Federal regulators are moving ahead with plans to auction wind energy leases with a potential 18-GW capacity off the coasts of Oregon and northern New England.
The U.S. Bureau of Ocean Energy Management announced the plans April 30 and is seeking comment on the details before finalizing what would be the first such auctions in either location.
Most of the capacity identified in this plan is in the Gulf of Maine, where eight wind energy areas totaling nearly 1 million acres hold the potential for 15 GW of electrical generation.
The southern New England coast is the site of heavy wind energy development efforts, with one utility-scale offshore wind farm completed recently, a second under construction, a third about to begin construction and others seeking to rebound from economic setbacks that have delayed construction.
The water there is shallow enough that wind turbines can be installed with conventional fixed-bottom tower foundations. The Gulf of Maine is so deep in most places that wind energy development there would rely on floating turbine technology, which only recently is being used at scale worldwide.
Maine is attempting to position itself as an early leader in the floating wind industry, with research programs at the state university and an application with BOEM to place a floating research array off the central coastline. (See Maine One Step Closer to OSW Research Lease.)
The eight potential commercial lease areas BOEM identified April 30 are farther south in the Gulf of Maine, most of them closer to New Hampshire or Massachusetts than to Maine.
Speaking at the International Partnering Forum — Oceantic Network’s offshore wind conference April 22-25 — Maine Gov. Janet Mills (D) announced her state has begun the process to procure up to 3 GW of offshore wind energy by 2040. The state issued a Request For Information on April 24 to shape this process.
Floating wind technology will be needed along the Oregon coast, as well, due to water depths there. BOEM is considering adding lease stipulations that would award bid credits for bidders that commit to help develop the workforce and supply chain for the floating wind industry.
The two designated Oregon lease areas total nearly 200,000 acres and sit dozens of miles apart off the state’s southern and central coastline.
The U.S. Bureau of Ocean Energy Management is proposing to auction two wind energy lease areas off the Oregon coast. | BOEM
BOEM’s efforts to site offshore wind off Maine and Oregon have drawn opposition for their feared impact on commercial fishing. BOEM has made changes to draft proposals based on feedback from fishers and other stakeholders, and it said April 30 it would continue to consider their opinions.
“As we move forward with offshore wind energy in Oregon and the Gulf of Maine, the Bureau of Ocean Energy Management remains dedicated to close collaboration with our government partners and key stakeholders,” BOEM Director Elizabeth Klein said in the news release. “We’re excited to unveil these proposed sales and emphasize our commitment to exploring the potential for offshore wind development from coast to coast.”
Oceantic CEO Liz Burdock said in an April 30 news release:
“BOEM’s combined announcement solidifies two new regional markets for floating offshore wind, balancing the development of this industry sector across both coasts. New lease areas in Oregon will support a further buildout of the West Coast’s regional supply chain, adding strength to California projects. And in the Gulf of Maine, this new 15-GW potential will drive the creation of a floating offshore wind supply chain on the East Coast.”
FERC on April 26 approved a settlement requiring the Twin Ridges wind farm in Somerset, Pa., to pay ReliabilityFirst $30,000 over a “litany” of reliability standard deficiencies at the facility.
The commission said in a filing that it would not further review the settlement, filed by NERC in its monthly spreadsheet notice of penalty March 28 along with a separate spreadsheet NOP concerning violations of NERC’s Critical Infrastructure Protection standards (NP24-6).
Exus Management Partners, which claims to manage renewable energy assets worldwide with a total capacity of 11 GW, reportedly acquired the Twin Ridges facility in March from global energy developer Vitol. However, the settlement stems from five self-reports submitted to RF in July and August 2021, the year before Vitol purchased the wind farm from a private equity fund managed by BlackRock.
An operations and maintenance (O&M) company employed by BlackRock informed RF in July 2021 that the plant was in violation of PRC-005-6 (Protection system, automatic reclosing and sudden pressure relaying maintenance). The following month it submitted additional reports of infringements of COM-002-4 (Operating personnel communications protocols) and VAR-002-4.1 (Generator operation for maintaining network voltage schedules).
According to the first self-report, the Twin Ridge owners did not perform required maintenance on several protection system components, including the facility’s only sudden pressure relay, its battery bank and each of its lockout relays. The violation began Jan. 1, 2016, when PRC-005-6 became enforceable, and ended Oct. 20, 2021, when Twin Ridges finished mitigation activities. These included performing the skipped maintenance and implementing annual reviews of its protection system inventory and maintenance activities.
Regarding the COM-002-4 violation, the O&M company reported that “there was no formal program for communications training of the entity’s operating personnel under the previous ownership,” or at least no program for which records could be found. The violation lasted from July 1, 2016 — the effective date of the standard — to Dec. 6, 2020, when the owners finished training operating personnel in the relevant communications process.
The three VAR-002-4.1 infringements similarly involved a lack of records establishing that required maintenance had been performed. Noncompliance began Dec. 22, 2017, the day after RF audited the facility, and ended in January 2022 when the entity adopted new control-room alarm capabilities, a corporationwide VAR-002 procedure and training for operations personnel.
