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December 27, 2025

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New York Preps Statewide GHG Emissions Report

New York officials on Monday held the first of three public hearings as they prepare the first annual report of statewide greenhouse gas emissions required by the state’s Climate Leadership and Community Protection Act (CLCPA).

The state Department of Environmental Conservation (DEC) is preparing the report to be issued this year and is seeking public input on its format and the methodology used to determine annual statewide GHG emission levels.

“There is no deadline at all for public input, but if you really want to inform the annual report you should get it in by May,” Suzanne Hagell, climate change policy analyst at the DEC’s Office of Climate Change, said. A second hearing on Friday will cover oil and gas emissions accounting, and the third hearing on Monday will cover net emissions accounting.

The CLCPA mandates that GHG emissions be reduced to 40% of 1990 levels by 2030 and 85% by 2050. It directs the DEC to measure emissions on a common scale using the carbon dioxide equivalence metric and the 20-year global warming potential of each gas, as derived from the U.N.’s Intergovernmental Panel on Climate Change.

The DEC in October completed its public hearing process on the (Part 496) emissions limits and in December finalized the regulations to reduce GHG emissions, the first regulatory requirement of the climate law. (See New York Holds Final CLCPA Emissions Hearings.)

EPA Model

The department is basing its report on the EPA draft Inventory of U.S. Greenhouse Gas Emissions and Sinks from 1990-2019, the final version of which will be published in April.

Inventorying manufacturing emissions would depend on their type, which may be confusing for industries with emissions that go under different categories, Hagell said. For example, CO2 emitted from a foundry would fall under the category of “industrial process and product use,” while emissions associated with combustion of fuel to drive or energize the process would go under “energy.” “I’d love input on how the EPA takes these emissions and categorizes them in different ways to present them for a different purpose, like for economic sectors as opposed to emissions sectors,” she said. “If there is something that is particularly helpful for New York state, a different way of organizing, we can always organize in multiple ways and provide figures in this report that would be helpful for the purpose of policy.”

Officials can evaluate whether to include the social cost of carbon in the GHG emissions report, though they are not aware of any other jurisdiction doing so, she said. Also, emissions data will not be reported at the county level, as such data is not always reported at a granular level and a hydrofluorocarbon inventory is not yet available.

The state is working to cut GHG emissions (including methane and hydrofluorocarbons) from buildings, food waste and other sources outside the power and transportation sectors, and data in the report will reflect that goal. (See NY Proposes Food Scrap Regs to Cut Waste, Emissions.)

In addition, the state plans to collect data on non-GHG emissions, such as particulate matter (PM2.5).

“We do calculate emissions from heating fuel use as well as from a host of other categories, and several pollutants from each,” Ona Papageorgiou, DEC chief of mobile source and climate change planning, said. “There are criteria pollutants as well as some others that may be included, and PM2.5 is part of that.”

Feedback may be provided at any time and can be mailed to DEC Office of Climate Change, 625 Broadway, Albany, NY 12233-1550 or emailed to [email protected] Include “Annual Report” in the subject line of the email.

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NY Kicks Off ‘Dynamic’ Great Lakes Wind Study

New York has launched a study to identify how the state could tap wind resources on Lake Ontario and Lake Erie in meeting its climate goals.

The New York State Environmental and Research Development Authority assembled a team to complete a Great Lakes wind power feasibility study for release early next year, Gregory Lampman, environmental research program manager, said Friday.

A variety of factors concerning citing on the two lakes suggest the “study needs to be very dynamic,” Lampman said during a public outreach webinar.

“Certain site conditions will allow for fixed foundations, while other site conditions may require floating foundations, or they may be on different development timelines, and as a result the timing in which they would come into play will be different,” he said.

The New York State Public Service Commission directed NYSERDA in an October order to conduct the study with a $1 million budget.

NYSERDA retained the National Renewable Energy Laboratory to coordinate the report in conjunction with Pterra, Brattle Group and Advisian Worley Group.

New York Great Lakes Wind Study
Viewshed analyses in NYSERDA’s Great Lakes wind feasibility study will show what turbines might look like on Lake Ontario from popular destinations like Rochester’s Charlotte Pier. | Magnolia677, CC BY-SA 3.0, via Wikimedia Commons

Pterra and Brattle will study grid infrastructure components of the study, while Advisian will cover environmental concerns and regulatory processes, Lampman said.

Friday’s webinar was the first in a series of outreach events NYSERDA has planned for this year. Dates for two webinars will be announced for the second and third quarters to provide an update on the study’s progress. Another webinar will be held in the fourth quarter when a draft of the study is completed.

Study Scope

NREL’s experience with floating wind turbines will inform the study’s review of the technologies that could be deployed in the Great Lakes.

The NREL team will look at the infrastructure and physical constraints associated with technology deployment and assess the timeline for new product developments, Lampman said. In addition, NREL will identify what site conditions, such as icing and wave action, will affect project development.

Technology selections and location of deployments play into costs and generation opportunities, Lampman said, adding that NREL will define how costs fit into any potential project portfolio.

The study will also help the state understand what it can do to advance the development of offshore technologies and “capture the economic development opportunities,” he said.

Pterra and the Brattle Group will bring their regional grid and interconnection expertise to the study.

Their primary focus will be on the interconnection opportunities associated with existing infrastructure to ensure that projects can deliver energy cost-effectively, Lampman said.

Advisian will be addressing a diverse set of factors, such as permitting and interconnection applications.

While permitting processes exist for offshore wind, Lampman said Advisian would address, for example, interregional issues within those processes and concerns about how to gain site control in the lakes.

The group will also address avian risks and work to present pathways to development that consider the needs of other waterway constituents, such as the shipping, fishing and recreational communities.

Further analysis will be provided on historical and cultural areas and public health benefits of the projects themselves, as well as visual impacts from the wind turbines.

Lampman said the scope of the project does not cover collecting new site condition information.

The study, he said, will be based on existing data that will be analyzed “in new ways to inform thinking.”

