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September 1, 2024

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NJ Community Solar Slowly Advances

New Jersey is implementing a plan to create a permanent community solar program built on the experience of two rounds of a pilot initiative in which only a third of the projects approved so far are operational, as developers struggle to sign up subscribers, prepare project sites and get their projects linked to the grid within the program deadline.

The New Jersey Board of Public Utilities (BPU) on Friday closed the public comment period seeking stakeholder issues to help shape the new program, which will award 150 MW each year and is expected to open in the fall. Among the issues the BPU sought to probe were: how should the agency pick future projects; should there be a waiting list on which to put projects not selected; and what should the BPU do to account for “scrub” projects, those that are awarded but are not completed?

The initiative comes 18 months after the BPU approved 45 projects totaling 75 MW in the first of two test solicitations that drew strong interest from developers and helped cement the program as a key element in the effort to reach Gov. Phil Murphy’s solar and clean energy goals. That sense was enhanced when the BPU approved another 105 projects, totaling 165 MW in the second phase in October. (See NJ Selects 165 MW in Community Solar Projects.)

Yet only 14 of those 45 projects were operating as of March, the latest that data are available, as they faced an end-of-April deadline to be operational. The completed projects total 28.9 MW, or about 38% of the capacity awarded in that phase. None of the second-round projects is operational.

“It’s developing much more slowly than we had anticipated, no question,” said Fred DeSanti, executive director of the New Jersey Solar Energy Coalition (NJSEC). “There’s not a lot going on.”

That slow progress contrasts with the potential that supporters see in the community solar program. Both solicitations were heavily oversubscribed by developers seeking to build solar projects on warehouse landfills, rooftops, above parking lots and other locations. The first year of the program attracted 252 applicants, five times as many as the number of projects awarded, and the second phase drew 412 applications, about four times as many as were awarded. And there is no shortage of future projects.

One developer, Solar Landscape, which completed eight of the 14 projects in operation, said it recently conducted a study that showed that solar projects have used only about 5% of the potentially usable rooftop space in the state.

“Every new program has its challenges,” said Mark F. Schottinger, the company’s president. “But the availability of rooftops is not one of them.”

Asked whether the number of projects in operation is lower than expected, BPU spokesman Peter Peretzman said: “The board continues to receive very strong interest in community solar and looks forward to transitioning to a permanent program which will provide further opportunities for new projects to be developed.”

Peretzman said there are a variety of reasons why more projects have not advanced, among them “site preparation challenges and disagreements between site host and developer.” He added that the goal of the pilot program was to “explore a new model for solar development and provide lessons for the development of a permanent community solar program.”

One possible outcome, he said, is that “the board may consider changing project maturity requirements for the permanent program.”

Meeting Deadlines

New Jersey is one of about 20 states that have recognized the benefits of shared renewables by encouraging their growth through policy and programs. The state’s initiative is part of Murphy’s push to have it reach 100% clean energy and generate 32 GW of solar, about nine times the capacity online today, by 2050.

Community solar projects target users who either cannot or do not want to have solar on their roofs but want to support a clean energy initiative. In many instances, developers start enrolling subscribers before they begin building a project or look for a business to be an “anchor” subscriber by committing to buying a certain percentage of the power from the project.

In return for subscribing, the consumer receives a credit on their utility bill, reducing the electricity cost by a set percentage. The solar project operator then supplies the electricity generated in the project to a utility company, which provides power to the consumer in the same way the utility did before opting into community solar.

Landfill Solar Project (AC Power) Alt FI.jpgA 0.83 MW solar project developed by AC Power on a closed landfill in Edison | AC Power

 

Developing projects that will bring that vision to reality, however, is no small feat. Annika Colston, president of New York City-based AC Power, said the BPU approved four company proposals in the first community solar solicitation, of which three are in operation, totaling 5.4 MW. The fourth project, and one approved in the second phase, are still pending.

The company struggled to meet the April deadline, in large part for reasons beyond its control, many of them related to a delay in Public Service Electric & Gas connecting each project to the grid because it was waiting for equipment held up in the supply chain, she said.

“The deadlines associated with the community solar program can be very stressful and can create a lot of investor uncertainty and financial uncertainty as you continue to develop projects,” she said.

Subscriber Hesitation

The process has unfolded as developers faced an environment already rife with pitfalls from the pandemic, which made it difficult to get municipal approval for projects and created equipment shortages and rising prices because of supply chain issues.

NJSEC’s DeSanti said a key issue holding up some projects has been the difficulty of meeting the state’s requirement that 51% of the subscribers are low- to moderate-income households.

“We are having a great amount of difficulty with subscriber eligibility and making sure that we can get people signed up,” DeSanti told the BPU at a public hearing last month. He urged the BPU to “look at those regulations as soon as possible to try to loosen them, or a lot of those projects are just not going to come to fruition.”

One problem is that some potential low- and moderate-income subscribers balk out of fear that the resulting reduction in their energy costs will interfere with the support they get from a state program that helps them pay their energy costs, DeSanti said. Another obstacle is that some lose their interest when they see the documentation they would have to submit to participate, especially the requirement to provide a W2 or other proof of income, he said.

“There’s a real reluctance to get involved with providing information about income levels,” DeSanti said. One solution would be to allow people to “self-attest” that their income is below the threshold that would classify them as low- or moderate-income, he said.

The BPU could also help by expanding the census tracts in which residents are automatically assumed to be low to moderate income, and so eligible for the program, he said.

Opening up the Market

Despite those concerns, Solar Landscape — which opened the state’s first two operational community solar projects on the rooftops of Perth Amboy warehouses in January 2021 — believes that the program will be a key element of the state’s solar energy portfolio.

The company’s Schottinger called it “the best product that New Jersey has ever allowed.” Aside from the company’s eight first-round projects, which total 20 MW, Solar Landscape received BPU approval on 46 projects in the second solicitation, totaling 50 MW. The company plans to submit applications when the BPU opens the permanent program.

Pent-up demand explains the flood of developer applications in the two pilot phases, Schottinger said. Before the BPU created the community solar program, New Jersey law largely limited the size of a rooftop solar project to the amount of energy that could be consumed on which it was mounted, he said. With community solar projects, “that limitation went away, because we no longer sell the electricity and community solar to whoever is in the building. Instead, we’re selling the electricity to people, residents, households and the surrounding communities,” he said.