RF attributed all violations to a fumbled ownership transition, suggesting that records were mislaid during interactions between “multiple owners and O&M companies,” along with a lack of oversight by the facility’s former owners and operators in the case of the VAR-002-4.1 violations. It assessed a moderate risk from all the infringements, noting that the small size of the facility limited “its overall … impact and the potential magnitude of harm.”
While the regional entity observed that entities “will not be excused from [their] compliance and reliability responsibilities … merely because [they are] small,” it also remarked on the “proactive actions of new owners and a new O&M,” crediting both BlackRock (which it referred to as the “2018 owner”) and Vitol (the “2022 owner”). RF said it decided to limit the penalty in order to “promote the transparent review and self-reporting seen here.”
NEW ORLEANS — One of the most common friction points as the offshore wind industry sets up in the United States is its potential impact on commercial fishing.
The effects are hard to predict because there’s so little operational data from U.S. waters.
Environmental impact reports prepared for individual proposals have projected that wind farm construction and operation likely will have negative effects on commercial fishers, with the severity depending on the equipment they’re using and the species they’re pursuing. The cumulative or synergistic effects of multiple projects in the same region are expected to be greater still.
Reducing the resulting friction with the fishing industry was a workshop topic at the International Partnering Forum on April 23. One focus of conversation was the effort by the 11 coastal states from North Carolina to Maine to create a regional framework for compensating fishers for economic losses caused by offshore wind farms.
The Fisheries Mitigation Project of the Special Initiative on Offshore Wind has the standard goals of avoiding impact where possible, minimizing impacts that cannot be avoided and mitigating those impacts that occur, with financial compensation if other mitigation options are exhausted.
Kris Ohleth, director of the Special Initiative on Offshore Wind, moderated the workshop discussions.
Greg Lampman, director of offshore wind for the New York State Energy Research and Development Authority, noted the current effort is a significant shift from the early days of offshore wind planning.
“Back in 2018, that was a real third rail,” he said. “No one wanted to talk about compensatory mitigation because we were not going to be harmed by offshore wind in any way, shape or form. And to suggest [otherwise] was going to be problematic for the industry.”
Vineyard Wind was the first major U.S. project to put steel in the water, and it did so with a problematic compensation plan, said Geri Edens, head of permitting and environmental affairs for Vineyard Offshore.
She said the regional approach is needed, especially in areas where multiple adjoining wind farms will span multiple states’ coastlines.
“It’s impossible for every single project in every single lease area to confine and set up these programs when fishermen are fishing across these lease areas,” she said. “The way it’s set up, it’s fraught with potential disadvantages and discrepancies between fishermen. There’s lots of opportunity for double dipping, there’s all kinds of things that could become really problematic if we have like five, six of these different individual programs set up.”
The panelists speaking in this IPF24 workshop were drawn from the offshore wind industry and government. The fishing industry was not represented.
“The fishermen are in this really awkward position where in general they’re not in favor of offshore wind and would like to see it stop,” Lampman said.
If they participate in the mitigation project, he explained, they might be seen as supporting offshore wind or be blamed for a final product the industry does not like; if they shun the process, they have no voice in shaping that final product.
Education and outreach are needed to get these vital stakeholders into the process, Lampman said.
In one notable instance, industry representatives quit a Rhode Island advisory board because they felt their concerns were being ignored. (See Fishermen Quit RI Coastal Board in Anger.)
Brian Hooker of the U.S. Bureau of Ocean Energy Management said the regional mitigation project has the advantage of not starting entirely from scratch.
“There are other programs that exist,” he said, such as a fisheries contingency fund in the Gulf of Mexico and fishery disaster declarations by the National Fisheries Service.
The workshop included audience questions.
Gordon Carr, executive director of the New Bedford Port Authority, asked what would happen if projects the mitigation program is based on prove inaccurate.
“What if downstream, we start realizing that the impacts are greater?” he asked. “By the time we’re realizing that, it’s really late for the commercial fishing industry, and obviously that’s sort of an existential concern, both for us and for them.”
“My response would be mostly geared towards what we have under our authorities under the Outer Continental Shelf Lands Act and our regulations,” Hooker said. “But I do believe we have that regulatory authority to address an unforeseen harm.”
Lampman suggested the federal government create a disaster fund, given that it is pressing for offshore wind development and regulating it.
“One of the big questions that remains is ecosystem change, and how [do] the fisheries, fish population and population dynamics change as a result of the big picture? And it’s not a number that you can really pick out of the hat right now,” he said.
Edens embraced the idea of taxpayers paying for impacts on fisheries that exceed the contracted mitigation sums, because open-ended financial commitments are difficult for developers to make. “I know that people don’t want to hear this, but these projects have to be financed. People that invest in these projects need certainty.”
Peter Silva of Coastal Tribal Resources, an elder of New York’s Shinnecock Nation, said his concern is not so much for the commercial fishery but the wellbeing of fish and the environment in which they live.
