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November 2, 2024

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RGGI Studies Find Economic Benefits for Participants, Little Impact to Pa. Energy Prices

Two recently published reports on the Regional Greenhouse Gas Initiative (RGGI) found that participation in its cap-and-invest auctions produce net economic benefits and that Pennsylvania would see a small change in power prices should it join.

A May 16 report from the Analysis Group found that between 2018 and 2020 auction proceeds generated $669 million in net economic value and nearly 8,000 job-years for the 10 participating states.

“Although the original focus of the RGGI program was to address carbon emissions, we have consistently found that the cap-and-invest program results in a net positive economic impact for participating states,” Paul Hibbard, report co-author, said in an announcement of the report. “Our analysis shows that the regional cap works to limit carbon pollution, and the investment of auction proceeds plus the program’s impacts on the power sector result in overall reductions in electricity usage, additional income for consumers and business owners, and new jobs.”

The Analysis Group report is the fourth in a series of studies evaluating the economic impact of each three-year compliance period for the RGGI auctions. Together they find in its 12-year history, RGGI has yielded $3.8 billion in auction proceeds, which states spent on programs creating $5.7 billion in net economic benefits and 48,000 job-years. The program has also contributed to a 46% reduction in carbon emissions from power generation from 2006 to 2020.

States have used the proceeds from CO2 allowance auctions to fund energy efficiency programs, renewable energy development, education and job training, measures to reduce greenhouse gas emissions and ratepayer relief.

“[Energy efficiency] and [renewable energy] programs reduce net electricity consumption for program participants and lower wholesale electricity prices for everyone in the RGGI region by lowering regional electricity demand,” the report states. “Overall, despite an initial increase in wholesale electricity prices during the compliance period, consumers enjoy net economic gains through the combination of direct program spending and savings associated with EE and RE spending.”

Though it was not the focus of the Analysis Group report, Hibbard said researchers observed that New Jersey has seen economic outcomes in line with it dropping out of RGGI in 2011 and its re-entry in 2020.

“Over the four reports we’ve done, New Jersey has at times been part of it, and when they were participating in RGGI they were achieving significant economic benefits, because New Jersey was taking their money, using it in certain ways, generating jobs within New Jersey and generating an increase in gross state product within New Jersey,” he said. (See NJ To Accelerate RGGI Fund Expenditures.)

Connecticut Department of Energy and Environmental Protection Commissioner Katie Dykes, who is also chair of RGGI Inc., said the report underlines that the benefits of RGGI go beyond its environmental goals.

“Throughout its history, RGGI has delivered numerous benefits to Connecticut and the other participating states, including lower energy bills for our residents and businesses, new jobs in our growing clean energy industries, and reductions in climate-damaging, health-harming pollution,” she said in the report’s announcement.

In addition to its economic analysis, the report looked at what states are doing to address potential disparate outcomes for overburdened communities, a discussion that members are undertaking as part of RGGI’s third program review. One proposal under discussion is a “hybrid methodological approach” to evaluate programs’ impacts on those communities. Also under consideration are using RGGI auction funds to conduct air monitoring, providing opportunities and resources for active community participation, spending requirements and tracking both environmental and health outcomes.

“In my view it’s almost certain the public health impact of RGGI is to reduce environmental risks even in overburdened communities,” Hibbard told NetZero Insider. “The reason it’s an issue in the context of RGGI is because some people have pointed out that you can have the program reduce emissions from power plants overall, but the financial signals of a cap-and-trade program might allow an individual power plant to actually operate more. There are some arcane circumstances [in which] that could be the case.”

Devashree Saha, senior associate at World Resources Institute and a member of RGGI’s technical advisory group, said that the report showed avenues for participating states to ensure that the environmental benefits of reducing emissions are spread equally for all residents.

“Even though the electricity sector has made significant progress in reducing emissions in the aggregate, existing policies and the RGGI framework do not fully address the fundamental problem of unequal pollution burden among communities,” she said in the announcement.

Study Finds RGGI Participation Presents Little Impact to Energy Prices

A second study, released May 9 by Resources for the Future and the Kleinman Center for Energy Policy at the University of Pennsylvania, found that joining RGGI in 2023 would have minimal impact on energy prices for Pennsylvania ratepayers. That is, in part, due to an expectation that allowance prices in the 2030 auction would fall from $8.59 to the floor price of $2.26 due to the widespread low-cost abatement opportunities in the state. A 2019 Executive Order issued by former Gov. Tom Wolf would make the state the 12th to join RGGI, however the order’s implementation has been prevented by ongoing lawsuits in state courts. (See Court Blocks Pa. from Joining RGGI.)

If the state were to begin participating in auctions this year, the study finds that 2030 emissions would be cut by 84% relative to 2020 levels, compared to a 49% to 52% decline if the state were not to join. That would amount to a 25-million-ton reduction in emissions to 28 million tons in 2030. The report bases its findings on the state’s proposal that its emissions cap be based on its 2020 emissions of 83 million short tons and decline by 3% annually, which follows the trajectory of the emissions cap in RGGI. An alternative scenario with a stricter cap of reaching zero emissions by 2040 finds similar reductions by 2030.

Retail electricity prices are estimated to increase by about 1% in 2030 under the 3% declining cap scenario and decrease by 0.6% under the scenario with a zero emissions cap in 2040.

“Initially, one might anticipate that introducing a carbon price in the electricity sector would raise the wholesale price (and thus retail price) by the allowance price times the emissions rate of the marginal generator. However, a Pennsylvania generator may not be the marginal generator in PJM,” the report says. “Furthermore, the price may be lower because even in the first year after a carbon price is introduced, there may be an opportunity to change the dispatch order of generation resources, including hydro or battery storage, such that the marginal plant changes to a lower-emissions plant, or for the marginal plant in the regional market to become a plant outside the state.”

While the report focuses on the impact to wholesale electricity prices, it notes that the auction revenues could be invested to the state’s economic benefit, particularly since much of that revenue would be coming from generators located in other states.

“Despite low allowance prices, the state still gains $101 million to $148 million from the auction of emissions allowances in 2030. A large portion of this revenue (71%) comes from the purchase of allowances by generators in other RGGI states,” the report said. “The net effect for Pennsylvania consumers, combining auction proceeds and the change in electricity prices, is slightly negative under the 3% cap and beneficial under the tighter cap. Pennsylvania may decide to direct some or all of this revenue to program-related purposes that could directly reduce electricity bills or accelerate decarbonization.

