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August 16, 2024

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BOEM Cites Fishing, Cultural Concerns for Atlantic Shores OSW

New Jersey’s largest planned offshore wind farm would have a “major” effect on commercial fisheries and “scenic and visual resources,” but only a moderate impact in 13 other categories, the Bureau of Ocean Energy Management said Monday in its an environmental impact statement (EIS) for the Atlantic Shores project.

The 900-page draft report on the 1,510-MW project concluded that the wind farm would have “moderate to major” impact on navigation and vessel traffic and a “major” impact on visual aspects of the sea and on cultural resources, such as historic, archeological and geographically significant areas.

The project would also have “negligible to moderate” impact on most mammals, including the endangered North American right whale, the report found. But the cumulative impact of nearby OSW projects and non-wind projects, and Atlantic Shores itself, including decommissioning of the turbines, would be “negligible to major,” the EIS reported. It said adverse impacts would “result mainly from pile-driving noise, vessel noise and presence of structures.”

The impact of OSW projects on whales has emerged as a significant issue in recent months, after several dead whales washed up on the Jersey Shore. Project opponents and two area congressmen have questioned whether the deaths were linked to preliminary marine study work underway for the projects and called for a halt to the projects while the issue is investigated.

Federal and state authorities say there is no evidence that the deaths had anything to do with OSW projects. But poll results released Thursday by Fairleigh Dickinson University suggest the unfounded reports are having an impact on public opinion.

The poll found that when the whale deaths were mentioned in the question, 35% of New Jersey residents said they favored continued offshore wind development, while 39% said development should be halted. When the whales were not mentioned in the question, 42% of those polled were in favor and 33% opposed.

The BOEM report says the impact to the whales of not approving the projects would be “negligible to major,” the same as if the projects go ahead because of issues such as “coastal and offshore development, marine transportation, fisheries use and climate change,” with a warmer ocean and strong storms affecting the sea mammals.

BOEM has scheduled two public hearing to solicit public comments on the draft on June 26 at 1 p.m. and June 28 at 5 p.m., with a 45-day comment period that ends on July 3.

Assessing Impacts

The New Jersey Board of Public Utilities picked the Atlantic Shores project in the state’s second OSW solicitation in 2021, when it also backed the 1,148-MW Ocean Wind II project being developed by Denmark-based Ørsted. The BPU picked Ørsted’s Ocean Wind I project in the state’s first solicitation in 2019. (See NJ Awards Two Offshore Wind Projects.)

The Atlantic Shores EIS covers the project’s first phase, which has been approved by the BPU, and a second phase for an additional 1,327 MW, which has not. Together, the two projects would involve installation of 200 wind turbines.

Monday’s EIS follows by a year BOEM’s release of the draft EIS for Ocean Wind I, which largely made similar assessments. (See BOEM Draft EIS Finds Potential Major Impacts from 1st NJ OSW Project.)

The BPU in March opened the state’s third OSW project solicitation, seeking projects totaling 1.2 GW to 4 GW. (See NJ Opens Third OSW Solicitation Seeking 4 GW+.)

The draft EIS for Atlantic Shores, a joint venture between EDF Renewables North America and Shell New Energies US, assesses the potential biological, socioeconomic, physical, cultural and other impacts of the project, which at its closest is 8.7 miles from the Jersey shoreline.

The study assesses impacts of six different scenarios if the project is approved. These included approval of the entire proposal, along with several scenarios in which the project is modified, including a reduction in the number of turbines and offshore substations to minimize the impact on certain habitats; a reduction of the number of turbines to reduce the visual impact; modification of the project to create a “setback” between the project and neighboring Ocean Wind I; and an adjustment in the type of monopoles used in the foundation to reduce the impact.

The draft EIS then assesses the impact of each scenario and defines them as negligible, minor, moderate or major.

The EIS, for example, concluded in all the scenarios that the impact was either moderate or lower for air; water; birds, coastal habitats and fauna; fish, invertebrates and essential fish habitat; sea turtles; wetlands; demographics, employment, economics; environmental justice; land use and coastal infrastructure; and recreation and tourism.

Increased Vessel Traffic

The study found that the commercial and recreational fishing sectors would be impacted by increased anchoring of boats working on the turbines, marine disturbance caused by cable emplacement and maintenance, and the additional noise generated by construction. Those factors could disrupt fishing trips and make it difficult to fish, as well as prompting some commercial companies to avoid fishing in certain areas — all of which could reduce revenue, the report said.

The effect might also be to push all commercial fishing operations into the same, smaller fishing area, resulting in smaller catches, the report concluded.

“BOEM expects that increased vessel traffic associated with the proposed action would cause long-term, localized, moderate impacts on commercial and for-hire recreational fisheries,” the report concluded. BOEM also found that the overall impact on commercial fishing operations could be “major” in many scenarios.

The study found that the area’s cultural resources would be affected whether BOEM approved the wind projects or not and labeled the impact in the long term “major” in all scenarios, but only “moderate” if the projects were not approved.

“The primary sources of onshore impacts from ongoing activities include ground-disturbing activities and the introduction of intrusive visual elements, while the primary source of offshore impacts includes activities that disturb the seafloor,” the report found. “While long-term and permanent impacts may occur as a result of offshore wind development, impacts would be reduced” through a consultation process to reduce the effects on historic properties, the study concluded.

Navigation and Visual Impacts

The study found that navigation and vessel traffic would experience moderate impact regardless of whether the projects went ahead, in part because of rising traffic in the area and also traffic generated by other offshore wind projects. New Jersey’s OSW projects, if approved, would have a moderate to major impact when added to the cumulative impact of vessel traffic from nearby OSW projects and general water transportation traffic.

“Impacts from the proposed action alone would include increased vessel traffic in and near the project area and on the approach to ports used” by the OSW vessels, the report found. Vessels in the area would also experience “obstructions to navigation” caused by the projects.

During construction, the project would cause “short-term increase in project-related construction vessel traffic, short-term presence of partially installed structures, and short-term safety zone implementation,” the study found.

“Impacts on navigation and vessel traffic would also include changes to navigational patterns and to the effectiveness of marine radar and other navigation tools,” the report said. “This could result in delays within or approaching ports, increased navigational complexity, detours to offshore travel or port approaches.”

The study found that scenic and visual resources would suffer a “major” impact in the longer term, whether the New Jersey wind farms were built or not, because of other wind farms nearby being built and as a result of other marine activities, such as dredging and port improvements, marine minerals extraction and marine transportation, the report found.

If the state’s OSW projects don’t go ahead, “the character of the coastal landscape would change in the short term and long term through natural processes and planned activities that would continue to shape onshore features, character, and viewer experience,” BOEM said.

“Ongoing activities in the geographic analysis area that contribute to visual impacts include construction activities and vessel traffic, which lead to increased nighttime lighting, visible congestion, and the introduction of new structures,” the report concluded. The cumulative impact of other OSW projects and general marine activities would create a “major” impact, the study said. As a result, the cumulative effects of the projects and others in the area would be “appreciable,” the study concluded.

“The main drivers for this impact rating are the major visual impacts associated with the presence of structures, lighting and vessel traffic,” the study found.

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PJM OC Briefs: May 11, 2023

PJM Doubles Synchronized Reserve Requirement

VALLEY FORGE, Pa. — PJM has doubled its synchronized reserve requirement to account for diminished performance since the implementation of the reserve market overhaul in October.

Donnie Bielak, PJM senior dispatch manager, told the Operating Committee that reserve performance has been approximately 50% since the RTO implemented reserve price formation last year, which consolidated reserves into one product, lowered the offer cap from $7.50/MWh to 2 cents and expanded resources subject to the must-offer requirement. (See Synchronized Reserve Pricing Falls in PJM Markets After Overhaul.)