He applauded the panelists and the entities they represent for their words and commitment but asked about all the unknowns that persist, now that the first large U.S. offshore wind farm is complete, the second is under construction and two more gear up to start construction this year.
Has boat traffic impacted commercially valuable fish in New York and New England waters? Are other species expanding their habitat into the area? Are breeding grounds affected? Are there changes in currents? Are dead zones expanding in Long Island Sound? Are water temperatures changing?
Those are excellent questions, Ohleth responded, but they are outside the expertise of panel members.
“I don’t think I’m the right person to speak the details there,” said Bryan Stockton, Ørsted Americas head of federal and regulatory affairs. “But I know that if your question is, as a determined condition of approval, do developers or government agencies in collaboration have a responsibility to continue to pursue robust monitoring, the answer is absolutely yes.”
Lampman said he, too, was unable to speak to fisheries population dynamics, but the Regional Wildlife Science Collaborative for Offshore Wind was established and funded for exactly that purpose, looking at not single projects but the aggregate impact of all offshore wind farms in the region.
Edens said Vineyard has multiple monitoring programs in place during construction that will continue through the project’s life. “So, I think we will get there, but it’s going to be a while before we have real answers to those very good questions,” she said.
“Thank you very much for your honest presentation and thoughts,” Silva said. “And hopefully the next time I’m here, if given the opportunity, I will hear [about] monitoring, and the good and the bad and the ugly of monitoring findings and corrective actions that we take.”
Additional IPF24 Coverage
Read NetZero Insider’s full coverage of the 2024 International Partnering Forum here:
Manny Cancel, a senior vice president at NERC who has headed the Electricity Information Sharing and Analysis Center (E-ISAC) for the past four years, will retire early next year, NERC said in a statement April 29. Stan Hoptroff, NERC’s vice president of business technology, also will leave the ERO in 2025, the statement said.
NERC plans to begin looking for candidates to fill both roles this summer and has retained executive search firm Heidrick and Struggles to manage the search.
“Both Manny and Stan have been exceptional teammates to NERC, the ERO Enterprise and our stakeholders. They have provided wise counsel and been stalwart contributors to our executive team as we navigated numerous challenges over the past years, and they will both be sorely missed,” NERC CEO Jim Robb said. “For both, this is their second retirement, and I wish them the best after their stellar careers in our industry. And I appreciate the time they have given us to prepare for their succession.”
Cancel joined NERC in January 2020, replacing Bill Lawrence as E-ISAC head. (See Former Con Ed Exec to Lead E-ISAC.) Before the ERO, he was chief information officer at Con Edison, where he was active on the Member Executive Committee, an advisory group for the E-ISAC.
His tenure as E-ISAC head has seen a marked rise in physical threats to grid reliability as well as damage to electric equipment. Some of these threats have political motivations, such as the neo-Nazi leader who allegedly plotted to damage substations in Baltimore to start a race war. Other attackers have smaller-scale goals, like the men accused of damaging electric facilities in Washington state to cover up a burglary. In the case of the Moore County, N.C., rifle attacks of December 2022, no suspects or motives have been identified.
Electronic threats also remain a major area of concern for the E-ISAC. In a media call earlier this month, Cancel said the center has seen a “dramatic increase in malicious cyber activity” amid rising geopolitical tensions between China and Taiwan, Russia’s invasion of Ukraine and Israel’s military actions in Gaza. (See Robb, Cancel Review Reliability Landscape.)
Cancel has represented the industry before Congress and in other forums such as the ERO’s annual GridSecCon security conference, and has overseen the past two iterations of the biennial GridEx security exercise.
Hoptroff has been with NERC since 2014; his previous positions at the ERO include chief technology officer. Before NERC, he worked with Southern Co. for 33 years in a variety of technology-related roles.
While at NERC, Hoptroff has had “overall responsibility for developing and overseeing the company’s IT strategy, systems, applications, budget and personnel,” according to his page on the ERO’s website. He has led such initiatives as the ERO’s Align software platform and Secure Evidence Locker, which went live in 2021 with the goal of collecting compliance and enforcement activities of NERC and the regional entities into a single secure platform.
NEW ORLEANS — Offshore wind is touted as a source not just of emissions-free electricity but also economic stimulus, giving many businesses at every level of the food chain a stake in each multibillion-dollar wind farm.
More than 375 exhibitors were on hand at the International Partnering Forum April 22-25, hoping to steer some of that money to their companies.
In dozens of booths across acres of floor space, they pitched everything from bird warning systems to construction vessels to training. Exhibitors ranged from startups to industry leaders, labor unions to national trade delegations.
On the last day of IPF24, NetZero Insider spoke with a random assortment of exhibitors about their impressions of the U.S. offshore wind market, their take on the convention and the products they were pitching. Here’s what they had to say.
Underwater Autonomy
A sleek machine on a three-axle trailer that looked like a cross between a torpedo and a submarine was neither — it was “Abraham,” Terradepth’s prototype autonomous underwater vehicle.
