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December 5, 2024

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Mass. Energy Leaders Talk Barriers to Innovation at NECA Conference

BOSTON — Massachusetts lawmakers and industry members must double down on efforts to rapidly scale up new renewable technologies to meet the needs of the energy transition, speakers at the Northeast Energy and Commerce Association’s Energy Innovation Forum on Nov. 14 emphasized. 

“If there is one aspect of this work that truly worries me, it is not innovation; … it is deployment,” said Ben Downing, vice president of public affairs for The Engine Accelerator, a public benefit corporation spun out of the Massachusetts Institute of Technology in 2016. 

Downing spoke optimistically about the “cavalry of new solutions coming in waves” to help the clean energy transition, including nuclear fusion, deep geothermal energy, long-duration energy storage and superconducting transmission lines. 

But even with solutions on the horizon, “I worry about our ability to deploy with the combination of speed and scale that is required,” Downing said. “Getting those concepts to commercialization is on all of us.” 

In the power sector, utilities and regulators will need to evolve their approach to new technologies, said Sarah Cullinan, senior director of the Net Zero Grid Program at the Massachusetts Clean Energy Center. 

“Our utilities are very open to innovation, but the landscape and the process make it really difficult,” she said. “The scale aspect for utilities is entirely determined within the Department of Public Utilities, and it’s ultimately ratepayers that would fund the full-scale deployment of any new technology.” 

Utilities have “very little room for error” in deploying new technologies, Cullinan said, adding that “the question is how do you test something on that system in a way that gives you the data and information that you need without compromising reliability.” 

Cullinan specifically cited grid-enhancing technologies as a key area of potential technological improvement on the distribution side, especially as they have gained traction in transmission applications. 

“I’m hoping that some of that can be scaled to distribution,” Cullinan said. 

Downing expressed hope that the changes to clean energy siting and permitting recently passed by the Massachusetts legislature would help expedite the deployment of new resources. (See Compromise Climate Bill Finally Approved by Mass. Legislature.) 

However, Jenny Liu of Jupiter Power stressed that interconnection backlogs still pose a major hurdle to development in the region. 

“It’s just taking too long to get through the process, and therefore, we can’t deploy [renewables] to solve the capacity deficiency pretty much everywhere,” Liu said. “This is a big problem; only if we get it solved will there be a big breakthrough in the renewable energy industry.” (See related story, Stakeholders Push for More Interconnection Rule Changes at FERC.) 

While FERC Order 2023 requires major changes to interconnection procedures across the country, the commission has yet to rule on RTO compliance filings, creating significant uncertainty for New England developers. (See New England Clean Energy Developers Struggle with Order 2023 Uncertainty.) 

On the consumer-facing side, the industry must work to educate and prepare customers for the rollout of advanced metering infrastructure (AMI) and time-varying rates, Cullinan said. Eversource Energy, one of the two major electric utility companies in Massachusetts, has said it will start deploying advanced meters in the state in 2025. 

Vinit Nijhawan, managing director of MassVentures, said the state must find a way to move faster to implement time-varying rates. 

“It’s not about the technology,” Nijhawan said. “We’ve been talking about time-of-day rates for as long as I’ve been here, which is 37 years. 

“We’ve got to move faster than we’re moving. … We need imagination.” 

At the same time, Nijhawan praised the state’s overall climate of fostering innovation.  

“Massachusetts is the most amazing place for new ideas to flourish. We don’t need to change much; I think it’s all there,” he said.

Regarding the potential effects of a second Trump administration on the state’s clean energy transition, Cullinan said there is “a lot of uncertainty” about the availability of federal funding going forward. 

“Across the entire state that question is popping up. There really is an effort to figure out what is at risk,” she said. “Luckily, we live in a state where there is a lot of funding and support still.” 

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‘Holistic’ Approach Needed for Tx Planning, NARUC Panelists Say

ANAHEIM, Calif. — To ensure a cost-effective energy transition, stakeholders must approach transmission planning holistically and avoid piecemeal investments, panelists argued during the National Association of Regulatory Utility Commissioners’ Annual Meeting from Nov. 10 to 13.

The total investments needed to meet the expected load growth “could easily exceed what individual market participants can finance or recover,” said Johannes Pfeifenberger, principal at The Brattle Group.

“Effective outcomes really require a multifaceted approach,” Pfeifenberger said. “On the transmission side, that means more comprehensive, holistic, proactive planning. We’re spending a lot on transmission incrementally, but we really need to plan that to achieve cost-effective outcomes with the least regrets.”

Some potential approaches Pfeifenberger highlighted include planning to avoid under- or overbuilding, loading order, cost control incentives and moving away from a compartmentalized transmission planning process.

Maine Public Utilities Commissioner Patrick Scully said the New England region has invested heavily in transmission, with annual transmission system charges rising from $869 million in 2008 to $3.3 billion in 2025.