The higher reserve requirement, announced to members Thursday morning, went into effect for the day-ahead market for Friday and was in place starting at midnight. The increase amounts to an additional 1,588 MW procured, equal to the single largest expected contingency.

“This is meant to be an immediate, albeit temporary measure,” Bielak said. “We are doing this to make sure we have reliable and uninterrupted service to the load.”

Several stakeholders questioned the timing and the immediacy of the decision, asking why there was not more notice. Bielak told RTO Insider that following stakeholders’ decision to initiate a quick-fix process to address reserve rates last month, PJM staff determined a more immediate solution was needed going into the summer months.

Generator performance during the December 2022 winter storm may have led to a violation of NERC’s disturbance control performance (DCS) standard by potentially taking 52 seconds longer than the permitted 15 minutes to alleviate a contingency event recovery period on Dec. 23.

Independent Market Monitor Joseph Bowring said PJM hasn’t provided any evidence of a reliability issue or that there is a risk of violating the DCS standard. After the operating reserve rule change on Oct. 1, 2022, the must-offer requirement for synchronized reserve significantly increased the amount of reserves available, he said, noting also that there have been no issues with violating the NERC DCS standards. Bowring also asked PJM to explain why it thinks it has the authority to unilaterally double the reserve requirement.

Bielak said PJM thinks it has been able to procure adequate synchronized reserves because some generators are continuing to operate under the old ruleset, despite not receiving revenue for doing so. As that reality becomes clear for market participants, the RTO may not receive the same response to its calls to generators. (See PJM MIC Briefs: April. 12, 2023.)

PJM Projects Adequate Supply This Summer

The 2023 Summer Study found that the RTO will have enough installed capacity, 186.5 GW, to meet its 90/10 load forecast of 162.7 GW. The non-diversified peak demand is expected to be 156.1 GW.

“PJM works diligently throughout the year to coordinate and plan for peak load operations, with reliability as our top priority,” PJM CEO Manu Asthana said in an announcement of the study on Thursday. “We’re not saying these extreme conditions will happen, but the last few years have taught us to prepare for events we have never seen.”

No reliability issues were identified; however, re-dispatch and switching could be required in some areas to avoid thermal or voltage violations.

Demand response may need to be implemented in the event of “extraordinary electricity demand and high generator outages,” with around 7.5 GW in pre-emergency load management found to be available in the study.

The study found that PJM should have resources to cover the outage scenarios historically seen in the summer months. It also draws on lessons learned from the February 2021 winter storm to incorporate the possibility of extreme conditions without precedent.

“We have learned through experience to expand the set of possibilities we prepare for,” Senior Vice President of Operations Mike Bryson said in the announcement. “We will continue to work with our utility partners and stakeholders to refine our planning, analysis and communications of the risks presented by new and challenging weather patterns and other variables.”

About 15.4 GW of discrete generator outages are expected in the study, as well as 4 GW being lost through net interchange. Under the largest gas-electric contingency, which is expected to take 4.8 GW off the grid, PJM would have an additional reserve margin of 4.1 GW. The no-wind and low-solar scenario would reduce available capacity by 5.6 GW, producing a margin of 3.4 GW.

Last year’s study presented the largest contingency and the low-renewables scenario together; however, PJM spokesperson Jeff Shields said it would be unlikely for those conditions to overlap. (See PJM Summer Forecast Reports Sufficient Supply.)

“We didn’t feel that stacking all the contingencies together made for a plausible scenario,” he said. “We wanted to emphasize that with high generator outage failures and high load, combined with either of the unlikely scenarios of almost no sun in peak summer conditions or major pipeline failure, we would have to call on demand response.”

Discussion Continues on Transmission Outage Coordination Proposals

Bowring and PJM presented additional information on dueling proposals to add transparency to the process transmission owners follow to schedule extended outages. (See PJM OC Briefs: April 13 Proposals Seek to Address Transmission Outage Coordination.)

A joint package from PJM, DC Energy and Public Service Enterprise Group (NYSE:PEG) would involve coordination between utilities and RTO staff to identify any extended outages that may be required, evaluate the impact of those outages and expand outage information shared by PJM. Upgrades to facilities may be considered if outages are expected to cause significant operational issues.

The Monitor’s proposal would consider requests to reschedule an outage as a new request and classify it as a late submission if the request comes too close to the scheduled date. The language also would aim to reduce or eliminate approval of outage requests after FTR bidding opens and prevent TOs from bypassing rules for long-duration outages by breaking them into smaller segments.

Bowring said the Monitor’s proposal wouldn’t change existing processes, but it would more clearly define when outages should be considered late and provide market participants with more information about outages.

“We’re not trying to change the way outages are scheduled. We’re just trying to ensure they’re labeled correctly,” Bowring said. “… The goal is to make it easier to understand why the system is behaving the way it is.”

PJM’s Paul Dajewski said the status quo rules allow for outages submitted on time to be rescheduled regardless of their duration, which provides TOs with flexibility when scheduling their outages. He said the ability to reschedule is necessary to account for circumstances such as delays in equipment availability or weather.

Bowring responded that he understood that outages have to be scheduled well in advance and include flexibility but said the Monitor’s proposal wouldn’t change market mechanisms or how outages are scheduled, instead providing more information for other market participants.

Other OC Business:

  • Stakeholders approved revisions to manuals 3 and 36 under each document’s periodic review. In both cases, the changes were updating the manuals with new information, as well as clarifying language in Manual 3.
  • PJM’s Steve McElwee provided a cybersecurity update, saying that a recent attack on Dragos displays the need to stay vigilant against “social engineering” hacks being used to gain access to sensitive systems. (See Cancel: Dragos Breach Did Not Compromise E-ISAC.) He said if a member’s email systems were compromised, it would be difficult for PJM to determine that a breach had occurred unless it had been detected by that organization.
  • The OC voted by acclamation to sunset the Synchronized Reserve Deployment Task Force due to an inability to determine a path forward since FERC rejected PJM’s intelligent reserve deployment in August 2022. Task force facilitator Vijay Shah said its issue charge has limited the ability to discuss the concerns the commission raised in its order and there has been limited discourse and no proposals currently before the group. Shah noted that PJM’s Adam Keech said during the Annual Meeting that RTO staff plan to bring a new problem statement and issue charge this summer.
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Overheard at the Energy Bar Association’s Annual Meeting

WASHINGTON — Much of the focus at the Energy Bar Association’s Annual Meeting last week was on the grid’s transition from fossil fuels — specifically matching carbon-free electricity to demand curves.

“For many of you, it may feel like the goalposts are moving, complicating business risks,” NorthBridge Group Partner Neil Fisher said. “And what was considered the gold standard five years ago may not be acceptable in the near future.”

While retiring renewable energy credits from wind farms far from the customer was seen as good enough in the past, now many large, sophisticated customers want to match their load with 24/7 clean energy.

The federal government — the largest buyer of electricity in the country, at about 54 TWh per year —historically only tried to comply with the Energy Policy Act of 2005, which required 7.5% of that come from renewables, said White House Council on Environmental Quality Director of Clean Energy Tanuj Deora.

But President Biden has upped that with a goal of getting the federal government to 100% carbon-free electricity by 2030.

“We know it’s very ambitious, right?” Deora said. “So, we are looking actively to figure out how we get there because not only is it ambitious, but it is absolutely necessary. I think we all know that we’re living the consequences of climate change, and the impact on the environment here real time, and so there’s no time to waste.”

Today the grid is already at 40% carbon-free power so the federal government procurements will take that into account.

Deora said the government would not seek to supply its facilities exclusively with the output from existing zero-emissions facilities. Instead, the procurements will focus on new resources. And the government is hedging its bets because it is still unclear exactly which technologies will prove economical and scalable among advanced nuclear, virtual power plants, carbon capture and storage, clean hydrogen and others.

