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November 14, 2024

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FERC Ends MISO Compensation for Reactive Power Supply

FERC last week approved MISO’s Transmission Owners’ request to eliminate reactive power compensation for generators, rejecting multiple protests.

The commission’s Jan. 27 order cited Order 2003, which said generators do not have to be compensated for providing a standard range of reactive power because they’re simply meeting a condition of interconnection (ER23-523).

MISO Transmission Owners in December filed to eliminate reactive power and voltage control charges from their own and unaffiliated generation resources. TOs said the revisions will result in a rate decrease for transmission customers. They argued that the number of unaffiliated generators collecting reactive power compensation has grown to a $220 million annual revenue requirement and climbing. (See MISO TOs File to End Reactive Supply Compensation.)

Under Schedule 2 of MISO’s tariff, most generation owners can apply to receive separate compensation for their reactive supply. The TOs asked FERC to eliminate separate charges to pay for reactive service supplied within the standard power factor range of 0.95 leading to 0.95 lagging.

Several clean energy generation owners accused the TOs of using their agreement with MISO in an “abusive” manner. Groups including the Coalition of Midwest Power Producers, American Clean Power Association and Clean Grid Alliance said MISO TOs lacked the authority to make the change, gave stakeholders just 19 days’ notice that it intended to make the change and failed to vet the proposal in the stakeholder process.

EDF Renewables and Vistra Energy argued many independent power producers in the footprint will suffer harsh financial effects. The Solar Energy Industries Association and Wolverine Power Supply Cooperative contended that eliminating reactive supply compensation could lead to generation developers installing reactive power capabilities only to the bare minimum standard power factor range, setting off a possible shortfall that could keep MISO from returning to reliable operations during an emergency.

The protestors also said the removal of Schedule 2 wasn’t fair because generation-based reactive power won’t be eligible for compensation while MISO TOs will continue to be paid for their transmission-installed reactive devices in their rate bases. They noted that MISO’s 2022 Transmission Expansion Plan includes $146 million of new reactive support and voltage control devices on which the MISO TOs will earn cost recovery plus a rate of return.

But FERC said a reliance on reactive supply compensation isn’t a good enough argument to continue its practice. It said new interconnecting generators must provide standard reactive service as a condition of interconnection and aren’t entitled to payment for doing what’s mandatory.  

The commission waved away concerns that MISO’s system reliability could suffer without the compensation. It said other wording in MISO’s tariff allows MISO to compensate a resource if it has to direct it to provide reactive power outside of the standard power factor range.

FERC also said it found no discrimination against independent power producers in the proposal. It said the IPPs are free to try to recover lost reactive power revenue through increased power sales rates, just as TOs’ generating units can through retail rates.

Finally, the commission rejected arguments that TOs can unfairly continue to collect reactive power payments through transmission-installed reactive devices. The commission said the issue at hand related to generation-based reactive power payments, not transmission. It said TOs proposed to treat affiliated and unaffiliated generation alike.

Commissioner James Danly disagreed with the commission’s decision, writing that MISO TOs did not meet their burden of proof that the current rate was unreasonable, given the “substantial unrebutted evidence of the negative rate impacts that this will have on generators not affiliated with the MISO TOs.”

Danly said it was unsatisfactory for MISO TOs to simply cite Order 2003 and previous orders where the commission decided that generators don’t have to be paid for reactive power within the standard range.

Danly argued that in prior cases, FERC “eliminated reactive power compensation when only a handful of unaffiliated generators were receiving — or still seeking — it.”

“The situation in MISO clearly is distinguishable where scores of generators are recovering reactive power compensation and it has been a part of the MISO tariff for years,” Danly wrote.

Commissioner Allison Clements concurred in a separate statement, writing that she would have preferred the MISO TOs use a “different procedural approach” that incorporated more stakeholder input.

She said MISO TOs’ filing is evidence that FERC’s current cost-based methodology for reactive power compensation “is poorly suited for newer technologies and non-synchronous generation like wind, solar, and storage.” She said FERC should act on its Notice of Inquiry opened in 2021 to examine the current regulations associated with reactive power compensation (RM22-2). The commission has not acted in response to comments filed in the docket early last year. (See FERC Seeks Comments on Reactive Power Compensation.)

“Whether or not generators located in MISO were justified in relying on continued reactive power compensation, parties have stated in the record that this decision will cause financial disruption,” she said.

Clements encouraged MISO stakeholders to “consider more effective alternatives to cost-based reactive power compensation.”

“Services should be appropriately compensated for the benefits they provide, and reactive power plays an important reliability function… [S]takeholders may wish to consider market solutions and/or compensation models that are based on the performance of the generators in providing reactive power when called upon, or that incentivize reactive power generation to be located where additional reactive supply is most needed from a reliability perspective,” Clements wrote.