However, the region failed to implement efficient public policies to go with the transmission, which has resulted in lost opportunities to bring more low-cost generation to fruition, Scully said.

The New England states decided to join forces and collaborate on the future of the grid, Scully said.

As a result of this collaboration, ISO-NE issued a report last year, which found that peak loads in New England would double from 28 GW to 57 GW by 2050. The transmission upgrades needed to meet this load could cumulatively cost between $22 billion and $26 billion, according to the study. (See ISO-NE Prices Transmission Upgrades Needed by 2050: up to $26B.)

“And at the request of the states, ISO agreed to establish a tariff process by which the states collectively can request that ISO issue [a Request for Proposals] to solicit competitive transmission project proposals that address the needs that have been identified in that 2050 study,” Scully said. FERC approved the changes in July.

The price tag to meet future transmission needs coming from heavy loads like data centers and chip manufacturing will be “tremendous,” said Karen Onaran, CEO of the Electricity Consumers Resource Council.

Onaran agreed with Pfeifenberger that transmission planning has so far been “very siloed,” which has resulted in limited generation options that could potentially drive down costs.

“We are encouraged by this recognition that we need more transmission,” Onaran said. “We absolutely see the big price tag. Let’s make sure that we are all coming together to figure out the solution.”

California has seen increased opportunities for interregional transmission, according to Neil Millar, vice president of transmission planning and infrastructure development at CAISO. Working across a broader footprint will enable the region to take advantage of the region’s diverse resources more efficiently, Millar added.

“Clearly, the better interregional coordination would be to the betterment of all,” Millar said.

MISO Vice President of System and Resource Planning Aubrey Johnson said there has to be a regulatory framework in place to encourage cost-effective transmission planning.

“Ultimately, if we want to see more transmission planning and more proactive stuff, it actually needs to start in a regulatory framework where people are encouraged, incentivized and challenged up to the table to do those things,” Johnson said.

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Not Waiting for Trump, DOE Sends More IRA, IIJA Funds to Red States

With just two months until President Joe Biden’s administration ends, the U.S. Department of Energy continues to fund projects with federal dollars from the Inflation Reduction Act and Infrastructure Investment and Jobs Act. President-elect Donald Trump may find it hard to claw back the money. 

Like much of the IRA funding, the latest DOE awards are going to states and districts that voted for Trump, and to projects with a lot of local and national media appeal. Pulling the plug on popular projects could create a virtual minefield for the president-elect and his DOE nominee, Chris Wright, CEO of a major fracking firm, Liberty Energy. 

For example, on Nov. 13, DOE’s Office of Clean Energy Demonstrations (OCED) announced it had finalized a grant of $5 million in IRA funds that will go to the Dallas County, Ala., Board of Education for energy efficiency upgrades at nine schools, many of which were built in the 1950s, according to a project fact sheet. Ancient HVAC systems will be upgraded, and modern building controls installed.  

Three schools also will get rooftop solar systems. The project is expected to take four years, and the money saved on the district’s energy bills could be reinvested in facilities and programs for students. 

In Nevada, OCED signed a contract for a $14.6 million award to Nevada Gold Mines LLC to begin the first phase of a project to install 100 MW of solar and close to 250 MWh of energy storage to help decarbonize the company’s operations at a processing plant and a working mine. The total federal award for the project is $95 million. 

The project is one of five DOE selected for funding in March under its Clean Energy Demonstration Program on Current and Former Mine Land (CEML) with up to $475 million from the IIJA. Four of the five projects — in Nevada, Kentucky, Pennsylvania and West Virginia — have finalized contracts with DOE. Trump won all four states. 

The fifth project, using geothermal energy and storage to increase production at a copper mine in Arizona, is in negotiations for its $80 million award, according to the CEML webpage. 

These and other funding announcements made since Trump’s victory in the Nov. 5 election could present an obstacle to the president-elect’s plans for rolling back provisions and funding in the IRA, ostensibly to pay for extending his 2017 tax cuts. 

Trump-proofing the IRA

During his visit to the Amazon rainforest Nov. 17, President Joe Biden defended the IRA and its clean energy programs against the rollbacks Trump likely is planning. 

“It’s true some may seek to deny or delay the clean energy revolution that’s underway in America,” Biden said. “But nobody — nobody can reverse it — nobody. Not when so many people, regardless of party or politics, are enjoying its benefits.” 

Christian Roselund, a senior policy analyst at Clean Energy Associates, also is doubtful of a major IRA repeal — in particular, the clean energy investment and production tax credits ― saying the current situation is “complex and nuanced.” 