The federal government is not alone in trying to procure more green power. Voluntary commitments from corporate buyers helped to build about 40% of new clean energy resources in recent years, Deora said.

Google (NASDAQ:GOOGL) has aggressive clean energy goals and a total load of 18 TWh annually that is growing because of computing power demands from new technologies like artificial intelligence, the firm’s Brian George said. Google says it has met its entire demand with renewable energy since 2017.

“Even as we do that, there are periods during the day where we still rely on fossil energy to serve our data center demand,” George said. “In 2021, around the world … our data centers consumed about 66% of carbon-free energy on an hourly basis.”

Like the federal government, Google wants to increase that to 100% by 2030, which will require it getting new resources built where they can directly serve its data centers. Focusing on 100% carbon-free electricity can help send the signals that are needed to build out the new technologies required to reach an emissions-free grid, he added.

EBA CFE Panel 2023-05-12 (RTO Insider LLC) Content.jpgFrom left: Neil Fisher, NorthBridge Group; Tanuj Deora, White House Council on Environmental Quality; Brian George, Google; W. Mason Emnett, Constellation Energy; and Lon Huber, Duke Energy. | © RTO Insider LLC

“Our systems are not set up to recognize and reward customers for what they are already doing just from paying their electric bills, much less … be tailored to the actions that the Googles of the world want to be taking to be driving change,” said Constellation Energy (NASDAQ:CEG) Senior Vice President of Public Policy Mason Emnett. “And so, we’re spending a lot of time working with our customers in terms of the product development, the commercialization of these types of products.”

While wind and solar are the cheapest options now, over time the more they get built the less the power produced matches up with demand every hour. Emnett said once they hit about 50% of demand that split starts to grow. Once you get to 100% annual match with renewables, the grid is still relying on balancing resources for about 25% of its total needs, he added.

Interregional Transmission

Another EBA panel focused on getting more interregional transmission lines built.

The experiences of Texas and its neighboring grids in SPP and MISO during the 2021 winter storm are one of the main reasons former FERC Chair Richard Glick wants to see interregional transmission built. ERCOT lacked major connections with the outside, and it was short on power for days, leading to hundreds of deaths, while  the nearby sections of the Eastern Interconnection were able to import power from farther afield and avoided the worst.

“There is a lot of consensus out there that much more is needed in terms of connections between these regions,” Glick said.

Many in Texas might still be skeptical about linking up with the rest of the grid. But in other regions, even state regulators have indicated that they support addressing the barriers to interregional transmission.

“We do know, with regard to interregional transmission in particular, that there are multiple benefits,” Glick said. “And part of the problem — some are very easy to quantify, like probably production cost reductions — …  but some of the benefits, whether it be resilience, whether it be achieving public policy goals … are more difficult to quantify.”

Figuring out a way to quantify those benefits is going to be necessary to make progress and deal with the very tricky issue of cost allocation, he added.

“Whenever we talk about transmission, it always does come down to cost allocation,” Glick said. “There’s a lot of other issues. There’s always barriers, but cost allocation is the big one.”

While interregional transmission can produce benefits, the conversation around expanding it has not been very refined, said Edison Electric Institute Managing Director Kevin Huyler.

“When I look at some of the proposals that are out there for driving interregional transmission investment, I don’t see a lot of nuance, which sometimes isn’t surprising, particularly if it’s a legislative proposal,” Huyler said.

Some have suggested that regions should be able to get a 30% minimum transfer requirement, but Huyler said nobody really knows what the right number is, and getting accurate figures is vital to proper transmission planning.

“It can’t be entirely precise,” he added. “But I think there has to be an effort made … to have customers and stakeholders [understand] why that much is being built.”

Invenergy is pursuing merchant interregional projects around the country, along with the development of new renewable resources and that makes it come at the issue with a sense of urgency, said its Executive Vice President of Public Affairs Kelly Speakes-Backman.

“I don’t want to turn this into a whole climate discussion, but it’s real and it’s here, and we’ve got not a lot of time to fix this,” Speakes-Backman said. “Frankly, the planning and the work that goes into it takes a really long time. And this is part of why we’re in the transmission business itself — to help with the urgency.”

Invenergy can make it easier to get transmission by investing its capital to get new lines constructed. But it does need to get paid for the benefits of such investments to make it work economically, she added.

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West Coast States Should Collaborate on OSW, Panelists Say

 

SACRAMENTO, Calif. — West Coast states need to work together on transmission, ports and industrial infrastructure to achieve their goals for floating offshore wind, speakers at this year’s Pacific Offshore Wind Summit said.

The two-day event, hosted by Offshore Wind California, drew 700 attendees to the SAFE Credit Union Convention Center in downtown Sacramento on May 9-10.

Panelists encouraging collaboration cited lessons learned, both positive and negative, from the East Coast’s experience developing offshore wind projects and infrastructure.

Travis Douville 2023-05-13 (RTO Insider LLC) FI.jpgTravis Douville, Pacific Northwest National Laboratory | © RTO Insider LLC

“What we have learned is that there’s great power in bringing the states together,” said Travis Douville, who leads wind energy grid integration research at the Pacific Northwest National Laboratory.

“There already are models of substance in play,” Douville said during a panel on offshore wind transmission. For example, the New England States Transmission Initiative “is showing real promise, and the idea here is that states can come together and develop a shared transmission plan that serves all of their needs at the state level.”

Last year, five New England states — Connecticut, Massachusetts, Maine, New Hampshire and Rhode Island — announced their joint initiative to explore investment in the transmission infrastructure they need to integrate offshore wind and other clean energy resources while improving grid reliability.

In January, the states said in a joint statement that they were seeking funding from the Department of Energy to strengthen New England’s grid and reduce dependence on fossil fuels. (See New England States Group Up To Push For Federal Transmission Funding.)

One of their proposals, the Joint State Innovation Partnership for Offshore Wind, would “proactively plan, identify and select a portfolio of transmission projects needed to unlock the region’s significant offshore wind potential, improve grid reliability and resiliency, and invest in job growth and quality.”

California, Oregon and Washington could benefit from similar arrangements, Douville said.

‘Pacific Coast Scale’

The West Coast states have nearly 300 GW of potential capacity from floating offshore wind turbines, the National Renewable Energy Laboratory estimated in a study last year. California has 88 GW of potential capacity. Oregon has 150 GW, and Washington has 59, NREL said.

The states, federal government and private industry are planning to develop that capacity, starting south and working north.

The Bureau of Ocean Energy Management (BOEM) held the first West Coast wind auction Dec. 7, when five lease areas off the California coast, with 4.5 GW of total capacity, brought more than $757 million in winning bids. (See First West Coast Offshore Wind Auction Fetches $757M.)

Three of the lease areas are in the Morro Bay Wind Energy Area off the coast of Central California, and two are in the Humboldt Wind Energy Area off the coast of Northern California.

The auction was crucial to achieving the Biden administration’s goal of deploying 15 GW of floating offshore wind in deep waters by 2035, the Interior Department said. The California Energy Commission has proposed offshore wind goals of 25 GW by 2045. (See California Boosts Offshore Wind Goals.)

Off the coast of Oregon, BOEM has identified three call areas with 17 GW of capacity, one of which, the Brookings Call Area, is 60 miles north of California’s Humboldt Wind Energy Area. The proximity quickly prompted discussion of collaboration between the West Coast states.

“The growing Pacific Coast scale of this … sets in motion a whole set of speculation about coordination across the region,” Adam Stern, executive director of Offshore Wind California, told an Energy Bar Association meeting shortly after BOEM announced the Oregon call areas Feb. 24, 2022. (See Energy Bar Weighs OSW in Oregon, California.)

