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December 27, 2024

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Form Energy Wants to Bring Long-duration Storage to New England

When FERC convened the New England Winter Gas-Electric Forum in Portland, Maine, in June of this year, the commissioners grilled ISO-NE executives, government officials and company representatives about how they will meet the impending electricity demand from electrification. (See NE Stakeholders Debate Future of Everett at FERC Winter Gas-Elec Forum.)

As weather-dependent renewables replace legacy fossil fuel units, how will the region ensure it has enough power during extended winter periods when the wind dies down and there is little sunlight to draw upon?

While others highlighted the uncertainty associated with predicting the future resource mix past 2030, Richard Paglia of the gas pipeline company Enbridge was quick to point to a simple solution: more natural gas.

“To me, the glue that holds all of this together [is] the gas plants that are highly dispatchable and can solve that problem,” Paglia said. “But we don’t have the supply to allow those plants to run when needed.”

In September, Enbridge followed up on its prescribed solution and announced a project to significantly expand the capacity of the Algonquin gas pipeline into New England, which the company hopes to complete by the end of 2029. (See Enbridge Announces Project to Increase Northeast Pipeline Capacity.)

But this solution would not come without major tradeoffs: Five of the six New England states have set strong decarbonization goals, and natural gas is one of the major sources of carbon emissions and air pollution in the region. Meanwhile, climate and environmental justice groups have vowed to fight the expansion and hold climate-focused politicians to their rhetoric.

At the same time, early-stage clean energy companies are scrambling to address this energy reliability gap, hoping to fill the firm generation role that has historically been dominated by fossil fuel resources.

Form Energy, a company started in 2017 and headquartered in the city of Somerville, Mass., is developing long-duration iron-air batteries that it hopes to pair with renewable energy to firm up that generation across extended stretches.

Form’s batteries are built to provide 100 hours of energy and charge by converting rust to iron, a process that is reversed when discharging to produce electricity.

“The technology is quite ready,” Marco Ferrara, Form’s co-founder and senior vice president of analytics and software, told RTO Insider. While the company has made significant scientific advances in getting high capacity out of the batteries, “the technology is inherently simple.”

Most current grid-scale batteries have comparatively short durations, sitting in the two- to four-hour range. The U.S. Department of Energy defines inter-day long-duration energy storage (LDES) as the ability to shift power 10 to 36 hours, and multiday LDES as shifting power for a period greater than 36 hours.

According to a DOE report on LDES released in March, the U.S. could need between 225 and 460 GW of LDES capacity to reach net-zero by 2050, which would require about $330 billion in capital investment.

The report found that LDES could replace the need for over 200 GW of new natural gas capacity by 2050, and that LDES reduced the need for natural gas in all modeled scenarios.

“Analysis shows that by 2050, net-zero pathways that deploy LDES result in $10 billion to $20 billion in annualized savings in operating costs and avoided capital expenditures compared to pathways that do not,” the DOE report concluded. To achieve this, LDES deployment capacity must reach 10 to 15 GW per year by 2030 and 30 GW per year by 2040, the report found.

Form does not have any utility-scale batteries in operation but has several pilot and demonstration projects in the pipeline. The company is currently developing a 1.5-MW pilot project with Great River in Minnesota, two 10-MW projects with Xcel Energy in Minnesota and Colorado, a 5-MW project with Dominion Energy in Virginia, a 10-MW project with the New York State Energy Research and Development Authority and a 15-MW project with Georgia Power. The expected in-service dates range from 2024 to 2026.

The two projects with Xcel will be located at the sites of two retiring coal plants, chosen in part because of the ability to charge the project with nearby renewable power, existing water-supply infrastructure and the ability to upgrade grid interconnection infrastructure.

Form Energy’s Somerville lab | © RTO Insider LLC

The company performs most of its research and development in its Somerville lab, where engineers test all sorts of variables in thousands of battery cells lined up in long rows, separated by grocery store-style aisles.

While the company does not have any projects in development for New England, it sees great potential for the technology in the region. A white paper published by the company in late September found that by adding 23 GW of multiday storage capacity by 2050, the New England grid would see a 33% reduction in the cost of eliminating fossil fuel generation and reduce clean energy curtailment by 83% compared to a scenario with no multiday storage.

“Pairing sufficient multiday storage with offshore wind can create a firm zero-carbon energy resource that would support grid reliability during all times of the year for a cost that is 80% less than with short-duration storage,” the report found.

The study modeled the grid during all days of the year under different weather scenarios. Ferrara emphasized that modeling weather and load across all hours of the year, instead of short representative stretches, is essential to understanding the true reliability attributes of a resource.

“Methodology matters,” Ferrara said. “If you solve a capacity expansion problem with that richness of information, you come up with a portfolio that is truly robust across weather years.”

Along with portfolio planning methodologies, Ferrara highlighted several key challenges to scaling up Form’s technology. He said the company’s ability to rapidly increase manufacturing would likely be the limiting factor as it works to meet growing demand.

“We don’t see any particular blockers on the supply side; we see a lot of opportunity on the demand side for our technology; and we’re there in the middle,” Ferrara said, noting the relative availability of the battery’s key components: iron, water and air. The company is fast-tracking construction on a large manufacturing facility in Weirton, W.Va., and is hoping to begin operations at some point in 2024.

Ferrara also pointed to the need for appropriate compensation mechanisms to account for the grid benefits that long-duration storage could provide. At a meeting of ISO-NE’s Consumer Liaison Group in June, a Form representative said the company is interested in bringing projects to the region but is limited by the RTO’s current market structure. (See Activists Want ISO-NE to Push for Renewables.)

Currently, ISO-NE does not differentiate between short-term and long-term battery storage systems in its capacity accreditation system, although the RTO is working to change this dynamic in its ongoing Resource Capacity Accreditation (RCA) project.

“Determining how to account for the reliability attributes of storage systems, which have different sizes, durations, etc., is a major component of the RCA project,” an ISO-NE spokesperson told RTO Insider in a statement. They added that while the region currently relies on stored fuels like oil and LNG when other resources are not available, “in light of the ongoing clean energy transition, it is clear that the region will need to explore alternative resources to provide these essential services.”

ISO-NE’s 21-day energy simulator — used to study future resource adequacy — only models two-hour batteries and pumped hydro. The RTO denied stakeholder requests earlier this year to look at long-duration storage in its Operational Impacts of Extreme Weather study, saying that developing a tool to model this could not be completed to fit the timeline of the study.

The inability to study a wider range of storage durations “is problematic for system modeling and transmission planning, where energy storage can act as a transmission-enhancing technology, as well as for the [alternative resource] sector’s larger goals of seeing energy storage markets advance in ISO-NE,” said Alex Lawton of Advanced Energy United, a clean energy association whose membership includes Form Energy and other storage types.

In future analyses, ISO-NE said it plans to continue improving its modeling capabilities, including adding the ability to model long-duration and multiday storage.

FERC recently approved an ISO-NE proposal to allow energy storage to serve as transmission-only assets to solve transmission issues. These new rules will allow batteries to function as transmission assets for the first time, but they impose strict limits on their use, including largely prohibiting them from participating in the RTO’s markets and limiting their total capacity on the grid to 300 MW. (See FERC Accepts ISO-NE Filing to Allow Storage as a Tx-Only Asset.)