Most of the reductions are expected to come from emissions reductions from coal generation, which report co-author Angela Pachon, research director at the Kleinman Center, said also accounts for the expected drop in allowance prices in the RGGI auction. Since Pennsylvania has a relatively large share of coal generation relative to other RGGI states, she said there are many more opportunities for abatement. The report was cowritten by Maya Domeshek, research associate at RFF, and Dallas Burtraw, senior fellow at RFF.

The study also finds that current allowance prices are not likely to be representative of the future of RGGI with Pennsylvania’s participation because of volatility in natural gas prices owing to current global instability and risk averse behavior observed in the markets in the past when the state was expected to join.

“New entities enter the program with no market experience or allowance bank. Consequently, every previous emissions market (including markets for sulfur dioxide and nitrogen oxides) has seen initially high levels of demand and temporarily high prices as firms acquire allowances to build up a bank (Burtraw and Keyes 2018). This market behavior is typically followed by a return to expected prices over the longer term as the generation mix has time to adjust,” the report states.

Unlike past studies examining the impact of the state participating in the RGGI auctions, which found that joining would likely lead to increased retirements of fossil fuel generation, the RFF report found that it would likely lead to increased renewable development in the state, in large part because of incentives under the Inflation Reduction Act.

Daniel Stuart, co-author of the Analysis Group report, said the RFF study dovetails with his findings by showing that the impact to energy prices is likely to be outweighed by the benefits derived from programs funded by the auction revenue.

“I did have a chance to review the RFF report. It seemed to be very carefully done, and really the findings are very consistent and complement our study in the sense that they find perhaps positive, perhaps negative, but overall very small impacts on wholesale electricity prices,” he said. “And then what our report demonstrates is that once you raise allowance auction revenue and spend it and reinvest it in local communities, you’re going to experience an economic impact.”

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BOEM: Major Visual, Scientific Impacts from NJ’s 1st OSW Project

The U.S. Bureau of Ocean Energy Management (BOEM) issued a final environmental impact statement (EIS) Monday for Ocean Wind 1, New Jersey’s first offshore wind project, concluding that the project combined with others will have a “major” impact on scenic and visual factors and on scientific research, but only a “moderate” impact on a host of other issues.

The over 2,300-page report, which will be used as a touchstone by federal and other decision-makers to determine the future of Ørsted’s 1,100-MW Ocean Wind 1 project, said the impact of the project alone on scenic and visual factors such as the “seascape, open ocean, and landscape character and viewers” would be only “moderate.”

But the cumulative impact of the project, which would erect 98 turbines about 15 miles from Atlantic City, on scenic and visual factors would be “major” once combined with “other ongoing and planned activities” in the area, the EIS said.

There could be 859 turbines installed in the area between 2024 and 2030 if all other planned projects go ahead, the report said. The EIS found the cumulative scenic and visual impact would be “major” even if Ocean Wind 1 did not go ahead.

Because Ocean Wind 1 is the state’s first offshore wind project, the EIS provides a kind of guideline for other, future projects. The BOEM release announcing the EIS said it will issue a decision on the project in the summer.

The EIS evaluates the impact of the project on 18 factors and defines the impact as either major, moderate, minor or negligible. The study also looked at four other scenarios with changes made to mitigate the impact, such as creating a buffer between it and an adjacent project or placing its turbines closer together.

Maddy Urbish, head of government affairs and market strategy in New Jersey for Ørsted, welcomed the release of the EIS.

“Ocean Wind 1 continues to advance through the multiyear federal permitting process, and we’re pleased to reach this latest milestone,” she said. “Ocean Wind 1 anticipates onshore construction beginning in the fall and offshore construction activities ramping up in 2024.”

OSW Progress

The release comes a week after BOEM issued the draft EIS for the 1,510-MW Atlantic Shores project, one of two projects approved by the New Jersey Board of Public Utilities in its second OSW solicitation. The other project, the 1,148-MW Ocean Wind 2, was also developed by Ørsted. (See BOEM Draft EIS Finds Potential Major Impacts from 1st NJ OSW Project.)

BOEM said the release of the EIS for Ocean Wind 1 is part of the agency’s ongoing effort to meet President Joe Biden’s goal of deploying 30 GW of OSW energy capacity by 2030. The agency said it held three public hearings  and received 1,389 comment submissions.

“BOEM continues to make progress towards a once-in-a-generation opportunity to build a new clean energy industry in the United States,” BOEM Director Elizabeth Klein said.

The progress in New Jersey is far from assured, however. Offshore wind projects face opposition from the commercial fishing sector, Jersey Shore homeowners, the tourism sector and state business groups concerned at the cost. Two local governments that represent communities through which Ørsted plans to run cables from the offshore generators to the state grid — Cape May County and Ocean City — have sued in state court to overturn the BPU’s approval of easements to allow the cable installation. (See County Contests Tx Easement for NJ’s 1st OSW Project.)

BOEM found Ocean Wind 1 would have only moderate impact in most of the categories studied, among them: recreation and tourism; navigation and vessel traffic; coastal habitats; birds; and water and air quality. It found a negligible to minor impact on land use and coastal infrastructure.

The study found the impact of the Ocean Wind 1 alone on scientific research and surveys would be major, as would the cumulative impact of the project and others nearby, including on National Oceanic and Atmospheric Administration surveys that support commercial fisheries and protected species research programs.

“The entities conducting scientific research and surveys would have to make significant investments to change methodologies to account for areas occupied by offshore energy components, such as [wind turbine generators] and cable routes, that are no longer able to be sampled,” the study said.

Significant Impact on Commercial Fishing, Whales

Similarly, the study found the impact on the commercial and for-hire recreational fishing sectors would be major, both from the project itself and the cumulative impact. In both cases, the impact would be “minor to major on commercial fisheries and minor to moderate on for-hire recreational fishing depending on the fishery or fishing operation.”

Even if Ocean Wind 1 did not go ahead, the commercial fishing sectors would face challenges from busy port use, inflated vessel activity, other offshore development and climate change issues, the EIS says.

