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November 12, 2024

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NE Stakeholders Support Developing Time-varying Rates

STOWE, Vt. — As New England plans how to cope with peak winter electricity demand with a growing reliance on renewables, energy leaders in the region are calling on the states to look at developing time-varying rates to reduce costs and environmental burdens.

Speakers at the 75th New England Conference of Public Utilities Commissioners Symposium generally agreed on the need to develop rate structures that would better allow customers to respond to market signals, incentivizing them to reduce energy consumption during periods of limited energy supply. The vast majority of customers in the region currently pay flat rates, regardless of the amount of stress on the grid.

“Advanced rates are critical to any cost-effective decarbonization strategy,” Long Lam, a senior associate at the Brattle Group, said. Lam pointed to a 2020 study from the Brattle Group that analyzed data from time-of-use rate pilot programs in Maryland. The study found that customers saved an average of 5 to 10% on their bills, while reducing summer peaks by 10.2 to 14.8% and non-summer peaks by 5.1 to 6.1%.

Lam also said that moving away from flat rates could be especially important as homes and vehicles electrify, and that rates should be designed to accommodate these changes.

Travis Kavulla, vice president of regulatory affairs at NRG Energy, argued that time-of-use rates should be the default rate design for consumers across the region, saying that customers would be far less likely to take the initiative on their own to opt-in.

“If you don’t have time-of-use rates … you’re putting consumers in a position where they’re just along for the ride,” Kavulla said.

By reducing energy peaks, Kavulla said, the region would be able to minimize stress to the grid, along with the financial and environmental costs of bringing heavily polluting peaker plants online to meet demand.

In a white paper Kavulla published earlier this year, he highlighted the untapped potential of smart meters and the need to develop increased demand flexibility incentives for utilities and customers.

“In nearly every other market, we have empowered consumers to decide whether, when, and how to buy products — and those decisions inform but are not supply-side decisions,” Kavulla wrote. “So too it should be in the electricity economy.”

But developing new rates will not be a simple process, with potential impacts reverberating throughout the energy industry and in households across the region.

“We need to be extremely thoughtful and have a thoughtful stakeholder engagement process from the very beginning,” said Carleton Simpson, a commissioner at the New Hampshire Public Utilities Commission. “We need to take the time to understand what the impact would be for many different groups of folks out there.”

Claire Coleman, who serves as consumer counsel for the state of Connecticut, was open to changing the default rates while keeping ratepayers in mind.

“There are strong affordability reasons to choose time-varying rates as the default option,” Coleman said. “I think the default option should be the one which the majority of customers benefit from.”

Coleman noted that customer education and engagement would be essential for successful implementation and that “shadow billing” options could help customers compare how different rates would affect their bill. She also spoke in favor of developing low-income discount rates to help customers struggling to pay their energy bills, which she said would be particularly important to equitably distribute the costs of the energy transition.

“Not every customer has the same ability to pay,” she said.

In order to accommodate customers with special needs or limited energy-use flexibility, the speakers agreed that if time-varying rates do become the default, customers need to have other options.

“We absolutely have to have an opt-out program where people can opt out if the rates are not working for them,” said Amy Boyd, vice president of climate and clean energy policy at the Acadia Center.

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A Look at How Some Utilities are Planning to Use Hydrogen

The Biden administration’s decarbonization objectives have prompted gas and electric utilities to look at using hydrogen not only for energy storage and generation, but also as a consumer fuel, delivered to homes and businesses blended with natural gas.

Hawaii Gas, a small Honolulu utility that delivers both pipeline gas and compressed propane to about 60,000 customers, is a pioneer in delivering blends of 10 to 15% hydrogen in the synthetic gas it has been producing for more than 50 years at a plant adjacent to the only refinery in the state.

The hydrogen percentage wasn’t planned, but rather an expected byproduct of the process used to make the fuel from one of the refinery’s products, explained Kevin Nishimura, vice president of operations, during a Wednesday webinar produced by RENMAD.

“At that time, we decided that rather than stripping off the hydrogen from the gas, we wanted to see if it were possible to just leave it there, because hydrogen is energy too, right?” Nishimura said. “So instead of investing money in removing those molecules, we [decided] maybe we can keep it. We did some testing, some research and decided that concentration of hydrogen and gas would not affect appliances.”

The company has about 22 miles of 16-inch seamless steel pipelines running at between 350 and 480 psi, just under the industry’s standard of 500, said Nishimura, explaining that hydrogen’s deleterious effect on steel pipelines is more likely to occur at higher pressures.

The company’s 1,100 miles of distribution lines to homes and businesses, about 12 psi, are a combination of steel and high-density polyethylene and “are pretty standard for natural gas service,” Nishimura added.

“So, nothing really interesting to report other than the equipment and the pipelines that we operate here in Hawaii are just like those in the mainland for natural gas service.

“All of our customers have been buying appliances made for natural gas service, whether it be cooking equipment, water heaters, boilers, our favorite tiki torches — all designed for natural gas service, and all have performed well and safely over the 50 years with our blend of typically 10 to 12% hydrogen. We have not seen any impact to the appliance life cycles or their performance or their safety.”