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Republican-backed Bill Seeks Clear Path for Ind. Renewables

A Republican-backed bill making its way through the Indiana legislature seeks to spur wind and solar development by setting statewide zoning standards for projects, overriding county ordinances that have obstructed renewable development.

House Bill 1381, now pending in the state Senate, would eliminate the application of Indiana’s “home rule” policy in relation to commercial wind and solar development. That policy provides counties “all the powers that they need for the effective operation of government as to local affairs,” according to Indiana Code.

The bill would instead require counties to adhere to statewide zoning standards for renewable energy farms, including uniform setback requirements, height restrictions, sound level and shadow flicker limitations and decommissioning.

It also stipulates that local authorities cannot impose “standards that are more restrictive than the default standards that are adopted in this bill.” If adopted, the rules would be in place by the beginning of July.

Of Indiana’s 92 counties, 34 have ordinances restricting wind and solar projects. Some, such as Tippecanoe County, have effectively banned commercial wind projects by prohibiting turbines taller than 140 feet.

The legislation comes from an unlikely source, Rep. Ed Soliday (R), a longtime champion of coal generation. Last year, Soliday authored a successful bill that prolongs the process of retiring or selling coal plants within the state by requiring six months’ notice, a public hearing and analysis on the reasonableness of the closure. (See Indiana Senate to Contemplate Slowdown of Coal Closures.)

Soliday said HB 1381 is not a pro-environment declaration, but a necessary response to market forces.

“There is a significant market for renewable energy. The state of Indiana, on some days, is buying almost 80% of our electricity from out of state,” Soliday said at a February hearing of the state’s House Committee on Utilities, Energy and Telecommunications. He said Indiana’s largest manufacturers want renewable generation.

“And they’re going to get it,” he said. “They’re going to get it either by buying it from other folks and paying the transmission costs, or we’re going to generate some of it.”

Other Republican representatives are starting to realize that Indiana cannot subsist on a diet of coal alone. Joining Soliday in co-authoring the bill were another Republican and a Democrat. The legislation attracted two Republican sponsors.

“There is an issue with the number of counties who have either outright banned or have in effect banned large-scale renewable projects,” Rep. Ethan Manning (R) said during a Fulton County Chamber of Commerce meeting in January.

Manning said the bill does “still contain an aspect of local control” because local governments are still able to determine whether a project meets state standards.

Utilities are moving away from coal because of aging plants and economics, he said, adding that it doesn’t make financial sense to keep upgrading antique plants.

“As they move away from that reliable baseload generation, what they’re looking towards is renewables. And we can’t really stop that. I mean, we could I guess, but that would be interfering with the free market,” Manning said. “No matter what happens with coal in the future, they’re going to continue to want to build wind and solar. And I don’t want all of Indiana’s energy to come from other states.”

Hoosier Environmental Council (HEC) Executive Director Jesse Kharbanda said the bill could reverse the renewable development deadlock in some counties.

“Were HB 1381 to pass, we definitely believe that it will cause renewables developers to think anew of counties that previously had bans, as several of those counties have excellent renewable energy resources,” Kharbanda told NetZero Insider.  “Furthermore, attitudes in those communities may have shifted, due to new local leadership, greater awareness of renewable energy’s economic benefits and continuing improvement in renewables technology that address past community concerns.”

Kharbanda said Republican backers of the bill are thinking “first and foremost” of the economic development that it will facilitate.

Indiana has attracted about $7 billion in utility-scale renewables, he said, “even in the absence of a renewable electricity standard.” He added that the state “is poised to attract considerably more dollars” based on utilities’ integrated resource plans, which ramp up renewable adoption throughout this decade.

‘Disjointed Patchwork’

Several counties are labeling the bill government overreach.

Henry County Council President Susan Huhn traveled to Indianapolis in early February to testify against the rule in a committee hearing.

Commissioners in Kosciusko and White counties passed resolutions in February and March, respectively, to oppose the bill.

Kosciusko County commissioners said the bill “disenfranchises” citizens from making their own land-use decisions.

The White County Commissioners’ resolution states that they “believe that decisions regarding wind and solar development are best made by the citizens living in the community, rather than by the wind and solar industry or state officials who live outside the community.”

Kharbanda said when local control turns to overt embargoes on renewable development, it’s time for the state to step in.

“When local control — like outright bans on utility-scale renewables in certain counties — interfere with good, long-term state public policy, such as a stable investment climate to facilitate the timely expansion of the renewable energy industry, then statewide policy is appropriate to take precedence over local policy,” he said.

Kharbanda said many aspects of wind and solar farm design are “unlikely to meaningfully vary due to the geographic particularities of a community” and “lend themselves to statewide standards … provided that those standards are shaped by the very latest and best science.”

RWE Renewables Director of Government Relations Will Eberle called the state “uniquely unfriendly” to the growing renewable industry and said the standalone ordinances have deterred about $5.5 billion in renewable energy investment in the state.

“Indiana has, until now, left its renewable energy future up to a disjointed patchwork of local government regulation,” Eberle said in committee testimony earlier this year.

RWE Renewables last year terminated a $600 million, 400-MW project in Gibson and Posey counties, which enacted stricter zoning rules after the project was proposed. The rules — sound and shadow flicker restrictions, setbacks of 4.4 times the height of a wind turbine and banning turbines closer than two miles from towns, schools, hospitals, clinics and residential care facilities — caused RWE to scrap its plans.

Kharbanda said HEC hopes the bill can clear Indiana’s Republican-led Senate.

“The prospects look challenging given the number of counties that have individually expressed their opposition to the bill,” he said, adding that the renewables industry “for reasons we’re unsure of, opted to not pursue a grand coalition strategy in their efforts to advance HB 1381.”

Kharbanda said while HEC is generally supportive of the bill, he’d like to see a change concerning groundcover standards under solar farms.

“The land footprint of solar farms in Indiana — by the end of this decade — could be on the order of Indiana’s state park system,” he said. “So making sure that the land underneath solar farms benefits the community as much as possible is so crucial, for the sake of pollinators, stormwater control, soil and water conservation and the aesthetics of the area.  We’ve been advocating, since the beginning of the legislative session, that Indiana either establish baseline standards for pollinator-friendly solar that are customized by local governments, or that Indiana allow counties to retain their authority over the groundcover in and around solar farms.”