If the project goes ahead as planned or with modifications, the factors that would determine the scale of the impact include: number, size and location/orientation of turbines; length and route of inter-array and offshore export cables; number of simultaneous vessels, number of trips and size of vessels, which could affect potential risk for vessel collisions and use of port facilities; and time of year during which construction occurs, which could affect access to fishing areas and availability of targeted fish in the area, thereby reducing catch and fishing revenue.

The study found that the impact on mammals would in general be moderate. But it found the impact of the project alone, and the cumulative impact with other projects, would be moderate to major for North Atlantic right whales.

The impact on the right whale population has emerged as a significant issue in New Jersey after a spate of whale deaths in recent months, with the bodies washing up on the Jersey Shore. Opponents of OSW, and two Republican members of Congress, have suggested the deaths could be linked to preliminary marine studies being conducted for the OSW projects. However, federal and state officials say there is no evidence linking the deaths with the wind projects.

The EIS says right whales are already facing considerable stress factors, including elevated vessel activity and collisions, and the effects of climate change. Because “offshore wind construction, operation and maintenance activities would be conducted with applicant-proposed and agency-required mitigation measures,” the activities are “not anticipated to substantially contribute to the major impacts,” the EIS states.

However, the study added that that “it is unknown whether the population can sufficiently recover from the loss of an individual to maintain the viability of the species.”

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Carper Throws Progressive Bill into Senate Permitting Debate

In the ongoing congressional wrangling over how to streamline and accelerate permitting for energy projects and transmission, Sen. Tom Carper (D-Del.) has lobbed a new, largely progressive proposal into the mix, with a strong focus on clean energy and environmental justice.

Labeled a “discussion draft,” the Promoting Efficient and Engaged Reviews (PEER) Act incorporates some of President Joe Biden’s permitting priorities, such as using “programmatic,” regional environmental reviews to cut time frames and establishing chief community engagement officers at federal agencies involved in permitting. But it also goes several steps further. (See Podesta Lays Out Biden’s Priorities for ‘Permitting Reform’.)

While Republican lawmakers have advocated for a narrow interpretation of environmental impacts in reviews required under the National Environmental Policy Act (NEPA), Carper wants these studies to look at the potentially positive environmental effects of a project, “including greenhouse gas reductions,” according to a summary of the bill. It would require that consideration also be given to indirect and cumulative impacts, as well as the “foreseeable adverse effects of not completing a project.”

NEPA reviews would also have to include “meaningful public involvement opportunities” and community impact reports to address environmental justice concerns, according to the summary. It would also allow a federal agency to require a developer to include a community benefits agreement as part of an environmental review.

Such agreements generally specify certain social and economic benefits, such as jobs and job training, that a community affected by a project will receive.

The bill also calls for $500,000 to be allocated for a feasibility study of setting up a single online permitting portal. An additional $20 million per year for five years would be authorized for the establishment of “linked interagency environmental data collection systems to standardize and facilitate the use of” data across agencies, project sponsors and the public to support environmental reviews.

To ensure adequate staff for permitting, the bill would provide $45 million per year, again for five years, “to fund scholarships, fellowships and research at institutions of higher learning relevant to the permitting process.” At the same time, federal agencies would be directed to “conduct human capital planning” and staff up to meet accelerated permitting processes.

In perhaps its most radical proposal, the bill would set up a process under which federal agencies could identify “commercially viable, nationally significant projects” and get them permitted and shovel-ready before opening competitive bidding for “nonfederal project sponsors” to develop them. The permitting process would also resolve any issues that might lead to litigation.

It would also promote development of clean energy projects on brownfield sites and authorize EPA to provide financial assistance to states to hire additional staff with the environmental and legal expertise needed to process them.

In a Thursday press release, Carper, who chairs the Senate Environment and Public Works Committee, said the bill would improve permitting “without undermining our nation’s bedrock environmental protections.”

Pointing to the passage of the Infrastructure Investment and Jobs Act and the Inflation Reduction Act, Carper said, “We need efficient permitting processes that allow our nation to meet our climate goals with the urgency that science demands. The PEER Act would help accelerate clean energy projects and create good-paying jobs across our country while ensuring that communities have a say in infrastructure projects.”

On Monday, Carper announced he will not run for reelection in 2024.

Five other Democratic senators joined Carper as cosponsors of the bill: Brian Schatz (Hawaii), Sheldon Whitehouse (R.I.), Tina Smith (Minn.), Chris Murphy (Conn.) and Alex Padilla (Calif.).

“It would be a huge, missed opportunity to let the transit and clean energy projects in the IRA and the [IIJA] get bogged down in our outdated and unwieldy permitting processes,” Murphy said in the press release. “If it takes a decade to get a permit to build offshore wind, expand passenger rail service or upgrade our electric grid, we won’t ever accomplish our climate goals.”

Opportunity for Bipartisanship

The PEER Act is the latest in a series of bills being offered from both sides of the aisle on the issue of permitting reform, which could become a major bargaining chip as Biden and House Republicans attempt to negotiate a package to raise the debt limit before a potential default.

The House of Representatives’ Limit, Save, Grow Act (H.R. 2811) includes the previously passed Lower Energy Costs Act (H.R. 1), with provisions that would accelerate permitting of fossil fuel projects, but without any mention of clean energy or transmission.

GOP bills sponsored by Sens. John Barrasso (R-Wyo.) and Shelley Moore Capito (R-W.Va.) aim to accelerate fossil fuel permitting or undercut NEPA and the Clean Air and Clean Water acts. Under Capito’s bill, for example, if an agency failed to complete a NEPA review within two years, the project would automatically be considered as meeting all NEPA requirements.

Sen. Joe Manchin (D-W.Va.), chair of the Senate Energy and Natural Resources Committee, reintroduced his Building American Energy Security Act, which drew some bipartisan support in the Senate in December but ultimately failed.

Points of agreement include limiting the time frames for NEPA environmental impact reports to two years, while less intensive environmental assessments would be capped at one year. A limit on litigation could also be part of any compromise: Carper’s bill would provide three years for legal challenges to an approved project — half the six years currently allowed — while Manchin’s would allow for 150 days and Barrasso’s and Capito’s 60 days.