It is built to operate for up to a thousand nautical miles on its own, conducting underwater surveys for up to a month at a time and resurfacing as needed so its diesel generator can draw air and recharge the lithium-ion batteries that power it underwater.
It holds the potential of massive savings in fuel and personnel costs compared with survey operations controlled from a crewed surface vessel.
Terradepth is trying to bring Abraham to the attention of offshore wind and other marine industries, said Chief Operating Officer Kris Rydberg. It needs decision-makers to open their minds about a new way to approach underwater tasks and open their wallets to make that happen.
“This is not inexpensive and we’re a startup,” he said. “We bootstrapped it up to this point. We’re going to need some additional funding to go from prototyping to full-on commercial. But the concept, the technology is proven.”
Richard Fryburg, chief growth officer of Subsalve, said he is eager for American manufacturers such as his company to reap the benefits of the wind projects proposed off our shorelines.
With his broad New England accent and his stack of blazing fluorescent buoyancy sacks, Fryburg and his booth were hard to miss. But visibility was not translating to sales.
“We’ve been approached to provide our products by many of these companies coming in from outside the U.S., who have proposed that they want to buy locally,” he said. “They’re not buying locally. They’re bringing products, staff and equipment from outside of the country. And there’s a gap, and I’m not sure how that gets fixed, but I don’t see that local vendors and suppliers are benefiting that greatly from this insurgence of foreign companies.”
Fryburg added: “I think we’re competitive on price.”
Ironworkers Local 5 had one of the more visually striking displays in the exhibit hall and easily the most ironic swag: The same guys who assemble tons of structural steel were handing out balsa-wood toy gliders weighing a few grams apiece.
The thousand-member local hopes its members will gain from the spate of construction planned off the East Coast, said Ray Cleland.
What the union would like, as early as possible, is a list of certifications that managers want ironworkers to bring to a given project, Gary Armstrong said. Local 5 can draw workers from any local in the country and it can do training — if it knows the skillsets needed.
“Sparrows Point (Maryland) was contracted for some secondary steel components, and we had like 45 ironworkers there working,” Armstrong said. “Then Ocean [Wind] 1 stopped, and we lost that contract.”
But things are looking up onshore.
“I think there’s always going to be work,” Armstrong said. “With the big infrastructure money starting to roll out, there’s going to be a lot of other opportunities, too.”
Simon Thomson, international business development director for English boatbuilder Diverse Marine, had a glum assessment of the U.S. market for his company’s crew transfer vessels:
“Flat and dead.”
He partly blames politics. There is one permitting system in the United Kingdom and hundreds in the United States, often with significant variations from one state to the next.
Thomson said things take longer to get built in America, too. He pointed to a mural-sized photo of the newest Diverse crew transfer vessel, the Predator, speeding away for delivery to the customer.
“The length of time to build a boat like that — that was delivered two weeks ago — is about a third of the time it’s taking here [in the U.S.],” he said. “If you said to me today, I want to build four of those, just like that, you could probably start cutting metal within — let’s go for it — 10 days.”
The issue is moot, in a sense. Because of the Jones Act, Diverse cannot sell the vessels it builds on the Isle of Wight for use on U.S. offshore wind projects. So, it has a manufacturing partner in Washington state.
Does Thomson see a growth pattern for U.S. offshore wind?
“That’s a very difficult question to answer, because of all the issues you have and all the political decisions,” he said. “We look at the United States as separate countries all held together in a union. You all have different rules, laws and interests.”
Woods Hole Group is the commercial oceanography spinoff of the oceanography research institute of the same name in Massachusetts.
The data and data analysis the company provides is valuable for every stage of a wind farm’s existence, from planning and design to operation to decommissioning.
Woods Hole Group started this work in oil and gas, senior manager Rafael Ramos said, and it was a natural transition to wind. The company sees a good future in this sector.
“In the U.S., it got off to a flying start, and then we hit this barrier with projects being canceled,” Energy and Mining Business Unit Director Rob Smith said. “I think it’s a hiatus, I think it’s a rebalancing.”
James Jatho and Liège Olmos were on hand to represent Liebherr, a German crane manufacturer.
Jathos said IPF24 was a mixed bag from his perspective, because the company’s push at the show was its maritime products — the cranes mounted on ships and offshore platforms.
“I handle mobile crawler cranes,” he said. “So, we’re pursuing offshore wind in the sense that you need something to move stuff around on the ports. For me, the show wasn’t as successful for direct customers who would buy from us, but more so talking to engineering firms, the various ports, getting our product out in front of them so that when they do need a crane, they come to Liebherr first.”
Olmos said they attended IPF23 in Baltimore last year. “We had a small booth there, but the quality of leads we got there was surprisingly good, so we decided to go bigger this year. This year, I think the convention center is too big. We got less traffic, but the quality of the leads are good.”
Liebherr does have an answer for the heaviest offshore wind components, Jathos said: the L-13000, rated at 3,000 tons. The seven that have been built are the largest crawler cranes outside of China. The eighth is being built now, and the wait time for the ninth will be in the 18- to 24-month range.