“Community solar opened up a ton of usable rooftop space for solar that didn’t qualify for solar before,” he said.

The task of signing up subscribers is a challenge, especially in overcoming a skepticism about the claims of what community solar offers, he said.

“Some consumers think the community solar product sounds too good to be true, because we offer guaranteed savings with no downsides (e.g., people can cancel any time without penalty),” Schottinger said in an email, adding that the claims are nevertheless true.

But as consumer understanding of community solar improves, acceptance will spread, he said.

Communicating with Consumers

To help that happen, Solar Landscape has since 2021 partnered with the Boys and Girls Club of Newark. The nonprofit organization is one of dozens that the developer has worked with in a strategy used by developers to reach the low- and moderate-income population by working with local partners.

The collaboration allows the club to promote the energy discounts to the community while supporting the effort to reduce climate change and bringing in income, said CEO Ameer Washington. The club provides information about community solar to the families of the 1,000 to 1,100 children who each year use the organization’s after-school or summer programs, and another 10,000 people in the community who are more loosely tied to the organization, through a combination of printed leaflets, email blasts and social media, he said. Anyone that wants to sign up would then go directly to Solar Landscape , he said.

In return, Solar Landscape pays the club about $100 for each subscription, which so far has brought in about $3,000, Washington said.

“It’s not big numbers,” he said, but “every dollar helps, for sure.”

One problem, he said, is that many people in the community don’t have utility accounts.

“There’s not a lot of homeowners here that we serve,” he said. “Probably 65 to 80% of our club members are from low-income families and single-parent homes, and a lot of people in Newark rent primarily,” he said. In that case, the landlord may hold the utility account, and it would have to be the landlord’s decision to shift to clean energy, he said.

Even if the tenant has their own energy account, “in terms of some of the families that we do serve, maybe it’s not high on their priority list and they’ve got other things that they’re probably talked about more than how they’re getting their electricity,” he said.

Still, he said, the partnership offers a good opportunity to help people “start making the transition to clean energy.”

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EBA Panel Hits FERC Pipeline Permitting

WASHINGTON — FERC took criticism from two sides over its permitting of natural gas infrastructure during the Energy Bar Association’s annual meeting last week, with the gas industry accusing the agency of overreach and an environmental advocate calling its past decisions “lazy.”

FERC’s Democratic majority created an uproar in February when it voted to immediately begin applying an update to its 1999 policy statement on natural gas infrastructure certificates (PL18-1) and released guidance on how it will evaluate the impacts of projects’ greenhouse gas emissions in its environmental analyses (PL21-3). Chairman Richard Glick said the changes were needed because of court rulings faulting the commission’s evaluation of the need for natural gas projects and their impacts on GHG emissions.

But after receiving a tongue lashing from the Senate Energy and Natural Resources Committee — and multiple requests for rehearing — the commission changed the statements to drafts. It also said any changes would only apply prospectively, with applications already pending before the commission unaffected by any future final policies. (See FERC Backtracks on Gas Policy Updates.)

In an EBA panel discussion May 10, natural gas proponents said that the proposed changes threaten state jurisdiction and could chill future gas development.

‘Second Guessing’ Precedent Agreements

Matthew Agen, assistant general counsel for the American Gas Association, which represents natural gas local distribution companies, said LDCs are concerned about FERC reducing its reliance on precedent agreements between shippers and pipeline customers in determining project need. In many cases, the agreements are between corporate affiliates.

He said FERC’s efforts to “second guess” LDCs’ needs could interfere with their planning for “peak day” demand.

Matthew Agen 2022-05-10 (RTO Insider LLC) FI.jpgMatthew Agen, American Gas Association | © RTO Insider LLC

“We feel we are in the best position to judge what is needed behind the citygate, whether that is for industrial facilities, residential customers or even your natural gas generation facilities,” he said. “About 25% of the volume of gas going into electric generators flows through an LDC. So it’s not a small number, [although] it does vary from areas of the country.”

Christopher Smith, regulatory counsel for the Interstate Natural Gas Association of America (INGAA), which represents 26 pipelines that control most interstate gas infrastructure, said pipelines and shippers are “sophisticated commercial entities. They are well aware of things like state laws and state targets for reductions in greenhouse gas emissions [and capable of] forecasting the demand for natural gas operating under those laws. And so these precedent agreements, in our view, are market determinations, and they should be sufficient to establish market need.

“To replace this clear, objective test with what is essentially going to be a battle of the experts — in which the pipeline will have to hire somebody to explain what the market’s going to look like in 20 years — [is] just going to add cost and delay to these projects without really adding much probative value, because the market already spoke to that issue,” he said.

But Gillian Giannetti, senior attorney for the Natural Resources Defense Council, said FERC’s reconsideration of how it treats precedent agreements is long overdue.

Before the 1999 policy statement, Giannetti said, precedent agreements were required “for a certain … volume of capacity, or a project would be rejected.” The 1999 policy statement gave FERC flexibility in how it evaluated the need for a proposed pipeline. “It states explicitly that FERC shall consider all relevant factors in determining need, including but not limited” to precedent agreements, Giannetti said.

Environmental advocates have never taken the position that precedent agreements are not relevant, Giannetti said. “I think they certainly are. The question is, are they the relevant factor? And we would say that they are not; that there’s a difference between ‘a’ relevant and ‘the’ relevant, especially when you are looking at other serious impacts — both benefits and harms — that are associated with gas infrastructure.”

Agen questioned FERC’s jurisdiction over the issue, noting that LDCs are state-regulated. “The issue we have is, is FERC overstepping the bounds in some of these new policies? And then how does that impact state commissions?”

LDCs “are very active in mitigating [greenhouse gas] emissions, whether that’s replacing cast iron pipe or having energy-efficiency programs and the like,” he continued. “Who is the master of those programs? … We think it should be the state commission.”

No Need for Major Changes

Former FERC Chair Kevin McIntyre initiated a review of the 1999 policy statement with a Notice of Inquiry in 2018. But the commission took no action before McIntyre’s death in 2019.

Smith said there is no need for major changes to the policy.