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Solar Trade Group Challenges MISO Ban on Renewable Ancillary Services

The Solar Energy Industries Association on Tuesday lodged a complaint at FERC against MISO’s practice of blocking intermittent resources from its ancillary service market.

SEIA, represented by Earthjustice, asked that the commission find as unjust and unreasonable MISO’s tariff provisions and business practice procedures restricting wind, solar and battery hybrid resources from providing regulation service, spinning reserves and supplemental reserves.

The organization said the RTO prevents its dispatchable intermittent resources (DIRs) from ancillary services participation “despite the fact that [they] have the operational capability to provide such services.”

“No other FERC-jurisdictional RTO or ISO codifies this explicit discriminatory prohibition,” SEIA said in its filing, noting that PJM and CAISO explicitly state wind and solar resources’ eligibility.

SEIA also pointed out that MISO never meant for its ban on renewable ancillary services to be permanent. In a 2010 filing with FERC, the grid operator said it needed “to gain experience with this new method of modeling and dispatching” before allowing renewable energy to supply operating reserves. SEIA said FERC’s ultimate agreement with MISO’s prohibition hinged on its temporary nature. To date, MISO has never provided a “technical justification” for its ban, the organization said.

It argued MISO’s market rules discriminate against some resources because they’re tailored to the large, centralized power plants of the past.

“MISO’s discriminatory and unjustified tariff provisions that prohibit DIRs from providing ancillary services in MISO’s wholesale market is a prototypical example of how outdated tariff provisions can result in unnecessary and deleterious market barriers,” the organization said.

SEIA said lifting the ban would increase competition and allow new resources to “provide the critical grid-stabilizing services that MISO will need.” It said that though MISO “fundamentally agrees” that renewable resources should be able to provide all the services they’re capable of, the grid operator hasn’t acted on a longstanding suggestion that it extend its ancillary service market to renewable energy. According to SEIA, the issue was raised as part of MISO’s 2018 market roadmap improvement ideas; staff last year recommended putting the idea to rest without action.

The complaint comes as MISO has announced plans to ban dispatchable intermittent resources from providing ramping needs, saying they’re historically unhelpful. (See MISO Plans to Bar Intermittent Resources from Ramp Capability.)

“Rather than doubling down on nonmarket-based blanket prohibitions, MISO ought to be focused on facilitating technology-neutral, operations-focused solutions that properly establish criteria for when a resource is called upon to provide ancillary services,” SEIA said.

In a press release accompanying the complaint, Earthjustice attorney Aaron Stemplewicz said his organization is prepared to challenge MISO’s “attempts to strip wind, solar and battery hybrid resources from providing ramp capability.”

“Any backsliding will be rigorously challenged with regard to the eligibility of renewable resources to provide all the services they are capable of providing,” he said.

SEIA Energy Markets Director Melissa Alfano added that energy markets must keep pace with a changing grid.

“Renewable assets like solar, storage and wind have more than proven themselves as reliable, and we need to recognize the full scope of their benefits if we want to rapidly decarbonize in the next 10 years,” she said.

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Transmission Project Would Span Across Interconnection Divide

A Midwestern utility and an independent transmission company are teaming up to build a first-of-its-kind line that would span across the Western and Eastern interconnections and through three different electric regions.

ALLETE (NYSE:ALE), a Minnesota-based energy company, and Grid United, a competitive transmission developer, announced their plans this week to build the North Plains Connector, a roughly 385-mile HVDC transmission line between North Dakota and Montana.

The developers say their project would be the first transmission connection between three “regional U.S. electric energy markets”: MISO, SPP and the Western Interconnection. It would create 3,000 MW of transfer capacity between the regions.

SPP spokesperson Meghan Sever said that Grid United has been conducting a feasibility study on several transmission projects with the grid operator’s staff and the Transmission Working Group, the scope of which was approved in September.

“Several merchant HVDC developers have approached SPP about projects in various stages of development. As with every project, SPP follows our stakeholder-approved study practices when evaluating the impacts of these projects on the SPP system,” Sever said.

The project is still in the development stage, with permitting expected to start this year and a planned in-service date of 2029. Its unique nature has captured attention from the energy world, earning praise for its ambitious goals to connect the regions.

Grid United is run by Michael Skelly, a prominent clean energy executive whose past portfolio includes building transmission and wind projects at Clean Line Energy and Horizon Wind Energy.

“It is no secret that the U.S. is in desperate need of new electric transmission capacity, and the North Plains Connector will provide resiliency and reliability benefits for decades to come,” Skelly said in a statement.

ALLETE owns utilities in Minnesota and Wisconsin, as well as energy production subsidiaries in North Dakota, Minnesota and Maryland. Its CEO and president, Bethany Owen, called the project “innovative” and said its an “important step toward a resilient and reliable energy grid across a wide area of the country.”