In a filing prior to the commission’s ruling, United called the changes a “first step” while recommending that the RTO develop guardrails to allow transmission-only storage assets to participate in ISO-NE markets and consider lifting the capacity limits as it gains operational experience with them.

As the region sits on the precipice of major new investments in fossil fuel generation and infrastructure, Ferrara said he hopes ISO-NE considers investing in and incentivizing zero-emission reliability solutions like long-duration and multiday storage. He advocated for reforming the capacity markets to account for differences in storage durations, as well as the establishment of a “zero-carbon capacity product.”

In January, Massachusetts released a proposal for a forward clean energy market (FCEM), which included a “clean capacity certificate” product aimed at incentivizing non-emitting capacity resources. However, this proposal has failed to gain traction with the other New England states.

ISO-NE has indicated that it is up to the states whether to pursue an FCEM, telling RTO Insider that “the New England states have communicated that they are not interested in pursuing this market design at this time. As a result, we have not conducted further analysis.”

A spokesperson for Massachusetts’ Executive Agency of Energy and Environmental Affairs told RTO Insider that the state is “committed to exploring new long-durational energy storage technologies that not only could reduce our dependence on the grid and our carbon footprint, but also offer savings for residents and businesses.”

With the dual challenge of impending state decarbonization targets and electricity demand increases, Ferrara said it is important to start developing projects in the region as soon as possible. He noted that the company’s white paper found that the least-cost 2030 storage portfolio to prevent outages would include about 3 GW of multiday storage.

“If we’re really serious about goals in 2040 and 2050, and we’re building assets that last 20 years, we need to build them now,” Ferrara said.

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Mood Anxious as Renewable Energy Industry Gathers in NY

ALBANY, N.Y. — Last week’s clean energy conference rounded out a very eventful October for the renewable industry in New York.

Developers, contractors and their advocates were still reeling from the state’s decision to not grant cost increases to 90 renewable projects totaling more than 12 GW — and still digesting the state’s announcement of 25 new projects totaling more than 6 GW.

Against this backdrop, the mood was restive as the Alliance for Clean Energy New York opened its annual fall conference in Albany on Oct. 25.

One speaker compared it to a roller coaster ride, but with none of the thrills and all the scares.

“We know a lot of work is not starting in ’24,” CS Energy CEO Matthew Skidmore said.

The mood was markedly different a year earlier. The 2022 edition of the ACE NY conference opened days after New York voters approved a $4.2 billion environmental bond act.

Alliance for Clean Energy New York Executive Director Anne Reynolds | © RTO Insider LLC

“At this time last year, the IRA was still news, and great news, but inflation has continued to be a problem since then,” ACE NY Executive Director Anne Reynolds told NetZero Insider on Oct. 26.

She described the prevailing mood at this year’s event as “anxiety” — developers who have said they can’t start construction without more money must decide the least bad way to proceed now they’ve been denied that money.

There’s no expectation the spiraling cost of materials will ever return to pre-inflation levels, Reynolds said, but interest rates will come back down eventually. How soon a developer must make their next payment to NYISO or the New York State Energy Research and Development Authority may determine whether they’re willing to wait for lower interest rates.

NYSERDA is a lead agency in the state’s clean energy transition, and its president, Doreen Harris, delivered a keynote at the conference.

Speaking to industry managers and leaders, Harris offered a more nuanced message than state leaders typically deliver to the public.

“I know the last months and indeed, for some of us, years have been extraordinarily challenging,” Harris said. “I believe our industry will rebound quickly from these challenges.”

Turbulent Times

Rising costs and limited supplies of materials, rising interest rates, regulatory delays and interconnection constraints are problematic for renewable developers everywhere, particularly in the offshore wind sector.

But New York has had a particularly rough October.

In June, developers who had secured state contracts for 90 projects in earlier solicitations said they might not be able to proceed to construction without more money. They petitioned for some form of relief, such as through the inflation adjustment mechanisms offered in more recent solicitations.

The Public Service Commission rejected the request Oct. 12, putting much of the state’s renewable project pipeline at risk of cancellation.

A week later, Gov. Kathy Hochul (D) vetoed a bill that would have allowed the proposed Empire Wind offshore wind farm to run a high-voltage cable under a city park. The cable has sparked resident pushback in the seaside city where it would be located, and Hochul said renewable developers must cultivate local support rather than seek legislative permission to do an end run around local opposition.

In some ways, the veto was just as worrisome to conference attendees as the PSC rejecting the cost adjustments — there are NIMBYs everywhere, and the veto may set a precedent giving them even more control over large-scale renewable development than they already have under the state’s home-rule laws.

In addition, the hydrogen hub proposed by New York and six other states was not among those tentatively chosen for up to $7 billion in federal support.

All of this complicates New York’s progress toward a looming milestone in its landmark 2019 Climate Leadership and Community Protection Act — 70% renewable energy by 2030.

Against this backdrop, Hochul in late October has made a series of announcements to emphasize the state’s commitment to clean energy development: a 10-point action plan to expand the renewables industry, contracts for 25 new renewable projects totaling 6.4 GW and an expedited process for the next onshore and offshore renewable solicitations, which will be open to rebids by the 90 previously contracted projects, should they opt to cancel their existing contracts.

The nation’s first offshore wind turbine nacelle and blade factories are part of the package, and the overall economic impact is estimated in the $20 billion range.

All of this has a nice ring — but most of the 10 points already were in place, the 25 new contracts still must be negotiated and the economics of rebidding up to 90 older projects are unclear.

Also, the full $20 billion does not materialize unless everything falls into place in sequence.

Then there is the regulatory structure in New York, which is known as a slow and expensive state in which to carry out large-scale renewable development.

Some panel discussions at the conference became forums on this, with developers complaining and state regulatory employees explaining or even apologizing.

Gripes

Ben Brazell, director of environmental services at EDR, said now that the state Office of Renewable Energy Siting is more than two years old, it’s time for it and the industry to devise a more efficient protocol.

Ben Brazell, EDR | © RTO Insider LLC

“It was mentioned this morning that the goal was to have one [notice of incomplete application] issued and move forward,” he said. “I’d like to push the envelope a little bit and have none. Other jurisdictions, other siting boards that have similar responsibilities do that, and do it frequently. … The culture can’t be, submit an application, assume it’s deficient and then move forward.”

VC Renewables Senior Vice President Wendy DeWolf said there needs to be more nuance at the regulatory level.

Every tree has value, she said, but so does the project that would be sited where those trees once stood. The impact on the site and its immediate neighborhood needs to be balanced against the climate benefits over the horizon.

Wendy DeWolf, VC Renewables | © RTO Insider LLC

“There’s no such thing as a perfect site,” DeWolf said.

“One of the main questions I get when I engage with community members is, why here? It often comes down to, this is the place that I felt that, given all the data analysis that we have, the interconnection is going to work and where I can permit this project.

“You’re never going to find a site that doesn’t have some environmental impact.”

Wesson Group President Tim Delaney said the pressures affect him as a construction contractor differently than they affect developers. But they’re rooted in the long wait for shovels to hit the ground after a project wins a state contract.