In Washington, BOEM has received two unsolicited bids for floating wind farms but has yet to identify any call areas.

‘Economies of Scale’

Ryan Calkins 2023-05-13 (RTO Insider LLC) FI.jpgRyan Calkins, Port of Seattle | © RTO Insider LLC

Washington has moved more slowly on offshore wind, in part because of its vast supply of hydroelectric power, said Ryan Calkins, a Port of Seattle commissioner and part of a panel on West Coast collaboration.

“We have such an abundant source of renewable energy in hydro that I think we didn’t get off the starting blocks very quickly,” Calkins said. “However, I think we’re starting to see some real progress.”

The state has an energy strategy that includes 3 GW of offshore wind by 2045, and “oftentimes you’ll hear our state officials talk about ‘it’s not if, but when’ we will get into offshore wind,” he said.

The state is expecting to learn from California’s experience with offshore wind, including its effects on fisheries, coastal communities and Native American tribes, he said.

“When we join California in a few years with our own plans for offshore wind, I welcome the inputs of California ports and supply chains to help us meet our targets,” Calkins said. “I think it just makes sense for us to have a systemwide approach to this.”

Some types of collaboration between the states are already happening and could serve as models for offshore wind, he said. For instance, West Coast ports employ standardized container shipping equipment that allows ships to offload in multiple ports, from Seattle to Long Beach, after crossing the Pacific from Asia. The setup promotes efficiencies of scale, he said.

“We also have a shared workforce, whether it’s the unions that tie us all together or the brain trust behind what we do, and the various contractors that every port relies on for port design or for engineering services,” Calkins said. “Those same sets of skills are going to be needed for the extension of ports along the West Coast.”

On an international scale, “I think that if we manage to pull off strong collaboration on a coastwide level here, we actually have an opportunity to chase a much bigger prize, which is a larger Pacific Rim system developing offshore wind that includes Korea, Japan, China and elsewhere,” he said.

“But if Washington tries to do it alone, or even if California tries to do it alone, we’re not going to have the kind of efficiencies or economies of scale to be able to participate in bilateral trade with some of those nations, which have even bigger goals than we do in a lot of instances,” he said. “So, I think we’d benefit if we collaborate.”

Competition vs. Collaboration

The East Coast has seen a combination of competition and collaboration that has fostered growth but has also led to inefficient development, panelists said.

Molly Croll, Pacific offshore wind director for the American Clean Power Association, said, “Competition as well as collaboration stimulates progress.”

“Competition has been a big part of progress on the East Coast,” Croll said. “There’s been competition for who can set the highest offshore wind target, who can procure the best projects first … and [who can offer the best] local incentives for supply chain and manufacturing. So, competition is a motivator, but obviously competition without collaboration will lead to inefficiencies, gaps and redundancies, which we don’t want.”

Croll, a California resident, said her home state should take the lead.

“I do not want California to wait for other states to get to where California is,” she said. “But I think there’s still so many areas for potential collaboration, [such as] best-practice sharing and information sharing. That’s a no-brainer. We should be doing that. California is doing a lot of things for the first time that Oregon and Washington will benefit from.”

“Then, moving up towards shared planning, I would love to see that, especially if we can coalesce states around a shared vision of large-scale offshore wind,” Croll said. “Harder to do [are] mutual commitments, shared investments, things like that, but we could get there. And hopefully, working on those first steps provides a platform and habit of collaboration.”

Tony Appleton 2023-05-13 (RTO Insider LLC) FI.jpgTony Appleton, Burns & McDonnell | © RTO Insider LLC

In a panel on building a sustainable West Coast wind industry, Tony Appleton, offshore wind director for engineering firm Burns & McDonnell, said the West Coast could learn from the East Coast’s mistakes.

“The lesson learned from the East Coast is that not everybody actually worked together,” Appleton said. “Everybody was kind of doing their own thing in their own little silos and actually not realizing what the bigger picture was.”

Developers focused on their own projects, and states competed for ports, jobs and supply chain opportunities, he said.

“I think what, what the West Coast could do — what California, Oregon, etc. can do — is actually work together, get all of those key stakeholders working together, rather than … against each other. Because if you get them working together, they will come up with solutions that everybody’s happy with.”

Europe spent 20 years learning to work together on offshore wind, Appleton said.

If California takes a collaborative approach from the start, “It goes straight from iPhone 8 to iPhone 15 and not through all the steps in the middle.”

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PJM Members Committee Approves Performance Penalty Reduction

VALLEY FORGE, Pa. — The PJM Members Committee on Thursday approved a proposal that would sharply reduce the penalties generators pay for underperforming during emergency conditions.

The proposed tariff revisions would effectively lower the current penalty rate ($3,177/MWh) and annual stop loss ($142,952/MW-year) by changing the figures from being based on the net cost of new entry (CONE) to Base Residual Auction (BRA) clearing prices for the locational deliverability area (LDA) that the resource is located within. The shift would result in a penalty rate of $394/MWh and a stop loss of $17,744/MW-year. (See PJM MRC Endorses Proposal to Reduce Performance Penalties.)

The conditions under which PJM could declare a performance assessment interval (PAI) would also be tightened, limiting when generators can be subject to performance charges.

PJM General Counsel Chris O’Hara said the tariff revisions should be filed by the end of the month to ensure that they can be implemented for the upcoming delivery year. The changes would be in effect through the 2024/25 DY, with proponents describing it as a temporary measure to realign penalty risks while stakeholders consider a capacity market overhaul through the Critical Issue Fast Path (CIFP) process. (See PJM Stakeholders Refine CIFP Capacity Market Proposals.)

The Markets and Reliability Committee endorsed the proposal, brought by American Municipal Power (AMP), a week earlier. Director of PJM Regulatory Affairs Lynn Horning said the RTO’s Capacity Performance (CP) structure has been a proven failure and the proposed tariff changes would align penalties with the revenues received by generators.

“We do need to get to a market design with appropriate penalties,” she said.

An alternative measure only including the PAI trigger provisions was presented by Constellation Energy, but it would only have been considered by the committee if the main motion had failed. Vice President of Market Development Bill Berg said the alternative was a compromise to reduce litigation and would have preserved a strong incentive for generation owners to ensure their facilities would be able to operate during emergencies.

“We think it’s better aligned with assuring reliability,” he said. “It ensures a fundamental CP market-based approach to incentivize strong performance.”

Berg said changing the penalty structure would have impacts on reliability and predicted that the company would protest any eventual FERC filing.

According to the voting report, the strongest support for the main motion came from the Electric Distributor sector, which gave unanimous support in the sector-weighted voting. The Other Supplier and Generation Owner sectors also gave significant support, while End-Use Customers were nearly split at 59% supporting — breaking down to industrial customers supporting and consumer advocates opposing. Transmission Owners were 67% opposed.

PJM’s Adam Keech said the RTO supported changing the PAI triggers, as staff participated in the drafting of the trigger language, but he expressed concerns that reducing penalties without creating mandates to ensure generator performance would undermine the logic of CP: to receive performance through incentives rather than hard requirements.

Heather Svenson, RTO strategy manager for Public Service Enterprise Group, said the proposal would use clearing prices in LDAs to determine penalties for generators in those regions but distribute the bonuses across the RTO. That arrangement could create significant imbalances between the penalty risk and bonuses a generator could receive, she said.

“There’s going to be an inherent mismatch between bonus and penalties,” she said.

PJM’s Stu Bresler said a similar arrangement exists today with the difference between CONE areas, but those regions have closer values than the current spread between LDAs and the Rest-of-RTO region.

Gregory Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), said some advocates were opposing the changes based on a belief that they would prioritize the preservation of existing generators, even if they are not meeting their capacity obligations.

Denise Foster Cronin of the East Kentucky Power Cooperative supported the proposal, saying it would align the penalties with the revenues received by generators.