Timeline of FERC Rulines (Energy Bar Association) Content.jpgTimeline of court rulings and FERC action on natural gas infrastructure policy | Energy Bar Association

“The significant changes in the industry that prompted FERC’s inquiry in 2018 are actually the exact sorts of changes that Congress envisioned when it enacted the Natural Gas Act. So, for instance, FERC observed dramatic increases in natural gas production … and the increased use of natural gas as a fuel source for electric generation,” he said. “These are all consistent with the aims of the Natural Gas Act. And so we have maintained that FERC should be hesitant to completely overhaul a system that is working as Congress intended.”

Giannetti, however, said Congress’ intent was clearly to require FERC to weigh precedent agreements on a case-by-case basis. FERC got “lazy” in failing to do so, she said.

“Precedent agreements — regardless of the volume, characterization, duration or alternative evidence — were universally treated as sufficient,” she said citing data showing FERC approved about 500 natural gas projects between 1999 and 2021, while no more than six were denied. “Every single one of those denials lacked a precedent agreement. So turning it around, every single project that has had at least one precedent agreement — for any volume, for any duration, with any shipper — has been approved.

“The Natural Gas Act says that only projects that are required by the public convenience and necessity be approved; the rest shall be denied. And I think we need to remember that when Congress has wanted to provide a more lenient standard, it has done so; for example, in the LNG context, where there is a presumption of approval unless it’s inconsistent with the public interest. I think that part of the problem is that we have forgotten that the [Natural] Gas Act is not a processing statute. It’s a reviewing statute.”

Rubber Stamp?

Smith said the statistics are misleading because of the commission’s “very robust pre-filing process.”

“In a lot of cases, projects will drop out in the pre-filing process,” he said. “So looking at what’s filed versus what’s approved isn’t really necessarily a good gauge as to whether FERC is acting as a rubber stamp.”

Agen also rejected that characterization of FERC.

“When we’re talking about [seeking] certainty, we’re not talking about FERC being in any way a rubber stamp. I mean, there are plenty of issues at the state level that our LDCs deal with that aren’t approved because the commission or [administrative law judge] decides it’s not appropriate,” he said. “But at the same time, we’re looking for certainty in a process. What is the evidence that’s needed? Right now, we’re not sure what evidence will be needed [to demonstrate] need. To me, the simple answer is a precedent [agreement] would be the best kind of evidence to that need. And if you need something else, tell us what that is, and we will get that to you.”

GHG Emissions

Smith said Glick and the Democrats overreacted to the court rulings remanding orders back to FERC for its failure to consider the significance of projects’ greenhouse gas emissions.

“While we believe that there are a discrete set of limited changes that may be appropriate to how FERC approaches its certificate review, what is in the draft policy statements go beyond what those court cases require; they go beyond what the law permits; and they go beyond … sound policy,” he said.

He predicted legal fights if FERC adopts the draft policy statement’s conclusion that the agency has the authority to deny certificate applications based on the volume of unmitigated indirect greenhouse gas emissions — those from upstream producers and downstream end users.

“Any order through which FERC would exercise this authority is going to be hotly contested. And it’s actually going to call into question the durability [of the policy statement] as opposed to promote durability,” he said.

“A lot of what the draft policy statements do is replace what have become clear, objective tests over the last 20 years … with a more amorphous test,” he continued. “As an applicant applying for certificate, we’re not really sure what evidence we need to propose, how FERC will weigh that evidence, how long it will take, and — at the end — whether FERC’s determination will significantly affect the cost, structure, or expectations or timing of the applicant and the shippers who executed the agreements to build this particular project.

“While there may be some changes that are appropriate in certain areas, what’s before us is a pretty significant overhaul that will introduce a level of uncertainty that will eventually chill natural gas infrastructure from being built at a time when we really need it the most.”

Landowners, Enviros Frustrated

Giannetti said FERC needs to make amends to those impacted by gas development.

“One of the things that has been very frustrating for the environmental community and for landowners and environmental justice communities is that they have felt as though their concerns are not treated as real or legitimate,” Giannetti said. “There are good actors in the gas industry. No doubt about it. There are folks who truly work to try and do reroute alignments or work with landowners to be able to get something where everybody can walk away from the table feeling happy. But it is important to remember that only one person is at that table voluntarily. … The private property owner is being brought to that conversation against their will.

“Unfortunately, there are some bad actors [and] many horror stories of … landowners who have been essentially told, ‘Well, you can negotiate with us now, or we’ll take you to court later.’ And these are folks who do not have the ability to hire Van Ness Feldman,” she said, in a wink to the panel’s moderator, Van Ness’ Michael R. Pincus. “These are people who had never heard of the Natural Gas Act before, regular people, often in rural communities who do not have a lot of means.”

‘Trial by Order’

One thing both sides agreed on was a need to end the “trial by order” that has marked FERC’s recent pipeline rulings.

“I think that all three of us would agree that this ‘trial by order’ system that the commission is doing right now is extremely problematic, especially the tendency to make changes in orders [when] the commission is well aware that not many people have standing to actually challenge them,” Giannetti said. “That happened in Newmarket [CP14-497-001]. And it also happened in Northern Natural [CP20-487], so it’s happened [to] both sides. And this is not a way to provide a durable system that pipeline applicants and environmental communities and landowners can rely on to know that their rights are being protected.”

Smith agreed. “It’s not fair to anybody to have the rules of the game change years — or millions or billions of dollars — into developing a project. The public, the pipeline developers, state and local agencies, they just haven’t had a chance to participate because they didn’t realize that these changes will be announced that way.”

Predictions on Future Policy

The panelists also made some predictions on what FERC’s final policy will look like.

Smith said he will be looking to how the commission decides two issues identified in Commissioner Mark Christie’s dissent from the initial order issuing the draft: safeguards for landowners and how the commission will weigh precedent agreements with affiliated parties.

“To the extent that the commission makes any changes, I would expect those two things to be there, because it looks like we already have at least four, possibly five votes on those areas,” Smith said.

“I agree with Chris,” Giannetti responded. “I think that we are going to see, for sure, changes when it comes to need and prospective precedent agreements, particularly with affiliates; landowner concerns, eminent domain concerns. And environmental justice, I think, is also going to be affirmed as being part of the need assessment.”

She said she sees “continued discord and … tension” regarding how FERC evaluates the “significance” of projects’ GHG emissions. She cited FERC’s March 2022 Iroquois decision, when the commission said it wasn’t “going to do a significance determination because the project would actually cause GHG benefits.”