The collaboration between a utility and an independent transmission company is also an innovative part of the project that energy experts have called out.

“It’s starting!” tweeted Rob Gramlich, an energy consultant and former FERC official. He predicted that “joint ventures, joint ownership and joint [transmission companies] will join forces to build infrastructure, serve specific utility load and upsize to serve wider market demand.”

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Murphy Signs NJ Low-carbon Concrete Law

New Jersey took a big step in promoting the use of low-carbon concrete Monday when Gov. Phil Murphy (D) signed a law that will provide business tax credits to producers who supply state projects concrete made with lower greenhouse gas emissions.

The law, S287, gives state corporation business and gross income tax credits to producers that provide more than 50 cubic yards of low-carbon concrete under a state procurement contract or to a private contractor contracted by state government. It enables the supplier to earn credits for up to 5% of the cost of the concrete if it is “low-embodied-carbon concrete.” The credits can be up to 3% if the concrete’s production incorporated “carbon capture, utilization and storage technology,” according to a legislative explanation of the bill.

Some producers may deliver concrete that meets both criteria, and so be eligible for up to 8% of the cost, an analysis by the state Office of Legislative Services said.

The law targets a major source of carbon emissions from one of the most widely used construction materials and could yield significant emissions reduction if low-carbon concrete is widely embraced, analysts say.

The Natural Resources Defense Council, which tracks low-carbon concrete initiatives, said the law is the first of its kind in the U.S.

“It’s a model for other states,” said Sasha Stashwick, NRDC’s director of industrial policy. The law is “a really unique policy that combines performance standards with performance incentives.”

“We hope to see a lot more states adopt it,” she said.

The bill’s enactment comes 14 months after New Jersey enacted a law, S3091, that provides builders with tax credits for using unit concrete — pre-fabricated concrete that is delivered in ready-to-use form, often as pavers or concrete blocks — produced in a low-carbon method. (See New Jersey Lawmakers Back Low-carbon Concrete.)

The International Energy Agency (IEA) has said that the cement sector, which provides a key ingredient of concrete, is the second largest industrial emitter of carbon emissions, generating about 7% of worldwide emissions.

Murphy, who has set a target for the state to reach net-zero emissions by 2050, said in a statement that the tax credit law is an example of the state’s “nation-leading innovation and cross-sector collaboration.” He said it shows that the benefits of clean energy extend beyond the environment and added that the law will “further support the construction of greener, cleaner buildings and roadways in New Jersey.”

“As our efforts to decarbonize our economy become more urgent, we must also ensure that they become increasingly more economically attractive,” Murphy said. “It’s bills like these that prove that the steps we take to combat climate change can — and will — stimulate economic activity and growth in the industries that remain key to our climate solution.”

Bipartisan Support

The law limits the amount of tax credits awarded to $10 million a year, and no producer can receive more than $1 million a year.

It requires the Department of Environmental Protection (DEP), working with the Department of Treasury, to create a process by which concrete producers can certify that their concrete is low-embodied-carbon concrete, or that its production used carbon capture, utilization and storage technology. The agency must produce a report three years after the program is implemented that contains a “cost-benefit analysis of the tax credits.”

The bill drew bipartisan support in the legislature, with a 74-4 vote in the General Assembly and 39-0 in the Senate. It was embraced by both environmentalists and business groups, such as the New Jersey Business & Industry Association (NJBIA), which is often at odds with some of the Murphy administration’s clean energy efforts.

“We must also incentivize the business community to further use innovative products and processes,” said Raymond Cantor, the NJBIA’s deputy chief government affairs officer. “This bill does exactly that, by providing tax incentives to developers to use low-carbon concrete.”

Reducing Cement Use

Stashwick said it’s not yet clear the extent to which the use of low-carbon concrete cuts emissions, in part because much of that depends on the specifics of each project.

Cement accounts for about 90% of the carbon emissions associated with concrete, and reducing the amount of cement in the concrete mix and replacing it with other ingredients can achieve a significant cut, perhaps by 50%, she said. But deeper cuts in emissions require changes upstream in production and in the plants that make it, with retrofitting and new technology, which can be expensive, she said.

“Cement kilns run at very high temperatures. So, you’re burning a lot of fossil fuels because you’re heating up the raw material,” she said. “So, the more we can reduce demand for cement with these types of policies like we have in New Jersey, the greater we will be able to reduce emissions associated with the final product, which is concrete.”

The governments of New Jersey, New York state and New York City are among the largest procuring low-carbon construction materials, with leaders in New York signing executive orders to do so, according to NRDC.