At its booth, Spinergie was promoting its suite of fleet efficiency services.
During planning, construction and operation of an offshore wind farm, “there’s a lot to coordinate, there’s a lot of vessels that are orchestrating the project all at the same time,” said Patrick Sanguily, general manager Americas.
“We recently supported a survey campaign off the East Coast. I can’t say for whom. We tracked all the service vessels, facilitated the daily reporting from the vessel to the charterer, we gave them the metrics dashboards so they could monitor the survey.”
This type of data is valuable for cost control.
His take on IPF24 and the industry in general?
“The enthusiasm is consistent,” Sanguily said. “Of course there was some recent news, some reshuffling of the schedule. But the goals remain the same. There’s some moving targets out there but it seems the industry will continue to push forward.”
Virtual Career Awareness
Vinci Virtual Reality CEO Eagle Wu was demonstrating his company’s virtual-reality workforce development tools.
Their primary intended use is early career familiarity and training, Wu said, giving prospective workers some sense of what it’s like to work in a situation or setting that they cannot see firsthand.
“These projects in the U.S. are coming four or five years from now, which has its challenges,” he said. “But what many people now recognize is, if you want to have workers to hire in four or five years, you need to talk to students today. There’s a lead time.”
A simulated experience of working on a wind turbine or the associated support functions can recruit youngsters to the field, he said.
Sabik Offshore has been coming to IPF for a decade, ever since it was a small event in a hotel. The safety equipment manufacturer appreciates the conference because it has fostered the formation of a community, said North America regional sales manager Stewart Erwin.
Sabik works only in offshore wind. Not oil rigs, not ferry boats, just offshore wind. The company’s products, including fog warnings and railings, are in place on the early projects off the Northeast U.S. coast.
Sabik has a steady business elsewhere in the world, Erwin said, and expects the U.S. market to grow as well.
Constellation Energy is requesting an increase in the cost-of-operation charges in their proposed agreements with Massachusetts gas utilities to keep the Everett LNG import terminal operating through the winter of 2029/30.
In comments to the Massachusetts Department of Public Utilities, Constellation — the owner and operator of Everett — wrote that it has not entered agreements for enough LNG supply to support the continued operation of the facility (DPU 24-25, 24-26, 24-27 and 24-28).
Constellation wrote that each of the four utility contracts contains a provision, or “conditions precedent,” that allows the company “to terminate the agreements in the absence of contractual arrangements for supplying a certain total volume of LNG.”
Based on the contracts entered to date, there is a difference “between the total contracted volumes and the threshold total volume identified in the conditions precedent,” Constellation said.
To cover this gap, Constellation is asking for an increase in the “fixed non-commodity demand charge,” a provision included in each of the contracts with the Massachusetts gas utilities intended to cover Everett’s costs of operation.
National Grid and Eversource Energy, the state’s two largest gas utilities, wrote that the rate changes would result in minimal increases to ratepayer bills and urged the DPU to approve the proposed increases.
Eversource estimated that the increase would add $2.85 to next year’s bill for an average customer, with the overall agreement costing customers about $100 for the year. National Grid estimated that the increase would amount to 72 cents for its average customer in the coming year.
“Given the important reliability benefits provided by the agreement,” National Grid wrote, “the company continues to respectively request that the department approve” the request by May 1. “The agreement is still needed by the company to reliably serve customers, and there are no viable alternatives that offer the services that could be provided to the company by the agreement.”
Constellation has said the May 1 deadline is necessary to provide enough time to procure the LNG needed to fulfill the contracts. If they do not receive final approval by then, Constellation has the right to void the agreements. (See Everett LNG Contracts Face Skepticism in DPU Proceedings.)
However, the proceedings are on track to extend past May 1; the DPU has set a May 2 deadline for comments on the rate changes and a May 7 deadline for reply comments.
Throughout the DPU proceedings, environmental organizations have expressed concerns about the cost and climate consequences of the agreements.
In an April 16 filing, the Conservation Law Foundation called on the DPU to reject the contacts, writing that the gas utilities “have failed to adequately consider alternatives to these agreements and have accordingly not shown that they are in the public interest.”
Environmental groups have also argued that the cost-of-operation charges would result in gas customers ultimately subsidizing Everett’s operations for the benefit of industrial or power sector gas customers that decline to enter long-term contracts but could still purchase LNG from the facility.
“The other buyers don’t want to execute fixed contracts,” said Joe LaRusso, senior advocate at the Acadia Center. “They want to buy in the spot market. … There’s financial risk associated with executing a fixed contract.”
LaRusso added that the “non-commodity charge, paid by the utilities customers, is de-risking the other transactions that Constellation is going to enter into in the spot market with everybody else.”
WASHINGTON — The ongoing turnover of the generation fleet to cleaner resources, the recent return of demand growth and the need to stitch all that together with transmission expansion all came up at the Energy Bar Association’s Annual Meeting.
“We’re at a major inflection point in the development and maturation of the electric utility industry,” MISO Assistant General Counsel Michael Kessler said. “And there are many factors that we are experiencing that are impacting almost all aspects of the industry.”