Alex Stern of Exelon said changing penalties for a delivery year after auctions have already been run could raise retroactive ratemaking concerns at FERC.

The Natural Resources Defense Council released a statement following the MC vote saying the proposal constitutes a bailout of underperforming generators at the expense of those that made investments to back up their capacity offers.

“The public has paid tens of billions of dollars to power plant owners for the promise of reliable service,” said Senior Advocate Tom Rutigliano. “Last winter, we found out that many of them, mostly natural gas owners, failed to prepare to deliver the power they were getting paid for. Today, those same owners have voted to let themselves off the hook if they fail again in the coming winter.”

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NJ EV Charger Plan Advances as Enviros Demand ACC II Adoption

The New Jersey Turnpike Authority has signed a deal to put 260 chargers on the state’s two main arteries — the turnpike and the Garden State Parkway — by 2038, even as environmental groups urged the state to move faster to adopt rules that would put more electric vehicles on state roads.

The authority’s agreement with Ireland-based Applegreen NJ Welcome Centres, which operates service area restaurants on the highways, requires the company to design, permit, install, own and operate 80 EV charging ports for passenger vehicles on the highways by the end of 2025.

Applegreen must install an additional 160 charging ports by April 2033, or whenever the number of EVs in New Jersey equals 10% of all vehicles in the state. The deal, which the authority board approved on April 25, also requires Applegreen to construct and operate 20 EV charging ports for medium-duty vehicles by the end of 2038.

The authority’s vote preceded a May 3 report by the Sierra Club and Natural Resources Defense Council (NRDC) highlighting what the groups say are the climate, health and job benefits of New Jersey adopting California’s Advanced Clean Cars II (ACC II) regulations. The rules would require 43% of new vehicles sold in the state to be zero-emission by 2027 and 100% by 2035.

“We urge New Jersey to move forward quickly with the Advanced Clean Cars II Program in order to promote public health and address the climate crisis, while also positioning ourselves as a market leader in clean transportation across the nation,” Anjuli Ramos-Busot, director of the New Jersey Sierra Club, said in a release outlining the report.

‘Omnipresent’ Charging Stations

The highway charger installation plan is the latest part of New Jersey’s aggressive effort to put more EVs on the road. The state had 93,000 EVs at the end of 2022, according to the Board of Public Utilities, well below the state’s target of 330,000 registered light-duty EVs by 2025.

New Jersey officials, like those in other states, believe that getting more chargers on the roads is key to motivating more EV purchases by reducing range anxiety — the worry that the distance limitations of an EV will cause a battery-powered vehicle to run out of charge in a location where there are no chargers.

“Electric vehicle charging stations need to become as omnipresent as gas stations in order to build the consumer confidence that’s necessary to make the transition that is undoubtedly required,” Commissioner Shawn LaTourette, head of the New Jersey Department of Environmental Protection (DEP), told a state Senate Budget Committee hearing on May 2.

He said the state now has 2,600 charging stations, up from 800 in 2020. The DEP, through a charger installation incentive program called It Pays To Plug In, has already awarded $16 million in subsidies for 1,700 chargers, with applications for another $8 million waiting because the funding has been exhausted.

The turnpike authority’s deal with Applegreen, which does not involve the DEP, sets out a $166 million program for charger installation, of which the authority will pay $25.7 million, contributing $1.28 million per service area. (See Rest Stop Operator Seeks Piece of $166M NJ EV Charger Push).

Service areas on the New Jersey Turnpike and Garden State Parkway currently host 76 chargers — 70 on the turnpike and six on the parkway. Most of the chargers are for Tesla vehicles.

Applegreen will be responsible for all buildout and operating costs, and the authority will receive 5% of the revenue from each charging space, or $1,250 — whichever is greater. The authority also will get 0.5% of any subsidy of $2 million, or $10,000.

The authority, in its approval order, said Applegreen’s existing on-site presence as a rest-stop restaurant operator means it is well placed to “quickly roll out and efficiently manage EV Charging Services at the Service Areas to the benefit of Authority patrons and overall Service Area operations.”

Market Trends

The state’s effort to ramp up charging stations is just one element of a passel of initiatives to promote EV adoption. They include several EV purchase incentives, as well as the adoption of ACC II, the plan that Gov. Phil Murphy announced in February. Environmental groups have since urged the state to move as quickly as possible in order to get them enacted by the end of the year. (See Enviros Demand NJ Move Faster on 100% EV Rule.)

If that happens, the rules would first apply to the 2027 vehicle manufacturing year, rather than postponing the impact until the following year if the state misses the year-end deadline. (See Enviros Demand NJ Move Faster on 100% EV Rule.)

Speaking at an Assembly Budget hearing on April 24, LaTourette said his agency is still evaluating the California rules and has not yet proposed New Jersey’s rules for adoption. Under federal law, the state can adopt California’s version of the rules and does not have much leeway to change them.  (See NJ Governor Sets Out Accelerated Emissions Targets.)

“I’m not sure that we can also get it adopted this year, given the time that it takes to get a rule from proposal to adoption,” LaTourette told the hearing, adding that “we would do all we could in order to make to make that happen [so] that we don’t lose out on a model year of benefit of improving air quality.”

There is no doubt the rules are needed, he said.

“This is the way the market is going; this is where the market is,” he said. “So having supportive regulatory reform coupled with incentives and market action, that’s the type of trifecta you want to see in order to make real progress on what is our greatest source of climate pollution in this country.”

He also told the hearing the state would have to “double down on our investment in electric vehicle charging capacity.”

Cost-Benefit Analysis

The Sierra Club-NRDC report, which was prepared by global consultant ERM, seeks to highlight the impact of ACC II by conducting a numerical analysis of the benefits of adopting the rules for light-duty vehicles.

The report looks at three scenarios of ACC II adoption and assesses the costs and benefits of their impact on the market and pollution in the state.

One scenario looks at the impact if car manufacturers used “compliance flexibilities” in the rules to meet their requirements, and so selling fewer EVs than predicted.

The second scenario assesses the impact given the same manufacturer response but if the state reached 100% clean electricity generation by 2035, earlier than expected.

The final scenario assesses the situation if manufacturers didn’t use the “compliance flexibilities” and reached the projected EV sales figures and the state achieved 100% clean energy generation by 2035.

The report also compared the outcomes of the three scenarios to the scenario of “business as usual,” with no implementation of ACC II.

The report found that all three ACC II scenarios would bring “significant cumulative net societal benefits,” ranging from $84 billion in benefits from 2027 to 2050 in the first scenario to $97 billion under the third scenario.

The benefits included between 175 and 358 fewer premature deaths from breathing polluted air and 170 to 362 fewer hospital visits from the same reason.

The report estimated that under the first two scenarios, 16% of light-duty vehicles in the state would be EVs by 2030, rising to 68% by 2040 and 94% by 2050.

In the third scenario, 19% of vehicles would be EVs by 2030, 70% by 2040 and 94% by 2050.

“The report findings make clear that adopting Advanced Clean Car II rules would bring immense benefits — including improved public health and vehicle owner savings — and put the state on a pathway that centers climate action around clean air, health and affordability for all New Jerseyans,” Kathy Harris, clean vehicles and fuels advocate at NRDC, said in the release outlining the report.

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NYISO Recommends NYPA-Transco Proposal for Long Island Tx Need

NYISO staff last week selected a proposal by Propel NY Energy to meet the ISO’s Long Island Public Policy Transmission Needs (PPTN) solicitation for transmission lines to export offshore wind energy and unbottle constraints across the island.

Propel, a partnership between the New York Power Authority and NY Transco, proposed three new 345-kV lines on the island. In a draft report released May 8, staff said the proposal would add “a strong 345-kV backbone to the Long Island transmission system that not only allows the delivery of offshore wind power but also will effectuate the efficient transfer of power in the future, providing optionality for resource planning and expansion needed to achieve” the state’s climate goals.