New York Gov. Kathy Hochul in January signed the Low Embodied Carbon Concrete Leadership Act (LECCLA), which established guidelines for procurement but was not as “robust” as the New Jersey law, Stashwick said. The New York law requires the Office of General Services to create a stakeholder panel to make recommendations for low-carbon concrete procurement policies, with that work set to start next month, she said.

“And now they have a real-world example of a type of policy that they could recommend for New York to adopt,” she said, referring to New Jersey’s new law.

In New York City, Mayor Eric Adams signed an order stating that “capital project agencies shall make their best efforts to incorporate low-carbon concrete specifications for all batch plant ready-mixed concrete used in capital projects and for concrete sidewalks.”

The Port Authority of New York and New Jersey also has made a point of using low-carbon concrete. The agency — which operates bridges, tunnels and the Port Authority Trans-Hudson, as well as three airports — enacted the Clean Construction program to promote low-emission construction, which included a requirement to use “low-carbon concrete mixes.”

The authority followed that in 2021 by enacting the Low Carbon Concrete Program, in which it put together a project with New York University and Rutgers University to develop and test new low-carbon concrete mixes.

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House Energy Panel Talks Permitting in First Hearing

The partisan divide was clearly visible at the House Energy & Commerce Committee’s first hearing of the new Congress Tuesday, but witnesses on both sides suggested they might find common ground on permitting “reform.”

Cathy McMorris (House Energy Commerce Committee) FI.jpgChair Cathy McMorris Rodgers | House Energy & Commerce Committee

“Energy is foundational to every aspect of our lives, whether it’s making energy more affordable and reliable, securing our supply chains, beating China, protecting the environment, addressing climate change, or putting energy security back at the center of policymaking,” new Committee Chair Cathy McMorris Rodgers (R-Wash.) said at the start of the hearing. “These should be bipartisan goals.”

So far, Republicans have proposed a couple of energy bills in the House that deal with the strategic petroleum reserve, and while those won some support among Democrats, ranking member Frank Pallone (D-N.J.) was not among them. One of the bills would limit the president’s ability to draw down the reserve just to lower prices, requiring that such a move be paired with additional leases for drilling on public land.

Pallone argued the oil companies were interested in keeping the price of their product “artificially high” and said that the committee should move forward on new sources of energy as it did last Congress.

“Let’s keep in mind that encouraging renewables — as we did with the Inflation Reduction Act, as we did with the Bipartisan Infrastructure Law — this is the way to go in the future,” Pallone said.

Maximizing those two laws’ impact will require an expansion of the transmission grid, both by building new lines and upgrading existing ones so that they can transport more power, said Ana Unruh Cohen, who was the Democrats’ staff director for the House Select Committee on the Climate Crisis until Republicans ended the committee when they took over the chamber.

“I think there does need to be more focus on grid enhancement,” said Cohen, the Democrats’ only witness. “Actually, Sen. [Joe] Manchin’s [permitting] proposal had some language on the grid that I think Energy and Commerce staff also liked to help deploy more things, deal with cost allocation.”

While Manchin’s (D-W. Va.) bill failed late last year, Congress did provide agencies up to $1 billion to improve their permitting processes and help get needed projects out the door, Cohen said. That initiative needs to be implemented quickly, she added.

Paul Dabbar, a former undersecretary of energy in the Trump Administration, also called for permitting reform and singled out FERC and its two biggest governing statutes — the Federal Power Act and the Natural Gas Act — for changes.

“FERC needs significant legislative reform to make them do their statutory obligation to ensure there is enough energy supply of all types,” Dabbar said in his written testimony. “They need to be required to approve transmission projects for all types of energy. And they need to radically overhaul ISO rules to encourage baseload power that is being shut down faster than new intermittent plants are being built.”

Neither the FPA nor the NGA are “definitive enough” to make FERC meet its statutory obligation to deliver energy of any type, Dabbar said. He suggested adding more time limits for FERC approval of infrastructure projects.

Dabbar said permitting relief is urgently needed because inflation is interfering project developers’ ability to predict their costs. Project approvals can take so long that by the time they win approval, the initial estimates the regulators relied on are too low and the infrastructure becomes uneconomic.

“We’re seeing that in, for example, Massachusetts, actually, with offshore wind right now,” Dabbar said. “They propose a contract, approvals have taken so long, and then the inflation topic is on top of it, all of a sudden the offshore wind projects, they withdraw them because they don’t make economic sense anymore.”

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BOEM Continues Planning Process for Gulf of Maine OSW

The concept of floating wind power in the Gulf of Maine continues to take shape.

The U.S. Bureau of Ocean Energy Management on Tuesday wrapped up a series of informational sessions online and in person in Maine, Massachusetts and New Hampshire, seeking feedback as it develops a map of potential wind farm sites.