“A main reason is that Republicans currently hold a six-seat majority in the U.S. House and are unlikely to get more than a seven-seat majority when the final five races are counted,” Roselund wrote in a LinkedIn post. “Meanwhile, of the 18 Republican members of the U.S. House who sent a letter to Speaker [Mike] Johnson [R-La.] opposing ITC/PTC repeal, 13 won reelection, and one race is still undecided.” 

Still another, Rep. John Curtis (R-Utah), won a Senate seat, and “Senate Republicans may be even more hesitant to make sweeping changes that affect projects underway and business certainty,” Roselund said. 

The best way to Trump-proof the IRA funds is to get them out the door as quickly as possible, according to advocates such as Adam Deveny, former director of energy policy for Senate Democratic Leader Chuck Schumer (D-N.Y.). 

In recent months, the pace of DOE award announcements has accelerated, Deveny, founder of Climate Vision, a policy advisory group, told Canary Media. “Getting that money out the door is critical, because any unspent money is at risk of not ever getting spent,” he said. 

The latest money going out the door, on Nov. 18, is close to $15 million for nine research and development projects that will combine hydropower with other renewables and storage “to increase hydropower’s ability to respond to changing demand on the electric grid,” according to the DOE announcement.  

Hydro provides 6% of U.S. power and 27% of the nation’s renewable energy, according to DOE. It also can ramp up or down quickly to ensure flexibility for grid reliability, possibly making it another no-go for potential rollbacks.  

DRG Technical Solutions of Memphis, Tenn., was selected to receive more than $3 million for a project meant to demonstrate the use of hydropower to produce clean hydrogen at a hydro facility in Colorado.  

“That hydrogen can then be stored to provide electricity to the grid when needed, and power or fuel for electric and hydrogen vehicles,” the announcement says. 

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EIA: Distribution, Transmission Led to Higher Utility Capital Spending

Data collected over the past 20 years shows an increase of 12% in utility capital spending, rising from $287 billion in 2003 to $320 billion in 2023. Spending on generation has declined, while spending on transmission and especially distribution has surged and more than made up for declines in cheap generation, according to data from the U.S. Energy Information Administration.

The sector spends 24% less on producing electricity than it did in 2003 due to lower fuel costs and the closure of older power plants that were costly to maintain. But spending on generation jumped 23%, or $4.7 billion, from 2022 to 2023 due to one project coming online — Southern Co.’s Vogtle nuclear plant expansion, which started commercial operation in April.

Spending on transmission nearly tripled over the two decades, hitting $27.7 billion in 2023, with some of the increase coming from transmission station equipment ($1 billion), poles ($1.1 billion) and computer software ($400 million) needed for operating regional transmission markets.

The distribution system was the main driver for overall increases in the utility sector as capital investments in that level of infrastructure were up by $31.4 billion, or 160%.

More than 20% of the increase in distribution spending happened between 2022 and 2023, when utilities spent $6.5 billion more for a total of $50.9 billion to replace and upgrade aging equipment and install new distribution infrastructure to help neighborhood grids withstand extreme weather and manage renewable intermittency.

The biggest categories for distribution system spending were on overhead lines, poles and towers as utilities spent $17.4 billion on overheard infrastructure in 2023. That marks an 11% increase from a year earlier, and 220% more than in 2003.

Spending on underground lines also ramped up significantly over the past 20 years to reach $11.8 billion in 2023. It was for new developments, as well as undergrounding old lines to mitigate power outages from storms and wildfires or improve neighborhood appearance.

Supply chain and manufacturing issues led to utilities spending 23% more for a total of $7.5 billion in 2023 on “line transformers,” which drop voltage to household levels.

Utilities spent $6.1 billion on distribution substations in 2023, which marks a 184% increase from 2003 and 15% from 2022. More substations allow utilities to better withstand extreme weather, manage renewable intermittency and allow for greater voltage control during emergencies.

Another major increase was spending on infrastructure located on or near customers’ property, which includes meters, leased property and rooftop solar. Utilities spent $5.1 billion on that in 2023, up 84% from 2003 and up 25% from 2022.

Although energy storage remains a relatively small portion of the total budget for distribution infrastructure, spending increased from $97 million in 2022 to $723 million in 2023. Energy storage at the substation or customer site enhances power quality and provides backup power in areas where lines and transformers cannot handle additional capacity, especially as more intermittent renewable resources come online.

The “other” spending category increased by 30% or $8.6 billion over the 20 years. It includes intangible plant expenses like licenses and general plant expenses like office space and storage buildings.

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Stakeholders Push for More Interconnection Rule Changes at FERC

Stakeholders are split on whether FERC should adopt more changes to its generator interconnection rules or focus on implementing Order 2023 while letting specific regions go further on their own (AD24-9). 