Nishimura said the only exception is that the company has never delivered gas to a customer using a gas furnace because there are no furnaces in the state. Looking to the future, the company is seeking to deliver a blend of renewable natural gas and low-carbon hydrogen, he said.

Nishimura was one of four speakers representing gas utilities, including those from NV Energy, Southern California Gas, and Pacific Gas and Electric.

Christopher Dancy of NV Energy said the utility is planning to store hydrogen made from electrolysis using solar power, retrieving it to fuel natural gas plants when solar power is low.

“Hydrogen storage provides us with interesting opportunities and helps mitigate some of the problems that are prevalent with renewable resources. … You can utilize excess power to produce hydrogen and then store that hydrogen to smooth out the need of power daily. And it’s able to provide longer-term storage solutions,” he said.

But hydrogen pipelines, as well as high-pressure storage, are issues that must be overcome, he said.

“As you increase hydrogen pressure in pipelines, for example, I think the likelihood to having cracks or issues with the pipelines increases. And so if there are improvements to metallurgy or pipeline infrastructure or storage infrastructure, that’ll help enable the storage of high-pressure hydrogen without having some of the problems that exist today.”

Jamie Randolph, hydrogen manager for PG&E, said the company has prioritized hydrogen blending as part of its 2030 climate goals.

PG&E is working with Energy Vault, a Swiss-based energy storage company, to build a microgrid that will have both battery and liquid hydrogen storage, along with a fuel cell. The microgrid will be capable of powering about 2,000 customers in the Northern California city of Calistoga for about 48 hours.

“This is the first of its kind integrating a short-duration battery system for grid forming and black start capabilities along with long-duration fuel cells using green liquid hydrogen, so there’ll be storing liquid hydrogen on site there,” Randolph said.

PG&E is also working on a large-scale hydrogen blending project dubbed “Hydrogen to Infinity” using blends of hydrogen and natural gas in an isolated transmission system in Lodi, Calif., testing the impact of the blends on pipelines. The blends will be used to fuel a modified gas turbine.

“A lot of it’s been done on paper studies and lab environments, or on a small scale,” Randolph said. “We want to bring this to a large scale and see how it works in a real-world environment.

“It’s a stand-alone system. It will not be serving their entire system. It’s only going to serve an electric generating facility owned by the Northern California Power Agency, one of our project partners. The turbine that they have at this facility can already blend up to 45% hydrogen.”

Yuri Freedman of SoCalGas reviewed the company’s plan to build a hydrogen pipeline from solar farms in the Mohave Desert to Los Angeles. (See SoCalGas Proposes Hydrogen Pipelines.)

“We are now in phase 1 of the investigation of the feasibility of this pipeline,” Freedman said. “We’re involved in the pre-engineering design and environmental review and expecting to conclude this phase and submit [a plan] to the California Public Utilities Commission in about a year.”

Freedman said California’s utilities are not the only utilities working to integrate hydrogen into their systems because of the realization that hydrogen is a clean fuel that can work as a storage medium with renewable power generation.

“If you look at the historical data, it takes usually a long time for the new commodities to enter the energy mix at scale. If we’re aspiring to execute an energy transition in a compressed time frame, we really have to focus on these clean molecules,” he said.

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PJM Board Rejects Lowering Capacity Performance Penalties

The PJM Board of Managers on Tuesday rejected a stakeholder-endorsed proposal to lower the penalties for nonperformance in the RTO’s capacity market but said it would propose to FERC to redefine when a performance assessment interval (PAI) can be triggered.

The proposal endorsed by the Members Committee on May 11 would have changed the formula for the penalty rate ($3,177/MWh) and stop loss ($142,952/MW-year) to be based on capacity auction clearing prices for the locational deliverability area (LDA) the resource is in, rather than resources’ net cost of new entry (CONE). (See PJM Members Committee Approves Performance Penalty Reduction.)

It also included tightening the conditions under which PJM could declare a PAI, limiting when generators can be subject to performance charges.

In a letter to stakeholders, board Chair Mark Takahashi wrote that by only proposing changes to the PAI trigger, the RTO can align penalties with when generators’ performance is critically needed while having the best chance of the proposal being accepted by FERC for implementation in the 2023/24 and 2024/25 delivery years.

“During the quick-fix process, PJM articulated concerns that the endorsed changes to the penalty rate and stop-loss may contribute to reliability concerns absent additional paradigm enhancements such as stricter winterization, testing and fuel security requirements, due to the reduced incentive for generators to respond in emergencies,” Takahashi said.

Takahashi also noted that three letters had been written to the board arguing that the proposal would reduce the incentive for generators to perform during emergencies and potentially violated FERC’s filed-rate doctrine. PJM staff agreed, he said, having raised concerns throughout the stakeholder process about lowering penalties without adding requirements for capacity resources with the aim of ensuring reliability.

Stakeholder Reaction

Steve Lieberman, American Municipal Power’s (AMP) vice president of transmission and regulatory affairs, told RTO Insider he was disappointed the board did not side with the majority of stakeholders in supporting the proposal and instead was swayed by unsubstantiated claims that it would harm reliability. AMP brought the proposal before the Markets and Reliability Committee, where it was endorsed May 4. (See PJM MRC Endorses Proposal to Reduce Performance Penalties.)

