher financing rate than it otherwise could secure through a lender. The commission also said interconnection customers may incur additional costs through securities to the TOs over a 20-year payback schedule.

“It appears that these increased costs do not provide any additional benefits to the interconnection customer than it would otherwise receive through generator upfront funding. We also are concerned that in some cases, an unjustified increase in costs may be significant enough to result in a barrier to interconnection because the costs are so high that projects that would otherwise be commercially viable cannot proceed,” FERC wrote.

Beyond that, FERC said it was troubled by the risk of discrimination to interconnection customers. It said vertically integrated TOs or TOs with affiliates may strategically decide to elect initial funding only for non-affiliate interconnection customers in an attempt to raise costs for competitors.

FERC also said it worried that initial funding may provide TOs the opportunity to double-dip on risk premiums because risks associated with owning, operating and maintaining network upgrades essentially are “baked-in” to TOs’ transmission rates, but also noted it might identify that TOs are not being adequately compensated for those risks.

The commission concluded the order saying that if it finds that TO initial funding is prejudiced but also finds that TOs take on uncompensated risks building network upgrades, it could enact a “replacement rate” compensation mechanism.

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DC Circuit Upholds NYISO 17-year Amortization Rule

The D.C. Circuit Court of Appeals has upheld FERC’s approval of a key NYISO capacity market price determinant that New York’s utility regulator says could raise costs by hundreds of millions of dollars per year.

At issue is the amortization period for a hypothetical new peaker plant in its installed capacity market.

NYISO in late 2020 had proposed reducing the amortization from 20 to 17 years due to New York’s decision to require a zero-emissions grid by 2040.

The period in question is the 2021/25 demand-curve reset, the middle of which was 2023, which was 17 years from 2040, when fossil-fired plants might have to shut down to meet the mandate.

FERC repeatedly rejected that proposal as “speculative,” prompting appeals by the Independent Power Producers of New York that ultimately led FERC to reverse itself and approve the 17-year time frame.

This prompted protests by consumer advocates and the New York State Public Service Commission over the costs likely to result, but FERC reaffirmed its decision in early October 2023.

The PSC in mid-October appealed to the D.C. Circuit, saying the policy likely would increase capacity costs by more than $225 million per year.

The court on June 14 rejected that argument.

In a prepared statement, the PSC said:

“We are disappointed in the court’s decision. The fact of the matter is that the effect of changing the amortization period for setting capacity prices is resulting in windfall profits to the existing fossil fuel power generators and does nothing to add the resources we need to meet the State’s climate and reliability objectives. We will continue to advocate for just and reasonable rates. PSC is reviewing its options to protect New York customers both at FERC and in the courts.”

In the 2-1 ruling, the court noted that the metric in question is a key part of the capacity market pricing. It said the relevant question in the PSC petition was whether FERC’s decision “fell within the zone of reasonableness.”

The ruling says: “To be sure, FERC’s change of heart a mere five months after its initial decision on remand is eyebrow-raising, and we usually view such ‘flip-flops’ in an agency’s position with some skepticism.”

But it added: “FERC appropriately concluded that the proposal fell within the zone of reasonableness.”

The ruling noted that New York’s 2019 Climate Leadership and Community Protection Act mandated a zero-emissions grid by 2040 but gave no indication how to reach that goal, or whether all fossil-fired plants in the state would have to shut down as a result.

So, it makes sense, the ruling said, that a reasonable investor could conclude a new fossil-fueled plant would not be viable after 2039, and it was reasonable for NYISO to design its rates accordingly.

The court previously highlighted the PSC’s failure to clarify the 2040 mandate, calling it “regulatory inaction.”

“It is ironic that the Public Service Commission objects so strenuously to the System Operator’s interpretation of the N.Y. Climate Act. That Act vests in the Commission alone the power to ‘establish a program’ to achieve the zero-emissions target [N.Y. Pub. Serv. Law § 66-p(2)], yet the Commission has not issued so much as a proposed rule implementing the Act.”

The court notes that the PSC was required to enact such a program by mid-2021 but only began the process in May 2023 and has only gathered comments since then.

Judge J. Michelle Childs dissented on the ruling, saying the majority’s attempt to justify FERC’s decision failed. She wrote:

“The distinction between what is required by the Act and what may be required by its future implementing regulations is crucial: No one disputes that the System Operator may justify its proposed amortization period based on what the Act requires, but an amortization period based on what future implementing regulations may require is difficult to square with FERC’s anti-speculation precedent.”

NYISO had reduced the amortization period from 30 years to 20 years in 2014 due to increasing risks to investing in the hypothetical new plant.