After issuing the order in July 2023 and working on grid operators’ compliance filings for nearly a year, FERC held a technical conference in September looking into how to further speed up processing the country’s interconnection queues, which according to Lawrence Berkeley National Laboratory include about 11,600 projects totaling 2,600 GW. (See FERC Workshop Examines How to Speed up Interconnection Queues.)  

In post-conference comments, submitted last week ahead of a Nov. 14 deadline, a group of “public interest organizations” — including the Natural Resources Defense Council, Sierra Club, Southern Environmental Law Center and Sustainable FERC Project — urged FERC to ensure that Order 2023 is fully implemented and to focus on future reforms that complement it. 

“Transmission providers’ obstinate, superficial compliance filings and continued litigation against Order No. 2023 underscore the need for the commission to only entertain proposals that would build on — rather than detract from — the reforms of Order No. 2023,” they said. 

They argued FERC should make improvements to surplus interconnection service and energy resource interconnection service (ERIS), which allow new resources to connect to the grid with fewer guarantees for delivery when the system is constrained. The services are not evenly implemented in organized markets, they said, and in some cases, ERIS interconnection costs can exceed network resource interconnection service (NRIS), which is intended to guarantee firmer connectivity. 

“The commission should reject proposals that run counter to open access by allowing new interconnection requests to queue jump: passing on additional uncertainty, delays and unfavorable cost allocations to interconnection customers that have already struggled to maintain viability in extensive queue backlogs and now rely on the Order No. 2023 cluster process,” the groups said. 

Advanced Energy United, the American Clean Power Association and the Solar Energy Industries Association did not warn FERC away from queue jumping entirely, but they cautioned against making that change permanent. Such Band-Aid approaches should be sunset by the end of the decade, they argued. 

“Queue caps and prioritization processes may make models solvable but are likely to prove challenging to design and implement without undermining open-access principles,” the clean energy trade groups said. “Further, inequitable and inconsistent stopgap measures may limit development and ultimately harm reliability. The commission must not lose track of the fact that open access is good for consumers; it reduces costs and drives innovation. This is equally, if not more, true in times of rapid change — like today — as in times of relative stability.” 

The high number of projects is logical and necessary to ensure healthy competition to serve new load, but high queue volumes were cited by other parties as the main problem that needed to be solved with caps and prioritization, the groups said. High project volumes are an issue only if they are a result of a faulty process. 

“A Band-Aid can be a stopgap solution — but if surgery is what’s needed, it should be prepped for, scheduled and performed as soon as possible, even if the Band-Aid is helping to temporarily address symptoms in the meantime,” they said. 

Region-specific Proposals

The Edison Electric Institute said FERC should focus on implementing Order 2023 but also let regions that propose revisions to their own processes to move forward with those. 

“Given the reliability concerns in some regions, EEI believes that the commission should be open to regions proposing reasonable mechanisms to prioritize the interconnection of certain resources to ensure continued reliable energy supplies,” the investor-owned utility trade group said. “Finally, EEI recommends targeted reforms rather than generic action to further integrate the transmission and interconnection processes.” 

New generic, nationally applicable processes risk disrupting ongoing compliance processes, consume significant time and financial resources, and could delay the goals advanced by Order 2023, EEI said. 

American Electric Power called on FERC to ensure ISOs and RTOs have effective, nondiscriminatory processes in place to prioritize or fast track interconnection requests for replacing retiring generation and new capacity needed to meet reliability or resource adequacy requirements. Shovel-ready projects that support reliability, need only existing transmission to connect and support state policies should be prioritized. 

Constellation Energy said FERC should adopt a new method that speeds up the queue, noting that PJM has talked about 2030 as being the year when reliability will come to a head. 

“Accelerating the pace of new entry of reliable resources is critical to solving this problem,” Constellation said. “To do so, Constellation and PJM have proposed stopgap frameworks that would prioritize shovel-ready interconnection requests that address demonstrated resource adequacy or reliability needs.” 

This “Expedited Reliability Process” would have the RTO establish objective criteria to determine whether a project is likely to satisfy the region’s reliability needs and whether it can be constructed on time to meet them. The proposal should be filed with FERC in December, the firm said. 

MISO told FERC it is facing similar issues with narrowing reserve margins and a slow queue, which it has been working to improve through automation and tracking. Part of the problem in MISO is that 58 GW of generation have signed a generator interconnection agreement and have yet to come online. 

“MISO will be launching an interactive tool on our website to understand the fuel type, location and reasons these generators are delayed in coming online,” it told FERC. “Additionally, MISO is pursuing a new study process known as the Expedited Resource Adequacy Study that will allow MISO to study interconnection requests necessary for resource adequacy in a matter of months.” 

The RTO did a survey of those projects, of which 26 GW have announced they expect delays or just not been energized on time. An additional 15 GW responded, with 40% saying the delay was from transmission issues, 18% from regulatory/permitting issues and 11% from difficulties securing power purchase agreements. Equipment supply chain delays dating back to the COVID-19 pandemic are also often a factor. 