“Saying that we’re not going to do an assessment because we think it’s going to lead to a reduction [in emissions] is basically saying it’s insignificant without actually saying it,” she said. “I think that we need to get rid of some of the wordplay and just actually do the assessments and call them what they are.”

Eminent Domain

Smith said FERC should remember that the NGA “does confer eminent domain authority, and it doesn’t allow the commission to condition that authority.”

“So while you can look at the process, I think we’re wary of [a ruling that] you can only use eminent domain for a certain percentage of the tract; otherwise, it’s not about the public interest. Things like that are contrary to the letter of the law,” he said. “I do think there will be a greater focus on the process … having our members show the work that they’re already doing” to minimize use of eminent domain.

As the 75-minute session came to a close, a member of the audience asked if NRDC could support any natural gas project.

“NRDC is not in every docket,” Giannetti responded. “I encourage you to take a look and see we do not challenge every pipeline project. We have always consistently taken the position that we want the Natural Gas Act to matter. And the Natural Gas Act does not say all pipeline projects should be approved, regardless of the environmental consequences, or the need for them or anything of that matter. That is how many feel that FERC has been exercising its authority. But that is not what it says. It says that FERC shall only approve projects that are required by the public convenience and necessity.”

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Australian Company Eyes Wash. Coal Mine as Green Hydrogen Site

An Australian “global green energy company” is exploring the potential of converting a disused coal mine in Washington state into a facility for producing green hydrogen.

Fortescue Future Industries (FFI), a company with a mission to produce zero-carbon hydrogen on a large scale, said Friday that it would study the feasibility of using the mine for its green hydrogen project after entering into a binding exclusivity agreement with the community-owned Industrial Park at TransAlta (IPAT), located in Centralia, Wash.

The project site is adjacent to TransAlta’s coal-fired Centralia plant, which is scheduled to fully close in 2025. The first of two units at the plant was retired in 2020. Previously fueled by coal from the local mine, the plant now relies on Powder River Basin coal delivered by train.

In a statement posted on its website, FFI said the green hydrogen production facility “would enable the decarbonization of hard-to-abate sectors of the North American economy and support the development of a Pacific Northwest green hydrogen hub, potentially creating hundreds of new local jobs.”

The company said it intends for the proposed facility to employ the existing workforce from the coal plant, “facilitating a transition into the emerging green energy economy.”

“FFI’s goal is to turn North America into a leading global green energy heartland and create thousands of green jobs now and more in the future,” FFI founder and Chairman Andrew Forrest said in the statement. “Repurposing existing fossil fuel infrastructure to create green hydrogen to power the world is part of the solution to saving the planet.”

Forrest was formerly CEO of Fortescue Metals, a mining subsidiary of FFI.

FFI said it has been working with the Lewis County Energy Innovation Coalition and Lewis Economic Alliance to perform due diligence related to the project.

Under the 2011 agreement between TransAlta and the state of Washington to close the Centralia plant, TransAlta agreed to invest $55 million in the state, including $20 million for economic and community development and $5 million to support the training of workers displaced by the closure.

“With the closing of the coal mine and the scheduled retirement of the Centralia coal-fired power plant, IPAT was formed to redevelop the site and attract investment that will support well paid, long-term employment opportunities in the region. FFI’s potential project represents the opportunity to do just that,” said Richard DeBolt, executive director of the Lewis Economic Alliance.

‘Low-carbon Leadership’

FFI’s proposed project would fit into a wider public strategy to help Washington land federal money to become one of the nation’s hydrogen hubs. Friday’s press release noted that the company will collaborate with other stakeholders in the Pacific Northwest to apply for a grant from the U.S. Department of Energy’s $8 billion hydrogen hub program, which is being funded by appropriations from the Infrastructure Investment and Jobs Act (IIJA) passed last year by Congress.

Washington lawmakers in March passed a bill to create a new Office of Renewable fuels to support the development of green hydrogen and other alternative fuels, a move partly intended to boost the state’s prospects for landing one of the four to eight national hydrogen hubs to be funded by the IIJA. (See Green Hydrogen Bill Passes Wash. Legislature.)

In February, Washington Gov. Jay Inslee circulated a letter to state agencies, utilities and private companies saying the state had a good shot at hosting one of the hubs because of the relatively low carbon intensity of its electricity system. Zero-carbon electricity is a necessary component of powering the electrolyzers needed to produce what is considered “green” hydrogen from water.

Echoing the governor’s sentiments, FFI North America CEO Paul Browning said: “The electric power grid of the Pacific Northwest is one of the lowest-carbon power grids in the world and can be used to produce green hydrogen, and could extend the region’s low-carbon leadership to hard-to-electrify sectors like long-haul trucking, ports, aviation and heavy industry.”

Other collaborators on FFI’s project include Puget Sound Energy, innovation and investment accelerator Washington Maritime Blue, and Lewis County bus operator Twin Transit, which plans to build a hydrogen refueling station for its buses in Chehalis. (See Hydrogen Stations Could Soon Dot Wash. Landscape.)

While many Washington utilities and private companies are exploring production or use of hydrogen, Douglas County Public Utility District, in the central part of the state, has made the greatest strides, having already begun construction of a $25 million production facility expected to be completed in late 2022 or early 2023. The PUD will use electricity generated by its 840-MW Wells Dam, located on the Columbia River, to produce hydrogen from river water.

Global Campaign

According to its website, FFI seeks to produce 15 million tons of green hydrogen worldwide by 2030. The company in the last year has entered various partnerships across the globe in order to hit that target.

In October 2021, FFI and Plug Power announced a 50-50 joint venture to build a 2-GW factory in Queensland, Australia, to produce large-scale proton exchange membrane (PEM) electrolyzers, “with the ability to expand into fuel cell systems and other hydrogen-related refueling and storage infrastructure in the future.”

In November, the company said it was seeking to invest $8 billion in a project in Argentina’s Río Negro province that would produce 35,000 tons of green hydrogen by 2024, increasing to 2.2 million tons by 2030.

And in March, FFI and European energy giant E.ON said they were looking to partner on an effort to deliver up to 5 million tons of green hydrogen to Europe per year, seemingly from supplies produced in Australia.