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WAPA Tariff Falls Short of Reciprocity Status, FERC Finds

The Western Area Power Administration’s non-jurisdictional Open Access Transmission Tariff does not meet the standard of an “acceptable reciprocity tariff,” despite recent revisions the federal power agency incorporated into the tariff, FERC ruled June 12. 

The commission’s ruling came in response to WAPA’s April 2023 request for a declaratory order affirming that tariff revisions the agency submitted to meet the requirements of FERC orders 676-I, 676-J and 881 conform with or are superior to FERC’s pro forma (OATT) and that the revised tariff satisfied the requirements for reciprocity status (EF23-5). 

The 676 orders, issued in 2020 and 2021, require transmission providers to incorporate certain North American Energy Standards Board standards into their tariffs, while 2021’s Order 881 requires providers to begin using ambient-adjusted ratings for their lines by July 12, 2025. 

While the commission determined WAPA’s tariff revisions complied with those three orders, it stopped short of granting reciprocity status because the agency said it would continue to defer implementing FERC Order 1000, the 2011 directive that intended to encourage development of interregional transmission projects by eliminating the right of first refusal for incumbent utilities. 

WAPA said it would need to continue delaying Order 1000 compliance until: 1) It can ensure final changes to the WestConnect transmission planning group’s regional planning documents do not conflict with the federal statutes governing WAPA and 2) it determines whether its Desert Southwest, Rocky Mountain and Sierra Nevada regions can continue to participate in that group. 

The power agency said it will consider altering its tariff to accommodate Order 1000 once FERC approves the changes to the WestConnect planning documents and after it completes a review of the needed tariff revisions and obtains input from its stakeholders. 

In denying WAPA reciprocity status, FERC also pointed out that WAPA has not yet complied with last year’s Order 2023, which directs RTOs/ISOs and other transmission operators to streamline their generator interconnection processes.  

“We find that WAPA’s proposed revisions to its tariff, including its ministerial changes, substantially conform with or are superior to the commission’s pro forma OATT,” FERC wrote. “However, for the commission to find that WAPA has an acceptable reciprocity tariff, WAPA must submit revisions to its tariff to incorporate changes the commission made to the pro forma OATT associated with Order Nos. 1000 and 2023. 

“Because WAPA has determined to defer implementation of Order No. 1000 to a later date, and because WAPA has not submitted revisions associated with Order No. 2023, we cannot find that WAPA’s tariff, as revised here, is an acceptable reciprocity tariff.” 

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Conference Explores AI Solutions to Data Center Power Demand

WASHINGTON ― The biggest roadblock to the clean energy transition now underway in the U.S. is not technology-related or even the anticipated spike in power demand from data centers, according to speakers at a conference on the energy transition June 12. 

It is the engrained, slow and risk-averse culture of U.S. utilities and other private-sector players, they said. 

The technologies are ready, said Jigar Shah, director of the Department of Energy’s Loan Programs Office, at the Clean Energy Transition Conference, held at the National Press Club by Tech for Climate Action, a UK-based event organizer.  

“Now we need to get utilities to act like private-sector companies and actually take risk. You see that in the stock market. … The utilities’ stock prices have [gone up] in the anticipation that they’re going to turn from dividend companies into growth companies,” Shah said during an on-stage conversation with Mary de Wysocki, chief sustainability officer for Cisco. “So, figuring out how that cultural and norm thing occurs is really fascinating to watch.” 

DOE is providing technical assistance “helping a lot of those folks through that change,” Shah said. 

Marissa Hummon, chief technology officer of Utilidata, a company developing grid-edge artificial intelligence applications, agreed that a major obstacle for her company is “getting the distribution utilities to act very differently than they have in the past.” 

The energy transition “is going to happen whether or not utilities decide to step up,” Hummon said during a panel on the role of AI in the energy industry. “There will be new energy demands on the system, but the distribution utilities could really be encouraged to take that proactive step to deploy a platform that allows them to actually respond to the changes.” 

The Biden administration’s position has been that the energy transition will be private sector-led and government-enabled with the billions of federal tax credits, loans and other incentives from the Infrastructure Investment and Jobs Act and Inflation Reduction Act. But the message that emerged from the conference is that at least some parts of the private sector have “been caught flat-footed” when asked to lead, Shah said, especially in the face of rising electricity demand from data centers and AI. 

While the private sector is supposed to be the most efficient allocator of risk, “that process has been messy,” he said. “But I do think it’s a little bit unreasonable to believe the entire ecosystem has figured this whole thing out [in] less than two years” since the IRA was passed. 