Order 2023 is an improvement, but its reforms were narrow, and FERC should continue to work on interconnection issues, argued the Electricity Customer Alliance, the Electricity Consumers Resource Council and R Street Institute. FERC could do another rulemaking or let regional changes bloom, they suggested. 

But they also argued the commission should announce an ongoing forum on the best generator interconnection processes that is held at least annually and articulate its policy objectives by issuing a statement. 

“The salience of GI reform, beyond Order 2023, continues to grow,” the consumer groups said. “Unnecessarily slow and costly GI process has been a growing economic burden on consumers for years. Grid upgrade costs for generators to interconnect have grown by multiples in many regions, and most of these costs are passed through to consumers. Interconnection wait times have increased from less than two years to a median of five years last year, with some regions now explicitly delaying or pausing the processing of new GI requests. GI delays now present a material reliability risk to consumers, especially as expectations for load growth have increased.” 

A New Type of Monitor?

The American Council on Renewable Energy suggested that FERC require regions with delayed queues to set up independent interconnection monitors to evaluate study practices, assumptions and outcomes, and then recommend improvements. 

Grid Strategies published a report this month advocating for a similar concept that would require TOs to hire independent construction monitors “to ensure compliance with timelines, budgets and projects specifications, providing transparent and unbiased evaluation throughout the construction phase.” 

“Available data — and data are very scarce — suggests that transmission owners’ budget priorities and construction management practices may play a substantial role in these construction phase delays,” the report says. “With perhaps half of all projects with interconnection agreements being significantly stalled or facing substantial cost overruns during the construction phase, this is a serious and widespread issue.” 

Construction monitors would get access to often sensitive data and be an independent set of eyes that could identify issues causing delays and make expert recommendations on how to speed up construction and equipment procurement, the report says. 

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Trump Stokes Concern for Clean Energy, but also Hope for Opportunities

ANAHEIM, Calif. — Clean energy experts at this year’s Annual Meeting of the National Association of Regulatory Utility Commissioners last week expressed confidence in the U.S.’ progress toward decarbonizing the grid.  

But just over a week after the U.S. re-elected former President Donald Trump, some also questioned how his plans to disrupt Inflation Reduction Act funding could impact the momentum of the energy transition. 

“All the progress that’s been made in the last four years … there’s absolutely a concern that it [IRA funds] will get rescinded, paused or subject to infinite delays that cause them to be ineffective at transforming not just the economy, but the grid itself,” Sara Baldwin, senior director of electrification at Energy Innovation, told RTO Insider. 

The IRA unlocked billions in funds and incentives for clean energy, but Trump has signaled an intent to roll back the historic climate legislation. (See Trump 2.0: Rolling Back Regulations, IRA Funding.) But because the U.S. doesn’t have a federal mandate for clean energy, Baldwin is counting on state policy and demand to maintain the flow of new clean generation onto the grid. 

Speaking on a NARUC panel Nov. 12, Priya Barua, senior director of market policy and innovation at the Clean Energy Buyers Association, added that a “shift in the corporate mindset” has led to an exponential growth of companies that are voluntarily working toward “science-based targets” and “net-zero goals,” further stoking confidence in the buildout of clean energy. 

“We’re in a really interesting and exciting juncture where there’s this opportunity to empower large energy customers, many of whom are driving some of this energy demand, to be a part of the solution at a system level,” Barua said. 

‘The Trifecta’

But continuing to bring new clean energy online will require balancing reliability, affordability and decarbonization — what Baldwin refers to as “the trifecta” — with cost. 

About 40% of the U.S. grid consists of clean generation, but cost and commercialization gaps remain. Natural gas generation will play an “absolutely critical role” in maintaining reliability as the grid moves beyond 40%, Baldwin said, but in the meantime, developers and policymakers should focus on deploying wind, solar, batteries and demand-side resources, rather than focusing just on firm power. 

Doug Vine, director of energy analysis at the Center for Climate and Energy Solutions, also emphasized the need for firming resources to complement solar and batteries, though the proportion is still “an open question.” 

Baldwin also identified the need to build a bridge between supply-side and demand-side planning and better understand the connection between the two. 

‘Tools in the Toolbox’

Panelists were united in the belief that clean energy presents an economic opportunity that the incoming administration would be remiss not to take advantage of.  

Vine emphasized that clean energy technologies benefit both conservative and liberal states, support workforce development, and bolster energy independence in the U.S. 

“It’s something that he [Trump] should support,” Vine said. “And hopefully he will.” 

Continuing to enable a more diverse portfolio of reliable, affordable electricity, while also supporting economic development and national security, will allow the U.S. to “leverage the full suite of tools in the toolbox,” Barua said, and fellow panelists echoed the sentiment. 