Studies by MISO and others have found the grid can be operated reliably even with higher levels of intermittent resources, but until new technologies are available, those renewables will need to be balanced with more traditional, dispatchable resources, he added.
“There’s a lot of uncertainty going forward in kind of managing this transition,” said Analysis Group Principal Todd Schatzki. “And in many cases, the speed at which things are happening is very uncertain. Some things [that] we think are going to happen very quickly are taking longer. And some things we don’t anticipate are suddenly coming in very quickly. The whole data center issue, AI and how that’s changing things, is a classic example of that.”
While the system is changing and regulators and the industry are working to address that, there is still substantial uncertainty about the pace of change, Alliant Energy Executive Vice President Raja Sundararajan said. Electric vehicle demand was supposed to grow at a steady clip, but now it varies by region and is slowing down in some, he said.
“There’s a natural skepticism: Are we going to overbuild?” Sundararajan said. “And if you’re going to overbuild, then you have the affordability issue that comes into play, where the regulators are saying, ‘Why should … customers pay a portion of the cost for [a] new set of customers? And how do I transfer the risk between existing customers and the new customer?’”
Basic regulatory processes need to speed up, he added, citing transmission and developing integrated resource plans.
FERC has a major rule coming May 13 aimed at improving transmission planning and cost allocation. Commissioner Mark Christie is a key vote there, but he declined to wade into the debate when asked after his speech at the conference. He did make clear he continues to favor a strong role for the states and wants to make sure the changes do not impose unneeded costs on customers.
While states have to site transmission lines, they do not get to decide what consumers will pay for them because that falls under FERC’s regulatory territory, he said.
“I’m very adamant that in any transmission planning that FERC is going to mandate, if you’re going to put policy-oriented projects in there, the states have to have the ability to consent to it,” Christie said. “So, we can restore the balance, which we have not had really for 20 years, where state regulators have the role that they should have in determining the transmission costs and how they get passed on to consumers.”
Risks are inherent in long-term planning, but it still is work that needs to be done, said Grid Strategies President Rob Gramlich.
“A lot of people sort of end the conversation and say, ‘Well, we might be wrong,’” Gramlich said. “Well, of course. Look at this great industry that is still a marvel of modern society that has been developed and that we all inherited, where we can flip the switch and get the lights on. That was all planned. Guess what? Planners in the ’50s, ’60s and ’70s didn’t know what to expect.”
A lot of transmission was built just 10 years ago in 2013, when different efforts such as MISO’s first Multi-Value Projects and the Competitive Renewable Energy Zone lines in Texas came to fruition. But since then, it has “slowed to a trickle,” Gramlich said. “If you care a lot about the pace of climate action and greenhouse gas reductions — well, 80% of the most historic climate legislation ever will not be achieved without doubling the pace of transmission.”
FERC’s transmission rule is the culmination of years of work, which includes the Joint Task Force with states, said Karin Herzfeld, senior transmission counsel to Chair Willie Phillips.
“The NOPR was silent as to what happens when states cannot come to an agreement on the cost allocation for any particular project,” Herzfeld said. “And I know there’s some friction here, but the chairman, as a former state regulator, is focused on keeping states front and center on this important issue.”
Another issue on FERC’s plate is what to do about dynamic line ratings, on which it has an open Notice of Inquiry. On that front, Herzfeld told the EBA crowd to “stay tuned.”
FERC on April 25 denied an application for a 3.6-MW pumped storage hydropower facility on the Little Colorado River in Arizona — near the Grand Canyon and entirely on Navajo Nation land — after the tribe protested that it had not been consulted by the developer (P-15024).
The order, approved unanimously at FERC’s monthly open meeting, follows a commission policy issued in February saying it will not issue preliminary permits for projects proposing to use tribal lands if the affected tribe opposes the permit. Tribal lands are administered directly by the U.S. government, not by the states in which their territory lies. FERC said this makes the policy consistent with how it has treated permit applications opposed by federal land managers or similarly affected federal agencies.
“Because the proposed project would be located entirely on Navajo Nation land and the nation has stated that it opposes issuance of the permit, we deny the application,” FERC said. “To avoid permit denials, potential applicants should work closely with tribal stakeholders prior to filing applications to ensure that tribes are fully informed about proposed projects on their lands and to determine whether they are willing to consider the project development.”
The developer, Pumped Hydro Storage, argued that because it had filed its application in 2020, the new policy should not apply to it. It also claimed that gaining tribal approval is difficult before being granted a permit, but that gaining one would give it more “resources” to consult with the Navajo.
“We are not persuaded by Pumped Hydro’s arguments,” FERC said. “Pumped Hydro provides no support for its assertions that gaining tribal approval at the permit stage is particularly difficult and that issuance of a permit, which is simply a placeholding action, would provide any additional resources to a developer.”