“When they bid a job as a developer it takes NYSERDA six to nine months, sometimes a year, to make an award,” he said. “Then you’ve got a year-plus in permitting and regulatory — if you’re lucky. So now your estimate of cost is two years old. And then in addition you start adding in the other legislative and [environmental regulatory] changes. It just makes it really hard.”

From left: Cordelio Power CEO John Carson, Wesson Group President Tim Delaney and CS Energy CEO Matthew Skidmore | © RTO Insider LLC

He cited as an example a new specification for the gravel used to build temporary roads, which would raise the cost of building a 150-MW wind farm by $3 million to $4 million.

The potential delay or cancelation of the 90 projects would be a new level of hurt.

“We probably had a half-billion dollars’ worth of work in the pipeline that essentially went to significantly less than that,” Delaney said.

Responses

Representatives of ORES and NYSERDA offered some impressive statistics: ORES has permitted 14 major projects — more in the two years the office has existed than in the preceding 10 years — and awarded those 14 permits just eight months after application, on average. NYSERDA has awarded 114 contracts in six solicitations since 2017.

But only one of the ORES projects has started construction, its pre-application process can take much longer than eight months, and it’s a new agency that has had to gain experience and build staff.

Meanwhile, only 26 of the NYSERDA projects have reached commercial operation; 88 are still in development.

ORES Deputy Counsel Hayley Carlock acknowledged criticism that the preapplication review process has become a pinch point in an agency created to eliminate pinch points.

“We agree. We also see that the completeness process is an area where we can improve. And we are striving to do that every day.”

In defense of ORES, some applications come in with glaring omissions, Carlock said. Developers should take the pre-application process more seriously, she said.

“The office is not here to put up walls and slow down projects … [but] it’s a fair critique and one we’re working hard to address.”

NYSERDA Director of Large-Scale Renewables Abbey DeRocker said the authority has attempted to expedite the process. One example is the Build-Ready program created in 2019, under which NYSERDA advances a project through the planning and review stages before requesting proposals to build it.

ACE NY

From left: Abbey DeRocker, NYSERDA: Haley Carlock, ORES and Zachary Smith, NYISO | © RTO Insider LLC

“The intent is to have difficult sites that could have more risks than typical sites build-ready for private renewable energy developers to construct and operate,” she said.

Initial applications are due in early December for NYSERDA’s first such project, which would be a 12-MW solar farm on a tailings pile at a defunct iron mine. Formal proposals will be due in March, and NYSERDA hopes to select a developer by mid-2024.

This timeframe — five years from launch of the program to its first potential contract — is not unusual. Much of the landmark CLCPA still is being hashed out more than four years after it was signed into law. Some projects can take a decade or longer to progress from site selection to commercial operation.

This is what may derail the 90 at-risk projects: Their revenue was locked in long before their cost of construction.

DeRocker acknowledged the potential for complications when a project spends so much time in development.

“A lot can change over that time period,” she said. “And we have the changing landscape of state priorities at the same time. For those of you who have been around since 2017, you’ve noticed we’ve never run the same solicitation twice. Some of that is because we’re trying to effectuate policy changes. … we’re learning as we go along.”

Zachary Smith, vice president of systems and resource planning at NYISO, said the state’s grid operator is preparing a set of reforms under FERC Order 2023 that would greatly streamline the interconnection process, which has bogged down as the volume of applications rose.

In five years, the queue has grown from 175 projects totaling 20 GW to more than 500 totaling 120 GW.

“In today’s process, admittedly, there is a lack of certainty,” Smith said.

“We are changing that. If FERC approves our reforms as we are proposing them … a major objective of mine is to provide certainty. You may not agree with the amount of time it is going to take, but we’re going to codify that in our procedures, and we’re going to stick to that.”

When Hochul announced the 6.4 GW of new renewable contracts earlier in the week, she struck a celebratory tone and made only oblique references to the 12 GW of existing contracts that recently had fallen into danger of cancellation. But she was speaking to the general public at an appreciative gathering of dignitaries supportive of the new projects.

Given the audience at the ACE NY conference, Harris could not do the same in her keynote. She acknowledged the setbacks and commiserated with the audience.

But she also segued into a pep talk, sounding like a football coach trying to rally the team back onto the field after getting mauled in the first half.

“The phoenix is rising here,” Harris said. “It is rising because of each of you … I want to take a moment to reaffirm the incredible contributions of everyone in this room today.”

“Who will the historians be writing about? What courageous visionaries in this room will be shaping that next chapter?” she asked. “They won’t be writing about the ones who decide to pull up stakes and move to the next market, where the grass may appear greener.”

When she finished, Harris left briskly through a rear exit rather than wading through the crowd she had just tried to rally.

Moving Forward

The 460-plus attendees at the ACE NY conference have a wide range of perspectives and roles in the clean energy transition — developer, builder, regulator, facilitator, advocate.

What they almost certainly have in common is a desire for the transition to continue and to succeed, if not for the sake of the planet, then for the sake of their bottom lines.

ACE NY

NRDC Climate and Clean Energy Program Director Kit Kennedy | © RTO Insider LLC

It’s hardly the first challenge they’ve faced, Reynolds reminded the crowd, and they’ve overcome many setbacks.

NRDC Climate and Clean Energy Program Director Kit Kennedy said New York needs to maintain its momentum, not just for its own benefit but because it’s a leader influential beyond regional and even national borders.

“There’s no sugarcoating the impact of some of New York state’s recent decisions,” she said. “This was a setback — if these projects or even some of these projects are canceled, New York will be regressing rather than progressing toward its 2030 goals.

“We need a continued and unremitting commitment to the successful projects, getting steel in the ground, building the transmission lines we need, and continuing grid investments.”

Cordelio Power CEO John Carson said his board asked if he thought New York was still a viable market. He does, but “it’s going to require a lot of patience.”

ACE NY

John O’Leary, the New York governor’s deputy secretary of energy and environment | © RTO Insider LLC

Some see the 70% by 2030 goal as aspirational, he added, but he still finds it inspirational.

“We’ve had a terrible bump in the road. I believe we’re going to get back on our feet. So, I’m saying we’re still doing business in New York.”

Delaney said: “We’re certainly still bullish. We live here, we work here during the season. … This industry has been really cyclical since its inception.”

Whatever their frustration with New York’s execution of the clean energy transition, no one faulted its intentions: “Just the fact that we have an Office of Renewable Energy Siting is reflective of what’s going well in New York state,” DeWolf said.

Hochul’s deputy secretary of energy and environment, John O’Leary, urged attendees to step back from the nettlesome details and remember the larger picture — the “why” of the energy transition.

“The work that everyone in this room is doing is making a livable planet possible. … I know it’s a difficult time and I’m hoping that this week marks the beginning of a new chapter.”

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Mixed Views on CAISO Interconnection Process Proposal

CAISO stakeholders have voiced multiple concerns about a straw proposal to revamp the ISO’s interconnection process, with some cautioning that the timeline to draw up a final plan is too ambitious given the lack of progress on the effort so far.