“The federal incentive was a tool in the toolbox to make [clean energy] cost effective and affordable,” Baldwin told RTO Insider. “If we’re smart as a country, we will stay the course and allow these incentives to play out.” 

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PJM Planning VP Announces Retirement

PJM has announced that Paul McGlynn, vice president of planning, will retire in 2025 and his role will be filled by Jason Connell, executive director of transmission and resource adequacy planning. 

McGlynn is set to continue serving with PJM through March 31, 2025, with Connell taking over as planning vice president on Jan. 1, 2025, to allow for a transitionary period. Connell has held several positions in PJM’s system planning department over his 12 years with the RTO, which came after a career at PECO doing transmission and substation engineering. 

“This is an incredibly dynamic time to be planning for the evolution of this industry,” Connell said in a PJM announcement. “I am excited to support and continue PJM’s important work to design and manage the grid of the future while preserving reliability.” 

Jason Connell, PJM | © RTO Insider LLC

Aftab Khan, executive vice president for operations, planning and security, said Connell “brings strong planning experience and leadership capabilities to ensure a smooth transition and to manage the evolving needs of the PJM grid.” He also thanked McGlynn for 17 years of contributions to PJM’s operations and planning departments. 

McGlynn was named vice president of planning in November 2023 following the retirement of Ken Seiler. He then was managing PJM’s real-time dispatch operations and assisted in developing near-term reliability studies, load forecasting, and the coordination of generation and transmission outages. He previously served as PJM’s senior director of system planning, which saw him administering the Regional Transmission Expansion Plan (RTEP) process. (See Retirements and New Faces on PJM Executive Team.) 

“It has been my privilege to have worked in this industry,” McGlynn said. “I am proud to have been part of such an outstanding team doing extremely important work for the energy industry, and I know PJM will continue to forge ahead with efficiency, innovation and technologically sound solutions to fulfill our critical mission of reliability.” 

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Avangrid Sues NextEra over ‘Scorched-earth Scheme’ to Stop NECEC

In an antitrust lawsuit filed in federal court Nov. 12, Avangrid accused NextEra Energy of conducting an “exclusionary and anticompetitive scheme” to stop a major transmission project connecting New England to Quebec, costing customers millions of dollars in elevated electric rates and delaying the region’s clean energy transition (3:24-cv-30141).

“NextEra has committed anticompetitive, unfair and deceptive business practices to foreclose competition for the supply of wholesale electricity on the ISO New England marketplaces,” Avangrid told the U.S. District Court for Massachusetts. “NextEra has reaped hundreds of millions of dollars from these illegal practices.”

The 1,200-MW New England Clean Energy Connect (NECEC) project was selected by Massachusetts in 2018 in a clean energy solicitation but faced a series of regulatory, legal and political obstacles delaying its development. Construction on the project resumed in 2023 after a two-year pause. (See Avangrid Details Progress on NECEC Tx Line.)

While Avangrid initially expected the project to come online in December 2022, its “most optimistic estimated in-service date” now is January 2026, the company wrote.

The delay comes with a hefty price tag to ratepayers; in October, Massachusetts’ electric utilities submitted a settlement agreement that would result in a $521 million cost increase in 2017 dollars, equal to about $670 million today (DPU 24-160).

Carbon emissions in the state also likely increased from the delay; utilities have estimated NECEC would reduce carbon emissions by about 1.93 million metric tons annually, equivalent to nearly 3% of the state’s emissions in 2021.

In its suit, Avangrid estimated damages of at least $350 million and demanded a jury trial. The company seeks an award of three times the damages, as well as interest, legal costs and an injunction “barring NextEra from continuing to undertake its anticompetitive scheme.”

Avangrid describes NextEra’s opposition to the project as a “a three-pronged scheme to delay or stop NECEC,” comprising “objectively baseless attacks” on its permitting applications, covert political funding to stop the project and a refusal to upgrade a circuit breaker at its Seabrook nuclear plant to accommodate the line.

“Through this premeditated and interwoven scheme, NextEra has and is continuing to exclude from the New England grid the clean and low-cost electricity NECEC would bring,” Avangrid wrote. “NextEra’s scheme has harmed competition, damaged Avangrid and consumers and held Massachusetts’ clean energy transition hostage.”

Along with the Seabrook plant, NextEra owns two oil generators in Maine, a gas plant in Massachusetts and several smaller clean energy resources throughout the region. Avangrid argued that NextEra’s incumbent generators have made “inflated profits” from the higher energy prices caused by NECEC’s delay.

Avangrid wrote that NextEra worked to slow NECEC’s permitting approval through “at least 10 serial sham petitions, which no reasonable litigant could realistically expect to succeed on the merits.”