The developer had named the proposed project the “Navajo Nation Big Canyon Pumped Storage Project,” but the text of the order omitted “Navajo Nation” from the name and refers to it simply as “Big Canyon” throughout. In an unusual footnote, FERC said the project was “not in any way affiliated with” the tribe, so it removed it from the name “to avoid the impression that the Navajo Nation is involved in developing the project.”
The project would have consisted of three new dams with walls spanning a collective 11,450 feet, a building to house nine 400-kW turbines and two double-circuit 500-kV transmission lines, among several other facilities. The Navajo Nation said it would adversely impact its water use and historic and cultural resources. Other commenters raised concerns about the fitness of the developer for such a project and the application’s completeness. The commission did not address these concerns.
“This disastrous project could have devastated the Little Colorado River and pushed the world’s last large source population of humpback chub toward extinction,” Taylor McKinnon, Southwest director at the Center for Biological Diversity, said in a statement. “It’s good news for these embattled fish that federal officials heeded the Navajo Nation’s staunch opposition and rejected this project.”
Cabin Run Permit Approved
FERC did approve a preliminary permit for Cabin Run Pumped Storage to study the feasibility of a 57.5-MW, closed-loop pumped storage hydropower facility near the Stony River in Tucker and Grant counties, W.Va. (P-15318).
The West Virginia Division of Natural Resources, Potomac Riverkeeper Network and Friends of Blackwater opposed the permit, arguing the project would adversely impact the river’s habitats, especially those of the native brook trout.
The commission did not address these arguments, noting that “a preliminary permit does not authorize access to project lands or project construction. Therefore, addressing the commenters’ concerns at the permit stage is premature.”
“The purpose of a preliminary permit is to secure the permit holder’s priority for filing a development application while it studies the feasibility of a project, including studying potential impacts, such as those identified by the commenters here,” FERC said. “The commission will consider in any future licensing proceedings potential project effects on water quality, water quantity and nearby infrastructure. Accordingly, it would be prudent for the permittee to consider and study these issues during the term of the permit.”
WASHINGTON — With the Supreme Court likely to overturn Chevron deference, the general counsels of FERC and the U.S. Department of Energy told the Energy Bar Association last week they doubt it would lead to massive issues with their agencies.
Under the doctrine, stemming from the 1984 case Chevron v. NRDC, if a statute’s meaning is unclear, and the agency’s action administering the law was reasonable, courts should defer to the agency. (See Supreme Court Hears Oral Arguments on Overturning Chevron.)
Chevron makes sense as a legal doctrine and provides judges with an easy way of affirming an agency’s decision-making when there is ambiguity in the law, FERC General Counsel Matthew Christiansen said at the EBA’s Annual Meeting. But underlying those decisions is some basic common sense being applied by the judges.
“Because I think that Chevron is largely deployed as a way of providing a compelling path to affirm an agency action, I’m not convinced that the loss of Chevron in many cases, if that is indeed what happens, is going to lead to wildly different outcomes,” Christiansen said. “I’m sure it’s going to lead to different outcomes on the margins. But at the end of the day, I’m a big believer in agencies’ ability to still put forth compelling justifications.”
Chevron has provided a lot of value over the decades, but the politics have reversed completely since it was first decided, DOE General Counsel Samuel Walsh noted. The late Justice Antonin Scalia, a textualist, was a big fan of the doctrine, and Justice Clarence Thomas authored the Brand X decision in 2005 that extended deference to the Federal Communications Commission and kept internet service providers from being regulated as common carriers.
“Some of the most important Chevron cases were cases where agencies were using the flexibility afforded by deference to regulate in a more light-handed way, or maybe not at all,” Walsh said.
The biggest area where DOE might be affected by the change in precedent would be on its ability to set efficiency standards for electric appliances, he said.
“But to my knowledge, we’ve only been upheld at Chevron Step 2 once,” Walsh said; Step 1 is deciding whether the law’s intent is clear from the text. “We’ve done hundreds of rules over the last four decades, and I think we’ve only benefited from it in a clear and explicit way once.”
DOE has benefited from the law more in its other functions such as litigation around nuclear waste storage in the 1990s and in litigation against the federal power marketing administrations it oversees. The law that governs sales from federal dams specifically calls “municipalities” preferred customers, so in the early 1990s, some “clever” city governments asked the Western Area Power Administration to sell them cheap electricity, Walsh said. WAPA argued that the term “municipalities” meant municipal utilities, and Chevron helped it carry the day in court.
Based on how the oral arguments went and other cases before the court, Victoria Nourse, a professor at the Georgetown University Law Center, said she thought Chevron deference would be overturned, as would the Skidmore deference that was used before Chevron was decided. The 1944 decision held that courts should defer to agencies’ interpretation of a statute as long as they essentially show their work.
“There were a lot of negative comments by Justice [Brett] Kavanaugh, who is very, very powerful and influential in statutory interpretation,” Nourse said. “A lot of the disruption is going to come because there are also FERC and other agency models that they may not consider. They’ll probably have a safety valve.”
Hopefully, she added, that safety valve allows courts to give some credence to agency expertise on areas where engineers and scientists are bigger experts than lawyers ever could be.