Stakeholders shared their views at an Oct. 24 meeting of CAISO’s Interconnection Process Enhancements Working Group. Top among their concerns: the ISO’s plan to introduce scoring criteria designed to rank requests to join the grid based on project readiness, as well as a proposed interconnection cap to limit any one developer’s ability to dominate the queue.

Stakeholders expressed frustration over a lack of information on how to implement the scorecard, including uncertainty about in which transmission zones projects would be developed, how open access and equal competition would be upheld and fears that the initiative’s timeline was rushed.

CAISO’s 2022-2023 Transmission Plan, developed in coordination with the California Public Utilities Commission and the California Energy Commission, outlined action items that could help transform the process of connecting new resources to the grid.

Key among the items, also discussed in the ISO’s Interconnection Process Enhancements straw proposal, was the introduction of designated geographic zones that should be prioritized for resource development. The approach would prioritize projects in areas where there are planned capacity additions approved in CAISO’s transmission planning process.

According to the plan, the CPUC would direct load-serving entities (LSEs) to focus energy procurement in those zones, and the ISO proposal will use the scoring criteria to select projects once the resources in a transmission zone reach 150% of the available or planned capacity in that zone. But some stakeholders contend that the straw proposal contains insufficient information regarding the location and details of the zones.

“If we’re going to move forward with this scoring criteria, it needs to be absolutely clear to both the CAISO and developers what locations are in and out of a zone,” Bridget Sparks, interconnection policy manager at AES Clean Energy, said. “If you’re asking developers to invest millions of dollars in land and other development activities, there shouldn’t be any uncertainty on whether or not a certain point on a transmission line is in or out of a zone.”

Cathleen Colbert, director of CAISO market policy at Vistra Corp., echoed that concern, saying that CAISO hadn’t provided enough data transparency on zone locations. She asked the ISO to use the heat maps requested in FERC Order 2023 (RM22-14-000) to provide more clarity, and that they be available in time to inform the next opening of an interconnection cluster window. Sparks also suggested CAISO provide line diagrams to identify zones.

Anish Nand of the Northern California Power Agency asked that CAISO provide line diagrams before the release of the draft final proposal, but Danielle Mills, the ISO’s principal of infrastructure policy development, said the grid operator could not commit given the strict timeline.

Approval, Pushback on Scoring Criteria

In a presentation at the meeting, Southern California Edison pushed back on a few key aspects of the scoring criteria, including the proposal to include demonstrated interest from off-takers as part of the scorecard. Because letters of interest from off-takers are non-binding, SCE proposed instead to include a bonus point system in which LSEs are given a certain number of points based on their load share. This modified process, according to the utility, would allow LSEs to better identify projects that serve their mandated needs, increase the scrutiny of projects and, in turn, decongest the queue.

The utility also proposed adding the procurement of long-lead equipment that could indicate commercial readiness as one of the scoring criteria.

“I think something like the bonus points concept is appropriate,” said Lauren Carr, senior market policy analyst at CalCCA. “It would be a good way to get some more granularity around LSE interest, where there can be a range of points assigned based on how interested an LSE is on a particular project.”

Some independent power producers (IPPs) expressed support for the proposal, but others, such as Terra-Gen LLC, were concerned that the addition of an LSE bonus points system could hinder open access and equal competition.

“We also believe that doing a load-ratio type share would unfairly favor larger LSEs,” said Terra-Gen Director of Energy Market Policy Chris Devon. “This addition of another bonus point criteria for LSE interest would further give more negotiating power to the LSEs and reduce competition.”

Interconnection Caps

Another key element in the straw proposal was the introduction of an interconnection cap. CAISO proposed that each developer be limited to only submitting projects that would take up 25% of available transmission across the footprint to address market power and domination of the queue by a small group of developers.

However, in a presentation to the working group, AES highlighted that the ISO provided no evidence or data to prove that market power is a current issue.

AES also raised concern over an interconnection cap leading to discriminatory treatment between IPPs and utilities, since non-CPUC jurisdictional utilities are automatically accepted into the queue without capping and included in the studied 150% of available transmission. On the flip side, IPPs would be subject to both the developer cap and the scoring criteria within the studied 150% of available transmission.

Strict Timeline

The draft final proposal is set for Nov. 15, leaving some stakeholders frustrated by the lack of solid progress with the initiative despite the strict timeline in which to move forward.

“It seems like CAISO isn’t really giving enough time for the stakeholder process to work and [is] so wedded to a specific end timeline, and you’re considering such a radical change in the way that the interconnection process is done,” Sparks said. “We would rather get this right the first time than to rush through a process that has a lot of unintended consequences or hasn’t been thoroughly thought through.”

CAISO acknowledged the frustration.

“I know the pace is exhausting,” Mills said. “We’re just really trying to push it as fast as we can for you, not because we don’t care what you think.”

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Midwestern States Become More Open to Small Modular Reactors in 2023

Several Midwestern states on opposite ends of the political spectrum have taken steps this year signaling receptiveness to small modular reactor (SMR) development while a factory in Ohio has begun producing uranium tailored to the smaller plants.

Most recently, Maryland-based Centrus Energy opened a uranium enrichment plant this month in Piketon, Ohio, to produce high-assay, low-enriched uranium (HALEU).

The Department of Energy awarded Centrus a competitive, cost-shared contract in 2022. The company was required to begin production of HALEU by the end of 2023 under the agreement. HALEU is tailored for types of SMRs and contains between 5% and 20% fissile uranium, while large nuclear reactors use fuel with up to 5% fissile uranium.

“We hope that this demonstration cascade will soon be joined by thousands of additional centrifuges right here in Piketon to produce the HALEU needed to fuel the next generation of advanced reactors, low-enriched uranium to sustain the existing fleet of reactors and the enriched uranium needed to sustain our nuclear deterrent for generations to come. This is how the United States can recover its lost nuclear independence,” Centrus CEO Daniel Poneman said in a press release.

Deputy Secretary of Energy David Turk said that for the first time ever, “an American company is producing HALEU on American soil.”

The 16-centrifuge cascade produces only about 900 kilograms of HALEU per year, but Centrus said it could expand the Ohio operation to 120 centrifuge machines if it secures enough offtake commitments and funding.

Centrus has TerraPower and Oklo Inc. lined up to execute fuel supply contracts; both are trying to get their own SMR designs certified with the Nuclear Regulatory Commission (NRC). Oklo plans to build two of its liquid metal-cooled, metal-fueled fast reactors in Piketon to supply energy for Centrus and the surrounding area. The plants will be situated on land owned by the Southern Ohio Diversification Initiative, a community reuse organization. The plans are part of the Department of Energy’s push to re-industrialize the area around the Portsmouth Gaseous Diffusion Plant.

Elsewhere in Midwestern states, utilities were in the early stages of development while bills meant to assist SMR progress were drafted.

Early this year, a bipartisan group of Minnesota Senate lawmakers backed a bill that would direct the state’s Department of Commerce to conduct a study exploring the feasibility of SMRs (SF 1171). The Minnesota House and Senate also mulled allowing the Minnesota Public Utilities Commission to issue certificates of need to build new nuclear plants less than 300 MW in capacity (SF 2824). Both bills have been referred to the Climate and Energy Finance and Policy Committee.