NYISO rankings for Tx projects from PPTN (NYISO) Content.jpgNYISO rankings for top-tier transmission projects from PPTN | NYISO

The goal of the PPTN was to add at least one bulk transmission intertie cable to increase Long Island’s offshore export capability by at least 3,000 MW and upgrade associated local transmission facilities to accompany the growing scale of wind power development off the Long Island coast, according to the report (20-E-0497).

Propel, along with the Long Island Power Authority and Consolidated Edison, would build two lines between Shore Road and Sprain Brook and one between East Garden City and Tremont for $3.26 billion. Propel, however, proposed a soft cost cap of $2.9 billion with a commitment to not recover 20% of included capital costs above the cap from ratepayers, which was one of the major evaluation criteria the ISO considered.

Staff also found that the proposal has a potential economic benefit of up to $3.6 billion over 20 years and, although not required by the PPTN, would relieve the 138-kV Barrett-Valley Stream congestion constraint.

NYISO presented the report to the Transmission Planning Advisory Subcommittee on Thursday.

Mark Younger, president of Hudson Economics, contended that the ISO’s “presented results are not detailed enough” and what stakeholders have seen “has been very high level.” He argued that because NYISO did not conduct a transmission security analysis examining the potential impact on the capacity of neighboring zone interfaces, the ISO’s stated benefits may be overstated.

“It’s like [NYISO] is the old economist, where [you’re] on a desert island and have a can of food but are assuming there is also a can opener,” he said. “It would be kind of embarrassing if after the line goes in that the ISO discovers that you have too much capacity in Zones H through K.”

Cost cap for PPTN Tx projects (NYISO) Content.jpgIndependent estimate and voluntary cost cap for PPTN transmission projects | NYISO

 

NYISO staff acknowledged that although they did not perform that specific analysis, “overall New York state will benefit from this public policy transmission need, and this is our recommendation to our board.”

Doreen Saia, an attorney with Greenberg Traurig, sought clarification on a potential appeals process, which NYISO confirmed was possible but added that the board is not looking to receive any more presentations.

The ISO will present its recommendation to both the Business Issues and Management committees on May 24 and 31, respectively, seeking stakeholder advisory votes before advancing to the Board of Directors for final approval. The board will consider any submitted written comments or requests sent to PublicPolicyPlanningMailbox@nyiso.com.

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Inslee Signs Wash. Bill to Dim Turbine Lights

Gov. Jay Inslee last week signed a bill that requires Washington wind farms to turn off their blinking aviation obstruction lights at night when no low-flying aircraft are around.

“This ensures wind farms are good neighbors,” Inslee said at the signing. There had been some speculation that the governor might veto the measure.

Rep. April Connors (R) introduced House Bill 1173 after residents of her hometown Kennewick complained that blinking lights at a proposed wind farm in the Horse Heaven Hills just south of the city would ruin their nighttime view of the ridgeline. The bill easily sailed through both the state Senate and House with bipartisan support. (See Washington House Calls for Dimming Turbine Lights.)

But Inslee vetoed two sections of the bill.

The first vetoed section would have made the bill effective immediately instead of the more typical date of July 1. Inslee did not say why he vetoed that segment.

The second vetoed section would have given county commissioners the authority to control the amount of light to be emitted.

Scout Clean Energy has proposed building up to 224 wind turbines — about 500 feet tall — on 112 square miles of mostly private land in the Horse Heaven Hills. About 294 acres of that land would also hold solar panels. The wind turbines and solar panels are projected to produce 1,150 MW at full capacity. 

At a Jan. 16 hearing before the House Environment and Energy Committee, Connors said the blinking lights on top of the 500-foot towers could be seen across an area with roughly 200,000 residents. Germany has a similar law in effect, she said. Connors noted that Washington already has about 2,000 wind turbines.

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Senate ENR Searches for Bipartisan Compromise on ‘Permitting Reform’

Sen. Joe Manchin (D-W.Va.) opened Thursday’s hearing of the Senate Energy and Natural Resources Committee with an urgent call for members on both side of the aisle to put politics aside and hammer out a bipartisan bill to accelerate and streamline permitting of energy and transmission projects.

“No energy sector is immune to permitting roadblocks,” Manchin said. “We all need to sit down and negotiate in good faith. We need to take our names off the bill and go back to a bipartisan permitting reform bill. That’s the only way we can take the politics out of this. It’s not me; it’s not [Ranking Member Sen. John Barrasso (R-Wyo.)]. It’s not any of our colleagues. It’s getting permitting done for the sake of our country.”

John Barrasso (Senate ENR Committee) FI.jpgSen. John Barrasso (R-Wyo.) | Senate ENR Committee

Manchin’s comments set the tone for a hearing that reflected the current state of play on “permitting reform,” as the issue is commonly referred to. Manchin wants to have a bipartisan bill completed by the time Congress goes into recess for August, but while potential common ground has emerged on some issues, flashpoints remain that will require tradeoffs and compromise.

Potential points of agreement include the need for permitting to be technology- and project-neutral, while also setting predictable time frames both for environmental reviews under the National Environmental Policy Act (NEPA) and for legal challenges to project approvals.

The points of conflict are cost allocation for interstate transmission lines and FERC’s “backstop” siting authority, under which the commission can approve such projects if a state has failed to act on a permit for a year or has denied a permit for a project deemed in the national interest. Both are issues that raise thorny questions about federal authority versus states’ rights on permitting such projects.

The momentum for compromise on these and other issues is being driven by the common agreement that changes are urgently needed. At stake is the country’s ability to leverage the billions of dollars of clean energy funding in the Inflation Reduction Act and Infrastructure Investment and Jobs Act to reach President Joe Biden’s goals of a 100% decarbonized grid by 2035 and net-zero emissions economy-wide by 2050.

Senators on both sides of the aisle talked about key projects in their states that have been bogged down in the permitting process or litigation for years.

Manchin’s is the Mountain Valley natural gas pipeline, a 300-mile-long project running from northwestern West Virginia to southern Virginia, which filed its first permit application in 2014. The pipeline is 94% complete, according to the project website, but remains tied up in litigation, with the U.S. Supreme Court most recently sending a suit filed by landowners in western Virginia back to district court for reconsideration.

Sen. Steve Daines (R-Mont.) pointed to the Rock Creek and Libby mine projects, proposed silver and copper mines to be located in a major wilderness area in his state, which environmental groups have been opposing for at least two decades.

‘Designed to Fail’

Industry stakeholders at the hearing also spoke of the diverse impacts of delayed and canceled projects resulting from the current system.

“The process for planning transmission that spans more than one region is unworkable,” said Jason Grumet, CEO of the American Clean Power Association. “It subjects developers to an impossible triple hurdle, requiring separate approvals by each region and a ‘coordinated’ interregional approval process, which is literally designed to fail because different regions apply different evaluation metrics and have no obligation or incentive to consider full project benefits.”

Jason Grumet (Senate ENR Committee) FI.jpgJason Grumet, American Clean Power Association | Senate ENR Committee

Growing markets for renewable energy and electric vehicles mean that “demand for [minerals] is expanding exponentially,” Rich Nolan, CEO of the National Mining Association (NMA), said in his testimony. “But we have not seen corresponding actions to support increased production of these critical mined materials.”

Citing an NMA analysis, Nolan said, “In 2022, the U.S. reached its highest level of mineral import reliance. … Each new announcement of a blocked domestic mine locks in our competitive weakness and weakens our national security. Without permitting reform, we will be watching the global competition for minerals and energy control from the sidelines.”