“This is a court that is a full employment bill for lawyers … because your clients can now challenge regulations, not only because they don’t meet the best interpretation; anything that ever relied on legislative history is a no-no up there, and if it was Chevron,” Nourse said.
Several of the appeals circuits lean so far on one side of the political spectrum that litigants now regularly engage in “forum shopping” by picking the circuit where their arguments are most likely to win out, Walsh said. Losing Chevron would only exacerbate that trend.
While the combination of polarized courts and the lack of deference to agencies could create significant issues for some parts of the government, Christiansen downplayed the risks in the electric and natural gas markets. Many of the major regulations FERC has issued have vastly influenced the industries it oversees.
“Maybe I’m overly optimistic, too sanguine,” Christiansen said. “I’m not terribly concerned those foundational precedents that I think are the bedrock for the way the industry operates now are at great risk.”
Arizona Public Service is prepared to implement public safety power shutoffs for the first time this year, and another utility in the state is laying the groundwork to use the wildfire prevention technique.
“It is a tool that we expect to use very, very seldomly, but one that we are prepared to use if conditions warrant,” said Scott Bordenkircher, APS forestry and fire mitigation director.
Bordenkircher’s comments came during an Arizona Corporation Commission workshop April 23 on electric utilities’ summer preparedness.
Salt River Project is also evaluating the possibility of a public safety power shutoff (PSPS) program.
“We are in the development stages and looking at what that could look like for SRP,” Jace Kerby, director of transmission line design, construction and maintenance at SRP, said during the workshop.
The utility has brought in a vendor to help model wildfire threat in SRP’s service territory — information that would be key in designing a PSPS program, Kerby said.
Utilities in other Western states have used PSPS as a wildfire prevention technique. In California, there have been 72 preemptive shutoffs since 2018, according to a California Public Utilities Commission dashboard.
Xcel Energy implemented the first PSPS in Colorado in April in response to a severe windstorm forecast. The shutoff affected an estimated 55,000 customers April 6-7.
After the event, Gov. Jared Polis (D) criticized the utility for failing to minimize outages and effectively communicate with customers. The Colorado PUC has opened an investigation into Xcel’s use of PSPS and will explore potential regulation of prescribed outages.
As the risk of wildfire increases nationwide, some predict that more states will be facing public safety power shutoffs.
“Ultimately, it’s a national push. This will happen very likely with all utilities in the nation very soon,” Commissioner Nick Myers of the Arizona Corporation Commission said during a wildfire mitigation town hall meeting April 4.
PSPS Design
Bordenkircher at APS said the utility has targeted 13 circuits in high fire-risk areas in Yavapai, Coconino and Gila counties for potential power shutoffs.
He said shutoffs would occur during “really bad fire weather,” when high temperatures, low humidity and strong winds elevate the risk of wildfires igniting and spreading quickly. He estimated that a shutoff would last about 20 hours, from when winds pick up in the afternoon and evening until crews could get out the next morning to inspect power lines for damage. Customers would be alerted four days in advance of a potential shutoff.
Kerby said SRP is exploring circuit segmentation to reduce the number of customers affected by an outage if the utility proceeds with PSPS.
Utilities are taking other steps to reduce wildfire risk, with two goals: to prevent utility equipment from starting wildfires and to protect utility infrastructure from wildfires of any origin.
Kerby at SRP said vegetation management “has got to be the biggest key component to helping drive down the risk when it comes to wildfire mitigation.” Utilities are clearing vegetation from rights-of-way, removing trees at risk of toppling onto lines and clearing space around power poles.
Another strategy at SRP is replacement of wooden poles with steel in its transmission and distribution systems. Tucson Electric Power (TEP) also has a pole-replacement program.
High-tech Approaches
Other wildfire mitigation efforts are more high-tech.
SRP has installed 12 artificial intelligence smoke-detection cameras on its transmission system as part of a research project. The cameras learn the topography in a 10-mile radius and send an alert if smoke is spotted. A limitation is that transmitting the data requires cellular service, Kerby said.
TEP is also testing a fire detection system in the Gila National Forest and in grassland areas around Fort Huachuca.
APS is adding weather stations and cameras to its circuits to better monitor conditions.
The utility is using covered conductors in high fire-risk locations and undergrounding lines “where it makes sense,” APS’ Bordenkircher said, noting the difficulty of digging through granite prevalent in parts of the state.
Another upgrade in fire-prone areas is expulsion-limiting fuses, which contain sparks rather than letting them fall to the ground. APS is using the fuses, as is TEP.
Kerby said SRP partners with APS on a “no reclosing program” for circuits in high fire-risk areas. If a fault occurs on one of those circuits during periods of high fire danger, it will remain out of service until it’s been inspected and found to be in good condition, he said.
Ultimately, Kerby said, “It should be every utility’s end goal to not need a PSPS,” and measures including equipment replacement, system hardening and vegetation management will help make that possible.
“[So] that ultimately our system is in a good enough shape and the environment around the system is in a good enough shape that it can withstand the environmental conditions that could come its way,” he said.