Minnesota’s nuclear moratorium is nearly three decades old, but some environmental organizations are rethinking their stance on new nuclear as a zero-carbon, baseload backstop to renewable power. Minnesota law mandates that the state reach 100% clean energy by 2040.

In general, SMRs are designed to yield anywhere from 50 to 300 MWs of electricity, as opposed to the typical 1 GW from traditional, large-scale reactors. They can be built indoors and then shipped to sites to be assembled. The U.S. doesn’t have any SMRs in operation.

Meanwhile, Xcel Energy is exploring whether it wants to become operator of a NuScale VOYGR SMR under development at the Idaho National Laboratory. That plant isn’t expected to be commercially operational until 2030.

NuScale’s VOYGR is the first SMR design to win certification from the NRC.

Dairyland Power Cooperative, based in western Wisconsin, has partnered with NuScale Power to evaluate use of small-scale nuclear reactors in Wisconsin.

NuScale also is planning to build a dozen 77-MW pressurized water SMRs for Ohio and Pennsylvania in order to energize two Standard Power data centers by 2029.

If passed, Michigan’s House Bill 4753 would create tax credits of 15% for qualified research and development expenses related to the “design, development or improvement” of SMRs and activities that will hasten them to market. The bill was referred to the House Committee on Tax Policy.

“Per capita, Michigan employs the highest number of engineers in the country,” said state Rep. Pauline Wendzel (R), who introduced the bill. “We have the talent, and we have the capability. Now we need to put our foot on the gas to develop this safe, clean and reliable form of energy.”

Efforts to resurrect the Palisades nuclear power station in southwest Michigan also involve SMRs. Last month, Wolverine Power Co-op signed an agreement with owner Holtec International to buy power, hoping Palisades reopens in 2025. That agreement includes a contract expansion provision to include up to two small modular reactors onsite.

Last year, Indiana Gov. Eric Holcomb (R) signed S271 into law, which mandated that the Indiana Utility Regulatory Commission work with the state’s Department of Environmental Management to devise rules around granting of certificates of public convenience for the construction, purchase or lease of SMRs. Those rules were adopted at the end of June.

Purdue University and Duke Energy have recommended that Indiana consider public funding of studies dedicated to new nuclear and issuing state tax credits for advanced nuclear technology. Those recommendations were in an interim report of a joint study issued midyear.

Purdue and Duke are exploring the feasibility of using SMRs to meet the energy needs of Purdue’s main campus.

Finally, the Missouri legislature this year weighed HB 225, which would have allowed utilities to file with FERC to raise rates to pay for SMRs. The bill, which cleared the house but failed to gain traction in the Senate after a public hearing, would have modified the state’s 1976 law that prevents utilities from raising rates to pay for the construction of new projects.

Whether SMRs are economical enough to compete in the market remains untested. This month, researchers published a cost analysis of SMRs in the peer-reviewed international journal Energy. They analyzed the levelized cost of electricity among 19 SMR designs and said the costs to generate electricity from SMRs seems to be “non-competitive when compared to current costs for generating electricity from renewable energy sources,” even when accounting for system integration costs that double renewable energy’s price tag.

Researchers also concluded that manufacturers’ cost estimates for SMRs “are mostly too optimistic compared to production theory” and that a Monte Carlo simulation showed “that no concept is profitable or competitive.”

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Xcel Energy Touts Steel for Fuel 2.0 Plan

Xcel Energy management told financial analysts last week that it has made “significant progress” on what it calls “industry-leading clean energy transition plans.”

“Given that the regions where we serve customers are the most resource rich in wind and solar,” CEO Bob Frenzel said during the company’s third-quarter earnings call Friday, “we believe that we can lead this clean energy transition for our customers more cost-effectively than almost any other company.”

The Minneapolis-headquartered company is relying on its Steel for Fuel 2.0 program, which builds on its plan to swap fossil generation for fuel-free wind and solar that the company rolled out seven years ago. Xcel has increased its capital investment plan through 2028 to $34 billion, with another $10 billion potentially necessary after state regulatory approval of clean energy projects. (See Earnings Up, Xcel Touts ‘Steel-for-Fuel’ Strategy.)

In September, Xcel’s Colorado subsidiary filed what it called the largest clean energy transition effort in the state’s history. The plan includes shutting down its remaining Colorado coal plants with approximately 6.5 GW of renewable energy and battery storage, doubling the state’s renewables, and about 600 MW of natural gas resources to ensure reliability during times of low wind or solar conditions.

Including about $3 billion in required transmission investments, Xcel will invest nearly $11 billion in the state. The company expects Colorado’s regulatory commission to rule on the proposal early next year.

In Minnesota, Xcel has received regulatory approval to add 250 MW of new generation at its Sherco Solar project, bringing the facility’s capacity to over 700 MW. The project will use existing interconnections from the Sherco coal plant, which is retiring by 2030.

Its Southwestern Public Service Co. (SPS) subsidiary filed a resource plan in New Mexico earlier this month that lays out a need for between 5 GW and 10 GW of new generation by the end of this decade. SPS already has proposed 418 MW of company-owned solar and battery projects that are pending commission approval.

“We have the potential to deploy [15 GW] to [20 GW] of new clean generation on our systems by 2030, dramatically lowering our emissions profile,” Frenzel said.

The company said it will appeal a Colorado district court decision Wednesday that awarded CORE Energy $26.5 million in damages for a breach of contract and mismanagement of Xcel’s Comanche 3 unit. CORE owns a 25% share of the plant, which has averaged 91 days of unplanned shutdowns a year since the unit went online in 2010.

“We have a strong legal basis for challenging that $26 million award,” Xcel CFO Brian Van Abel said.

The company reported earnings of $656 million ($1.19/share), compared with $649 million ($1.18/share) for the same period in 2022. The results reflect the effect of increased recovery from infrastructure investments, higher sales and demand, and lower operating and maintenance expenses, partially offset by increased interest charges and depreciation, the company said.

Its share price lost 2.4% Friday, closing down $1.46 at $58.31.

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Chasing Goals, Facing Obstacles at Md. Clean Energy Summit

COLLEGE PARK, Md. — Maryland has already cut its greenhouse gas emissions to 30% below 2006 levels, putting it halfway to reaching the 2031 goal of a 60% reduction set in the 2022 Climate Solutions Now Act (CSNA), Secretary of the Environment Serena McIlwain told the recent Maryland Clean Energy Summit.

Maryland Secretary of the Environment Serena McIlwain | © RTO Insider LLC

Implementing existing state policies will cut emissions 55% by 2031, which means “we really only need 5% to take us to the finish line,” an achievement worth celebrating, McIlwain said, leading off a panel of state officials at the event sponsored by the Maryland Clean Energy Center. Still, she warned, getting to 60% “will not be easy for any of us.”

The law also sets a 2045 target for Maryland to slash its greenhouse gas emissions to net zero. “What this really means is we have to create new policies, and new policy action may not be welcomed by everyone, because [the policies] are bold, they are specific; they will be specific for sectors and for this entire economy,” she said.

Former state Sen. Paul Pinsky (D), who sponsored the CSNA, put it more bluntly.