Cross-agency coordination, with one federal agency leading the permitting on any one project and releasing a single environmental impact statement or assessment, also has general bipartisan support, as does expanding the use of programmatic reviews and categorial exclusions.

Programmatic environmental reviews can assess impacts in a specific region or a transmission corridor and then be used for multiple projects within the region or corridor. Categorical exclusions are waivers, finding that a project will have no significant environmental impacts. Carper’s bill would allow one agency to use another’s categorial exclusion after consulting with the other agency and providing an opportunity for public comment.

Flash Points

While Capito and Barrasso have both called for permitting reform to be technology- and project-neutral, their respective bills and H.R. 1 tilt heavily toward fossil fuels. Carper and the White House tilt toward renewables and zero-emission projects, as well as transmission.

Manchin’s bill goes for an all-of-the-above approach, with provisions that the president must draw up a list of 25 geographically and technologically diverse, high-priority energy projects that would also be a high priority for permitting. But his must-have is the completion of one of his own high-priority projects, the Mountain Valley natural gas pipeline.

A major sticking point may be the expanded role Democrats, including Manchin, want FERC to play in federal permitting of transmission projects, which so far the GOP has not supported. Two issues, FERC’s backstop siting authority and cost allocation, are key points in Manchin’s and Carper’s bills, as well as in ongoing debates between states and FERC. (See related story, FERC Backstop Siting Proposal Runs into Opposition from States.)

Manchin’s bill would streamline FERC’s backstop siting authority, which allows the commission to permit transmission projects of national interest in the event a state denies or does not permit such projects within a year. It also calls on the commission “to ensure project costs are allocated to customers that receive proven electricity benefits.”

Carper’s bill provides a more detailed vision of FERC’s role in transmission planning and permitting, including amendments to the Federal Power Act “to allow the United States to proactively plan and build the broad regional grid it needs.”

On cost allocation, Carper’s bill would direct FERC to “account for the full scope of benefits from transmission investments, such as renewable energy transmission and connection, reliability and resiliency improvements, and meeting decarbonization goals,” according to the summary. “Rules must require portfolio-based cost allocation and prioritize interregional cost-benefit considerations over regional ones.”

At a recent ENR hearing and in a Saturday op-ed in The Intelligencer, Manchin urged senators to put politics aside and work toward the difficult but necessary compromises needed for a bipartisan bill. He also said he would be scheduling “more sector-specific energy permitting hearings in the weeks ahead to learn more about the issues these projects face and [that] inform our work.”

But as long as permitting reform is tied to the debt ceiling debate, the possibility of finding more substantive common ground and compromises appears less likely, according to ClearView Energy Partners.

“Both sides have rolled out rhetorical postures that we regard as nonstarters,” ClearView said in a recent rundown of the permitting bills now in play. “A bigger challenge may be the limited overlap between both sides’ maximalist aspirations, as this leaves little room for a consensus mini-deal before the early June debt ceiling [deadline]. …

“If permitting reform were inevitable, its proponents would not be looking for a ‘must-pass’ bill like the debt ceiling, and if its momentum were insurmountable, it would not require a forcing event like imminent default to propel it.”

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Mass. Climate Advocates Want Polluters to Pay for Resilience

BOSTON — Massachusetts legislators and climate advocates called for a billion-dollar fine on the country’s largest carbon-polluting companies at a meeting of the legislature’s Joint Committee on Environment and Natural Resources on Wednesday.

The committee took public testimony on 44 bills from both houses concerning climate and energy policy. A large portion of the testimony focused on several bills that would fund and support climate resilience.

Prior to the hearing, climate activists rallied in front of the Statehouse in favor of Senate Bill 481 and House Bill 3581, which would create a “climate change superfund” by imposing fines on the largest carbon-emitting companies in the country based on their proportional shares of historic emissions. The fine would impact entities responsible for more than 1 billion tons of carbon-equivalent emissions and is designed to generate $75 billion over 25 years.

The fund would support projects such as seawalls, stormwater management upgrades, adaptation improvements to transportation and grid infrastructure, ecological restoration projects, and cleanup projects after storms.

“The question now is who is going to pay for the damage caused by climate change,” said Jon Grossman of SEIU local 509, which represents nearly 20,000 educators and service workers in the state. “If we don’t take appropriate action, this will come to a significant cost to taxpayers and also a significant cost to Massachusetts residents who rely on public services. …

“As we in the labor movement know, when we look around, we can see that there is money out there, and it seems that the folks that caused this crisis have a lot of it; fossil fuel companies are among the most profitable in the world,” Grossman added.

Similar legislation was proposed in 2021 by Democrats at the federal level and has been introduced at the state level this year in New York and Maryland. Representatives for groups, including the Massachusetts Youth Climate Council, Communities Responding to Extreme Weather, Massachusetts Climate Action Network, 350 Massachusetts, Elders Climate Action and the Mass Power Forward coalition, spoke in favor of the bills, highlighting the responsibility of major fossil fuel companies in driving the climate crisis and blocking climate action.

“It is well documented that at least Exxon hired scientists more than 30 years ago to study the effects of their product, found it was detrimental to all living species and then lied about it,” said Cabell Eames, political director of the Better Future Project. “The level of deceit is of epic proportions, and at this point to allow the fossil fuel industry to continue business as usual without holding them accountable is enabling an industry that has proven criminal in its wanton fraud and disregard for the human race.”

Youth Climate Coalition Activists (Mass Joint Committee on ENR) FI.jpgActivists from the Massachusetts Youth Climate Coalition call on the committee to advance Senate Bill 481, which would impose a fee on the state’s largest climate polluters. | Mass. Joint Committee on Energy and Natural Resources

Another bill focused on addressing climate fallout, filed as House Bill 750 and Senate Bill 472, would fund climate resilience projects by imposing a fee on property insurance, which advocates said would avoid financial burdens for low-income residents. Representatives of the Conservation Law Foundation, the Nature Conservancy, Mass Audubon, the North Central Climate Change Coalition and My Brother’s Table spoke in favor of the bill.

“While the funding proposed in this bill is only a small portion of what’s needed, its aim … is to turbocharge programs in Massachusetts that support, enhance and supplement climate adaptation and mitigation programs that have equitable goals and outcomes,” said Sam Anderson of Mass Audubon.