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Public Skeptical of New FERC Participation Office

Aggrieved landowners across the country told FERC on Wednesday that they doubted its new Office of Public Participation (OPP) would improve the commission’s decision-making over natural gas infrastructure.

Still, many expressed gratitude to the commission for holding its first ever “listening session” and gathering input on the office, created in 1978 under the Public Utility Regulatory Policies Act but only recently given renewed attention by Congress at the end of last year. Under the Energy Act of 2020, FERC has until June 25 to issue a report on the office’s status, including its structure and budget. (See FERC Sets ‘Listening Sessions’ on New Office.)

The session — scheduled for an hour-and-a-half Wednesday and focused on landowners and impacted communities — lasted far longer than that, as more than 350 people each spoke for up to three minutes. The vast majority of these were landowners who had fought, many in vain, with gas companies exercising eminent domain to build pipelines, compressor stations and LNG facilities.

Many took the opportunity not to give their advice on OPP, but to criticize the commission for its ineffective public outreach, sounding similar complaints by protesters at commission headquarters over the years. They spoke of only learning about their properties being taken just before construction was to begin; of the commission’s poorly designed website and electronic filing process; and of traveling to scoping meetings hundreds of miles away to voice their concerns, only to feel ignored when a project was approved.

Citing these past experiences, speakers said they were deeply mistrustful of the commission, and they doubted a new office could fix that mistrust.

“FERC can never be trusted to make the right decisions based on fact,” said one speaker, a resident of Virginia in the path of the Mountain Valley Pipeline. He called OPP a “baby first step” toward improvement, but he ultimately dismissed it as a political stunt meant to stifle public protest.

FERC Participation Office
The under-construction Mountain Valley Pipeline | Chesapeake Climate Action Network

“The heart of the issue is there is no rational discourse with FERC,” said another speaker, a resident of New Jersey that would be impacted by the PennEast Pipeline. He dismissed OPP as “window dressing.”

“It will take a lot more than OPP for FERC to regain public trust,” another speaker said.

Without establishing trust, said a speaker from Pennsylvania, “OPP is just lipstick on a pig.”

Those that did give recommendations for the office shared similar concerns:

  • The director of the office should be someone with experience in community organizing and outreach.
  • The office should be overseen by an advisory board, made up of members both geographically and ethnically diverse and whose directions are legally binding.
  • FERC should “completely overhaul” (a phrase used by multiple speakers) its website and make filing comments on a project as easy as sending email.
  • OPP should hold far more scoping meetings in a variety of places around the impacted area to allow for more participation.

The session was the first of four FERC had planned. The next day, at the commission’s open meeting, Commissioner Allison Clements, whom Chair Richard Glick appointed to oversee the office’s institution, announced that staff were working on scheduling a fifth, to be held in the evening, as many speakers also complained about the time it was held (1 p.m. ET). As she did at the opening of the session, Clements asked the public for patience as staff learn as they go.

Clements called the session “a powerful experience” and said she had “already learned a great deal.”

“We heard people express anger, frustration, devastation and inequity,” she said. “And then we also heard people channel these experiences into productive recommendations for the commission to consider in setting up the office.”

Language Barriers

Clements also acknowledged that many complained about the lack of opportunities for Spanish speakers to participate in the session, and that FERC would try to hold a sixth session entirely in Spanish.

But during the second session, held Monday, speakers also urged FERC to translate all documents in the dominant languages of the region where a proposed project would be located. One speaker, representing the Houston-based Bayou City Waterkeeper, said that 140 languages are represented by the residents in the Galveston Bay area, with sizable populaces of Chinese and Vietnamese speakers.

This session ended at the hour-and-a-half mark on the dot, with some speakers able to queue up for a second turn. Though the session was intended to focus on environmental justice and indigenous communities, some speakers merely reiterated landowner concerns while paying lip service to those communities.

Those who did offer substantive comments on indigenous concerns stressed that “consultation is not consent,” and that FERC should not conflate the concerns of these communities with those of their tribal governments. They also urged the commission to make an effort to consult with tribes not federally recognized.

FERC Threatens $20M Fine

Several speakers in both sessions urged the commission to simply stop approving gas infrastructure projects — something that would take a highly unlikely act of Congress.

But on Thursday, FERC said it did assess, for the first time, the greenhouse gas emissions of a project and its impact on global climate change, finding it negligible. (See related story, FERC Assesses Climate Impact of Gas Project for 1st Time.)

The commission also ordered Energy Transfer Partners and Rover Pipeline to show cause why they should not be fined $20.2 million for misleading the commission regarding Rover’s destruction of a historic Ohio property (IN19-4).

The order includes a report by FERC’s Office of Enforcement alleging that during the application process for a certificate to build Rover’s $4.2 billion, 711-mile pipeline, the company misrepresented its intended treatment of a historic house in Dennison, Ohio, known as the Stoneman House.

Staff said Rover purchased the house in May 2015 and demolished it in May 2016 without notifying the commission.

“Rover stated that it was ‘committed to a solution that results in no adverse effects’ to the Stoneman House, an 1843 farmstead located near Rover’s largest proposed compressor station,” the commission said. “In truth, the OE staff report alleges Rover was simultaneously planning to purchase the house with the intent to demolish it, if necessary, to complete its pipeline.”

The order says that the commission has not adopted or endorsed the staff report. Rover has 30 days to respond.

Separately, FERC ordered Midship Pipeline Co. to resolve restoration issues along the right of way for the Midcontinent Supply Header Interstate Pipeline Project in Oklahoma (CP17-458, CP19-17). The commission said landowners have complained of ponding from trench subsidence, erosion, compaction, construction debris on-site, topsoil loss and lack of revegetation. The order said the commission “strongly recommends that Midship engage the commission’s dispute resolution service to assist in negotiations between Midship and certain landowners.”