The eight-step process is intended to refine and shrink the initial planning area into individual lease areas, eliminating millions of acres less suited for wind power for reasons as varied as lobsters, pipelines, whales and commercial shipping.

There is more to come: Fisheries data, for example, have not been incorporated into planning yet.

The current “draft call area” is only Step 3 along the way and, at 9.9 million acres, is already 27% smaller than the area initially outlined.

“We recognize that this still a large area with significant conflict, and that’s really what we’re now turning our focus toward, looking toward the fishing effort, marine mammal and avian hotspots and any additional concerns that exist within this area,” BOEM project coordinator Zack Jylkka said Tuesday.

An audience member at the virtual meeting asked if a tract eliminated from the area of consideration could later be added back.

It typically would not be, Jylkka said. The process is slow and deliberative in hopes of avoiding the need for changes. But the ocean is a dynamic environment, so changes are sometimes needed, and BOEM is not precluded from making them, he said.

Has there been coordination with grid operators on the best interconnection points for electricity from offshore wind?

“One of the variables there is distance to shore, distance to interconnection points,” Jylkka said. “So, we’re certainly looking at that to inform some of the suitability of potential areas. But ultimately, we’re still asking a lot of questions ourselves.”

Is impact on endangered species weighted more than impact on nonendangered species?

The methodology has evolved in the last couple of years, said James Morris, a marine ecologist with the National Oceanic and Atmospheric Administration’s National Centers for Coastal Ocean Science. “We’ll essentially assign a score to each one of those species, based on its status and trend.”

A species with small and declining numbers would get a very low score for compatibility with a wind project, for example. All the scores for all the species are combined to produce a single data layer, to be added to the map with layers for the various other potential impacts.

The U.S. Department of the Interior in 2021 said it hoped to hold a lease sale in the Gulf of Maine by 2025. Jylkka said Tuesday that the auction is currently projected to be in the third quarter of 2024.

The offshore wind industry is still in its very early stages in the U.S., and the projects now being built and planned on the East Coast entail towers on seabed foundations. But the areas targeted for development in the Gulf of Maine, like those off the California coast, are deep enough to require anchored floating wind turbines, a technology still being developed and refined.

Five companies so far have expressed interest in potentially developing wind power in the gulf, Jylkka said: Avangrid Renewables, Hexicon USA, Pine Tree Offshore Wind (RWE Renewables and Diamond Offshore Wind), TotalEnergies SBE US (TotalEnergies and Simply Blue) and US Mainstream Renewable Power.

As large-scale commercial wind power is considered in the Gulf of Maine, the state of Maine is pressing forward on a related track: It has applied to BOEM for a research lease on 9,700 acres about 45 dozen miles southwest of Portland for up to a dozen floating turbines with a combined capacity of up to 144 MW.

The University of Maine has been designing and developing a floating concrete hull technology for offshore wind for more than a decade. A research array would advance that technology and give insight to the interaction floating wind turbines would have with fishing, shipping and other maritime activities and ecosystems.

On Jan. 19, BOEM announced a “determination of no competitive interest,” moving the state’s application to an environmental review of potential impacts from such a project.

The university, in a partnership that includes RWE and Diamond, is planning to anchor a single 10-MW floating turbine close to Monhegan Island in 2024. It is an up-scaled version of a turbine that was tested off the coast at Castine a decade ago.

Kelt Wilska, energy justice manager for Maine Conservation Voters and Maine’s lead representative in New England for Offshore Wind, told RTO Insider later Tuesday that he likes the progress being made.

“I view this through the lens of urgency,” he said. “We need to move very quickly to meet our climate goals both at the state and federal level.”

But there is value to a deliberative process, Wilska added.

BOEM was not required to hold the series of public meetings, he said. The fact that it did so indicates the agency is committed to a just and inclusive process, which is important to him and those he works with.

“I am pleased with the amount of care they are putting into winnowing down this area,” Wilska said.

The draft version of Maine’s own offshore wind roadmap shows the results of extensive outreach and collaboration, he added. “We want to really build on that.”

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Wash. Bill Seeks to Accelerate Renewable Buildout

A catch-all bill to boost construction of renewable power in Washington picked up support ranging from conditional to strong at a hearing Tuesday.

Senate Bill 5380, introduced by Sen. Joe Nguyen (D), covers several subjects, including:

  • Requiring environmental impact statements for hydrogen projects statewide and for solar projects in the Columbia River Basin. These projects currently go through a preliminary review that determines whether a full environmental impact study is needed.
  • Speeding up the state Environmental Policy Act’s process to prepare environmental impact statements, declaring they must be complete in two years or less.
  • Creating a coordinating council among state agencies to improve cooperation in setting up clean energy projects. This would be different from the Washington Energy Facility Site Evaluation Council, which makes permitting recommendations to the governor. The new coordinating council’s purpose would be to make project preparation work more efficient.