Elizabeth Shuler, president of the AFL-CIO, measured the impacts of permitting delays in terms of potential union jobs lost. The 18 years it took for the recent final approval of the TransWest Express transmission line meant “18 years of lost economic opportunity for workers,” she said.

Elizabeth H Shuler (Senate ENR Committee) FI.jpgElizabeth Shuler, AFL-CIO | Senate ENR Committee

“Every job in every part of the energy sector and the manufacturing sector depends on permitting and siting,” she said.

“Full implementation of the [Inflation Reduction Act] alone will create more than 1 million new jobs and bring down emissions across the economy. But without permitting reforms, job creation will be more modest, and emissions could actually go up.”

Paul Ulrich, vice president of Jonah Energy, a Wyoming natural gas producer, spoke of increasingly long time frames for permitting oil and gas projects, with environmental reviews taking anywhere from six to 12 years.

“The average time to process an [application for a permit to drill] a well has increased by 124% from 2018 to 2022, averaging 271 days,” Ulrich said.

Certainty, Speed, Consistency

In his opening remarks, Sen. Barrasso summarized the three principles that GOP lawmakers and many industry stakeholders are advancing as a basis for reform.

“First, legislation must benefit the entire country, not a narrow range of special interest-favored technologies or a limited group of projects,” he said. “Second, it must include enforceable timelines to ensure environmental reviews don’t drag on for years. Third, it must place limitations on legal challenges to prevent endless litigation intended to kill projects.”

Bills introduced by Manchin, Barrasso and Sen. Shelley Moore Capito (R-W.Va.), ranking member of the Senate Environment and Public Works (EPW) Committee, all have proposed a two-year limit on environmental impact studies, the most intensive level of NEPA review, and one year for lesser environmental assessments. (See related story, Podesta Lays Out Biden’s Priorities for ‘Permitting Reform.’)

Paul Ulrich (Senate ENR Committee) FI.jpgPaul Ulrich, Jonah Energy | Senate ENR Committee

They also call for reviews to be led by a single federal agency that coordinates the associated reviews of other agencies and issues a single, final environmental review.

Manchin’s Building American Energy Security Act includes a 150-day time limit on legal challenges once a project has been permitted. Both Barrasso’s Spur Permitting of Underdeveloped Resources Act and Capito’s Revitalizing the Economy by Simplifying Timelines and Assuring Regulatory Transparency Act would cut that time frame down to 60 days.

Grumet said ACP supported the basic concepts such proposed reforms with the caveat that “none of these changes will undermine the bedrock protections of our environmental law.”

But, he said, “while NEPA reform is necessary, it is not sufficient” to accelerate the buildout of the interstate transmission needed for rapid clean energy deployment and to ensure adequate energy transfers between regions in emergency situations.

Rich Nolan (Senate ENR Committee) FI.jpgRich Nolan, National Mining Association | Senate ENR Committee

Grumet’s written testimony details ACP’s “discussion framework” for changes to NEPA permitting and FERC backstop siting authority that could cut transmission approvals to three years. Under this framework, project developers could apply to the Department of Energy for a designation of a National Interest Electric Transmission Corridor for their projects, with the department issuing a decision within 90 days. FERC would undertake a NEPA review, with a two-year time limit, while the project developer could simultaneously file for state approval and begin the pre-application process for FERC backstop siting. (See DOE Rolls out New Process for Designating Key Transmission Corridors.)

“Congress [would] codify FERC’s proposed policy for simultaneous state and FERC review,” according to Grumet’s statement. “This would continue to recognize the primacy of the states’ role in siting transmission infrastructure but would help remove a year off the backstop siting authority process, as the FERC prefiling process takes that long and would likely be completed by the time a state made its decision on whether to permit a line, saving a year in the overall permitting process.”

Shuler also advocated for accelerated permitting timelines “that [do] not come at the expense of the rights of states, tribes, communities or other stakeholders to have an effective voice in the process or to intervene informally.”

Her three must-haves were certainty (“We need to know when a final decision will be made, and that it is in fact final.); speed “to deploy a full range of clean energy technology”; and consistency, meaning “a standardized process that can apply to all forms of permitting for all technologies.”

Ulrich and Nolan both called for clear timelines on permitting and legal challenges, and a prohibition on moratoriums on either coal or natural gas leasing, or pipeline approvals.

Federal vs. State Primacy

While Democrats and Republicans spoke of the need for speed on permitting, the sharpest questions of the hearing came on the issues of cost allocation and FERC’s backstop siting authority.

Sens. Cindy Hyde-Smith (R-Miss.) and Josh Hawley (R-Mo.) pushed Grumet for his position on federal versus state primacy on permitting and whether states should pay for transmission that provides no direct economic benefits to their residents.

While first established in the Energy Policy Act of 2005, Grumet said, “the backstop authority enabling federal action to permit projects of national significance has been used successfully exactly never, and if it were employed, it would take a decade or longer to permit a long-distance line.”

But using the backstop authority does not mean cutting states out of the process, Grumet said. “Instead of having to wait for states to move forward, we can use the backstop authority that was already put into law, give the states a chance to move forward with that permitting but have the federal government have a response if the states fail to act,” he said. “It is not taking them out of the process; it’s just requiring them to work within the process.”

Answering a question from Hawley on states’ jurisdiction in transmission permitting, Grumet said, “States have a role to play and have to have a role. But that role has to be guided with the same kind of deliberate national interest that we’ve been talking about … that there [are] transmission interests that [are] in the national interest. …

“Electricity moves very quickly, covers far distances, and we have to be able to bring that larger vision so that we actually protect ourselves as a nation and as a community,” he said.

Similarly, on cost allocation, Grumet said regions have a role to play, but “they have to play it. They can’t rope-a-dope the nation into energy insecurity.”

Projects must be justified on the basis of the economic benefits they provide, he said, “but we have to recognize that there are benefits greater than what you’re paying per kilowatt-hour. It’s a benefit for your lights not to go out. It’s a benefit for your region to be able to be saved with power if you have a terrible storm. It’s a benefit for you to have the capacity to bring new industries into your region. It’s a benefit to have lower-cost power brought to you from other parts of the country.”

Herding Cats

The calls for a “regular order” of bipartisan negotiations notwithstanding, the chances are mixed for a substantive bill being negotiated by August recess.

Manchin is calling for concessions on both sides. “We can’t let the perfect or the politics be the enemy of the good and continue to live with an outdated permitting system that kills much needed projects across the spectrum,” he said at Thursday’s hearing.

But ClearView Energy Partners sees only limited overlap between the GOP bills and Manchin’s, as well as a bill that EPW Chair Tom Carper (D-Del.) hopes to have finished by Memorial Day.

Capito’s bill could undercut NEPA authority by allowing de facto approval of projects if an environmental review is not completed within the proposed two-year time frame. Further, legal challenges to such approvals would be severely limited.

Manchin has promoted his bill, which he reintroduced this year after failing in December, as the only one currently on the table that has drawn demonstrated bipartisan support, with 40 Democrats and seven Republicans voting for it.

One of its key provisions is a requirement for the president to designate a list of 25 key energy projects that would be prioritized for permitting. The list would be periodically updated and would have to represent a “balanced” mix of technologies: “critical minerals; nuclear; hydrogen; fossil fuels; electric transmission; renewables; and carbon capture, sequestration, storage and removal.”

Its key sticking point is its provisions that would expedite the completion of the Mountain Valley pipeline and severely limit any legal challenges to final permitting.

The apparent consensus at the Senate ENR hearing was far from universal, as environmental organizations, absent from the hearing, have advanced a different strategy for accelerating permitting, based on early engagement with communities and tribal groups and “smart from the start” planning.