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Va. Solar Farm Wins PJM MOPR Challenge

FERC last week found that the tax relief granted to a solar farm being constructed in Virginia does not fall under PJM’s minimum offer price rule (MOPR) or qualify as a state subsidy (EL21-35).

Hollow Road Solar, a 20-MW qualifying facility being developed in Frederick County, filed a petition with the commission seeking confirmation that it will not be subject to the MOPR in the upcoming Base Residual Auction (BRA) for the 2022/23 delivery year scheduled to take place in May. The project sought a determination that local property tax relief granted by a Virginia pollution control statute is exempt from the definition of a state subsidy under the MOPR.

The facility’s developers brought the petition to FERC after seeking guidance from PJM. They said the commission specifically exempted “general industrial development” and “local siting statutes” from the definition of state subsidy in recent MOPR orders, saying that comparable support was generally publicly available and not “tethered to” or “directed at” PJM’s wholesale capacity or energy markets. (See FERC Acts on PJM MOPR Filing.)

Hollow Road argued that the Virginia statute should be exempt from the MOPR because its benefits are available to all businesses and not “nearly directed at or tethered” to the “new entry” or “continued operation of generating capacity” in the PJM capacity market. It said the subsidy is focused on the control and abatement of pollution in Virginia.

state subsidy

Hollow Road Solar project | Frederick County Planning & Development

In its response, PJM said it previously examined the statute and proposed to stakeholders that it met the definition of a state subsidy under the tariff. The RTO said provisions of the statute have separate sections specifically addressing property tax exemption rules that applied only to standalone solar facilities.

In its December 2019 MOPR order, FERC said the definition of state subsidy focuses on out-of-market payments that “squarely impact the production of electricity or supply-side participation in PJM’s capacity market” and does not include “every form of state financial assistance that might indirectly affect commission-jurisdictional rates or transactions.”

The commission also allowed an exclusion for certain forms of state support that are “available to all businesses and not nearly directed at or tethered to the new entry or continued operation of generating capacity in the federally regulated multistate wholesale capacity market administered by PJM.”

In Thursday’s order, FERC said the Virginia provisions should be excluded from the definition of state subsidy because they apply “broadly to certified pollution control equipment and facilities” and not just those used in electricity generating facilities. Under the statute, certified equipment and facilities include “any property, including real or personal property, equipment, facilities or devices, used primarily for the purpose of abating or preventing pollution.”

“We find that the Virginia pollution control statute is generally available and not nearly directed at or tethered to wholesale market participation, and therefore excluded from the definition of state subsidy,” FERC said.

“The reference to solar facilities cited by PJM does not require a contrary conclusion,” the commission said. “Solar facilities are included as part of a non-exhaustive list of example technologies that also includes a wide range of equipment unrelated to electric generation or the PJM capacity market — everything from certain on-site sewage systems, thermal energy storage devices and ‘equipment used to grind, chip or mulch trees [and] tree stumps.’”

PJM’s Independent Market Monitor argued that the fact that some nonpower production entities may be eligible for tax relief under the law is “irrelevant for purposes of the MOPR” and that providing an exclusion for the statute would “create a loophole undermining implementation of the MOPR.”

The commission disagreed.

“The definition of state subsidy was never intended to cover every form of financial assistance,” FERC said. “Excluding the Virginia pollution control statute from the definition of state subsidy will not affect the applicability of the MOPR to those subsidies that it was intended to address.”

Commissioner Views

FERC Commissioner James Danly provided the lone vote against the petition, dissenting strongly in a separate statement.

Danly faulted the commission’s finding that the Virginia law’s subsidy is “generally available” because it includes other technologies such as sewage systems and tree chippers. He said most of those technologies had been included in the statute since 2003, but solar equipment was added by separate bills in 2014 and 2016.

The “overwhelming preponderance of statutory text” in the statute involves solar facilities, Danly said, including whole sections devoted solely to solar facilities and creating conditions for those facilities to receive tax relief.

“Our order today thus allows a subsidized solar facility to bypass the PJM minimum offer price rule and bid into the PJM Base Residual Auction below its actual costs,” Danly wrote. “The consequences for PJM’s capacity market prices are obvious. Every existing capacity resource in the applicable zone will suffer artificially low prices caused by new resources ‘competing’ on an uneven playing field.

“Many disagree that PJM should mitigate new renewable resources subsidized by the states, but the proper course is to change the mitigation rules (if in fact they need to be changed) rather than to declare that tax relief overwhelmingly directed at solar facilities is not really a subsidy directed at solar facilities because the tax relief may also be available to a wood chipper,” he said.

Commissioner Neil Chatterjee expressed appreciation for Danly’s reasoning and his “certitude” on the issue but said the majority opinion offered a “well explained, thoughtful analysis” and that he was “pleased” to support the ruling. He said Hollow Road’s petition gave the commission the opportunity to apply the MOPR rule “in a manner that’s both consistent with our prior findings and reflective of plain old common sense.”

“We’ve made clear along the way that the MOPR is not intended to address generally available state assistance, nor should it reach every program that may indirectly affect the economics of a particular resource,” Chatterjee said.

Technical Conference

FERC issued the ruling just before hosting a technical conference tomorrow at which it will lead stakeholders in a discussion of the role of capacity markets in Eastern RTOs and ISOs.

The first panel will explore the growing interplay between state policies and capacity markets and examine the long-run impact of continuing with the status quo MOPR framework.

A second panel will zero in on the implications of continuing the status quo MOPR in the PJM capacity market and consider the viability of the market with current rules as state policies continue to impact resources. FERC officials want to determine whether PJM can retain its responsibility for resource adequacy as states take measures to create their own energy resource mix.

A final panel will look at alternative approaches for the PJM capacity market and its evolution with changing state policies.

MOPR’s Outside Viewpoints

In a recent report titled “The Numbered Days of PJM’s MOPR-Ex?”, ClearView Energy Partners said PJM could change its market rules as early as this summer. Those changes could include a reversal or narrowing of the MOPR to be approved in time for the BRA for the 2022/23 delivery year scheduled to take place in December.