Advocates also testified in support of a bill that would open the door for advanced research into nature-based solutions to dealing with climate effects.

Representatives of the University of Massachusetts Boston, Boston Harbor Now and the Boston Children’s Museum spoke in favor of House Bill 3581 and Senate Bill 458, which would ease regulatory hurdles for research and demonstration projects looking at nature-based mitigation approaches to rising sea levels and severe storms. These could include projects mimicking natural coastal marshes, dunes and bluffs.

“These nature-based systems can offer many advantages over concrete sea walls, such as decreasing erosion, not increasing it. They are less expensive to construct, and they also provide many environmental and social co-benefits that promote social justice and equity,” said Paul Kirshen, professor of climate adaptation in the School for the Environment at UMass Boston.

Lawmakers and advocates also testified in support of a variety of bills focusing on ocean acidification, carbon sequestration in marine ecosystems, increasing staffing of climate agencies in rural municipalities and mitigation of ecosystem impacts from offshore wind development.

Addressing Embodied Carbon Emissions

Climate advocates also spoke to the committee about the importance of addressing the lifecycle emissions associated with building materials, from concrete to petroleum-based insulation. Frequently referred to as embodied carbon, these emissions account for about 11% of global emissions, according to data from the Global Alliance for Buildings and Construction and the International Energy Agency.

“When it comes to embodied carbon, we’re really talking about the elephant in the room,” said Logan Malik of the Massachusetts Climate Action Network. “In order for us to build and decarbonize our buildings holistically, we have to incorporate embodied carbon. But at the same time … very, very little is being done in our state to actually do that.”

House Bill 764 would establish an expert advisory board on embodied carbon, commission a report to inform additional legislative action, incorporate embodied carbon into the state’s stretch code and require the Department of Energy Resources to issue recommendations for reducing embodied carbon emissions.

Banning Fossil Fuel Extraction

Legislators also presented bills to the committee that would ban fracking and offshore drilling in the state, citing climate, environmental and public health concerns.

Rep. Carmine Gentile (D), who sponsored House Bill 815 to ban all forms of fracking in the state, highlighted the risks of groundwater contamination, as well as the link between fracking and children born with congenital heart defects.

“There’s no fracking at the moment in Massachusetts, but there’s a real potential of future oil and gas development that could take place in the Hartford Basin, which stretches into Western Massachusetts,” Gentile said.

Meanwhile, Senate Bill 464 would ban offshore drilling infrastructure, exploration and development in Massachusetts state waters, along with any onshore infrastructure to support offshore drilling. Sen. Julian Cyr (D), the bill’s sponsor, said that while the Biden administration does not plan on opening up the East Coast for offshore drilling, “the threat of an administration that would open up the Eastern Seaboard to coastal drilling is very real.”

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ACP Finds Renewable Deployments Slowed in Q1

New renewable deployments were down in the first quarter this year as the industry continues to face headwinds, the American Clean Power Association said Monday.

The Inflation Reduction Act’s historic incentives helped to grow the development pipeline to 140 GW by the end of the first quarter of 2023, up 11% from the same time last year, the group said in its Clean Power Quarterly Market Report. But those developments are too early to impact installations, which have slowed for the first time since 2017.

“The clean energy revolution is underway,” ACP CEO Jason Grumet said in a statement. “We have the technology, financial capital and workforce to power our economy with clean, affordable and secure energy. There is broad bipartisan support for American energy innovation. But the clean energy transition will not succeed unless Congress and Governors enable the siting and construction of new energy facilities and support the build out of transmission that is required to bring clean power to the people.” 

The first quarter saw 95 projects come online, totaling 4,079 MW of capacity, which was down 36% from the first quarter of 2022 and the lowest first-quarter total since 2020. Those installations included 2,200 MW of solar, 1,418 MW of wind and 461 MW of storage.

Florida was home to the most installations in the quarter with 974 MW, knocking Texas — with 701 MW — off the top spot that it had occupied “quarter after quarter.”

Wind installations were down the most, falling 50% from the first quarter last year, while storage and solar were down by 32% and 23%, respectively.

The decline can be attributed, in part, to the large quantity of projects that experience delays in the first quarter, with ACP saying 12 GW reported delays in the first three months of 2023, including 6.4 GW that had already experienced previous delays. That compares to just 6.9 GW of delays reported in the first quarter last year.

“Seesawing regulations due to the U.S. Department of Commerce’s ongoing anticircumvention investigation delayed or forced changes to solar module delivery plans,” ACP said. “Furthermore, long release timelines for modules detained by U.S. Customs and Border Protection further pushed back delivery timelines for some major solar projects too.”

When added to capacity that is still delayed from the previous two years, some 63.3 GW of projects are facing delays now, and two-thirds of the delayed projects are solar power.

New projects might be down, but the clean power industry continues to have a very healthy development pipeline with 81,509 MW of solar, 20,176 MW of wind and 19,621 MW of storage all under development. Hybrid projects with storage paired with wind or solar make up 61% of the storage pending development.

A total of 406 projects are under construction across 44 states, totaling 48,957 MW. Florida appears unlikely to repeat as the number one state in the future as it is home to just 774 MW of new construction, compared to 12,684 MW in Texas, 6,564 MW in California and another five states with more than 2,000 MW under construction.

Projects in advanced development total 89,850 MW in 48 states, with Texas home to 11,272 MW, New York at 8,678 MW, California at 8,196 MW, Virginia at 6,214 MW and Indiana at 5,289 MW.

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New York Fine-Tuning its Market for Energy Storage 

ALBANY, N.Y. — The state with the highest goal for installed energy storage also has some market structures that make it hard for the private sector to pursue those goals.

The 2023 Capture the Energy Conference & Expo featured ideas on moving past the challenges in an environment where storage is expected to become indispensable to vehicles, structures, the grid and society itself.

Storage is boosted by favorable government policy, tax incentives and intensive research. It is hampered generally by some of the same challenges that face other renewable energy sectors: rising costs, still-evolving technology, workforce and supply chain shortages and interconnection delays.

In New York, there is the added barrier of a wholesale power market that is not favorable for storage. But the state, its ISO and the industry are working on these things.