Speaking at a recent EPW hearing on permitting, Dana Johnson, senior director of strategy and federal policy at WE ACT for Environmental Justice, said, “We really need to start community engagement much earlier in the process. … Advocates in that space noticed that when industry comes to them, when they are able to negotiate, when we have community meetings before a permitting process even begins, we are able to work in partnership to solve the challenges of bringing a project to fruition.”

Federal support for such engagement was a central provision of Biden’s permitting reform priorities, which the White House released last week. Biden specifically calls for federal agencies to designate a chief community engagement officer and provide funding to help small communities and groups build the resources and expertise to participate in federal permitting processes.

In direct opposition to GOP bills, the president’s priorities put a stronger focus on clean energy, calling for legislation to accelerate interconnection of solar, wind and storage projects sitting in interconnection queues. Rather than limits on NEPA reviews, Biden supports increased interagency cooperation and the use of “programmatic environmental reviews” to speed up permitting in transmission corridors or in specific areas of federal lands.

ClearView characterized Biden’s priorities more as “trying to find a middle ground” between Manchin’s bill and Sen. Ed Markey’s (D-Mass.) “progressive priorities” released in March, which call for increased funding for NEPA reviews and for engagement with environmental justice communities.

“Herding proverbial cats within one’s party may be a prerequisite to successful negotiations with the other side,” ClearView said. “But we would suggest it falls well short of bridge building between Republicans and Democrats at this time.”

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Massachusetts Lawmakers Look to Address Heating, Building Emissions

BOSTON — Massachusetts lawmakers and climate advocates held a legislative briefing Wednesday on a set of bills looking to spur the decarbonization of the state’s heating sector.

The overarching goal of the legislation is to redirect investment away from natural gas infrastructure and toward clean energy technology like heat pumps and networked geothermal.

“We need to stop powering our homes and household appliances with gas,” said Senate Majority Leader Cindy Creem, who also serves as the chair of the Senate Committee on Global Warming and Climate Change. “It’s simply not compatible with our climate ambitions, and it’s not good for our health.”

Massachusetts is lagging behind its 2050 net-zero goal for its buildings sector. While the number of electric heat pump installations in the state has rapidly increased — from about 500 in 2020 to about 18,000 in 2022, according to the Boston Globe — a 2020 report commissioned by the state found that the commonwealth needs to electrify about 100,000 homes each year for the next 25 to 30 years to meet its climate goals.

Aiming to address this issue and spur the transition to electrified heating systems, Senate Bill 2105 and House Bill 3203 (An Act Relative to the Future of Clean Heat in the Commonwealth), contain a wide range of provisions that would transform the role of gas utilities in the state and incentivize non-emitting clean heat technologies.

Clean Heat Bills Infographic (RTO Insider LLC) Content.jpgInfographic promoting the bills | © RTO Insider LLC

The bill would authorize the state’s gas utilities to replace gas pipes with electric heat pumps and networked geothermal systems, and allow gas companies to sell electrified home appliances. While National Grid (NYSE:NGG) and Eversource Energy (NYSE:ES) are currently collaborating with the Home Energy Efficiency Team (HEET), a clean energy nonprofit, on networked geothermal pilot projects in the towns of Lowell and Framingham, they currently are limited in their ability to expand their programs to meet demand outside of the pilot projects.

The legislation would also create a “thermal transition trust fund” within the Massachusetts Clean Energy Center (MassCEC) to provide funds for residents to replace gas appliances with electrified alternatives, with priority given to low- and moderate-income residents. It would also provide funding to utilities to train and retain workers in the transition away from gas. The fund would be paid for in part by gas customers at a cost of 1.5 cents/therm, which advocates estimate would total about $20 million annually, about half of the total.

The bill would also require gas utilities to provide the state’s Department of Public Utilities (DPU) with detailed plans to transition entirely off emitting energy sources by 2050, while also retaining gas workers, by the end of 2025.

Advocates also addressed the plans presented by gas utilities in the DPU’s 20-80 proceedings, which would decarbonize the gas system using “fossil-free fuels” like green hydrogen and biomethane. Climate groups have pushed back on these plans, arguing that these alternative fuels are scarce, expensive, hazardous and ultimately still damaging to the climate.

The gas utilities “have submitted plans that claim to decarbonize the system, but the reality is that it’s just business as usual,” said Rep. Steven Owens, one of the bill’s cosponsors in the House of Representatives.

The act would prohibit the use of hydrogen gas for heating buildings and limit the use of biomethane to gas with net-zero lifecycle emissions.

Advocates made the case that strategically shifting investments away from replacing gas pipes, which could quickly become stranded assets, and into clean heat technologies would also benefit ratepayers, who are facing a multibillion-dollar bill for the state’s Gas System Enhancement Program (GSEP). Estimates of GSEP’s total costs range from $13.4 billion to about $40 billion.

Making up for Bad Math

In Massachusetts and across the country, climate advocates have long made the case that greenhouse gas inventories based on EPA accounting methods dramatically undercount the scale and impact of methane emissions, which are responsible for about 30% of climate warming.

“The problem that we’re solving is even bigger than it appears today because we are using outdated science,” said Zeyneb Magavi, co-founder of HEET.

To update the state’s accounting methods, the Making Methane Accounting Truthful Helps (MATH) Act (Senate Bill 2092 and House Bill 873) would require the state to calculate the warming impact of its methane emissions on a 20-year timescale, along with the 100-year time frame currently used. Methane is a short-lived gas in the atmosphere, and the magnitude of its warming impact depends on the timescale used to calculate it. Over a 20-year period, the global warming potential (GWP) of methane is about three times larger than its GWP on a 100-year basis.

The state’s inventory would need to account for all gas leaked in the process of transmission, storage, distribution and end use. The bill would also require a review of accounting methods every three years, looking at the best available science.

However, as the bill is currently written, it does not target the full scope of issues in the state inventory identified by experts and climate advocates. The legislation does not address the state’s chronic underestimation of methane leak rates from the gas system: A 2021 study by Harvard University researchers found methane emissions from the gas system in the greater-Boston area to be about six times higher than the estimates from the state’s Department of Environmental Protection (DEP).

The bill also would not address how the state calculates lifecycle emissions from biofuels like biomethane, which the state essentially considers to be net-zero but are typically associated with some level of climate impact, though the impact can vary significantly based on the fuel’s source. The bill also doesn’t contain language considering out-of-state emissions associated with gas consumed in Massachusetts.

Advocates said that they hoped to address these issues in future legislation.

Democratizing the DPU

The presenters also spoke about the importance of updating the intervener process at the DPU. House Bill 3137 would require the DPU to allow municipalities, groups of ratepayers and nonprofits with utility law expertise to intervene in department proceedings.

“The DPU’s intervenor process is in desperate need for democratization,” said Rep. Jennifer Armini, the bill’s sponsor. “If we’re going to have safe, clean communities, and fight climate change, we need to change the processes that are preventing progress.”

The legislation would also require utilities to provide information to ratepayers and municipal officials about pipeline characteristics and risks, and return streets to good condition after conducting pipeline work.

“Municipalities just don’t have enough information about the gas system, and we have no authority to require that information,” said Lise Olney, chair of the Wellesley Select Board.

Next Steps

Advocates called on state legislators to sign on as co-sponsors of the three bills, which will all face scrutiny in the state’s powerful Joint Telecommunications, Utilities and Energy Committee.

A similar bill to the “Future of Clean Heat” failed in the previous legislative session. National Grid, the state’s largest gas utility, lobbied against the bill, while Eversource, Unitil and Berkshire Gas (a subsidiary of Avangrid) registered their lobbying on the bill as “neutral,” as they did for nearly all other bills.

National Grid did not respond to requests for comment. An Eversource representative wrote that the company was still reviewing the bills but noted that it will “continue to explore an array of solutions to responsibly decarbonize our natural gas system, while still providing safe and reliable heating service to all of our customers at the lowest cost possible.”