“We think that a smaller, more ‘residual’ capacity market looms as a real possibility over the next several years, unless an overarching federal program (such as a clean energy standard or substantive [greenhouse gas] limits) is enacted,” ClearView wrote in its report.

ClearView said it may be easier for PJM to allow its states to take on their own decarbonization goals through “bilateral arrangements” rather than attempting to create a solution for all the states in the RTO.

“Unless or until federal policy overtakes individual state agendas on decarbonization, meeting disparate needs through a centralized market appears destined to be problematic,” ClearView said.

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Appeals Court Backs NJ Nuclear Subsidies

A New Jersey Appellate Court on Friday dismissed a lawsuit seeking to block state subsidies for Public Service Enterprise Group’s Salem and Hope Creek nuclear plants, which paid the company $300 million last year.

The court ruled that there was nothing wrong with the process by which the state Board of Public Utilities (BPU) assessed whether Salem 1, Salem 2 and Hope Creek were eligible to take part in the state’s Zero-Emission Certificate (ZEC) program, and concluded that they deserved subsidies (A-3939-18).

The three-judge panel made its 47-page ruling in response to a suit filed by the New Jersey Division of Rate Counsel, which is charged with protecting ratepayers’ interests, to block the BPU’s 2019 subsidy award. The Rate Counsel argued that the award of ZEC’s to the three plants was arbitrary and capricious and that none of the three plants need the ZEC subsidies to remain financially viable.

New Jersey Nuclear
PSEG’s Hope Creek, Salem 1 and Salem 2 nuclear plants are receiving subsidies from New Jersey ratepayers. | Public Service Enterprise Group

The suit struck at the heart of New Jersey’s plan for nuclear energy to remain a key element of the state’s power generating system as it seeks to transition to carbon-free energy, much of which is still in the early development stage.

The ZEC program provides subsidies to nuclear power plants at risk of closure so that they can remain open to generate carbon-free power and help the state meet its goal of reducing greenhouse emissions by 80% by 2050. Gov. Phil Murphy has said he wants to the boost the share of energy generated by carbon-free resources to 50% by the end of the decade.

The Ruling and Future Subsidies

The Rate Counsel filed the appeal after the BPU on March 18, 2019, awarded ZEC’s to Hope Creek, which is owned and operated by PSEG and Salem 1 and 2, which PSEG operates and co-owns with Exelon. (See NJ Approves $300M ZECs for Salem, Hope Creek Nukes.) At the time, BPU Board President Joseph Fiordaliso said the plants provided 32% of the state’s energy mix and 90% of its clean energy.

The board rejected a conclusion by its staff evaluation team, which found that all three units would operate profitably through May 2022 and were therefore ineligible for the subsidies. PJM Monitor Sounds Market Power Alarms.)

But the BPU said the evaluation team improperly excluded from its calculations consideration of PSEG’s operational and market risks, as required by the legislation creating the ZEC program.

In its ruling, the court agreed. “The plain language …  makes clear that the legislature intended for the board to consider the applicants’ ‘costs and risks’ when determining eligibility. Had the legislature intended for the board to exclude the applicants’ operational and market risks when analyzing financial eligibility … and to instead assess only whether the applicants were `projected to not fully cover [their] costs,’ it would not have included the words ‘and risks’ after ‘costs.’”

The ZEC program awards subsidies worth about $300 million a year to PSEG, and the company is lobbying for an extension of the award. However, PSE&G CEO Ralph Izzo said in February that the subsidy, which works out to $10/MWh, is not enough to make the plants competitive with natural gas and zero-marginal-cost renewables. (See PSEG Presses for Higher Nuke Subsidies.)

The rate counsel said that it was not surprised by the decision but had hoped for “some independent analysis” of the issues in the case.

“Instead, the court simply applied deference to the agency without considering the considerable impact on ratepayers, many of whom are suffering under the current economic crisis,” said Rate Counsel Director Stefanie Brand. She said no decision has yet been made on whether to appeal the ruling.

PSEG welcomed the court’s ruling.

“This decision confirms that the BPU appropriately followed the statute and gives clear guidance on how to apply the existing law to the ZEC case currently before the BPU,” said Marijke Shugrue, a spokeswoman for PSEG. “Nuclear is critical to achieving New Jersey’s clean energy goals for 2050.”

The BPU, which saw Friday’s ruling as an affirmation of the need for the ZEC award, is expected to decide in the coming weeks on whether to extend the ZEC subsidies to PSEG for another three years.

Environmentalists ‘Disappointed’

Jeff Tittel, director of the New Jersey Sierra Club, said the organization was “disappointed” by the court’s ruling because the nuclear subsidies divert funds that could be used for renewable energy projects.

“The Appellate Division sided with nuclear subsidies over the ratepayers,” he said. “We think this decision will mean the people of New Jersey will be paying more for electricity and enriching the utilities at the expense of renewable energy and the environment.”

“This subsidy takes money away from renewable energy and undercuts efforts in achieving clean energy goals,” he said, adding that the state will be paying the subsidies for decades.

The Rate Counsel argued that the power plant operators had not met a requirement of the ZEC program that without a subsidy the state would be in danger of losing the carbon-free generation. Under the requirement, the plants needed to show that they wouldn’t cover the “risks and costs” of operating and would cease to do so in three years, the opinion said. The Rate Counsel argued that the plants had overstated their costs and understated revenues, and none of the plants needed subsidies to be financially viable, the opinion said.

The Rate Counsel also argued that the BPU “ignored its responsibility to ensure that the $0.4-cent/kWh charge mandated in the ZEC Act to fund the ZEC program was just and reasonable,” the opinion said.

The appellate panel, however, concluded that the BPU had compiled an extensive record to show that the plants could close without the subsidy, and concluded that the agency did not have the power to change the $0.4-cent/kWh charge, which was set by the legislature.

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Texas Supremes Sidestep Ruling on ERCOT Lawsuit Shield

The Texas Supreme Court on Friday left standing an appellate ruling granting ERCOT sovereign immunity from lawsuits, an issue the courts will likely revisit in suits involving last month’s blackouts (18-0781).