“We have to shift from fossil fuels to clean energy. Period. End of discussion, end of paragraph,” said Pinsky, now director of the Maryland Energy Administration. “We can’t hang onto the old ways of doing business, we just can’t. It won’t get us where we need to be.”

According to McIlwain, Pinsky and other speakers at the day-long summit, the CSNA emission-reduction goals — coupled with Democratic Gov. Wes Moore’s 2035 target for a decarbonized electric system — are among the most ambitious in the nation. (See Md. General Assembly Sends Climate Solutions Bill to Hogan.)

Paul Pinsky, MEA director | © RTO Insider LLC

As reported at the conference, the CSNA and other recently passed laws have triggered a range of model projects and programs. The state’s largest investor-owned utility, Baltimore Gas and Electric (BGE), is preparing for a November ribbon-cutting at a new electric-vehicle (EV) fast-charging station in Johnston Square, a low-income, historically African American neighborhood in Baltimore.

One of the new laws passed this year (HB 908) made Maryland’s pilot community solar program permanent. Soon after, Solar Landscape, a New Jersey-based solar installer, announced a partnership with Public Storage to put community solar installations on the roofs of 57 of the company’s storage facilities throughout the state.

Solar Landscape will focus on signing up households in low-income communities, according to Elizabeth McKeever, the company’s general counsel. The first projects are currently under construction.

The state is also in the process of finalizing regulations for building energy performance standards for commercial buildings of 35,000 square feet or more, another provision in the CSNA. The proposed regulations could go into effect in 2025, when covered buildings will have to benchmark and start reducing their energy use, said Mark Stewart, climate change program manager at the Maryland Department of the Environment (MDE).

The law sets a 2030 target for a 20% emissions reduction from 2025 levels and a 2040 target for net zero.

But attendees also heard about some of the tough obstacles ahead.

State Sen. Brian Feldman (D) | © RTO Insider LLC

State Sen. Brian Feldman (D), chair of the state Senate Committee on Education, Energy and the Environment, reported on a recent meeting with officials from PJM, who warned of rolling blackouts in the Baltimore region if the Brandon Shores coal-fired generation plant in Anne Arundel County is closed in 2025, as is currently planned. The grid operator said it would need another three years to complete up to $800 million in grid upgrades to ensure system reliability when the plant is shut down.

“This is where things get a little more complicated,” Feldman said. “Moving forward, in 2024 and beyond, we’re going to have some very challenging policy calls.”

Maryland’s natural gas utilities could also slow progress toward the state’s emission reduction goals, with their plans to continue investing in new infrastructure at current levels, despite projections that demand for the fuel will taper as more homes and businesses electrify, said People’s Counsel David Lapp.

He foresees costs for recovering those investments shifting to lower-income customers through higher rates as more affluent households go electric.

The Right Policies

The CSNA required the MDE to produce a plan to implement the law, with an initial draft due in June of this year, to be followed by a final report sent to the governor and state legislature by the end of December.

Authored by the Center for Global Sustainability at the University of Maryland College Park, the draft plan laid out a range of policy options, some very aggressive, without making any recommendations. The report’s potential pathways included a 500% increase in solar deployments, the launch of an in-state, economywide cap-and-invest program and shifting all the electricity Maryland imports to 100% clean energy. (See Maryland Climate Report Lays out Pathways to Achieving Goals.)

Looking ahead, McIlwain was mum on specifics, but she hinted at the general direction the final report would take.

“It’s going to lay out a clear strategy that focuses on creating new statewide policies around transportation and buildings, and we’re going to explore, as we’re doing now, renewable energy pathways as well,” she said. “We’re going to focus on the right policies because when we do that, it’s going to allow us to accelerate, and when you accelerate you push the markets to respond.”

McIlwain also stressed the health and economic benefits of Maryland’s emission reduction goals. Lower emissions could result in a reduction of respiratory illnesses in the state, which could provide $591 million in health savings by 2030, she said.

The clean energy incentives and tax credits in the Inflation Reduction Act are another driver for Maryland to move fast on its climate policies and programs, she said: “It makes decarbonization way more affordable.”

Pinsky said decarbonization has to start with energy efficiency, electrification and renewables, and encouraged companies to leverage state and federal dollars to grow their markets. “We have to put our creative juices and your dollars to invest when you see a good idea that can be scaled up and has implications not just for the state of Maryland but for the nation.”

But, like McIlwain, he warned of opposition — “people who want to take potshots” at the state’s clean energy goals — and called for broad business and social support.

“We need the public and the advocacy community … the business community to get behind [this] and say, ‘There’s no wavering.’ … We’re not going to make this tentative. We’re going to implement this damn thing if we’re going to move our state forward,” Pinsky said.

Business Opportunities

Business leaders at the conference talked about both the economic opportunities and risks in decarbonization.

For A.O. Smith, a manufacturer of water heaters, the potential market is enormous, according to Josh Greene, the company’s vice president for government affairs. Of the 10.2 million units of water heating equipment shipped in the U.S. in 2022, only 145,000 were heat pump water heaters, he said.

But while heat pumps are the most efficient technology for water heating on the market, a range of factors can affect adoption, such as a state’s decarbonization goals and regulations, local utility distribution systems, consumer awareness and, of course, cost.

About 25,000 water heaters are either repaired or replaced every day in the U.S., Greene said. After one cold shower, “when you think about that turnover and what consumers are looking at, are you going to wait a few days” to get a heat pump water heater, he asked.

Overcoming such barriers to market growth also means educating contractors to stock and install heat pump water heaters, Greene said. A.O. Smith is training 2,000 contractors a week on heat pump installation, he said.

The opportunities for utilities are also significant. For example, EV programs can simultaneously support state and local decarbonization efforts, increase electricity demand and allow for new capital investments — in the form of EV chargers — that can be included in their rate base.

Alexander Núñez, BGE vice president of governmental, regulatory and external affairs, framed the utility’s EV programs as part of its efforts to “leave no one behind.” Using federal funds, BGE has partnered with ride-sharing company Lyft to help develop a fleet of 100 EVs that Lyft drivers in Baltimore can rent at discounted rates.

Alexander Nunez, BGE | © RTO Insider LLC

The first 25 EVs in the Lyft fleet were Kia Niros, which “have been on the road for just over a year, and already they have produced an aggregate of more than one million miles,” Núñez said. “These are one million miles of new people getting into an EV, experiencing … the comfort, the quiet, getting them a chance to consider whether that’s going to be their next car.”

He also noted that about one half of the Lyft drivers renting the EVs are “diverse,” and one half of the rides are either starting or ending in the city’s disadvantaged neighborhoods. The rest of the fleet will be unveiled at the ribbon-cutting for the Johnston Square EV chargers in November, he said.

But Núñez said that leaving no one behind also means maintaining service for the utility’s 700,000 natural gas customers. BGE has been working to replace gas equipment, he said, including more than 350 miles of main distribution lines, with newer equipment that helped the company lower its greenhouse gas emissions by 27% by the end of 2022.

The Coming Gas Cost Shift

Lapp and the Office of the People’s Council (OPC) have countered arguments of BGE and other utilities in proceedings before the Maryland Public Service Commission.