“We have an industry that is really at the center of the transition,” William Acker, executive director of the New York Battery and Energy Storage Technology Consortium (NY-BEST), said as he welcomed the crowd to the expo Wednesday. “This conference is going to delve into those opportunities … we’re going to hit head-on some of the key challenges, also.”

Batteries get attention because they are an available technology, but as its name indicates, NY-BEST advocates for all other forms of energy storage, too.

Doreen Harris, CEO of the New York State Energy Research and Development Authority, emphasized how important storage will be to a future grid where intermittent wind and solar provide a sizable percentage of the state’s electricity.

“When we think about how we get from here to there, storage is, full stop, critical to enabling the decarbonization that we are talking about,” she said.

The state’s strategy relies on storage in three ways, Harris said: to serve as a power source for peak demand; to make the grid more flexible; and to be an avenue for developing new technology.

The state has set a goal of 6 GW installed by 2030, but it may need 12 GW by 2040 and up to 21 GW by 2050, she said.

“Those are really big numbers, but they’re also very necessary numbers. That’s why we’re all here today, to drive toward that outcome.”

Developing a viable form of long-duration storage — days-long rather than hours-long — is essential to meeting those goals, Harris said, and is a focus area for the research support NYSERDA provides.

Barriers

Large-scale deployment of storage in New York has not kept pace with the ambitions set for it.

NYSERDA attributes this to two primary factors: the slow interconnection process and the structure of the wholesale energy market.

Interconnection delays are universal, but energy storage faces some unique market challenges in New York.

“As identified in the 2022 Energy Storage Roadmap, current wholesale market revenue is insufficient to support energy storage deployment,” a NYSERDA spokesperson said, explaining that this includes “market uncertainty, market pricing not fully representative of system needs, and the fact that market prices are based on current system conditions.”

Beyond this, the market is not particularly volatile: There aren’t the price swings that allow storage operators to make a steady profit by charging batteries with low-cost power and selling the power back into the grid for a significantly higher price.

The state’s response has been to propose an index storage credit mechanism for storage projects larger than 5 MW. It is being drawn up by NYSERDA and the Department of Public Service; the Public Service Commission will have final approval.

NYISO President Rich Dewey told the audience that the ISO is developing ways to enhance energy market products such as a hybrid pricing scheme for co-located storage and generation resources and a ramping product that would incentivize a rapid response capability to replace the gas turbine peakers that are targeted for retirements.

Attorney Adam Conway, a partner at the Couch White law firm who specializes in energy project development, touched on some of these issues when he spoke at the conference.

He told NetZero Insider that the proposed credit aims squarely at the problems facing storage development and is similar in concept — but not details — to the well-received renewable energy certificate system.

“What they’re proposing is really a brand-new compensation scheme,” Conway said. “My understanding is that it’s not one that has been used elsewhere yet.”

Other obstacles face storage development, including local opposition that is often based in ignorance of the technology, he said.

But he said it is important to remember that these are the early days of energy storage. He said he is reminded of the early years of community solar, which Couch White was heavily involved in.

“It felt like at the time it was taking a lot of time to get the program off the ground,” Conway said. “I think you can draw some parallels to battery storage.”

Extensive community education helped build public acceptance of solar, and NYSERDA is mounting the same effort with storage, he said.

“My sense is this is just going to take time.”

Infrastructure

Bart Franey, vice president for clean energy development at National Grid (NYSE: NGG), spoke of the upgrades being made to prepare for renewable energy and storage. New York’s power grid was designed a century ago, he said, and is not optimized to support repeated large-scale charging and discharging of batteries.

“We see that short- and long-term storage are essential to overall reliability of system operations,” Franey said. “However, short-duration storage works best to address transmission security, while long-duration is needed for supply security.”

“A four-hour battery works very well in addressing transmission security,” he said. “However, we need hundred-hour dispatchable resources to address supply security.”

Venkat Srinivasan, who heads the Argonne National Laboratory’s Collaborative Center for Energy Storage Science, said the United States lags in developing a domestic manufacturing ecosystem and needs to not just catch up with China but leapfrog ahead of it.

“You really want to go beyond what is happening in the rest of the world,” Srinivasan said, and that means moving beyond lithium battery technology as the market matures, and beyond batteries.

There is much interest and activity in the non-lithium battery pace, he said, but no clear front-runner yet among those alternative technologies.

Key strategies for the United States developing a leadership role in batteries are maximizing attractiveness for investments; supporting research, innovation and commercialization; helping industry secure access to critical minerals and low-carbon infrastructure; developing education and training curricula; and most of all, establishing a workforce development pipeline.

“The one big topic that kept coming up is workforce,” Srinivasan said. “Everybody is worried about the workforce. This is probably one of the biggest challenges they’re going to face in the energy transition.”

Necessity

New York Public Service Commission Chair Rory Christian reiterated the importance of getting it right. “Storage is going to offer a degree of flexibility that is only going to become more valuable over time.”

The PSC and NYSERDA are developing a roadmap for the buildout of grid-scale storage in New York state, he said, but the technology has many behind-the-meter applications as well, particularly when combined with smart meters.

“I believe through the proper alignment of incentives, through proper establishment of markets, battery storage in a residential setting can completely transform our relationship with energy at a level not previously imagined,” Christian said.

NYISO President Dewey spoke of the balance the grid operator is trying to maintain as dirty-but-steady fossil fuel generation assets are retired in favor of clean-but-intermittent renewables.

The first tranche of peaker retirements was May 1, he said, and there needs to be caution about prematurely shutting down the others.

NYISO has changed its annual reliability study to a quarterly study because the rate of change has accelerated so much.

“When you think about the promise that storage brings to that transition, and the facilitation of that transition, it gives us so many more options, and it’s such a valuable tool,” he said.

NYISO is proud to have developed the first set of integrated energy storage rules, Dewey said, and is looking at how to fine-tune the market signals that are needed to attract the right mix of development.

He acknowledged a common complaint at this conference and elsewhere: the slowness of the interconnection process.

“I know it’s viewed as a barrier and a pain point,” Dewey said, but NYISO has a lot of work to do. On Thursday morning there were 520 projects in the bulk system interconnection queue. Among them there were 178 storage proposals rated at a combined 28 GW.

“That is a phenomenal increase from where we were even a couple of years ago,” he said, and he only expects the numbers to grow.