Five justices on the nine-person court said a lower court’s dismissal of a complaint in a case that began five years ago rendered the case moot and that, according to the Texas Constitution, they no longer had jurisdiction to rule in the case. The procedural ruling means that for the time being, ERCOT still enjoys sovereign immunity, as do many governmental agencies.

Panda Power sued ERCOT and three of its officers for fraud, misrepresentation and breach of fiduciary duty in 2016, claiming it was led by the grid operator’s demand projections to spend $2.2 billion on three gas-fired power plants that were never needed. ERCOT argued the case should be dismissed because the Public Utility Commission has exclusive jurisdiction over Panda’s claims.

A trial court ruled in Panda’s favor, but ERCOT appealed and the 5th Court of Appeals in Dallas ruled that the grid operator is not a governmental unit but was entitled to sovereign immunity. The appeals court ordered the trial court to dismiss the lawsuit. Panda then appealed to the Supreme Court, leading to the decision Friday.

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The Texas House of Representatives is not taking up a bill to reprice billing errors in the ERCOT market. | Texas Highways

“Because the trial court’s interlocutory order merged into the final judgment and no longer exists, we cannot grant the relief the parties seek,” the majority said. “As a result, any decision we might render would constitute an impermissible advisory opinion, and these consolidated causes are moot.”

Chief Justice Nathan Hecht was among four who dissented from the ruling, saying the majority’s procedural ruling was incorrect.

“The immunity issue has been important to [Panda and ERCOT] since the case was first filed in the trial court more than five years ago. Now it happens that the public stakes are high too,” Hecht wrote. “After Winter Storm Uri last month, the public also wants to know whether ERCOT can be sued. Will ERCOT be immune to claims against it for failing to prevent the power outages across Texas that not only crippled millions of users but resulted in water outages that were at least as bad, if not worse? … The parties want to know. The public wants to know. The court refuses to answer. The court can resolve the parties’ dispute, but instead it chooses delay and wasting more of the parties’ and judicial system’s time and resources.”

The Panda case now returns to the appeals court.

ERCOT, which has said it needs immunity from lawsuits because it is funded by generators’ transaction fees, welcomed the ruling.

In an emailed statement, spokesperson Leslie Sopko said, “ERCOT looks forward to presenting these arguments in the court again once the pending case in the Dallas Court of Appeals has concluded.”

February’s outages prompted lawsuits by individuals, counties and ERCOT market participants against the grid operator, PUC and other market participants. (See “ERCOT, MPs Hit with Lawsuits,” Texas PUC Turns Focus to Customer Bills.)

The winter storm and the ensuing dayslong blackouts have been blamed for at least 57 deaths.

House Ignores Senate Repricing Bill

The Texas House State Affairs Committee last week voted out six bills related to the February blackouts, but it declined to take up a bill, rushed through the Senate on March 15, that would reprice billions in market transactions piled up during 32 hours of scarcity pricing after the grid was stabilized last month.

During a press conference following the committee votes, Lt. Gov. Dan Patrick, who presides over the Texas Senate, cited a nonbinding legal opinion from Attorney General Ken Paxton in making his case that the PUC has the authority to retroactively reset prices.

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Lt. Gov. Dan Patrick during a legislative hearing on the Texas blackouts | Texas State Senate

Patrick called on Gov. Greg Abbott to use his emergency powers to force the PUC the reprice the market transactions, which amount to $5.1 billion. Commission Chair Arthur D’Andrea, who resigned last week but retains his position until a successor is named, has steadfastly refused to order the ERCOT market be repriced. (See D’Andrea Resigns from Texas Commission.)

“Under an emergency declaration the governor has extraordinary power. He is the commander-in-chief. He is the ruler of all of the agencies,” Patrick said. “He can make this corrective action if he so chooses.”

Paxton’s opinion said that a court would likely find such an action legal if it “furthers a compelling public interest.”

“Such authority likely could be interpreted to allow the [PUC] to order ERCOT to correct prices for wholesale electricity and ancillary services during a specific timeframe,” Paxton wrote.

The six bills passed on by the House committee included:

  • HB10: replaces five unaffiliated directors on the ERCOT board with three members, including one representing residential consumers, appointed by the governor, and one each appointed by the lieutenant governor and the speaker of the house.
  • HB11: defines “extreme weather emergency” and requires the PUC to order each generator in the ERCOT market to implement measures to prepare for such events by Nov. 1 and to restore service as soon as possible following an event.
  • HB12: orders a study on a statewide disaster alert system similar to the state’s Amber Alert system.
  • HB13: establishes the Texas Energy Disaster Reliability Council — comprising ERCOT, PUC, Railroad Commission and Texas Division of Emergency Management personnel — to prevent extended power outages caused by a disaster and coordinate other activities during the disaster.
  • HB16: prohibits the sale of wholesale-indexed retail electric products, such as those once offered by now-bankrupt Griddy Energy, whose customers received bills of $5,000 or more in February.
  • HB17:  prevents any Texas regulatory authority, planning authority or political subdivision from adopting or enforcing measures that prohibit utility connections based on energy sources. According to the Natural Resources Defense Council, Texas is among at least 15 states that are considering “pre-emption” legislation, including Arkansas, Colorado, Florida, Georgia, Indiana, Iowa, Kansas, Kentucky, Mississippi, Missouri, North Carolina, Ohio, Pennsylvania and Utah.

Committee Chair Chris Paddie said the bills are essentially shells, leaving room for revisions as they move through the legislative process.

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Carver-Kingston Line Review Holds for NTA Analysis

A transmission line proposed by Eversource Energy in eastern Massachusetts has regulators seeking more information about whether solar-plus-storage would be an appropriate non-transmission alternative for the project.

Solar panels and battery storage are “no longer in the boutique range;” they are “becoming pretty substantial,” Andrew Greene, director of the Massachusetts Energy Facilities Siting Board, said during a public hearing Thursday.

Eversource, however, said in its proposal that solar-plus-storage was not a cost-effective or timely alternative under current market conditions.