Lieberman said AMP would not support a package that undermined reliability and noted that PJM had indicated support for LS Power’s proposal, which would have reduced the stop-loss limit to $24,659/MW-year. He said that is nearly as low as AMP’s proposal, which contained a $17,744/MW-year stop loss.

The main difference between the proposals was that the LS Power package would have retained the status quo penalty rate derived from net CONE, while AMP would have shifted to basing it off the Base Residual Auction clearing price to yield a $394/MWh rate. By keeping a high rate and reducing the stop loss, Lieberman said the LS Power proposal posed a reliability risk by potentially clustering penalties in a small number of hours, which if reached would effectively exempt generators from penalties for the remainder of the delivery year.

“Imagine a generator during a Capacity Performance event July 1 and the generator fails to perform and it accumulates all these penalties if it reaches the stop loss limit. … For the rest of the delivery year, if there’s another capacity performance event, the generator would be more or less excused from any penalties,” he said. Under the AMP proposal, reaching the stop loss would take about 45 hours of penalties, the same as the status quo, while under LS Power’s package it would take about 7.5 hours, he said.

By focusing only on the penalty triggers, Lieberman said the board missed the problem the quick-fix issue charge was meant to address: aligning penalties with the revenues generators receive from the capacity market. Under the current rules, as much as two years worth of capacity market revenue could be lost because of penalties. While he said PJM will likely pursue penalty rate and stop-loss changes through the ongoing Critical Issue Fast Path process, he said that could take years to unfold, and more immediate changes are needed.

“The reason that we went down this path around a month ago is still unaddressed,” he said. “It’s very troubling that the board is ignoring the solution and willing to kick out a fix for years.”

Marji Philips, senior vice president of wholesale market policy at LS Power, said the changes to the PAI triggers were necessary to avoid the “irrational and nontransparent” situations that arose during December 2022’s Winter Storm Elliott, during which generators were subject to penalties while LMPs were low and PJM was exporting.

LS Power initially brought the issue charge and problem statement before stakeholders through the quick-fix process but revised it based on PJM feedback. AMP’s proposal was LS Power’s as originally issued.

“You need to align the pricing with what is needed operationally, and that’s what this fix for the triggers will do,” Philips said.

While she lauded the changes to the triggers, she said more work is needed to address imbalances between the penalties and capacity market revenues. “The stop loss really needs to be fixed so there’s some balance between your capacity payment revenues.”

“PJM did the right thing, and we’re relieved to see such a swift response to such a reckless proposal,” Tom Rutigliano, senior advocate at the Natural Resources Defense Council, said in a statement. “There should not be a public bailout of bad investment decisions, and we hope FERC takes the same tack on the questions before them now. There should be a clear message to industry that you must be able to keep the promises you are paid to keep.”

Letters to the Board

In a Tuesday letter to the board hours before Takahashi’s letter was released, several environmental groups urged the board to reject the MC-endorsed proposal, saying the CP construct had preserved reliability through Elliott and reducing its penalties would undermine PJM’s markets and risk reliability as generators make decisions about how to prepare for next winter.

“In the coming months, generation owners and demand-side suppliers will make decisions on winter readiness preparations,” the groups said. “The 60% to 90% reduction in penalty rates contemplated under the May 11 proposal would be an explicit signal to reduce spending on those preparations. It would also render the capacity prices to be paid in the 2024/25 delivery year unjust and unreasonable, as they reflect the status quo level of Capacity Performance risk.”

State regulators and consumer advocates said in a May 22 letter that PJM deliberately included high penalties when it proposed CP to FERC in 2014 in order to incentivize investments to improve reliability. Stakeholders had been asked to consider changes to that paradigm through an expedited quick-fix process in under a month, they said. They noted that PJM has stated that it plans to release a report on the impact of Elliott in mid-July; without that, they cannot come to an informed decision.

“Modifying one component without an opportunity to discuss other aspects would be a mistake,” the state officials said. “It has been stated that consumers have paid billions of dollars for the enhanced reliability measures afforded by the existing Capacity Performance construct. While the stakeholder-approved proposal modifies the risks for resources, it does nothing to ensure reliability or ensure consumers are getting fair value for the overall construct.”

Several generation and transmission owners also sent a letter to the board on May 17, saying CP has encouraged investments, such as winterization or upgrades to reduce startup times, which would be undermined by the proposed penalty reductions. Introducing those changes in delivery years for which auctions have already been run would amount to retroactive ratemaking.

“To provide adequate incentives for performance during emergencies, PJM imposed a carrot-and-stick approach, penalizing resources that failed to perform and rewarding those that exceeded expectations,” the GOs and TOs said. “The proposed penalty reductions severely mute the incentives of that framework resulting in capacity market incentives similar to those in place prior to the 2014 polar vortex events. … However, as a result of Winter Storm Elliott and the penalties assessed to generators for failure to perform, some stakeholders are now seeking to shift resource performance risk back to retail and wholesale suppliers and customers who have little ability to manage that risk.”