While acknowledging the role utilities play in providing critical services to all Maryland residents, Lapp also stressed that they are monopolies making decisions that primarily benefit the interests of their investors.

“It is the state’s job, through the legislature and the Public Service Commission, to regulate monopolies,” he said.

Maryland People’s Counsel David Lapp | © RTO Insider LLC

If Maryland gas utilities continue to invest in distribution infrastructure at their current rates, the cost of those investments could triple by 2050, from just over $1 billion to $3.1 billion, an OPC analysis projects.

Lapp said the concern is that customers will leave the gas system as electrification becomes more economic “just on a pure technology basis.”

“Climate policy will also drive further customers [off the system] for incentives like the IRA and other policies … increasing [natural gas] rates because those revenues have to be recovered from fewer and fewer sales and fewer customers,” he said.

While Lapp does not oppose all gas infrastructure spending, he said “we don’t need to replace entirely the existing systems we have today.” But even utilities that acknowledge that gas use is going to decline continue to argue for maintaining current investment levels to provide backup, he said.

Others claim that they are “not aware of any heat pumps currently available that would require no backup heating system,” Lapp said.

The OPC currently has a petition before the Public Service Commission asking it to open a proceeding aimed at ensuring gas utility planning is based on the state’s climate policies and a future of diminished gas use.

At the same time, as Feldman said, working with PJM to balance Maryland’s ambitious climate goals with grid reliability also will be critical.

Talen Energy had originally planned to convert its coal-fired Brandon Shores plant to natural gas, but found that fuel switching would not pencil out and set a closure date of June 2025. According to Jeff Shields, PJM’s media relations manager, the plant closure could result in “voltage collapse and thermal overloads on the transmission system, particularly in the greater Baltimore area.”

The issue underlines the extent to which Maryland’s dependence on imported power will affect its decarbonization efforts. A Brandon Shores closure could mean the Baltimore region will need to import 80% of its power from outside the state, Shields said.

To ensure adequate power imports, PJM has planned for system upgrades as part of its Regional Transmission Expansion Plan and is in talks with Talen to keep Brandon Shores online with a special contract, called a reliability-must-run agreement. (See PJM Shortlists 3 Scenarios for 2022 RTEP Window 3.)

Speaking with NetZero Insider at the conference, Pinsky said Maryland will need to get more aggressive on transmission, but acknowledged that the state will have to figure out how to build the system it needs without putting all the costs on its ratepayers. “I think we’ve got to look at a period of years to do that,” he said.

U.S. Sen. Chris Van Hollen (D-Md.) raised concerns about the challenges states face in applying for the $8.5 billion in federal dollars available from the IRA for home energy efficiency upgrades, one of the law’s provisions that he worked on and supported.

“It’s our goal to make sure these [funds] can be provided to states in order that they can quickly get them out the door and into the hands of the people that are doing this work,” Van Hollen said. The current application process may be making that more difficult, he said.

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NYISO: Costs of Mitigation Tool Bug Negligible

RENSSELAER, N.Y. — NYISO on Thursday said a market software problem identified this year in the day-ahead and real-time ancillary services markets had a negligible financial impact and did not result in any market manipulation.

In an update to the Installed Capacity/Market Issues Working Group, NYISO staff disclosed that an issue with the automated mitigation process (AMP), a mechanism that identifies and mitigates instances of market abuse to keep conditions competitive, led to a mere $893 of missed real-time mitigation over two hours and $41,729 in day-ahead mitigation over three days.

NYISO determined that the issue did not meet the threshold to be considered a significant market problem because the issue was quickly resolved and no unfair market behaviors were observed.

The AMP validates and adjusts bids in the day-ahead market before settlement and conducts ongoing monitoring in the real-time market to ensure that market participants are not manipulating the market for their own gain. NYISO found that it was not working properly July 6 because of an April software deployment, which prevented the AMP from both effectively executing its mitigation procedures and evaluating start-up or minimum generation references correctly.

In response, NYISO issued a notice of a potential market problem July 11, initiating a confidential investigation in collaboration with its Market Monitoring Unit and FERC to determine whether the issue significantly disrupted the market or if any market participants were gaming it. (See NYISO Discovers Market Problem, Opens Confidential Investigation.) By July 18, the software issues were resolved for the day-ahead market.

Further investigation showed that the conditions for the AMP to “trigger” never materialized during the period it was malfunctioning, indicating that the impact was minimal. ISO staff noted how AMP activates infrequently to adjust bid offers, mitigating less than 0.5% of the unit hours throughout the previous year.

Mark Younger, president of Hudson Energy Economics, encapsulated stakeholders’ reaction to the $893 cost in the real-time market, exclaiming sarcastically, “That is outrageous!”

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DOE Releases Draft Interconnection Roadmap Aimed at Fixing Queues

The U.S. Department of Energy on Wednesday released a draft of its “Transmission System Interconnection Roadmap,” which offers ways to improve the backlogged process of connecting new generation to the grid.

The draft comes after meetings with more than 2,000 individuals from 350 different organizations, the department said. DOE is hopeful that even more comment on the draft so it can come out with a final report, Becca Jones-Albertus, director of the department’s Solar Energy Technologies Office, said in an interview Thursday. DOE is working on another report on interconnection issues at the distribution level.

“We’re focused at DOE at how we can enable achievement of the president’s goal to decarbonize the electric grid by 2035,” Jones-Albertus said. “There are a number of big challenges we need to tackle to get there, and interconnection is one of them.”

Interconnection queues have about 2,000 GW of wind, solar and batteries in them; if they were all somehow built, it would be nearly enough to reach that decarbonization goal, Jones-Albertus said. Only about 20% or so of projects get built, but the fact that developers sit in them for an average of five years shows they are clogged and need reforms, she said.

DOE was working on the roadmap at the same time FERC worked on Order 2023, which covers about a quarter of its recommendations, according to the draft. The commission’s still-pending Notice of Proposed Rulemaking on transmission planning includes other proposals in the roadmap.

“Though this roadmap contains some solutions that relate to Order 2023, it also introduces additional ideas that support longer-term interconnection process evolution,” the draft says. “Such an approach is important not only to facilitate industry-wide discourse that builds upon Order 2023 but also to maintain usefulness for transmission providers that are not FERC jurisdictional.”

A major reason queues are so overstuffed is the transition to clean energy, which has led to a spike in requests. The report says that “queue volumes are likely to be large and potentially volatile for the foreseeable future.”

When FERC issued Order 2003 20 years ago, it did not contemplate the extent to which resource developers would use interconnection processes to obtain cost and siting information, the report says.

“Because the interconnection process provides accurate, binding information on interconnection costs and operational requirements, resource developers often use the interconnection process to determine ultimate project viability,” the report says. “Additionally, due to long queue wait times, resource developers may also submit interconnection requests to maintain a place in line, to be able to turn around projects more rapidly if they can find a buyer.”

Those “speculative projects” have contributed to the larger queues now; some of DOE’s recommended improvements are aimed at limiting them going forward.

“We really believe it’s possible to get to better processes and doing that by improving the data … [and] having more information available to developers about where to site projects,” Jones-Albertus said.