The need for the project was identified through an ISO-NE-led study with Eversource of peak demand on the grid in Plymouth and Norfolk counties. The study found low-voltage conditions and thermal overloads in the Kingston, Mass., area that could affect service to 44,000 customers. The proposed 8-mile transmission line would connect the Carver, Plympton and Kingston substations to meet that reliability need, according to Eversource’s proposal.

Carver-Kingston Transmission Line
A growing interest in Massachusetts for solar-plus-storage, like this 4.5 MW solar-3.8 MWh storage facility in Amesbury, has regulators questioning whether these technologies would be an appropriate non-transmission alternative for Eversource’s proposed 115-kV Carver-Kingston line. | CS Energy

Keith Jones, principal engineer at Eversource Energy, said during the hearing that adding a new renewable energy project in the area and pairing it with solar would also require transmission upgrades.

“We don’t yet know the full requirements of all the transmission upgrades, and we don’t know how these will be from a load forecasting standpoint,” Jones said.

The reliability issues in the area, he added, need to be addressed by 2022 to avoid a potential overload or overheating problem on the existing lines.

The load reduction achieved by a solar and battery storage system in the area would need to reach approximately 50 MW by 2022, Bob Andrew, director of systems solutions at Eversource, said.

Greene questioned whether a proliferation of energy storage under the state’s Solar Massachusetts Renewable Target (SMART) program and Clean Peak Energy Portfolio Standard could affect the need for the new transmission line.

SMART has been operating since 2018 to encourage development of community solar for low-income customers. Last year, the state energy department revised the program to make it easier and more appealing for private solar developers to serve low-income customers.

Massachusetts also adopted its new clean peak standard last August. The standard aims to ensure that peak load demands are increasingly met with clean energy resources instead of traditional fossil fuel resources.

Department of Public Utilities officials at the hearing directed Eversource to submit further information before it can continue with the transmission line review process. Among other things, DPU is seeking additional analysis on how much solar and storage would be necessary to meet the reliability needs in the Kingston area. It also is seeking details on what the impact to the project might be from the growth of the SMART program and clean peak standard.

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Newsom’s $1.5B ZEV Plan Takes Flak from Democrats

Fellow Democrats are questioning California Gov. Gavin Newsom’s budget proposal to spend $1.5 billion to accelerate the adoption of zero-emissions vehicles (ZEVs) by building charging infrastructure and providing incentives to low-income households and buyers of heavy-duty vehicles.

Newsom’s proposal does not renew funding for the state’s Clean Vehicle Rebate Program (CVRP), a mainstay of the state’s transportation electrification efforts for the last decade. CVRP gives a $2,000 rebate to mid-income residents who buy an EV.

During a State Assembly budget subcommittee hearing on Wednesday, the omission proved controversial — as did what lawmakers called a troubling lack of specificity in the governor’s proposal.

Assemblymember Phil Ting (D), chair of the full Budget Committee, said during Wednesday’s hearing that the governor’s plan to spend such a vast sum remains too vague for him to support.

“You’re coming forward to this committee for over $1 billion of appropriation, and I’m hearing a lot of very lofty goals but no detailed information,” Ting told representatives of the California Energy Commission (CEC) and the California Air Resources Board (CARB), the agencies that would administer programs funded by Newsom’s plan. “What are we getting for $1.5 billion?”

Hannon Rasool, deputy director of the CEC’s Fuels and Transportation Division, said $300 million would go toward installing 62,000 EV chargers and building 21 hydrogen refueling stations.

But details about how the CEC and CARB intend to spend the other $1.2 billion were less concrete. Sydney Vergis, a CARB division chief, told the subcommittee that funds would be put toward “buckets” of various programs and that, later, a public process would help determine how to spend the money specifically.

Several Democratic members of the subcommittee — Budget Subcommittee 3: Climate Crisis, Resources, Energy and Transportation — said the sketchy outlines from the agencies and governor’s office would not justify such large appropriations.

CEC Commissioner Patty Monahan told the subcommittee that the proposed allocations were a statement of the state’s larger goals and would put commercial interests at ease about investing in ZEVs.

“This big investment now shows the world that we’re committed,” Monahan said. She agreed with Ting, however, that a “cash-on-the-hood” rebate program was the best way of getting residents to buy electric vehicles.

Ting questioned eliminating the CVRP incentives. He said it did not make sense to build so much infrastructure without enough EVs to use it. The state is far behind its target, ordered by former Gov. Jerry Brown in 2018, of putting 5 million ZEVs on the road by 2030, he noted.

Democrats Among Critics

Building on Brown’s order, Newsom in September ordered that all new passenger vehicles sold in California must be ZEVs by 2035. (See Can California Meet Its EV Mandates?)

Newsom’s budget proposal is meant to bolster that effort. His proposed budget for fiscal year 2022, released in January, would allocate $1 billion to ZEV infrastructure, including charging and fueling stations for battery-powered EVs and hydrogen fuel cell electric vehicles (FCEVs). (See Calif. Governor Proposes $1.5 Billion for ZEVs.)

The spending plan calls for securitizing revenues from vehicle registration fees to support the expansion of the CEC’s Clean Transportation Program. A portion of the proceeds would fund loans “to leverage additional private sector capital to build the necessary infrastructure,” the governor’s office said in its summary of the plan.

Another provision would allocate $465 million in one-time cap-and-trade funds for incentives, rebates and financial assistance “to improve access to new and used zero-emission vehicles,” including $315 million for heavy-duty vehicle adopters and $150 million for low-income programs, it said.

The plan would put $50 million toward the installation of ZEV charging stations at state-owned facilities.

Those now questioning the proposal include Democrats representing liberal, affluent districts where EV adoption is widespread.

Subcommittee Chair Richard Bloom, whose district includes Malibu and Beverly Hills, and Assemblymember Laura Friedman, who represents Glendale and Burbank, said they too wanted to see more specifics from Newsom, the CEC and CARB.