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NYISO Business Issues Committee Briefs: May 24, 2023

Long Island PPTN

NYISO’s Wednesday Business Issues Committee (BIC) voted to recommend that the Management Committee (MC) also votes to recommend that NYISO’s board approve the draft Long Island Public Policy Transmission Needs (PPTN) report.

The draft report identified 16 viable projects that could unbottle Long Island’s transmission constraints and enable the island to export offshore wind energy to the rest of New York. Propel NY’s Alternative Solution 5 project (Project ID: T051) was ranked No. 1 because it would add a 345-kV backbone and help with the efficient transfer of power in the future. (See NYISO Recommends NYPA-Transco Proposal for Long Island Tx Need.)

Propel NY, a partnership between the New York Power Authority and NY Transco, would build the project along with the Long Island Power Authority and Consolidated Edison.

According to NYISO, this was the first PPTN evaluation cycle in which cost containments were explicitly required as part of a developer’s proposal and a mechanism was included to evaluate and implement a transmission owner’s right of first refusal for related upgrades on their system. (See “ROFR ‘Upgrades’ Clarification,” NYISO Management Committee Briefs: Nov. 30, 2022.)

The report moves to the MC meeting where it will undergo a similar advisory vote on May 31. The Board of Directors will select the project to be built, and it will have a required in-service date of May 2030.

Manual Updates for DER

The BIC meeting also approved several updates to NYISO manuals, including changes to the revenue metering requirements manual, meter services entity manual, and the accounting and billing manual, which help enable distributed energy resource market participation.

NYISO confirmed that these approved revisions become effective at the same time as other DER tariff revisions accepted by FERC (ER19-2276).

Bilateral Transactions

BIC stakeholders voted to recommend that the MC approve NYISO proposed tariff revisions necessary to enable withdrawal-eligible generators, such as energy storage resources (ESRs), to be sinks for bilateral transactions. (See “Energy Market Projects,” NYISO Outlines Timelines for 2023 Projects.)

The revisions will update current software capabilities to enable this functionality by the end of this year. ESRs can then contract with a specific generator for its energy, such as a wind farm, through a bilateral contract and enter directly into that agreement.

The proposal moves to the next MC for consideration.

FERC Compliance Filings

NYISO on Tuesday informed the Installed Capacity Working Group/Market Issues Working Group (ICAP/MIWG) that it had submitted a third compliance filing for Order 2222 earlier this week, which corrected inconsistencies identified by FERC (ER21-2460).

The commission found several of NYISO’s earlier tariff revisions, which relate to distributed energy resource aggregation market participation in New York, to be either redundant or noncompliant. (See FERC Orders More Compliance Filings from NYISO for Order 2222.)

NYISO also told ICAP/MIWG stakeholders that the ISO would begin working to implement a 17-year amortization period when calculating fossil fuel peaker plant capacity market metrics, after FERC approved the ISO’s proposal last week. (See FERC Accepts NYISO’s 17-Year Amortization Period Proposal.)

The ISO said it would submit demand curve compliance filings in early June and planned to use the 17-year period for July spot auctions, which run at the end of June.

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Former FERC Chair Richard Glick Sets Up Consulting Shop

Former FERC Chair Richard Glick and commission staffer Pamela Quinlan announced Wednesday that they have launched a new consulting firm called GQ New Energy Strategies, which is focused on navigating customers through the clean energy transition.

Quinlan, who left FERC earlier this month, was most recently a senior policy adviser to Chair Willie Phillips and was the agency’s chief of staff under Glick.

Glick stepped down from FERC early this year after his renomination for a new term was sunk because of opposition from Sen. Joe Manchin (D-W.Va.). After that, his job search included pursuing other opportunities at law firms, but Glick told RTO Insider Wednesday that setting up his own firm with Quinlan was a better fit.

“I get to work with Pamela,” Glick said. “I always enjoyed working with her before. Secondly, as I got to talk with law firms, I realized that there’s a lot of potential clients out there that I think might be interested in having us do work for them — and when you go to law firms, there’s all sorts of conflicts with other clients and so on. You don’t always get to work on the clients you want to work on.”

The new consulting business avoids those conflicts and enables Glick and Quinlan to work with whom they want to on the issues they want to, he added.

Prior to joining the commission in 2017, Glick held senior positions with the Senate Energy and Natural Resources Committee, the U.S. Department of Energy and Avangrid (NYSE:AGR). Quinlan has more than 18 years of experience in the sector, having previously worked at Consolidated Edison (NYSE:ED) and Standard and Poor’s.

GQ New Energy Strategies will provide market insights and strategy, analyze the impact of regulatory proposals on a client’s business, advocate for beneficial policy and legislative outcomes, and help clients solve problems and identify opportunities as the energy business continues to change, Glick said.

He said he hopes to help clients navigate the energy transition in a way that ensures the grid remains reliable, the right investments are made, and the transition continues at a pace needed to avoid global warming. The Biden administration and other policymakers have set ambitious goals to make that transition happen in the next decade or two.

“There’s no doubt the goals are ambitious,” Glick said. “Having said that, you know, and I always say this … what are your choices? Look at just extreme weather over the last five years. There’s clearly a trend going on here that is very harmful to everything — our way of life, the economy, clearly our children’s future and their children’s futures.”