Along with regulatory challenges, NextEra also helped fund two ballot referendum efforts in Maine to stop the project. The first referendum was deemed unconstitutional by the Maine Supreme Judicial Court, which also invalidated a second successful ballot question opposing the line.

NextEra spent about $20 million to fund the second ballot question. In 2023, two opposition groups associated with NextEra-funded efforts to stop the project were fined a cumulative $210,000 for campaign finance violations, including a $150,000 contribution to the Maine Democratic Party made in the name of a pop-up company called Alpine Initiatives.

According to the Energy and Policy Institute, a utility watchdog nonprofit, NextEra has also funded a group working to oppose offshore wind in Maine.

Avangrid also alleges NextEra’s efforts to avoid installing a circuit breaker at its Seabrook plant are part of the company’s overall opposition strategy.

ISO-NE determined in its interconnection analysis for NECEC that the power imported on the line would overload Seabrook’s circuit breaker. FERC ruled in early 2023 that NextEra must replace the circuit breaker, with Avangrid covering the direct costs of the upgrade (EL21-3, EL21-6). (See FERC Resolves NextEra-Avangrid Dispute over Seabrook Circuit Breaker.)

NextEra then appealed the ruling to the D.C. Circuit Court of Appeals, arguing FERC does not have jurisdiction to require the company to upgrade the circuit breaker. The D.C. Circuit affirmed FERC’s ruling in October. (See DC Circuit Affirms FERC Ruling on Seabrook Circuit Breaker Dispute.)

Avangrid argued NextEra “purposefully allowed the Seabrook breaker to creep up to almost 100% capacity so that any substantial new power source seeking to join the New England grid would be blocked unless NextEra agreed to cooperate.”

“NextEra knew the Seabrook breaker was at near-capacity for a decade, and that operating under such conditions created enormous risks associated with a potential fault, should the breaker be over-dutied,” Avangrid wrote, emphasizing that NextEra risked “human life and a nuclear plant disaster.”

Avangrid also alleged top NextEra executives “demanded an improper quid pro quo,” offering to drop its opposition to the line if Avangrid would purchase power from the Seabrook plant at “substantially above-market rates.”

“NextEra’s naked quid pro quo offer was simply a ploy to force Avangrid to pay NextEra the money it would lose when NECEC would enter the market,” Avangrid wrote.

All of these actions amount to violations of the Sherman Antitrust Act of 1890, the Massachusetts Antitrust Act and the Massachusetts Unfair Trade Practice Act, Avangrid alleged.

“Both on its own and in conspiracy with others, NextEra engaged in a multifaceted, scorched-earth scheme to delay and even try to block NECEC altogether. NextEra’s actions have delayed Avangrid from offering clean, lower cost electricity through ISO New England’s wholesale electricity marketplaces. …

“This conduct included overt acts that constitute monopolization, attempted monopolization, civil conspiracy, intentional interference with contract, sham petitioning, dark-money deception, and false and misleading statements.”

NextEra did not respond to repeated requests for comment in time for publication. The Massachusetts Attorney General’s Office also did not respond.

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NY Gauging Industry Interest in Advanced Nuclear

New York is dipping another toe in the water on nuclear power, trying to determine market interest in developing advanced generation technologies in the state. 

The New York State Energy Research and Development Authority issued a request for information Nov. 15.  

The move comes two months after NYSERDA issued a draft blueprint for consideration of advanced nuclear technologies at a summit convened to discuss the state’s future energy economy. All forms of clean energy were on the agenda, but nuclear had a more prominent role in the discussion. (See NY Takes a Closer Look at Advanced Nuclear.) 

Nuclear historically has been very expensive and controversial, but it is increasingly attractive to a growing number of policymakers, as next-generation technology is touted as safer, faster and cheaper to build. 

So far it is none of those things, but the potential is exciting, given the imperative to generate more electricity with less emissions.

New York officials have maintained a neutral tone on the prospect of expanding its presence in the Democratic-controlled state, but they, too, appear interested. The state has fallen behind on the ambitious decarbonization schedule lawmakers set, as utility-scale wind and solar projects see delays, cancellations and soaring prices. 

Even if New York exceeded its goals for solar and wind, nuclear and its near-100% capacity factor could provide an important backstop for intermittent renewables. 

There has been bipartisan federal support for developing next-generation nuclear technology, and New York is laying groundwork to make decisions once it is commercially viable. 

In a Nov. 15 news release, NYSERDA President Doreen Harris explained the reasons, again without specifically endorsing more nuclear generation within state borders: “As local, national and international companies pursue nuclear energy for their on-site energy needs and the federal government signals interest in investing in this resource, we recognize that now is the time to position New York to fully engage this new sector that can drive significant economic development.” 

Two days earlier, during a fireside chat with former U.S. Secretary of State Hillary Clinton, N.Y. Gov. Kathy Hochul (D) also did not explicitly call for more atoms to be split in the Empire State. 