“Green energy will reduce fossil fuel consumption dramatically in Germany and quickly help substitute Russian energy supply, while creating a massive new employment intensive industry in Australia. This is a cohesive and urgently needed part of the green industrial revolution underway here in Europe,” Forrest said in a press release announcing the partnership.

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Maine Community Program Preps New Round of Emissions, Resilience Grants

Maine’s Community Resilience Partnership (CRP) will open a new grant round next month to help communities reduce carbon emissions, develop clean energy and build climate resilience.

The funding is “the heart” of the Maine Climate Council’s work, Hannah Pingree, director of the Governor’s Office of Policy Innovation and the Future (GOPIF), said during the council’s quarterly meeting Thursday.

Maine Climate Grants Map (Maine Community Resilience Partnership) Content.jpgA map demonstrating the geographic diversity of climate-related community grants awarded by Maine’s Community Resilience Partnership in April | Maine Community Resilience Partnership

“The actions that communities can take [with the funding] are almost all the actions of the state’s climate action plan, so we’re asking communities to consider anything that they would prioritize as the most important thing to them, and the state is finding ways to help,” she said.

Maine Gov. Janet Mills launched the CRP in December with an initial $4.75 million in grants that are being administered through three award rounds.

Funding for the program is part of the state’s general fund, and additional grants will likely become available beyond the first three rounds, Brian Ambrette, senior climate resilience coordinator at the GOPIF, said during the meeting. Ambrette expects that the CRP will initiate the third round by next spring.

Community grants are available for greenhouse gas emissions-reducing projects related to electric vehicle infrastructure, clean heating and cooling for buildings, clean energy codes, renewable energy permitting and ordinances, green power purchases, renewable energy facility deployment, and emissions tracking.

On April 22, the partnership awarded $2.5 million in grants that support communities directly through project funding and indirectly through service provider and regional coordinator funding. Awardees received $500,000 for projects that will help reduce GHG emissions.

The projects include:

      • electrifying the transportation network in Bangor;
      • installing public EV chargers in Bar Harbor, Mount Desert, Tremont and Carrabassett Valley;
      • purchasing an electric school bus in Bridgton;
      • purchasing a solar array in Limestone;
      • tracking GHG emissions in Orono and Windham; and
      • installing heat pumps in certain town buildings in Waterford.

Additional awards from the first round will help 12 service providers work with 46 communities to enroll in the CRP and apply for grants in the next rounds, Ambrette said.

“We’re looking forward to communities building some best practices and having some lessons learned that they can share once their grants are concluded,” he said.

To help educate communities about options for reducing emissions and building resilience, the Climate Council will host its first conference on June 17 in Augusta.

Representatives of communities that are already taking climate action will share “practical tips and insights” with attendees for initiating climate-related projects and making investments that reduce building and transportation emissions, said Sarah Curran, deputy director of climate planning and community partnerships at the GOPIF.

The council will release additional registration, speaker and program details this week.

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Response to Russian Invasion Undermining Budget Reconciliation Effort, Former Murkowski Aide Says

WASHINGTON — Efforts by Sen. Joe Manchin (D-W.Va.) and Sen. Lisa Murkowski (R-Alaska) to craft an energy bill in response to Russia’s invasion of Ukraine is threatening Democratic hopes for a party-line budget reconciliation bill with tax breaks for renewables and storage, a former Murkowski aide told the Energy Bar Association annual meeting last week.

Manchin, chair of the Senate Energy and Natural Resources Committee, began work on the bipartisan bill last month after rejecting the Biden administration’s proposed $2 trillion Build Back Better budget reconciliation package in December. (See Manchin Says ‘No’ on Build Back Better.)

Kellie Donnelly, executive vice president and general counsel for government affairs and communications firm Lot Sixteen and former chief counsel for the committee, said the two senators and other members of Congress have met several times.

Manchin “is very interested in crafting a new bill on energy and climate, and he wants to model this on [the Infrastructure Investment and Jobs Act]. So he wants this to be a bipartisan bill that goes through regular order … not using the budget reconciliation process,” she said in remarks at the EBA general session May 10.

“There’s been some paper that has been shared at those meetings but no outline that has officially come out yet about what the bill would look like. I imagine a bill would have increased domestic [oil and gas] production, probably increased production of critical minerals,” she said, adding that it could be a vehicle for transmission-related policies that couldn’t get carried in a budget reconciliation bill.

“But really, this kind of detour on energy and climate is taking the focus — really the oxygen — out of the effort on the budget reconciliation bill,” Donnelly said. “And it’s hard to see what Sen. Manchin is doing right now getting traction. [Manchin’s] committee does not have tax writing authority, so none of the taxes could really carry on this new bill, unless there was agreement from the Finance Committee and leadership. … But it’s my understanding that [the] Democratic leadership still wants to proceed with budget reconciliation.”

A budget reconciliation package would have to be completed by the end of September.

“If reconciliation fails … the end-of-the-year play is really going to be a tax extenders package. This will be a post-election, lame duck Congress,” she continued. “There’s going to be a lot of industry pressure on the [Biden] administration and on Congress to move the tax extenders package. And really, what I think it’ll come down to is the scope and duration of that package. You know, how long is it going to be? We’ve seen a lot of these end of year tax extenders, but only one to two years. You’re not going to get the 10-year budget window that they have in reconciliation. You’re not going to get the transition to a technology-neutral clean energy tax credit.”

Glick Renomination

Donnelly also discussed the risk that FERC’s rulemakings on transmission planning, cost allocation and interconnection policies could falter if Glick is not renominated soon for a second term. Although his term expires June 30, he could continue serving until the end of the year absent a replacement.

“Over the years, we’ve seen the loss of a working quorum, and we’ve seen tie votes at the commission literally tie up commission actions,” she said. “It’s a little nerve wracking … because, of course, for rulemakings, tie votes fail. I hope that we will see a Glick renomination soon, because without it, the administration [has] really risked their transmission agenda.”

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OMS Drafting Letter over MISO Resource Adequacy Concerns

The Organization of MISO States is preparing a letter to MISO leadership to stress resource adequacy work following the Midwestern capacity shortage revealed in last month’s capacity auction.

State regulators discussed the draft letter — not yet public — at an OMS Board of Directors meeting Thursday.