The Biden administration recognizes that and is working as hard as it can under the confines of the law, he added. Some of the big challenges include greatly expanding the transmission grid, speeding up the interconnection queues and ensuring reliability as the grid takes on more intermittent, renewable resources.

“It’s not going to be easy,” Glick said. “But I don’t think you can just throw up your hands and say you just can’t do it. You have to basically go get to work and do what you can do to make to make it a reality.”

The transmission agenda that Glick and Quinlan kicked off at FERC is a key part of that effort. Glick said he was hopeful their proposals would soon translate into some final rules, something Phillips has repeatedly said he wants to achieve.

The transition involves plenty of politics, which contributed to Glick needing a new job, and now Congress is paying closer attention to FERC than it has in the past.

“That has benefits, but it also has a downside,” Glick said. “The downside is nominees are put through the wringer a little more vigorously than they have [been] in the past.”

But Glick doesn’t think any of his former colleagues on the commission are influenced by such political pressure.

“None of the four existing commissioners, I don’t think they’re sitting there saying, ‘I better not do this because I won’t be able to get another term.’ That’s not in their mindset; their mindset is they came to do a public service, and that’s what they’re doing,” he said.

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NERC Issues Cybersecurity Data Request

Registered entities have until July 24 to report to NERC on the cyber assets present on their systems and the potential impact of adding security monitoring software under a data request issued by the ERO on Thursday.

NERC released the data request in accordance with an order that FERC issued in January approving the development of reliability standards requiring internal network security monitoring (INSM) to be implemented in high-impact cyber systems and medium-impact systems with external routable connectivity (ERC) at grid facilities. (See FERC Orders Internal Cyber Monitoring in Response to SolarWinds Hack.)

FERC also required the ERO to submit a report within 12 months on the feasibility of implementing INSM on systems to which its order did not apply, namely medium-impact systems without ERC and low-impact systems. NERC’s classification of high-, medium- and low-impact is based on the functions of the assets within each system, along with the risks they could pose to reliable grid operations. Utilities are responsible for classifying the systems’ impact level.

NERC’s data request affects balancing authorities, distribution providers, generator owners and operators, transmission owners and operators, and reliability coordinators. The ERO is hoping to find out from each entity:

  • the number of substation and generation locations containing medium-impact cyber systems with and without ERC;
  • the number of substation, generation and control center locations containing low-impact systems with and without ERC;
  • the estimated percentage of network configurations for several categories of medium-impact systems without ERC, and low-impact systems with and without ERC; and
  • the estimated percentage of low-impact systems that currently have network-based malicious code detection.

The ERO also asked utilities to rate a series of challenges involved in extending INSM to medium-impact cyber systems without ERC and to all low-impact cyber systems, including equipment retrofit and network redesign, compliance burdens, implementation and maintenance costs, and supply chain constraints. In addition, entities have the option of suggesting alternate approaches to mitigate the risk of operating without INSM and, for those that have already implemented INSM on their cyber systems, how they went about it.

Responses are due within 60 days from the issuance of the request.

Chinese Hackers Targeted US Infrastructure

The commission defines INSM as a set of practices or tools for gaining visibility into an entity’s own system, including anti-malware, intrusion-detection and prevention systems. It initially suggested the addition of INSM to NERC’s Critical Infrastructure Protection standards last year in response to recent cyberattacks, most prominently the SolarWinds hack of 2020 that left network management software used by thousands of public- and private-sector organizations worldwide infected with malware. (See FERC Proposes New Cybersecurity Standard.)

SolarWinds now claims the actual number of customers affected by the hack to be fewer than 100, but the prospect of malicious actors, particularly hostile nation-states, caused alarm bells to ring throughout the cybersecurity community. (The U.S. has accused Russia’s Foreign Intelligence Service of perpetrating the SolarWinds hack.) FERC, which was one of the organizations potentially affected, said last year that the attack “demonstrated how an attacker can bypass all network perimeter-based security controls traditionally used to identify the early phases of an attack.”

Those concerns have continued to grow. The day before NERC issued its data request, the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA), along with the National Security Agency, FBI and several of CISA’s international counterparts, published a joint cybersecurity advisory warning about Volt Typhoon, a cyber actor believed to be sponsored by China.

According to CISA, Volt Typhoon uses “legitimate network administration tools [to blend] in with normal system and network activities, avoid identification … and limit the amount of activity that is captured in common logging configurations,” an approach commonly called “living off the land.” A separate statement from Microsoft identified Volt Typhoon as having “targeted critical infrastructure organizations in Guam and elsewhere in the United States,” including the utility sector.

“For years, China has conducted aggressive cyber operations to steal intellectual property and sensitive data from organizations around the globe. Today’s advisory highlights China’s continued use of sophisticated means to target our nation’s critical infrastructure, and it gives network defenders important insights into how to detect and mitigate this malicious activity,” CISA Director Jen Easterly said in a press release. “We encourage all organizations to review the advisory, take action to mitigate risk and report any evidence of anomalous activity.”

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1st Substations Set Sail for 1st US Offshore Wind Projects

Transport ships set sail nearly simultaneously this week from Denmark and Texas to the New England coast, carrying the first substations to the first large-scale U.S. offshore wind projects.