Faced with rising demand from data centers, Shah said, the focus has been on the AI chips and servers, but “much of the rest of the data center actually uses the electricity, so figuring out how we make the system more efficient is the more difficult thing to do. … 

“We can’t actually decarbonize our processes by thinking the same way we thought about things 10 years ago. This is not just [about] buying carbon credits, figuring out direct air capture and doing everything exactly the same. This is about us reimagining how we actually still live a modern lifestyle but doing things with materials that are more sustainable; doing things with a more thoughtful approach.” 

The electric power system must be able to “flex” load with the “same level of dexterity that we currently only flex supply,” he said. 

“When you think about what it’s going to take to really meet this moment, it was something we actually needed to do in 2000, but people weren’t forced,” he said. “When you’re a monopoly, obviously, you have a tendency not to deploy innovation as fast as a more vibrant capital system, and so we’re doing it now because the pressures are just so great from weather and load growth.” 

A similar sense of urgency should be used to create new narratives about AI, said Charles Yang, policy adviser at DOE’s Office of Critical and Emerging Technologies. 

The challenge of load growth from data centers can be converted, not into new natural gas plants, but “into building an order book for the next generation of clean, firm, advanced technologies,” Yang said, pointing to Microsoft, Google and Nucor’s recently announced plan for aggregating their demand and contracting for clean power. 

“We need better stories about what AI can do,” he said. “How it can help us discover more abundant, affordable batteries; how it can help us coordinate our EV charging and lower costs for ratepayers. These are the stories that we haven’t really told; they’re not the future we’ve been told about.” 

Moving AI to Grid Edge

Since ChatGPT was introduced in November 2022, AI has exploded in the public consciousness, but, Hummon said, “Utilidata has been running AI models to operate the grid for more than 12 years. … We’ve been using data-driven, real-time methods to create outcomes of a more efficient, powerful grid, very reliably.” 

What’s changed is the emergence of “generative AI” and the creation of large language models (LLMs) that allow users to ask questions or “prompt” the software in plain language.  

Utilidata is deploying these advanced technologies to move AI to the grid edge, improving system visibility and opportunities for more efficient operations for distribution system operators, Hummon said. Such systems could not only get “the right information back to a central system to make a better decision, but also … interface with the customer using natural language about their energy use, about their choices, about just what sort of resources they want to purchase,” she said. 

AI can also support better use of unused capacity on the grid to increase the power that can be sent down distribution lines without having to build new substations or feeders, she said. Optimizing the operation of a substation with traditional, physics-based calculations can take 12 to 18 months, Hummon said. 

“If you’re using data-driven, machine-learning methods, you can be up and running in two weeks,” she said. 

Claus Daniel, associate laboratory director at DOE’s Argonne National Laboratory, said his researchers and scientists want to push the use of AI in the electric power system further “to figure out how we can use that technology to help us in research and development to find better ways of utilizing energy; better ways of generating energy. … 

“Artificial intelligence is particularly well suited to figure out what are the tradeoffs … and what are the connections. It’s particularly well suited for handling complexity and recognizing patterns that we currently cannot fully resolve when we just use high-performance computing and physics-based models.” 

DOE and the National Labs are currently working with their Frontier and Aurora supercomputers ― the largest computers in the world ― to create “reliable and safe large language models,” Daniel said, noting that most publicly available LLMs often answer questions with convincing but completely wrong information. 

Eelco de Jong, head of AI-enabled utility service at McKinsey & Co., zeroed in on how AI can be used to “more precisely allocate our capital towards the investments that have the highest return for [grid] reliability.” 

Instead of replacing equipment based on age or zip code, “we’re seeing companies using granular data to forecast, for example, which households are most likely to adopt electric vehicles or heat pumps or switch from gas to electric,” de Jong said. “And based on that forecast data, we know exactly which neighborhoods or even which feeders are going to first run out of capacity, and we can channel … our capital dollars to that.” 

Similarly, AI can help with stressed supply chains by routing equipment “to the places where [it has] the biggest impact on customer reliability,” he said. 

DOE’s recent AI for Energy report, released in April, focuses on advancing the intelligence of the grid, Daniel said. (See AI Critical to US Clean Energy, Grid Modernization Goals.) 

“This is something that will fundamentally change how we operate the grid” and help solve the problem of non-dispatchable wind and solar, Daniel said. “If I manage through building controls, through heating and cooling needs … [to understand] what’s happening on the edge, I can control my demand in a better way. I can live with a higher percentage of non-dispatchable generation.” 

AI integrated into thousands of devices on the grid edge could also make the system more resistant to cyberattacks, Hummon said. 

“If the edge is intelligent in and of itself, then every individual endpoint can make its own separate decision,” she said. “You’d have to hack all those separate decisions in order to create the same type of risk that with pure central decision-making.”