As described by OMS leadership, the letter will emphasize an urgency for continued work and collaboration on resource adequacy within in the footprint, the role MISO plays ahead of its capacity auctions and the need to work together. It will also express concerns with the “surprising nature of the auction results,” according to OMS Executive Director Marcus Hawkins.

MISO’s 2022/23 Planning Resource Auction (PRA) failed to secure enough capacity in its Midwestern zones, which cleared at the cost of entry for new generation. Now, MISO Midwest faces the possibility of rolling outages in the 2022/23 planning year, which begins June 1. (See MISO’s 2022/23 Capacity Auction Lays Bare Shortfalls in Midwest.) Though members approached the auction with more capacity year-over-year, MISO said the resource additions were mostly intermittent and generally less available than retiring thermal generators.

OMS President and Indiana Utility Regulatory Commissioner Sarah Freeman said the organization has notified MISO CEO John Bear that it is composing the letter. It’s not clear if the letter will contain any specific requests to the RTO.

“The PRA honestly showed us a lot of things,” Freeman said.

North Dakota Public Service Commissioner Julie Fedorchak said OMS must approach any recommendations following the capacity deficit “delicately” because resource planning is the states’ arena. But she said she worries at times that states are too protective of that arena.

“We can’t protect our customers from being curtailed when we’re part of a regional grid. … The reality is we’re beholden to everyone else,” Fedorchak told her fellow regulators. She said MISO should ensure its price signals are efficient, its supply data are correct and that it manages “markets that effectively reward resources when they’re there when we need them.”

“We are very concerned. How do we protect our customers in Iowa? Iowa is a net exporter of power, but that doesn’t protect us,” Iowa Utilities Board Commissioner Richard Lozier agreed.

OMS plans to refine wording of the letter in upcoming nonpublic spring meetings. Later this month, OMS will release its annual resource adequacy survey results in conjunction with MISO.

Summer Concern, Winterization Talk

In spite of looming summer concerns, OMS members also heard an update on MISO’s preparations for new NERC winterization standards at the meeting.

Bobbi Welch, MISO principal adviser of standards and assurance, said the first round of standards set to go into effect April 2023 involve preparedness, operations training and better communications coordination. (See FERC Approves Cold Weather Standards.)

A second round of standards in response to the February 2021 winter storm will likely involve asset investments, including insulation and heaters, Welch said. (See FERC, NERC Release Final Texas Storm Report.)

Of the 28 recommendations FERC and NERC most recently proposed — 37, counting the multipart recommendations — MISO has found 13 that directly apply to its operations. A few of these are being addressed as part of NERC’s development of more standards.

MISO has also already addressed a few of the recommendations, including improving near-term load forecasting, incorporating intermittent resource output in load forecasting and more quickly reporting generation and transmission derates and outages during emergencies. These were in response to the January 2018 Southern cold snap, which prompted the new standards.

Welch said MISO now has two meteorologists on staff to better forecast weather conditions.

On some fronts, there’s more work to do, including more accurately predicting reserve margins, performing bi-directional seasonal transfer studies and determining how generators should be compensated for winterization investments, among other items.

MISO must also work on guidelines for critical natural gas facility loads in the footprint. Welch pointed out that the footprint contains 36 pipelines and several different state jurisdictions, making standardized pipeline notifications and a prioritized method of gas circuit shutdowns more of a challenge than in single-state ISOs.

Welch said that in some instances, grid operators rationing electricity supply in cold-weather events have inadvertently cut off electricity to circuits fueling critical natural gas facility loads including power plants, thus worsening blackouts. She said industry efforts are underway to identify the locations of critical natural gas infrastructure facilities so that these circuits remain energized when there is a need to shed load.

She also said MISO has recently begun studying its emerging and atypical east-to-west flow patterns, as well as its neighbors’ flow patterns, during recent cold-weather events.

MISO will give progress reports on its road to compliance with the cold-weather standards at upcoming Reliability Subcommittee meetings, Welch said.

“It’s a very tight development timeline,” she told state regulators.

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Tesla Ineligibility to Shake up Calif. Clean Vehicle Rebate Program

A price increase for certain Tesla models has made the cars ineligible for California’s clean vehicle rebate incentives, a change that could slash short-term demand for the incentive by nearly 60%, according to data presented last week.

Tesla hiked the MSRP for its Model 3 and Model Y on March 15, and Tesla vehicles are no longer eligible for the rebate, according to the Clean Vehicle Rebate Project (CVRP) website.

The program sets a cap of $45,000 on the manufacturer’s suggested retail price (MSRP) for electric cars. The MSRP cap for SUVs, trucks and vans is $60,000. The Tesla price increase in March brought the price of the least expensive Model 3 to $46,990, according to news reports.

The rebates are available for new battery electric vehicles, fuel cell vehicles and plug-in hybrids, and range from $1,000 to $7,000, based on the buyer’s income and vehicle type.

The California Air Resources Board (CARB) held a work group meeting on May 11 to discuss CVRP.

The Tesla ineligibility is projected to decrease CVRP applications for battery-electric vehicles by about 70%, and by about 59% for the program overall, Francis Alvarez, a research analyst at the Center for Sustainable Energy, said during the workshop.

“The 83% to 88% of funds going to Tesla vehicles will become available over time, likely reducing program use initially and then normalizing again as other products fill the gap,” Alvarez said in his presentation.

CVRP Changes

The Tesla ineligibility was one of several changes to the CVRP program that were discussed during last week’s workshop.

The CARB board in November approved $515 million in funding for CVRP, intended to last for three years. At the same time, the agency is planning to ramp down the program as ZEV adoption increases, while shifting the focus to lower-income car buyers.

A first set of changes was implemented in February, when statewide ZEV sales topped 1 million.

The annual income cap for car buyers dropped to $135,000 for single tax filers, down from $150,000 previously. The new MSRP cap of $45,000 is a decrease from $60,000.

Another round of changes is proposed for when ZEV sales hit 1.25 million, a milestone expected in February 2023. The income cap would drop further, plug-in hybrids would lose eligibility and the rebate amount could be reduced.

CARB is still gathering feedback on the proposed changes and watching ZEV sales trends, and the agency could decide not to implement the second phase.

