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November 14, 2024

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PJM MIC Briefs: Nov. 1, 2023

VALLEY FORGE, Pa. — Generators that plan to come online by the start of the 2025/26 delivery year will have until Dec. 12 to notify PJM of their intent to participate in the Base Residual Auction (BRA) for that year, slated for June 2024.

PJM’s Pete Langbein told the Market Implementation Committee Nov. 1 that resources that do not notify the RTO by Dec. 12 will not be permitted to participate in the BRA; those that do will be required ultimately to enter an offer.

The requirement is one of several prospective changes to the capacity market that PJM has filed at FERC following the Critical Issue Fast Path (CIFP) process that concluded in October; if the filing is not approved, the notification process will be the same as in past years, with no firm requirements. (See PJM Files Capacity Market Revamp with FERC.)

Langbein said that if a planned resource notifies PJM it will be participating in the auction, any capacity it does not offer cannot be used in that delivery year, including through Incremental Auctions (IAs). He gave the example of a generator that could offer 100 MW into the auction entering in 80 MW. That resource would not be able to offer the remaining 20 MW into subsequent IAs for that delivery year.

An information session will be held Nov. 8 to go over the template that generation owners will be asked to submit to PJM to make the notification. Questions can be submitted to rpm_hotline@pjm.com.

Manual Revisions for New Performance Assessment Interval Triggers Endorsed

The MIC endorsed conforming revisions to Manuals 11 and 18, which sets the capacity market rules, to codify changes to the triggers initiating a performance assessment interval (PAI).

The changes were approved by the Members Committee in May and signed off on by FERC on July 28. (See FERC Approves PJM Change to Emergency Triggers.)

Generators with a capacity commitment are required to meet or exceed their obligation during a PAI or face penalties, which in the case of the December 2022 winter storm amounted to about $1.8 billion.

The changes would set two conditions for triggering a PAI, with the first requiring a primary reserve shortage paired with any one of the following: a voltage reduction warning and reduction of noncritical plant load; manual load dump warning; maximum generation emergency action; or curtailment of nonessential building load.

The second condition requires a deploy-all-resources action, manual load dump action, voltage-reduction action or load-shed directive.

The MC approval of the trigger changes also included modifications to the penalty structure that generators are subject to, but PJM’s Board of Managers included only the trigger changes in the FERC filing. Changes to the penalty structure are included in the CIFP proposal submitted to the commission Oct. 13. (See PJM Board Rejects Lowering Capacity Performance Penalties.)

Stakeholders Endorse Issue Charge on DR Energy Market Parameters

The MIC endorsed an issue charge to explore creating new parameters that demand response resources can enter into the energy market. (See “Voltus Withdraws Issue Charge on DR Offer Parameters” PJM MIC Briefs: Sept 6, 2023.)

Voltus Vice President of Energy Markets Emily Orvis said DR generators lack equivalents to some of the parameters thermal generators can include in their offers, namely maximum run times and minimum times between deployments. Adding those parameters would be particularly beneficial for consumers who can shift building heating and cooling away from peak grid periods, she said. While that energy use could be deferred, temperatures would need to be regulated after some time and a recovery period might be needed before load could be curtailed again.

Resources can offer themselves into the market for specific times of day, but that must be manually done each day and is not flexible. If a resource can be available for only two hours, it would have to choose two hours ahead of time and mark itself as available. Orvis said creating a new parameter would give PJM dispatchers flexibility to call on short-duration DR resources when they would be most economical.

Much of Wednesday’s discussion focused on educating stakeholders on how any changes to energy-only DR resources could affect accrediting corresponding capacity resources under the effective load-carrying capability (ELCC) methodology.

Langbein said economic DR participating in the energy market is treated as a separate resource from load management in the capacity market, and the parameters of one would not affect the other.

Calpine’s David “Scarp” Scarpignato pushed for discussion of any potential interactions with ELCC accreditation to be included as an educational item to check for unintended consequences.

Independent Market Monitor Joe Bowring argued the issue charge should allow for changes to the capacity rules for DR if any interactions are identified during the education process and said market rules should reflect differences between resources.

“The issue is to ensure that any such demand-side resource with limited response times should not be allowed to be a capacity resource because the proposed limits are not consistent with the obligations of demand-side capacity resources,” Bowring said.

Orvis said her priority is to keep the discussion focused on changes to the energy market side, but she acceded to adding education on ELCC interactions to the in-scope portion of the issue charge.

EE Resources Concerned About Issue Charge on Market Participation

PJM presented a first read of a problem statement and issue charge to consider how energy-efficiency resources participate in the capacity market.

Langbein said EE was introduced to the capacity market about a decade ago without any subsequent consideration of how it is functioning, and staff feel it could use a fresh set of eyes.

The work timeline was set at nine months, with the idea that if changes are identified that could be implemented quickly, they could be made in time for the 2025/26 BRA. Langbein said staff aren’t trying to rush any changes and if stakeholders desire more time, the work could continue longer.

Several EE market participants expressed concern about the wide range of the issue charge and urged PJM to include more clarity on the scope. They also sought assurance there would be adequate time for any changes to be understood by all stakeholders and for them to make necessary changes to their offers for the next capacity auction.