The bill would also require the Washington State University Energy Program to create a “least-conflict” siting process for pumped storage projects. Washington has one pumped storage project in the works, which is controversial because part of it would be on land that the Yakama Nation of Indians considers culturally sacred.

Rye Development of Boston, is hoping to build Washington’s first pumped storage project for $2 billion in southern Klickitat County near the John Day Dam. It would be in operation between 2028 and 2030.

The project would include two lined 600-acre water reservoirs that are 60 feet deep and separated by 2,100 feet in elevation. One reservoir would be on the river shore and the other at the top of a cliff. An underground pipe would connect the two reservoirs with a subterranean electricity generating station along the channel. Water would flow from the upper reservoir to the lower one to power the four-turbine generator station and then would be pumped back up to the upper reservoir in a closed-loop system.

At Tuesday’s hearing before the Senate Environment, Energy and Technology Committee, which Nguyen chairs, the senator said the bill’s purpose is to increase efficiency in setting up renewable energy projects. “We will not be able to meet our energy goals without more energy facilities,” he said.

No opposition to the bill surfaced at the hearing. Meanwhile, support among 27 testifiers ranged from strong to tentatively neutral until some changes are made in the bill.

Labor and business interests liked the jobs that renewable energy projects would create.

Others wanted proposed wind, nuclear and solar projects outside the Columbia River Basin to be subject to the required environment impact studies without going through the preliminary reviews.

John Rothlin of the Avista Utilities said the bill needs more and clearer deadlines for the processes that it addresses.

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NH Lawmakers Want to Take a Look at Leaving ISO-NE

Should New Hampshire leave ISO-NE?

A group of six Republican state lawmakers is putting forward a bill that would create a commission to study that question.

The commission would investigate whether it would be feasible for the state to withdraw from ISO-NE and become its own independent grid operator, market administrator and power system planner.

In a hearing of the Science, Technology and Energy Committee on Monday, the primary sponsor Rep. J.D. Bernardy (R) said that costs to consumers are what’s motivating his effort to consider separating from New England’s grid.

“In my campaign, one of the key issues I faced was explaining to constituents why there were skyrocketing costs of electric power,” he said during an informational hearing.

If New Hampshire — a net exporter of power to the rest of the region — were to withdraw from ISO-NE, it could harness the electricity produced in-state to power its own economy and households, he argued.

“Peak power in New Hampshire is a little over 2,000, 2,100 MW. What does Seabrook [Nuclear Power Plant] produce? About 1,200. That’s about 60% of the power for New Hampshire,” Bernardy said.

The proposal was met with significant skepticism by the other members of the committee, who noted that Seabrook’s power is contracted out to buyers in a number of other states and couldn’t necessarily be contained to New Hampshire.

Other committee members also pointed out that there would be immense legal and logistical challenges associated with separating from the regional grid operator.

“By withdrawing from the ISO, we would be blowing a big hole in the regional power system,” Rep. Tony Caplan (D) said.

And, he asked, “how would we be able to provide lower rates for New Hampshire ratepayers given that the administration and regulation and all those services we would have to provide ourselves?”

Maine and Connecticut have both taken on similar assessments — Maine in 2007-8 and Connecticut in 2020 — and neither decided to move forward, said Joshua Elliott, director of the division of policy and programs at the New Hampshire Department of Energy.

Elliott said the agency is neutral on the bill because it would only involve studying the subject. If the legislature does move forward with the proposal, he suggested that it consider recruiting consultants to help put forward a more “substantive” end product.

The other sponsors of the bill are Republicans James Summers, Susan Porcelli, Fred Plett, Jason Janvrin and Yury Polozov.

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NJ Steps up Remote Net Metering Approvals

New Jersey regulators have approved two remote net metering (RNM) projects totaling more than 250 kWdc in the latest of a series of RNM projects given the green light, while the legislature considers a bill that supporters say would make development of such projects easier.

The two Rutgers University projects are among half a dozen projects totaling nearly 1,000 kWdc backed by the New Jersey Board of Public Utilities (BPU) in the last eight months under a 2018 program designed to promote development of solar projects by municipal governments and other public bodies.

The Rutgers projects approved Jan. 11 — an 82.35-kWdc project developed by Rutgers’ Snyder Research Farm and a 173.88-kWdc project developed by the university’s Cook College — followed the board’s Nov. 9 approval of 251 kWdc developed by the Borough of Edgewater, a project located on top of the town’s community center that will feed energy to a second location in the community.

The BPU last year approved a series of solar facilities, including a 141.3-kWdc project to be built at the Sommers Point Sewerage Authority, with power to be shared with the City of Somers Point; a 89.91-kW facility at a property used by the City of North Wildwood; and a 202.5-kW facility at Newton High School.