Order 2023’s requirement for transmission planners to offer heat maps should cut back on the use of speculative projects to find cheap spots to plug into the grid, she added. DOE is also focused on bringing new information technology solutions on the queue, upskilling the workforce and tackling the ever-thorny issue of cost allocation.

“By addressing all of these, I believe we can get to much better interconnection processes, where we can get timelines that are down from averages of five years to less than 18 months,” Jones-Albertus said. “We can have higher completion rates, lower cost uncertainty and better system reliability.”

CAISO and MISO have both proposed strategies that would “ration” interconnection capacity to reduce their queue volumes. CAISO does it by prioritizing interconnection in zones that have available capacity, or resource-rich areas, while MISO would limit interconnection requests to its annual peak demand.

“Administrative rationing may be a short-term strategy for temporarily clearing backlogs, but it would likely be inconsistent with open access and competition policies and may thus be more of a short-term, emergency solution rather than a longer-term one,” the report says.

Another reason to speed up the queues is that demand has started to grow for the first time in a decade in many regions. That is expected to increase with electrification efforts, while many traditional generators are retiring.

“Certainly having shorter queue timelines, higher completion rates [and] lower costs will help that additional capacity be built … in a predictable manner so that grid operators can count on when that generation capacity is going to be there for resource adequacy,” Jones-Albertus said. “I think it is a challenge now that it is hard to predict when some of these plants will come online, in part because of the lengthy interconnection process timelines.”

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Vineyard Wind 1 on Track to Produce Power by Year’s End

Vineyard Wind 1 is on track to start generating power by the end of this year and achieve commercial operation by the end of 2024, Avangrid told investors in its third-quarter earnings call for 2023.

The 806-MW project’s construction is about 60% complete, with the offshore substation, 15 array cables, 25 monopiles and two turbines already installed, Avangrid CEO Pedro Azagra said.

Vineyard Wind is competing with New York’s South Fork Wind to be the first utility-scale offshore wind project to begin operations in the U.S.

“The lessons learned will be invaluable as we continue developing this project and others in the U.S,” Azagra said.

On Oct. 25, the company announced a $1.2 billion tax equity transaction for the Vineyard Wind 1 project with J.P. Morgan Chase, Bank of America and Wells Fargo. The financing uses tax credits from the Inflation Reduction Act (IRA), and marks “the largest single asset tax equity financing and the first for a commercial scale offshore wind project,” the company said.

“The IRA is bringing tremendous opportunities to the industry,” Azagra said, adding that the act is essential to the company’s plan to repower up to 4.6 GW of renewable assets by 2032, with the goal of increasing production by about 30%. “Repowering does not require full development and permitting, allowing the projects to reach completion much faster.”

Azagra also touted the successful termination of the Commonwealth Wind and Park City Wind power purchase agreements.

“By terminating these contracts, we have improved the economics of our offshore wind projects, and avoided billions in write-offs at minimum costs,” he said. “Now we have two highly valuable leases ready to leverage, and experience as part of Iberdrola Group developing, financing and constructing offshore projects like Vineyard Wind 1.”

“We’re not going to put in danger the financial health of the company,” Azagra said. “We’re not going to be in the race of growth for megawatts, we’re in the race of making money.”

Azagra also addressed what he called the “challenging regulatory environment in Connecticut.” Earlier this year, the state’s Public Utilities Regulatory Authority (PURA) denied a request from Avangrid subsidiary United Illuminating for an 8% rate increase over three years. In response, United Illuminating has filed an appeal with the New Britain Superior Court.

PURA’s decision would prevent the company from recovering “reasonably incurred costs, and [earning] a fair return on enough capital,” Azagra said. He added that this would “hinder [Avangrid’s] ability to invest in the grid to improve the storm resiliency and reliability and would slow down the state’s progress on its clean energy goals.”

The Energy and Policy Institute (EPI), a utility watchdog group, has alleged the company was behind a pressure campaign that coordinated employees and charitable organizations to oppose a draft version of PURA’s decision. EPI found the comments contained similar or identical language that it traced back to a United Illuminating lobbyist.

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Solicitor General: SCOTUS Should Reject Texas ROFR Appeal

Solicitor General Elizabeth Prelogar has urged the Supreme Court to dismiss a petition to review a 2022 appeals court ruling that found Texas’ right-of-first-refusal law violates the Constitution’s dormant Commerce Clause.

Prelogar filed a brief with the high court Oct. 23 asking it to deny Texas’ request for a writ of certiorari, a formal request to review a lower court’s judgment against the petitioning party (No. 22-601).

At issue is the 5th Circuit Court of Appeals’ ruling last year that the Texas law (Senate Bill 1938) giving incumbent transmission companies the right of first refusal (ROFR) to build new power lines within the state is unconstitutional. Texas, with former Public Utility Commission Chair Peter Lake as the lead petitioner, requested the review in December. (See Texas Petitions SCOTUS to Review ROFR Ruling.)

“The court of appeals correctly determined that SB 1938 discriminates against interstate commerce by prohibiting any company without an existing in-state presence from competing in the market for the construction and operation of electric transmission facilities that would be part of the interstate transmission grid,” Prelogar said in her filing.

She said the Texas law “discriminates on its face against interstate commerce” and that the state’s “contrary arguments lack merit.” Prelogar also noted that FERC Order 2023, which would overhaul transmission planning, would render moot a review of the 5th Circuit decision.

“If FERC were to adopt the proposed rule (or some alternative) while this case was pending before the court, that development might require supplemental briefing or otherwise complicate this court’s consideration,” she wrote.

Consumer advocacy group Electricity Transmission Competition Coalition welcomed the solicitor general’s filing.

“ROFR laws are not just unaffordable, they are unconstitutional,” the organization’s chair, Paul Cicio, said in an emailed statement. “Texas’ ROFR law was unconstitutional from the outset, and this was affirmed by the [appeals court]. Electricity transmission competition benefits consumers in the form of lower electricity prices; the filing of the United States is a welcome addition to the cause of lower electricity prices.”

Chris Reeder, a partner with Husch Blackwell in Austin, told RTO Insider that the Supreme Court’s request for the solicitor general to provide its opinion “indicates the court views the legal issues as having significant constitutional implications on which the government should weigh in.”

The opinion also means briefing on Texas’ request has been completed, he said. The justices will vote on whether to grant review and, if they do, the case will be set for argument and additional briefing requested.

“If it declines review, then the Supreme Court proceeding is over as a practical matter,” Reeder said. “The 5th Circuit’s ruling would become the ‘law of the case.’”

Texas could seek a rehearing of the denial, but those rehearing requests are almost never granted, Reeder said.

The appeals court’s order remands the proceeding back to the district court. (See 5th Circuit Finds in Favor of NextEra’s ROFR Appeal.)

NextEra Energy brought an appeal to the 5th Circuit after the U.S. District Court for Western Texas rejected the utility’s challenge of SB 1938. The district court ruled the legislation didn’t discriminate against interstate commerce because it “regulates only the construction and operation of transmission lines and facilities within Texas.”

At the time, NextEra had been awarded a pair of competitive projects by MISO and SPP in Texas’ non-ERCOT regions. Both projects have since been cancelled, but NextEra has said it intends to pursue other projects in Texas.