NYISO has added personnel and is looking at revising its processes and procedures to streamline the interconnection process, Dewey said.

“It’s not quite as simple as just throwing resources and manpower at it. But I want you to know that we recognize how important this is, and you have our commitment that we’re going to very aggressively approach that.”

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NY Office of Renewable Energy Siting Survives Court Challenge

An appeals court has rejected an attempt to derail New York state’s streamlined permitting process for large renewable energy projects.

Several upstate New York towns and ornithological organizations argued in a June 2021 petition that the state Office of Renewable Energy Siting violated state law as it drew up the set of uniform standards and conditions it adopted earlier in 2021.

A county-level judge ruled in favor of ORES later in 2021 and an Appellate Division court rejected the petition in a ruling issued Thursday. Because the ruling was unanimous, there is limited avenue to appeal to the state’s highest court.

New York codified renewable energy goals through its landmark Climate Leadership and Community Protection Act in 2019. The Accelerated Renewable Energy Growth and Community Benefit Act of 2020 established ORES to speed up the buildout of renewables by creating a standardized environmental review and permitting process for projects with capacity of 25 MW or larger.

Developers of projects sized 20 to 25 MW can also opt in.

After ORES determines an application to be complete, it has one year to issue a final decision on a siting permit, or six months if the project is on a brownfield.

Local government and community groups are allowed to provide input and participate, but ORES leads the process. Local ability to delay and thwart projects has contributed to New York’s reputation as a slow, expensive place to develop renewables.

New York has a strong home-rule tradition, and an indeterminate but vocal percentage of its residents are opposed to utility-scale wind and solar installations. ORES’ ability to override local laws does not sit well with them.

In their court challenge, the six towns and seven organizations sought annulment of the regulations through which ORES accomplishes its mission.

They said the state had given power plant siting authority to an understaffed and inexperienced new agency that outsourced the writing of its regulations to an energy industry consultant that represented 25 wind and solar developers in New York at the time.

In drawing up the regulations, the petition charged, ORES disregarded the requirements to avoid or minimize adverse environmental impact and to allow meaningful involvement of citizens.

ORES gave itself the power to authorize clear-cutting of forests, level hilltops, destroy wildlife habitat, kill birds and bats, interfere with bird migration and eliminate farmland, the petition states, and in so doing, to degrade the character of rural New York.

Thursday’s appellate ruling rejected the towns’ and organizations’ challenge and most of the arguments on which it was based.

It found that ORES did classify the rule-making process incorrectly, as the petition alleged, but said that was not cause to invalidate the result of that process.

The ruling also rejected the claim that ORES had not fully considered the environmental implications of its rule making or followed the correct procedure with them. “A review of the vast record reveals that ORES took a thorough and hard look at the potential negative environmental impacts associated with the proposed regulations,” the judges wrote.

The judges also rejected the assertions that ORES had exceeded its statutory authority and that ORES’ ability to pre-empt local laws violates the home rule provision of the state constitution.

“Unreasonably burdensome local laws would thwart the ultimate goals of the legislation,” they wrote.

ORES did not return a request for comment for this story.

On Thursday, the same day the ruling was issued, Gov. Kathy Hochul announced the latest siting approval by ORES — a 94-MW solar farm proposed by EDF Renewables North America in a rural area of southwest New York.

It was the 13th permit ORES has issued since 2021. Those 13 projects have a combined nameplate capacity of more than 2.1 GW.

The case was brought by the American Bird Conservancy, Save Ontario Shores, Cambria Opposition to Industrial Solar, Clear Skies Above Barre, Delaware-Otsego Audubon Society, Genesee Valley Audubon Society, Rochester Birding Association, and the towns of Cambria, Copake, Farmersville, Malone, Somerset and Yates.

Named as defendants along with ORES were its director, Houtan Moaveni, the state itself and the state Department of State.

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NYISO Operating Committee Briefs: May 20, 2023

Summer Operating Study

NYISO’s Operating Committee on Thursday approved the results of an ISO operating study showing New York’s bulk power system can operate reliably this summer based on transfer capabilities.

Prepared by NYISO’s Operating Studies Task Force, the study estimates internal and external thermal transfer capabilities for the summer based on forecast load and dispatch assumptions, as well as any generation or transmission changes occurring since last year. The external analysis covers the ISO’s adjacent balance areas of ISO-NE, PJM and Ontario’s IESO.

The study showed notable changes in internal thermal transfer limits, including a 300-MW increase for the Dysinger East interface and a 400-MW decrease for the Central East interface.

Dysinger East increased due to the redistribution of flows attributed to changes in load pattern in the West and Genesee areas, while the Central East interface decreased due to the modeling of Segment A’s December in-service date. The Segment A project refers to the alternating current transmission projects identified as being needed to increase the Central East transfer capability by at least 350 MW and unbottle the congested region.

A change to external transfer limits was seen in the NYISO-to-Ontario and Ontario-to-NYISO interfaces, which both increased by 100 MW or more due to thermal rating changes for the Niagara–Beck (PA27) 230-kV direct tie line.

NYISO reported that 1,007 MW of fossil-fuel based generating capacity was deactivated and that 1,045 MW of renewable generation was added since last year’s study.

Utility Loss of Gas Studies

The OC approved loss-of-gas-supply study results from Consolidated Edison and PSEG Long Island, which verified loss of gas or minimum oil burn requirements for the coming summer capability period.

Both utilities found that dual-fuel generation would remain necessary during periods of above-average demand, but based on anticipated dispatch conditions, the two studies results remain largely the same as last year.

April Operations Report

NYISO told the OC that 104 MW of land-based wind and 101 MW of solar resources were added in April, and that load peaked for the month at 18,915 MW on April 14.

NYISO also included a new detail in its report: that the month’s minimum load of 11,742 MW occurred April 9. The ISO will be including this data point in its future monthly operations reports to show the impact of increasing behind-the-meter solar generation on loads.

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SPP Briefs: Week of May 15, 2023

RTO Expects ‘Normal’ Summer Operations

SPP said last week it expects “normal” operations in its balancing authority and reliability coordinator areas this summer, with no forecast for extreme operational situations.