All the projects were approved under a program, part of the 2018 Clean Energy Act, that allows kilowatt-hours of solar electricity generated by a local government project in one location to be credited to the account or accounts of public entities at other locations that are not geographically connected.

The strategy of removing the requirement that the solar generation occur in the same place that the energy is used enables project development in locations that are not able to operate a solar facility — perhaps because of too much shade, grid connection barriers or other reasons.

The program is similar to the state’s community solar program, which also allows the development of projects in which the electricity is generated and used in different locations. But in that case, the power is sold to a large number of subscribers, at least 51 % of which need to be low- and moderate-income, as opposed to a few public entities under the RNM program. (See NJ Celebrates Completion of First Phase 2 Community Solar Project.)

Under both programs, the customers — which in the RNM program are public bodies — are awarded credits that reduce the cost of their electricity bill.

Promoting Local Government Solar

The BPU’s wave of RNM approvals come as the legislature mulls a bill, A4328, that supporters say would make it easier to develop RNM projects, and opponents — among them the New Jersey Division of Rate Counsel — fear would add to the cost to ratepayer subsidies of the program.
 
The state is looking to ramp up solar production to meet Gov. Phil Murphy’s goal of reaching zero emissions by 2050, with solar reaching 5.2 GW of capacity by 2025 and 12.2 GW by 2030. The state wants to have 17.2 GW of solar power installed by 2035, a goal more than four times as large as the 4.3 GW of capacity installed by December, BPU figures show. (See NJ Faces Challenges as Solar Sector Hits 4 GW.)

Abraham Silverman, executive policy counsel at the BPU, said the legislature created the state’s remote net metering program to make it easier for municipalities to pursue solar projects. It “fills a void” for public bodies that in several aspects would fit into the community solar program but don’t match the requirement to have a large number of subscribers, he said.

For example, the RNM program helps a public body that may have several locations suitable for mounting a solar project but individually would use either more or less electricity than the project would generate. Under the RNM rules, the demand and electricity generation could be spread across all the locations, allowing the development of a project that would fit their needs.

Silverman said the BPU “has been very, very supportive” of the RNM program. “And you’ve seen a few different places where we’ve provided higher incentive rates for projects owned by municipalities.”

RNM projects enjoy “favorable retail economics,” he said. “They are larger-scale projects, and so benefit from economies of scale, but they sell the power back to grid at retail — rather than wholesale — prices, which makes the project more economically feasible,” he said.

“As we sort of step back and look at the remote net metering program, you’re kind of getting wholesale cost structure, but you’re getting retail revenues,” he said. “And so it’s a significant incentive that’s really only open to municipalities.”

New Opportunities

A4328 would update the rules and regulations of the RNM program to make them similar to those of the state’s Community Solar Energy Program, in which solar developers sign up customers who agree to buy the solar generated energy in return for a discount.

The proposed new RNM rules would define how the credit is calculated and would enable “electric public utilities [to] recover all costs incurred in the implementation of or compliance with the remote net metering program, including the full value of all credits provided to participating customers,” according to the Office of Legislative Services’ analysis of the bill. The costs, however, would be subject to review by the BPU.

The bill also doubles the size of projects allowed in the RNM program, from 5 MW to 10 MW, said Fred DeSanti, executive director of the New Jersey Solar Energy Coalition.

“I think it’s going to open up a whole lot of opportunities for developers and for communities,” DeSanti said. One reason is that A4328 would end the current requirement that a solar array must be on municipal property for the municipality to benefit from the project.

“That was way too restrictive,” he said, adding that bill would allow an array to be located anywhere in the territory of the project’s utility company.

The bill also revises the calculation method by which the BPU determines the maximum size of the project. At present, the size is based on an average of the power used by all the entities or accounts that will receive the power. The revised rules base the maximum size on an aggregation of the entitites’ historical usage, DeSanti said.

“So, this will allow a developer to go in and make a deal with five, six, seven or eight towns, whatever he needs, up to 10 MW, and then basically put it together in a deal,” DeSanti said.

Increasing Ratepayer Burden

Whether the new rules become law depends on the state General Assembly — and Murphy. The Senate version of the bill passed 40-0 on June 29. The Assembly version, having secured the backing of the Assembly Telecommunications and Utilities Committee on Oct. 17, is now before the Assembly Environment and Solid Waste Committee, where approval would lead to an Assembly vote.

Support for the bill is far from universal. In an Oct. 14 letter to the Assembly Telecommunications and Utilities Committee, Brian O. Lipman, director of the Division of Rate Counsel, said the bill would “significantly expand the scope of the [BPU] board’s remote net metering program for public entities,” and expressed concern that it would “result in additional costs to taxpayers.”