A 1,500-ton substation built by Kiewit Offshore Services in Texas was loaded and departed Wednesday for the South Fork Wind project south of Rhode Island, which will feed up to 132 MW into the New York grid. It is the first U.S.-built offshore wind substation.

Meanwhile, Bladt Industries inched a 3,200-ton behemoth out of its production facility on the Denmark coast, down an access road and onto a waiting heavy-lift vessel (HLV). It set sail Wednesday for the Vineyard Wind 1 project off Massachusetts, which will feed up to 800 MW into the New England grid.

The Vineyard substation’s 2,000-ton, four-pile jacket foundation is making the journey as well, secured to the deck behind the substation.

South Fork and Vineyard both began construction last year and are expected to start generating power this year.

One of them will have the distinction of being the first utility-scale offshore wind farm to come online in U.S. waters, where the offshore wind sector now consists of seven turbines rated at a combined 42 MW.

Other nations have been building offshore wind farms for a third of a century, and installed capacity worldwide has surpassed 63 GW as the industry has matured. As a result, initial U.S. offshore wind development will rely to a significant degree on foreign equipment while a domestic supply chain is created and expanded.

Nascent Industry

For this reason, design and fabrication of the South Fork substation in the U.S. is a milestone, developers Ørsted and Eversource Energy said in a news release Thursday.

OSW Substation (Orsted and Eversource) Alt FI.jpgThe first U.S.-built offshore wind substation is prepared for transport Wednesday from Ingleside, Texas, to the South Fork Wind Project off the Rhode Island coast. | Ørsted and Eversource

 

“South Fork Wind continues to demonstrate the enormous power of offshore wind to create a new, American-based supply chain as we work to grow the clean energy industry here in the United States — spreading economic opportunity to workers and local communities across the nation,” said Mike Ausere, vice president of business development at Eversource.

Also in Texas, Dominion Energy is building the first U.S. wind turbine installation vessel, and Ørsted and Eversource will be the first to charter it after its expected completion next year.

The supply chain for this new class of U.S. ship spreads far and wide.

The Eco Edison, the first service-operations vessel being built in the U.S., is using components made in 34 states, according to Ørsted and Eversource, which will use it for their Revolution, South Fork and Sunrise wind projects. The 262-foot ship will be the home at sea for up to 60 offshore wind technicians, the first group of whom are being trained now by Ørsted, the Danish firm that is the world’s leading offshore wind developer.

Mature Industry

Denmark has become home to a mature offshore wind industry since the world’s first offshore wind farm went online there in 1991.

Among the companies in the sector is Bladt, which has produced more than 3,100 foundations and 25 substations. For the Vineyard project, it partnered with two other Danish firms, Semco Maritime and ISC Consulting Engineers: Bladt worked on steel manufacturing, Semco and ISC on design, and Semco on electrical installation.

Bladt said it and Semco have been targeting the new U.S. offshore market and secured seven of the first 11 substation contracts awarded in U.S. waters. When the substation and its foundation arrive at the installation site south of Martha’s Vineyard, Vineyard Wind contractors will install it, and then Semco and Bladt will work over the summer to commission it.

In a news release Thursday, Bladt Chief Project Officer Klaus Munck Rasmussen said, “Many years ago, we were a part of the first offshore wind projects in Denmark when the industry evolved here, and it feels great adding a new chapter to our story with our involvement in the first U.S. project.”

“Moving a 3,200-ton object is not something that we experience every day, so we have been excited to follow both load-out and sail-away from our side of the Atlantic,” Vineyard Wind CEO Klaus S. Moeller said. “With the components on their way, we look forward to welcoming the barge here in Massachusetts.”

Also Wednesday, a Portuguese-flagged HLV docked in New Bedford, Mass., bearing the first supersized components for the 62 towers that will be erected for Vineyard.

New Bedford years ago moved to make itself a shoreline hub for the wind industry envisioned off the New England coast.

There is a little irony in this: A fleet based in New Bedford helped hunt some whale species nearly to extinction, harvesting their oil for lamp light. Now construction crews will sail out of New Bedford to create a new source of electricity to light homes and businesses. They are strictly mandated to take a long list of precautions to not kill any whales in the process.

New Bedford Mayor Jon Mitchell on Thursday called the landmark delivery of tower components “poetic.”

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MISO to Evaluate System Attributes Through Year’s End

CARMEL, Ind. — MISO says it will wait until the end of the year to determine how it measures and encourages the six generating attributes it says are necessary to its system operations.

The system reliability attributes include availability, delivering long-duration energy at a high output, rapid start up times, providing voltage stability, ramp-up capability and fuel assurance. (See MISO Considers Resource Attributes as Thermal Output Falls.)

During a Wednesday Resource Adequacy Subcommittee meeting, MISO Director of Policy Studies Jordan Bakke said staff need to tap the RTO’s resources to strengthen system health as the resource transition exposes reliability hazards. He added that there’s no one “perfect resource” or small group of resources that can furnish a flawless balance of reliability, flexibility and affordability.