According to the grid operator’s summer seasonal assessment, SPP estimates a 99.5% probability that it will have sufficient resources available to serve region-wide load during peak hours. The study found that if load increases by 5% above forecasts, the RTO still has a 95% likelihood that it will maintain resource sufficiency and serve all load.

“We’re expected to be normal this summer,” SPP’s Garrett Crowson said during a May 18 summer preparedness workshop. “It’s possible that we might be tight on certain days, but there are a lot of different avenues that we can use in order to mitigate those issues. We expect to be able to address anything in the near-term horizons, but if there are any high levels of alertness that we need to notify our members, we’re definitely going to be utilizing those existing processes.”

Staff began a seasonal assessment in February and incorporated all capacity and planned outage plans that had been submitted by that time. They included additional outages based on historical experience and other available unknown variables.

“We did a couple of different things in order to stress the system to see if we needed to identify potential mitigations for the summer,” Will Tootle, manager of operational planning, told stakeholders.

That included additional imports and exports with neighboring RC regions and drought conditions that might affect water levels in different rivers. Weather forecasters are predicting extreme to exceptional drought conditions developing in the Central U.S., with low soil moisture increasing daytime surface heat.

“That’s definitely going to have an impact on how different generated resources are going to produce,” Tootle said.

Staff expects transmission constraints and mitigations to be manageable in maintaining required operating criteria.

The grid operator already has issued two resource advisories in May for its 14-state BAA, elevating one of those to a conservative operations call. SPP recorded its highest peak load for May when it reached 34.2 GW, with 2 GW of total reserves, on May 8.

The operating staff has conducted seasonal assessments and presented the results in summer and winter preparedness workshops. The workshops now include the Emergency Communications User Forum, which was created after the February 2021 winter storm.

MMU to Host Market Report Webinar

SPP’s Market Monitoring Unit will host a webinar May 25 at 9 a.m. (CT) to discuss its recently released 2022 market report.

The report identified increasing wind generation, uplift and resource adequacy challenges as continuing issues that deepened last year and played a significant role in the market. It said wind generation has produced many challenges, including increasing variability and supply uncertainty, requiring out-of-market actions to ensure system reliability.

High natural gas prices last year led to increased energy prices in SPP’s markets. Gas prices at the Panhandle Eastern hub rose 69% to $5.83/MMBtu, driving day-ahead and real-time prices to averages of $48/MWh and $43/MWh, respectively, up 80% and 75% from 2021. (See “MMU Report: Energy Prices up,” SPP Board/Members Committee Briefs: April 25, 2023.)

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FERC Accepts NYISO’s 17-Year Amortization Period Proposal

FERC on Friday approved NYISO’s proposed 17-year amortization period when calculating the annual costs for hypothetical fossil fuel peaker plants, a key parameter in its capacity market demand curve (ER21-502).

The order reversed its two previous rejections of the ISO’s proposal, including one on remand from the D.C. Circuit Court of Appeals. The amortization period is now the assumed length of time over which a hypothetical gas-fired power plant is expected to be operational and is used to calculate the net annual cost of new entry (CONE), itself used to calculate the demand curve.

NYISO proposed to move from a 20-year amortization period to 17 years because New York’s enactment of the Climate Leadership and Community Protection Act (CLCPA), which set strict net-zero emission and energy requirements by 2040, will, according to the ISO, force fossil plants to retire sooner.

The proposal was part of a larger set of changes collectively called the demand curve reset (DCR), which altered the parameters and assumptions for capability years 2021/22 through 2024/25. The DCR was approved by FERC on April 9, 2021, though it rejected the 17-year amortization period. (See FERC Approves NY Demand Curve Reset, Rejects 17-Year Amortization.)

The commission had said the proposed period was “speculative and may result in unnecessarily high net CONE estimates” and “fails to consider that the CLCPA does not require that power generators retire in order to satisfy the 2040 zero-emission requirement.”

The Independent Power Producers of New York (IPPNY) appealed FERC’s ruling to the D.C. Circuit, which vacated and remanded the order on Aug. 9, 2022, saying the commission had failed to properly explain its reasoning. (See “DC Circuit Ruling,” No Consensus on PJM Capacity Parameters.)

In response, FERC in December affirmed its earlier rejection with more explanation. It continued to emphasize that the CLCPA did not require plant retirements, as new fuels or retrofits could enable zero-emission dispatchable resources to meet the 2040 zero-emission target.

IPPNY filed a rehearing request, saying the commission “largely recast” the same arguments found insufficient by the D.C. Circuit, ignored the “plain language” of the CLCPA and failed to provide evidence showing NYISO’s proposal is unjust and unreasonable.

The court had said that because NYISO had filed under Federal Power Act Section 205, it was only required to show that its proposal was just and reasonable in and of itself — not whether it is more or less reasonable than alternative designs.

IPPNY also argued that FERC’s reliance on evidence from NYISO’s Market Monitoring Unit and the New York Public Service Commission, which both wanted to maintain the 20-year period, was inappropriate because neither could know “which resources or technologies will be feasible, economically viable or eventually permitted by the state to meet the goals of the CLCPA.”

“Upon further consideration, we set aside the prior determination and conclude that NYISO’s proposal reflects a reasonable interpretation of the CLCPA,” FERC said Friday. “NYISO had to make certain assumptions, which NYISO made based on the currently effective laws and regulations. Given the information available, NYISO’s choices were reasonable. … NYISO’s decision to not consider the potential for new fuels and technologies enabled NYISO to avoid speculating about future technological development and costs.”

NYISO must now submit compliance filings within 21 days of Friday’s ruling that show how the ISO will adopt the new 17-year amortization period for the remainder of the 2021-2025 DCR.

Commissioner Mark Christie dissented against the majority’s decision, arguing that FERC’s reversal not only undermines the commission’s original decisions but disregards expert consensus from the PSC and MMU, whose support for the 20-year period was based on existing knowledge of New York’s energy markets.

Christie said evidence presented suggests that the 17-year proposal would result in “higher costs borne by consumers” and “unnecessarily high net CONE estimates for the proxy peaking unit.”

By the PSC’s own admission, “continuing a 20-year amortization period follows the plain reading of the [CLCPA], which explicitly provides for these implementation processes to be developed over many years and does not require all generation currently running on fossil fuels or the hypothetical proxy unit to retire by 2040,” Christie said.