“Net metering credits are a form of subsidy that are paid for by other ratepayers,” he said. When net metering customers receive those credits, “rates must be raised for other ratepayers to cover net metering customers’ share of the cost of maintaining and operating the utilities’ electric distribution systems.”

He said the current program rules have two “important” factors that limit the project size, and so the burden on ratepayers: that the proposed facility sits on property with at least one host customer, which will use the energy generated; and the project is limited in size by the total annual usage of the host customers’ electric public utility accounts. The bill eliminates those limits and effectively expands the pool of public bodies that can receive credits, which are subsidized by other taxpayers, Lipman argued.

The rate counsel also expressed concern at the speed and lack of public input in the process set out in the law to enact the rules, and the lack of “public advertisement” and a competitive process.

This would “impair the [BPU’s] ability to assure that the implementing regulations recognize the interests of all stakeholders,” he said.

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NYISO Presses Onward with DER Revisions; Stakeholders Struggle to Keep up

NYISO on Thursday presented the Installed Capacity and Market Issues Working Groups (ICAP/MIWG) with further revisions to its proposed rules for distributed energy resource aggregations based on stakeholder feedback, but the groups’ members continued to express concern and confusion.

As it is never clear exactly which resources in an aggregation are providing electricity, NYISO has proposed to calculate their reference levels based on lists of average marginal costs for different resource types. “Aggregation-level offers will include a resource type from this list for each hour to indicate the highest-cost resource that is available to produce energy in the aggregation,” according to the ISO. “The NYISO-estimated marginal cost of that resource type will serve as the reference level for the entire aggregation for that hour.”

But there was extensive discussion and questions at the meeting about how exactly NYISO would do this, and how this would influence market bids and signals.

Aaron Breidenbaugh, director of regulatory affairs at CPower Energy Management, questioned NYISO’s proposed cost-based approach and why it didn’t stick with locational-based marginal prices. He said market participants who possess variable operations, such as crypto miners, may struggle to produce granular reference points to decide whether to make offers and may see “their net revenues being held hostage.”

NYISO responded that LBMPs and bid-based reference levels are based on 90-day historical data, but an aggregation’s composition can change day to day. A cost-based approach would enable aggregators to dynamically reflect different technology types, though the ISO expects that when someone “makes an offer based on their estimated marginal cost of production, they should be able to reflect that.”

Import Rights for Neighboring Control Areas (NYISO) Content.jpg2023 Import Rights for Neighboring Control Areas | NYISO

 

Stakeholders also continued to express confusion over how aggregations would be deployed and the timing for the transition to the new construct. (See NYISO Stakeholders Still Concerned About DER Participation Model.)

Julia Popova, NRG Energy’s manager of regulatory affairs, said she was concerned that dispatched generators would not be compensated in the real-time market, even though they made bids based on ISO economic forecasting in the day-ahead market showing their units being profitable.

“In real time, there is opportunity to buy out our position, but with everything else going on with DERs, it does not work every time as intended,” Popova said.

“If NYISO can’t give us to the tools to make sure we aren’t dispatched uneconomically, then it is not fair to penalize us” because “we did what we said we would do based on [the] day-ahead,” Breidenbaugh chimed in.

NYISO offered stakeholders offline discussions in response to concerns and told them about upcoming training opportunities to help with onboarding. It expects to begin accepting customer registrations for DER aggregations in mid-April and anticipates the proposed tariff revisions becoming effective in early summer.

The ISO will seek approval of revisions from the Business Issues and Management Committees on Feb. 15 and Feb. 22, respectively, and will return to the ICAP/MIWG to continue discussions on necessary manual revisions.

Capacity Accreditation Kickoff

NYISO kicked off its capacity accreditation modeling improvements project, one of many that the ISO wants to prioritize this year. (See NYISO Outlines Timelines for 2023 Projects.)

Zach Smith, NYISO capacity market design manager, said the effort “allows a twofold change”: more accurate representation of installed reserve margins (IRMs) and locational capacity requirements (LCRs) in resource adequacy models, and more accurate capacity accreditation factors for capacity accreditation resource classes.

NYISO scoped out four topics that need to be addressed:

NYISO does not currently capture natural gas constraints, nor start-up notifications for non-baseload units, in the IRM/LCR models. SCRs, although currently modeled, were found to not align with their expected performance and obligations.

But Smith said the ISO expects to spend most of its efforts this year on tackling the problems identified by the MMU by better capturing how ambient conditions impact correlated derates of combined cycle and combustion turbines.

NYISO will spend the first and second quarters analyzing areas for enhancement; the third quarter identifying any solutions; and the rest of the year either prototyping these solutions or making implementation recommendations. It plans to return to the ICAP/MIWG next month to discuss gas constraints, SCR modeling and the correlated derate issues.