But she did say New York would lose a competitive edge with other states if it didn’t allow large commercial/industrial loads to use plug-and-play small modular reactors, once the technology is developed and approved. 

Nuclear is something people have not been talking about for a long time, Hochul said, but New York needs to take another look at it. 

New York state has four operational commercial reactors. In 2023 they provided 22% of the state’s electricity and 45% of its zero-emission electricity. Three of the reactors rank among the oldest operational units in the nation, first licensed 50 to 55 years ago. 

NYSERDA’s request for information seeks to identify entities pursuing or interested in pursuing a role in the development of next-generation nuclear energy in New York. 

It will, Harris said, let NYSERDA develop partnerships and initiatives for complementary resources, and keep the state in the forefront of emerging energy technologies. 

NYSERDA hopes to hear not only from prospective developers but supply chain companies, potential host communities and entities in the workforce development, finance and research and development sectors. 

Responses can be submitted via its online portal through Dec. 16. 

Meanwhile, NYSERDA is finalizing its draft nuclear blueprint. The State Energy Planning Board is readying the latest update of the State Energy Plan, which provides broad direction on program and policy development in the public and private sectors. 

And the Department of Public Service continues the work begun in June 2015 on implementing a Large-Scale Renewable Energy Program and a Clean Energy Standard (case 15-E-0302). 

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Court Nullifies Sale of NY Peaker to Crypto Miner

Environmental advocates won a round in their long-running court battle over the conversion of a New York peaker plant into a cryptocurrency mining operation.

A county-level court on Nov. 14 ordered the state Public Service Commission to reconsider the decision that allowed the conversion to go through.

In 2022, the PSC (21-M-0238) and FERC (EC22-78) signed off on the sale of Fortistar’s 60-MW gas-fired plant in North Tonawanda to a subsidiary of Digihost Technology to power an on-site crypto farm. (See FERC OKs Sale of NY Power Plant to Crypto Miner.)

The PSC opted not to block the sale because it posed no potential harm to captive utility ratepayers and no potential exercise of market power.

FERC authorized the transaction because it found no impact on horizontal or vertical competition, no adverse impact on rates, no impairment of regulation and no cross-subsidization.

The Sierra Club and the Clean Air Coalition of Western New York challenged the PSC’s ruling on the grounds that it was inconsistent with the state’s Climate Leadership and Community Protection Act of 2019, which mandated policies to reduce the use of fossil fuel and minimize its impacts. (See Green Groups Seek to Block NY Power Plant Sale to Crypto Miner.)

The challenge initially was rejected in court and by the PSC, and the sale was finalized in early 2023.

Operation of the crypto facility has generated noise and air quality complaints in the neighborhood and prompted North Tonawanda to enact a two-year moratorium on new or expanded data centers and cryptocurrency mining operations.

Digihost, in its quarterly earnings report Nov. 15, called the North Tonawanda facility its flagship power plant. It said it had completed maintenance work and soon would bring the plant back to full operation.

The Nov. 14 ruling by Justice Richard Platkin in Albany County Supreme Court reopens the case before the PSC.

The PSC had no comment Nov. 15, saying only that it would review the latest ruling.

Earthjustice, which represented the environmental groups, celebrated the ruling.

Earthjustice said in a news release that the PSC erred in its review of the proposal, and said this allowed a gas peaker plant that had been operating 10 to 74 days a year to ramp up to 24/7/365 operation. This boosted carbon dioxide emissions as much as 3,500%, it said, and increased output of other harmful pollutants.

“This is not only a victory for the North Tonawanda community, but also a significant win for New York’s climate law,” said Dror Ladin, senior attorney at Earthjustice. “Today’s ruling confirms that every state agency and official must fully consider and uphold the CLCPA in all its decisions, safeguarding both our climate and the well-being of the public.”

The ruling was not a clean sweep for the environmental advocates.

Justice Platkin rejected their contention that the PSC failed to consider the impact on several nearby disadvantaged communities, as it is required to do under the CLCPA. The state had not finalized its designation of disadvantaged communities at the time, he ruled, and therefore the PSC could not have considered such impacts.

And he rejected the complainants’ request for declaratory judgment.

But the PSC had argued that allowing the sale to go forward was not an “affirmative approval” and therefore not subject to CLCPA requirements, and this was incorrect, Platkin wrote.

So he annulled the PSC rulings and remanded the matter for further proceedings.

If the PSC determines the sale will interfere with the state’s greenhouse gas emissions limits, it must identify alternatives or mitigation measures to be required near the plant, Platkin wrote.

An earlier appeal in the same case determined that substantial completion of a project may render a case moot, he wrote, but the CLCPA allows for substantial relief short of completely unwinding a transaction.