Other potential changes to the program include giving rebate recipients a prepaid card to use for EV charging, in a yet-to-be-determined amount. Another possibility is to expand car-buyer prequalification so that low-income buyers could use the incentive at the point of purchase.

“In making changes to the program, we also want to make sure that we leave some funding on the table for future model releases,” said Raquel Leon in CARB’s Innovative Light-Duty Strategies Section.

Rebate Perspectives

Some workshop attendees supported holding off on CVRP changes proposed for February 2023.

“Continued programmatic changes to this program as well as other rebate programs create confusion among dealers as well as consumers,” said Anthony Bento, director of legal and regulatory affairs at the California New Car Dealers Association. “I think we need to be very cautious on making further changes.”

Eileen Tutt, executive director of the California Electric Transportation Coalition, said it’s clear that CVRP is about to become undersubscribed. Not only should the second phase of changes be dropped, she said, but the income cap should be returned to the pre-February levels.

Tutt said she knows people who were interested in buying an EV but went with a conventional vehicle after losing CVRP eligibility because of the income cap decrease.

“As we move into a 100% ZEV requirement and we really need every single person … to pick an electric vehicle, now is not the time to make it ineligible to a very large group of people,” Tutt said.

CARB staff said a second work group meeting may be scheduled in coming weeks. The agency expects to release a draft funding proposal for clean transportation incentives in mid-July.

The funding plan, which would include proposed changes to CVRP, would then go to the CARB board for approval in November.

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US and Canada Working to Deepen Energy Collaboration

Jennifer Granholm (CSIS) FI.jpgU.S. Secretary of Energy Jennifer Granholm | CSIS

U.S. Secretary of Energy Jennifer Granholm on Thursday decried efforts by some Maine residents to stop a state-approved New England Clean Energy Connect (NECEC) power transmission corridor that would link Hydro Quebec to New England.

“Hydro Quebec wants to make sure that they are able to deliver … hydropower, and a state votes against it, and that state is a critical state to be able to make that connection to the Northeast. It’s extremely frustrating because it’s left in the hands of local interests,” Granholm said without mentioning the state by name.

“We should take local interests into account, but sometimes those local interests are funded by bigger interests that don’t have necessarily the big goal of getting to 100% clean electricity,” she added in a reference to utility funding of a successful grassroots referendum drive to block the construction of an already-approved transmission line through Maine delivering Canadian hydro power to Massachusetts.

Granholm’s remarks came during an energy policy discussion with Canadian Minister of Natural Resources Jonathan Wilkinson and sponsored by the D.C.-based Center for Strategic and International Studies.

The comments also came just two days after the Maine Supreme Court heard arguments in the appeal of a lower court decision to vacate a 1-mile lease of public land for the project, halting construction of the entire corridor. (See Maine Supreme Court Hears Entangling Arguments in NECEC Appeals.)

The fight over the transmission corridor is an early warning of battles to come as the Biden administration backs utility efforts to build new transmission carrying renewable power to demand centers — key to its goal to sharply reduce power plant carbon emissions by moving to wind, solar and other renewable generating technologies.

“The barriers have always been on deployment of electricity. It’s always about the grid. And it’s always about the local NIMBY permitting challenges,” Granholm added.

She said the administration does have a new tool, a provision in the bipartisan Infrastructure Investment and Jobs Act that “allows the DOE to take a position of offtake so that those builders of transmission lines can feel some comfort that they are not going to be left holding the bag.” (See DOE Seeks Input on Tx Loan, ‘Anchor Tenant’ Programs.)

“Then we get paid back as they fill up the rest of the line,” she explained in a reference to other off takers of power flowing through a new transmission line.

“It’s a revolving fund,” she explained of the $2.5 billion allocated in the legislation to help jump start new transmission projects. “It’s a new mechanism that we’ve never used before … to ensure that we can actually get transmission [projects] going.”

“The opportunity is just so powerful to have a North American powerhouse … of an alignment on clean energy deployment and technology development,” Granholm said.

“I raised that because I think that all of our desire for peace in the world, so much of that can rest upon our movement to clean energy.

“If we are successful in converting our energy to clean, [we] can create energy security, not just for our individual countries, but around the world. We will not be under the thumb of petro-dictators. It could be a great peace plan, and that I think is a great aspiration.”

Wilkinson, in Washington to discuss energy security and climate change, said the two issues are “ultimately linked.”

“You often hear in Canada, and I assume it’s probably the case in the United States, the two polar kinds of views on this, which are: energy security has come to the fore [because] it’s so important [and] we should forget about climate change.

“On the other hand, you have voices who say climate change is an existential threat. It’s so important that you should essentially forget about energy security, at least as it relates to helping our friends and in Europe.

“There is a way for us to think about these things as being complementary, that we can work towards addressing the short-term energy security issues that have come out of Russia, that are arising from shifts in geopolitics generally,” he said.

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PJM Monitor: LMP Rose to Near Record in Q1

Energy prices in PJM increased by 75.5% in the first quarter of 2022 from a year ago, the Independent Market Monitor reported Thursday, driven primarily by higher fuel costs.

In its Q1 State of the Market Report for PJM, the Monitor said the real-time load-weighted average LMP increased from $30.84/MWh to $54.13/MWh. This is the highest first-quarter price since the polar vortex in the first quarter of 2014, the Monitor said, and the third highest increase in first-quarter LMP since the start of PJM markets in 1999. The second highest price occurred in 2003, when winter load increased and natural gas prices doubled to above $8/dekatherm that year.

Of the $23.29/MWh increase, 49% was directly from higher fuel and emission costs, especially higher natural gas prices. Both coal and natural gas prices were higher in the first quarter of 2022 compared to 2021, with prices doubling in the eastern part of the RTO.

Real-time hourly average loads in the first quarter increased by 2.4% from 2021, going from 89,887 MWh to 92,007 MWh. The total price of wholesale power increased from $53.30/MWh in the first quarter of 2021 to $80.28/MWh in 2022, an increase of 50.6%. Generation from coal units decreased 3.1% in the first quarter, while generation from natural gas units increased 6.9% compared to the first three months of 2021.

Monitor Joe Bowring said that despite the increased energy prices, PJM’s wholesale electric energy market produced competitive results in the first quarter.