Bakke said earlier this year that MISO’s attribute discussions could prompt “fundamental changes” in how it operates the markets and ensures reliability. He said staff think it will take several years to roll out solutions in the most “equitable” way they can.

Bakke said MISO believes that the six attributes will become increasingly scarce in coming years. He said their rate of disappearance will help determine whether “new and adaptive market products, new participation requirements or just plain more visibility” are needed.

Renewable resources may account for as much as 40% of the fuel mix in the 2027-28 timeframe, he said, “relatively sooner than we thought where we were going to be five years ago.”

Minnesota Public Utilities Commission staffer Hwikwon Ham said decisions on cultivating the attributes need to happen urgently given that Missouri River Energy Services and MidAmerican Energy announced this week they’re scrapping a planned pumped hydro storage project in central South Dakota over financial concerns. The Gregory County Pumped Storage Project would have stored output from MidAmerican’s wind fleet. MidAmerican Energy and MRES said they will “continue to evaluate all options,” including pumped storage.

Independent Market Monitor David Patton has called MISO’s attempt to single out and quantify necessary system attributes “somewhat misguided,” saying that recognizing attributes as discrete is problematic. He said the grid operator should instead pursue an accreditation method that values a generator’s usefulness to the grid.

“I don’t think you can model these things. Nobody can,” Patton said during a Resource Adequacy Subcommittee meeting in April.

Bakke said that while an accreditation more representative of generation output is necessary, there is still much to be done in ensuring resource adequacy.

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MISO: Sloped Demand Curve Would Have Raised 2023/24 Capacity Prices

CARMEL, Ind. — MISO said Wednesday that a sloped demand curve applied to its recent seasonal auction would have boosted summer clearing prices as much as sixfold, better reflecting the footprint’s tapering supply.

Staff said their internal analyses showed that a seasonal systemwide sloped demand curve would have cleared the Midwest region at $65.50/MW-day in the summer, $25.90/MW-day in the fall, $5/MW-day in the winter and $19.10/MW-day in the spring. MISO South would have cleared at $25.70/MW-day (summer), $25.90/MW-day (fall), $5/MW-day (winter) and $19.10/MW-day (spring).

The subregional transfer constraint between the South and Midwest would have bound and resulted in price separation for the summer season, MISO said.

The RTO is on a mission to design and implement downward-sloping demand curves by its 2025/26 capacity auctions. It’s aiming to have a FERC filing ready sometime in the third quarter. (See MISO Charts Course on Capacity Auction’s Sloped Demand Curve.)

The grid operator said the 2023/24 auction would have cleared 137.7 GW systemwide for the summer with a sloped demand curve, 3.6% beyond its 132.9-GW planning reserve margin requirement. In other seasons, the auction cleared 0.8% above the PRM requirement (spring and fall) and 2% (winter).

The 2023/24 planning resource auction cleared most of its subregions at $10/MW-day (summer), $15/MW-day (fall), $2/MW-day (winter) and $10/MW-day (spring). (See 1st MISO Seasonal Auctions Yield Adequate Supply, Low Prices.)

During a Resource Adequacy Subcommittee meeting Wednesday, MISO’s Mike Robinson said that the nearly 4.7 GW in excess capacity from this year’s auction in MISO Midwest does have incremental value, though the current vertical demand curve has no way to appraise it.

“Prices have crashed because we’re a little long. Prices have gone from the highest price possible last year to $10/MW-day this year,” he told stakeholders.  

MISO said its current capacity auction design “does not facilitate the investment and retirement decisions necessary to maintain the resources to meet system reliability.”

The grid operator intends to base its sloping demand curves on separate seasonal reliability targets for the Midwest and South auctions. Its analyses have only shown an incremental capacity value for capacity procured beyond the season’s reliability target in summer. Robinson said the summer value is a “reflection of assignment of risk.”

To formulate sloped demand curves, MISO will run studies using the net cost of new entry (CONE), or an approximated revenue requirement from capacity payments. To do this, MISO is using three years of historical data to calculate inframarginal rents that cover generators’ fixed costs. Net CONE is calculated by subtracting inframarginal rents from CONE and will be used to influence the curves’ final shape.

MISO said the Midwest’s net CONE averages $73,200/year (about 71% of CONE) and the South averages $58,500/year (about 62% of CONE).

Robinson said staff are hoping to lock in the demand curves’ shape for three to four years at a time, periodically re-evaluating them to reflect the changing resource mix.

“Can we set up an auction design where asset owners can cover their costs?” Robinson asked hypothetically. “But we don’t want to over-procure. We want to do this judiciously.”

Bill Booth, a consultant to the Mississippi Public Service Commission, said the auction has little financial impact on vertically integrated utilities. He said bilateral contracts are a better measure of capacity value.

“Don’t think that these signals are going to stop someone who wants to retire a coal plant from retiring it,” Booth said.

Michelle Bloodworth, CEO of coal trade group America’s Power, argued that increased revenues in MISO’s auction might make a difference to owners of existing thermal plants.

“We do believe that the auction results reflect this year. However, the long-term trend of depleting resources continues to play out,” Durgesh Manjure, MISO’s senior director of resource adequacy, said.  