“One of the things that we’re suffering from here today, if it hasn’t been evident, is a lack of analysis showing that the proposals that are being made support the goals that we all share,” Bloom said. “More information demonstrating that would be very, very welcome as we continue to analyze the budget proposals that are made by your agencies.”

Friedman said the low-income components needed more work.

“I think this program has to have extremely strong oversight and metrics and guardrails, because it’s a lot of money that will be put up,” Friedman said. “Great intentions, but it would be awful to see later that the money was spent and it’s not helping the communities that it’s intended to help.”

Ting authored a 2018 measure, Assembly Bill 2127, that requires the CEC to assess the EV charging infrastructure needed to reach the state’s ZEV goal and reduce greenhouse gas emissions to 40% below 1990 levels by 2030.

“I am a big fan of the idea that we need to do upfront investments,” Ting said. “The time is definitely now to be investing in this infrastructure. However, I’m not clear what we’re investing in, and it’s not clear what we are spending this money on, so if we don’t know what we’re getting for a billion dollars … I don’t know we could approve that.”

In a Jan. 11 hearing of the full Budget Committee, Assemblymember Jim Wood (D) asked whether it was appropriate for the governor to propose spending $1.5 billion on ZEVs but far less on helping small businesses recover from the economic damage of the pandemic.

Priorities need to be targeted, and addressing the pandemic is paramount, Wood said. That includes reopening schools and businesses and putting people back to work.

“I think my environmental record is pretty strong in this building,” he said. “I own an electric car. I love my electric car. [But] we have $1.5 billion in the budget for electric car infrastructure and incentives. We have $575 million going to small businesses. I wonder, is that the right number?”

The state’s 4 million small businesses are an economic driver for the state, and the workers they employ will be among the residents purchasing ZEVs, Wood said.

“Those are the people,” he said, “that are going to buy the electric cars, that are going to use that [charging] infrastructure.”

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Pennsylvania to Source 50% of Govt. Electricity from Solar

Pennsylvania is set to take a leap in its renewable energy procurement in what officials are describing as the largest solar commitment by any state government in the U.S.

Gov. Tom Wolf announced Monday that nearly 50% of the electricity used by the state government will be produced by seven new solar energy arrays comprising 191 MW of capacity to be built around Pennsylvania. Pennsylvania PULSE (Project to Utilize Light and Solar Energy) will go into operation in January 2023 as part of the governor’s GreenGov initiative created in 2019. (See Pennsylvania Joins US Climate Alliance.)

Wolf said when he introduced the GreenGov initiative, he challenged the state government to lead by example through lowering greenhouse gas emissions in state operations and to obtain at least 40% of electricity from renewable resources.

The governor also cited the May sunset date of Pennsylvania’s Alternative Energy Portfolio Standard — which drove solar and renewable development for the past 15 years — as a spark to making local renewable energy markets strong.

“Pennsylvania has been a national energy leader for more than 100 years,” Wolf said. “As we continue to diversify our grid with clean, renewable sources of energy, we want to maintain Pennsylvania’s leadership position and bring the associated economic, health and environmental benefits to all Pennsylvanians.”

The solar arrays will be built in seven locations in six counties, including Columbia, Juniata, Montour, Northumberland, Snyder and York. Officials said the 191-MW project is expected to deliver 361,000 MWh per year and supply 100% of energy for 434 accounts across 16 state agencies, or roughly half the electricity used by state government.

The solar usage will reduce carbon dioxide emissions statewide by 157,800 metric tons each year, officials said, the equivalent of emissions from around 27,000 homes or 34,000 cars.

Lightsource BP, a utility-scale solar developer, will build, own and operate the solar arrays, creating hundreds of new construction jobs. The arrays will be built on as much as 2,000 acres of farmland, with farmers signing 30-year leases with Lightsource.

Kevin Smith, CEO of Lightsource BP of the Americas, said the private long-term ownership of the arrays teamed up with government entities procuring the electricity is a “great model” that can be replicated across the country. Smith said Lightsource, which is headquartered in Philadelphia, currently owns and operates four solar arrays generating 90 MW of power in the state.

“What the Commonwealth of Pennsylvania is doing is a model for other governments in the U.S. to address climate change and usher in a new sustainable era, bringing measurable job and economic benefits to its people while reducing emissions that lead to healthier citizens,” Smith said.

The Pennsylvania Department of General Services contracted with Exelon subsidiary Constellation to secure a 15-year fixed-price supply agreement for about 5 cents/kWh.

The solar renewable energy credits created by the projects will be retired when purchased by Pennsylvania, officials said, guaranteeing they won’t be used by other entities looking for renewable credits for climate goals.

Secretary Opinions

Secretary of General Services Curt Topper said the contract with Constellation provides the state with “long-term price protection and budget certainty.”

“Pennsylvania PULSE reflects our commitment to making renewable energy the heart of DGS energy strategy,” Topper said. “We’re excited to have this new model in place as we work toward more clean energy use in the future.”

Governor Wolf’s Climate Change Executive Order in 2019 set a goal of lowering Pennsylvania’s GHG emissions 26% by 2025 and 80% by 2050 compared with 2005 levels.

The order also re-established the GreenGov Council, made up of the secretaries of the departments of General Services, Environmental Protection (DEP) and Conservation and Natural Resources (DCNR), which was originally charged with developing strategies for GHG reductions. Other goals for the group included reducing energy usage by state government at least 3% annually and replacing 25% of the state vehicle fleet with electric vehicles.

DEP Secretary Patrick McDonnell said Pennsylvania needs to move toward renewable energy in every sector of the government and economy to step up to meet GHG reductions. McDonnell cited power plants, transportation and manufacturing as key groups in meeting goals.

He said Pennsylvania needs to be more aggressive with its solar deployment, with only 1% of electricity in the state currently coming from 700 MW of installed solar capacity. He added that Pennsylvania can get 10% of its electricity from solar if it can reach 11 GW of installed solar capacity by 2030.

“Solar energy at an enterprise scale, as Pennsylvania PULSE demonstrates, will make a big impact,” McDonnell said. “The cleaner the grid is, the cleaner other greenhouse gas mitigations will be, such as switching to electric transportation.”