“The steadily increasing role of gas-fired generation and the declining role of coal highlight the importance of ensuring that PJM has real-time, detailed and complete information on the gas supply arrangements of all generators and that PJM consider rules requiring capacity resources to have firm fuel supplies,” the Monitor said in its report. “It is also essential that FERC consider and address the implications of the inconsistencies between the gas pipeline business model and the power producer business model and the issue of market power in the gas markets under extreme weather conditions.”

Theoretical net revenues from the energy market increased for all unit types in the first quarter, the Monitor said, with theoretical energy net revenues increasing by 145% for a new combustion turbine, 94% for a new combined cycle, 54% for a new coal unit and 75% for a new nuclear plant.

Total energy uplift charges decreased by $5.9 million, or 17.2%, in the first quarter, going from $34.3 million in 2021 to $28.4 million.

Total congestion prices increased by $389.2 million, or 321.5%, going from $121.1 million in 2021 to $510.3 million in 2022. The Monitor said only 31.9% of total congestion paid by customers for the first 10 months of the 2021/2022 planning period was returned to customers through the auction revenue rights and self-scheduled financial transmission right revenues offset.

“Congestion belongs to customers and should be returned to customers,” the Monitor said. “The goal of the FTR market design should be to ensure that customers have the rights to 100% of the congestion that customers pay.”

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NERC Board of Trustees/MRC Briefs: May 11-12, 2022

Positive COVID-19 Test Prompts Return to Virtual Sessions

Multiple attendees at NERC’s Board of Trustees and Member Representatives Committee meetings this week praised the organization’s staff after a last-minute pivot from what would have been the groups’ first in-person gathering in more than two years into yet another virtual session.

The meetings — along with those of NERC’s Finance and Audit Committee, Technology and Security Committee, and Corporate Governance and Human Resources Committee — were to have been held on Wednesday and Thursday in Arlington, Va. (See “Face-to-face Meetings to Return in May,” NERC Board of Trustees/MRC Briefs: Feb. 10, 2022.) However, after an attendee tested positive for COVID-19 at the conference site Tuesday morning, NERC announced that all events would be held virtually, following up with webconference links the same day.

Speaking at the MRC meeting on Wednesday, Board Chair Ken DeFontes acknowledged that the events of the past two days were another reminder of the ongoing pandemic. He said NERC still intends to hold the August and November meetings in Vancouver, Canada, and New Orleans, respectively, though with appropriate precautions in place.

“There’s no question that we’re not done with COVID yet, and we saw the evidence of that this week,” DeFontes said. “So we are thinking about how we can shape that meeting to encourage people to come, but at the same time be prepared in the event that we have to do another virtual setup, maybe even try to look at some hybrid options.”

Standards Actions

The board voted to approve the new reliability standards FAC-001-4 (Facility interconnection requirements) and FAC-002-4 (Facility interconnection studies), bringing to an end the work of Project 2020-05.

The project began nearly two years ago with the aim of modifying FAC-001-3 and FAC-002-3. The former standard requires transmission owners and generator owners to “document and make facility interconnection requirements available,” while the latter requires GOs to “study the impact of interconnecting new or changed facilities on the bulk electric system.”

At issue with the standards was the term “materially modified,” which both FAC-001-3 and FAC-002-3 implied should be used to determine what facility changes should be studied and which should not. However, neither standard said who would determine what counts as a material modification. The existing language also created confusion with FERC’s open access transmission tariff implementation, because in FERC-jurisdictional areas, “material modification” means the impact of a new generation project on other generators in the interconnection queue.

To address these issues, the revised standards replace the phrase “materially modified” with “qualified change” throughout. In addition, a new requirement in FAC-002-4 specifies that the planning coordinator will define what constitutes a qualified change and will make the definition publicly available.

After the board accepted the new standards, Howard Gugel, NERC’s vice president of engineering and standards, delivered an update on Project 2021-07, which NERC began last year in response to the joint FERC-NERC report on the winter storms that knocked thousands of megawatts of capacity offline in Texas and the Midwest. (See NERC Standards Committee Agrees to New Cold Weather Project.)

According to Gugel, the standard drafting team (SDT) has completed an initial draft of the new standards and plans to submit it to the Standards Committee at its meeting next week for initial formal comment and ballot period. The SDT is further requesting that the comment period be reduced to 30 days from the standard 45, in hopes of finishing the standard and submitting it to FERC for approval as soon as possible.

Summer Assessment Highlights Risks in Texas, West

Large parts of North America face “elevated or high risk of energy shortfalls during peak summer conditions,” according to NERC’s upcoming Summer Reliability Assessment, due to be released next week. NERC staff previewed the assessment, along with the 2022 Long-term Reliability Assessment, during Thursday’s board meeting.

As Mark Olson, NERC’s manager of reliability assessments, explained, droughts and heat events are a major concern across the Western Interconnection and Texas.

In WECC’s footprint, these risks take the form of depleted water resources for hydroelectric generators, as well as “another active wildfire season,” Olson said. Extreme heat in Texas raises the potential for demand-related shortfalls, while thermal generators may face challenges in SPP because of lowered river water levels.

MISO faces potential shortages because of a 2.3% reduction in generation capacity since last year. Olson said extreme temperatures, high generation outages or low wind conditions could lead to outages even at normal peak demand. The assessment rates the region as the highest risk in North America.

New Québec Agreement Approved

The board also approved revisions and amendments to the agreement between NERC, the Northeast Power Coordinating Council and Québec’s Régie de l’énergie.

The existing agreement, originally approved in 2014, spells out how NERC’s Compliance Monitoring and Enforcement Program (CMEP) activities will be carried out in the Canadian province, along with establishing a Québec-specific CMEP (QCMEP). NERC, NPCC and the Régie agreed to modify the document in 2020.

The new agreement includes the following changes:

    • NPCC, NERC and the Régie may update the QCMEP without seeking approval from Québec’s government.
    • Duplicative terms have been removed, along with specific processes that are already addressed in the QCMEP.
    • Another regional entity may take over NPCC’s responsibilities if it dissolves or otherwise cannot perform them.
    • Billing of simultaneous interpretation as needed for audits is permitted.
    • A mediation and arbitration clause was added.

NERC also said the agreement contains unspecified “other administrative changes.” With the board’s approval, all that is left for the document to take effect is the acceptance of Québec’s authorities.