Manjure said that by dividing capacity procurement into seasons this year, MISO spread risky times into separate seasons and lowered PRM requirements. He said this year’s annual requirement was 7.4% on an unforced capacity basis, compared to 8.7% last year.

The RTO is also proposing to include an opt-out provision from the sloped demand curve for market participants.

Robinson said that while MISO is “trying to craft more reasonable” auction outcomes to reflect excess capacity’s incremental value, it also must respect states’ rights to resource adequacy.

MISO plans to require load-serving entities opting out of the curve to meet a capacity requirement that relies on the PRM requirement plus an additional, yet-to-be-determined percentage likely ranging from 1.5 to 3%. The RTO has proposed that LSEs opting out of the curve do so for three years at a time.

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Lawsuit Against Vineyard Wind over Threat to Whales Tossed

One of the federal lawsuits challenging approval of the Vineyard Wind 1 offshore wind project off the south coast of Massachusetts has been dismissed, and the remaining three are based on similar arguments before the same judge.

A group of Nantucket residents challenged the authorization of the 800-MW offshore wind project on the contention that federal agencies that reviewed it performed inadequate environmental assessments. Specifically, they argued that the project could negatively impact whales, including the critically endangered North Atlantic right whale, and degrade air quality.

The plaintiffs are the Nantucket Residents Against Turbines (or ACKRATS, “ACK” being the International Air Transport Association code for Nantucket Memorial Airport) and a founding member of the group, Vallorie Oliver. The judge hearing the matter ruled May 17 that they had not made their case.

Named as defendants are the U.S. Bureau of Ocean Energy Management, Interior Secretary Deb Haaland, the National Marine Fisheries Service (NMFS), Commerce Secretary Gina Raimondo and Vineyard Wind, jointly owned by Avangrid Renewables and Copenhagen Infrastructure Partners.

U.S. District Judge Indira Talwani ruled that the plaintiffs had standing to challenge the approval regarding the project’s potential harm to whales but not on the potential impacts to air quality from vessels constructing the wind farm.

Talwani shot down their arguments one by one in a 52-page ruling and granted the defendants’ motion for summary judgment dismissing the case.

The other three lawsuits before Talwani are based on similar arguments, though some details differ. They each accuse federal agencies and administrators of various failures and violations.

Long History

BOEM awarded a lease to Vineyard Wind 1 on April 1, 2015, and gave final approval to its construction operations plan on July 15, 2021.

The lawsuits began rolling in almost immediately. On July 18, Allco Renewable Energy alleged that the defendants’ legal errors would negatively impact solar qualifying facilities under the Public Utility Regulatory Policies Act in the Northeast.

ACKRATS filed its complaint Aug. 25. Then on Dec. 15, several parties in the fishing and seafood industries filed a complaint saying the defendants disregarded their legal responsibilities with their “unintelligent” pursuit of energy policy goals. As a result, they say, the plaintiffs will have to stop fishing in the Vineyard lease area and be economically ruined.

On Jan. 31, 2022, the Responsible Offshore Development Alliance, a D.C.-based fishing industry nonprofit, filed a complaint saying the defendants failed to comply with numerous statutes and regulations. It noted that the several dozen towering turbines of Vineyard Wind 1 are the first of thousands expected to be erected off the U.S. East Coast.

As part of its study and review process, NMFS concluded construction would not jeopardize the continued existence of the right whale. But it found the project might disrupt the lives of as many as 20 individual whales; fewer than 400 right whales are estimated to exist.

Pile-driving operations are allowed only under certain circumstances in December and not at all in January through April, the period of greatest right whale activity in the area. Other mandated protective measures include trained species observers on-site, acoustic monitoring and a 10-knot speed limit.

BOEM has authorized Vineyard Wind 1 to inflict Level A incidental harassment — involving potential physical injury — on as many as 115 marine mammals during construction through April 30, 2024. These include up to 10 humpbacks, nine long-finned pilot whales, five fin whales, two minke whales and two sei whales, along with 63 Atlantic white-sided and common dolphins. Zero harm is authorized to sperm and right whales.

Level B harassment — involving potential disruption of behavior patterns — is authorized against up to 307 whales of the seven species, as well as 5,753 specimens of the two dolphin species and 845 gray, harbor and harp seals.

The project entails 62 General Electric Haliade-X turbines rated at 13 MW, standing on monopile foundations 1 nautical mile apart from each other and as close as 12 nautical miles from the shores of Nantucket and Martha’s Vineyard.

Construction of Vineyard Wind 1 began in 2022, as did work on South Fork Wind, a 132-MW Ørsted-Eversource Energy wind farm south of Rhode Island. Later this year, one of the two will become the first utility-scale offshore wind project to come online in North America.

“Avangrid commends the efforts of the U.S. Department of Justice, the federal government and the Vineyard Wind 1 project team to defend the nation’s first commercial-scale offshore wind project, and is pleased that the ruling issued by the U.S. District Court acknowledges the rigorous and thorough administrative review that the project underwent over the last many years,” Sy Oytan, Avangrid COO of offshore wind, said in a news release May 18. “Avangrid is proud of its role in launching the offshore wind industry in the United States and bringing enough clean energy to power 400,000 homes and businesses in Massachusetts.”