Luke Fishback of Affirmed Energy said setting the scope of the issue charge to be so broad makes it difficult for EE market participants to evaluate where the discussion may go and how it may affect their operations, creating a chilling effect. He suggested a phased approach would be preferable to allow any changes that can be made ahead of the auction to be considered while minimizing market disruption before more substantial changes.

“Let’s give adequate time and space for the exercise of evaluating a resource and, in the near term, make sure that market participants can make investments that support their class of resources,” he said.

The problem statement says PJM’s capacity market has seen significant changes since EE was introduced. EE clearing the capacity auction has grown from 78.1 MW in DY 2011/12 to 7,668.7 MW in the 2024/25 BRA, making up about 5% of the capacity procured.

The issue charge would “evaluate EE participation and consider opportunities to eliminate ambiguity regarding what qualifies as an EE resource and ensure the energy saving attributed to the EE resource is nonbiased, accurate and reasonably consistent across providers” and make any changes toward those ends.

Other Committee Business

Stakeholders endorsed an addition to Manual 11, which relates to energy and ancillary services market operations, to define the amount of energy intermittent resources with a capacity commitment are obligated to enter into the day-ahead market. Resources should enter either the larger of their economic maximum value or their expected output based on hourly forecasts. Resources could use PJM’s forecast to estimate their availability or substitute their own forecast so long as it has a higher confidence interval.

The committee also endorsed a quick-fix solution brought by PJM seeking to revise references and typos in Manual 11. The quick-fix process allows an issue charge and solution to be voted on concurrently.

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NEPOOL Votes to Delay FCA 19

The NEPOOL Participants Committee voted Nov. 2 to delay Forward Capacity Auction (FCA) 19 by one year, seeking time to revise its resource capacity accreditation rules and consider moving to a prompt and/or seasonal capacity market.  

FCA 19, for capacity commitment period (CCP) 2028/29, currently is scheduled for February 2025.  

ISO-NE recommended the one-year delay in September but has yet to make a recommendation on the larger market changes under contemplation. While the FCA typically is held three years prior to the CCP and covers a year-long period, a prompt auction would reduce the time between the auction and the CCP to a few months. A seasonal auction would break up the commitment period into two or more distinct seasons per year. (See ISO-NE Recommends Delaying FCA 19 and Discussion Continues on ISO-NE Capacity Market Changes.)

If ISO-NE ultimately decides to stick with the existing three-year FCA format after the delay to FCA19, the RTO has proposed the following five FCAs be conducted on a 10-month cycle, instead of the current year-long process, to eventually return the auction process to its current timeline. If the RTO elects to move to a prompt auction for FCA 19, it will void the timeline instituted by the delay. (See ISO-NE Details FCA 19 Domino Effect.) 

ISO-NE and NEPOOL submitted the changes with FERC on Nov. 3. 

In response to concerns about the effects of the delay on new resources seeking FCA qualification, ISO-NE proposed two changes which generally were applauded by stakeholders. FCA qualification is necessary for resources to be eligible for reconfiguration capacity auctions, which can allow them to receive capacity payments in the near term.  

First, ISO-NE agreed to allow resources lacking capacity supply obligations to submit qualification materials using the typical FCA timeline, to prevent a delay in their ability to participate in reconfiguration auctions for earlier CCPs.  

Second, the RTO noted that peak demand resources are defined after the capacity qualification deadline, which would be shifted back by a year under the proposed delay.  

To address concerns about negative effects this could have on demand resources looking to qualify in FCA 19, ISO-NE proposed that new demand capacity resources in FCA 19 will include on-peak demand resources and seasonal peak demand resources “consisting of measures that have not been in service prior to June 1, 2024.” 

ISO-NE has proposed a January 2024 effective date for the tariff changes and is continuing discussions on the potential move to prompt and seasonal market constructs. 

A correction was made on Nov. 7, 2023: An earlier version of this article incorrectly stated that the auction delay must be approved by the ISO-NE board before being submitted to FERC. The request was submitted Nov. 3.

 

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FERC, NERC Leaders Voice Concern About Loss of Everett Marine Terminal

The retirement of the Everett LNG import terminal could jeopardize the reliability and affordability of the region’s electric and gas networks, FERC Chair Willie Phillips and NERC CEO James Robb wrote in joint comments issued Monday. 

Based on the evidence presented to FERC at the New England Winter Gas-Electric Forum in June, Phillips and Robb said they have “serious concerns about certain local gas distribution systems’ ability to ensure reliability and affordability in the region without Everett.” 

“As discussions regarding the future of Everett continue, we encourage all parties to keep reliability and affordability at the center of those negotiations,” they added. 

Phillips and Robb highlighted the fallout from Winter Storm Elliott in December 2022, noting that reduced flows of gas, combined with requests from shippers for increased gas volumes, caused pipeline pressures to plummet. (See Déjà Vu as FERC, NERC Issue Recommendations over Holiday Outages.) 

“That dynamic put significant stress on the natural gas system, which only narrowly avoided significant outages,” Phillips and Robb wrote. The officials referenced emergency LNG injections made by Consolidated Edison that saved its system from collapse, noting that “it would have taken ‘many months’ to restore service, leaving hundreds of thousands of natural gas customers without heat in the middle of winter.” 

Speaking at the New England-Canada Business Council (NECBC) Executive Energy Conference on Nov. 1, Robb said the Northeast “dodged a major bullet last winter during Elliott.” 

“Had the temperature not warmed up on Christmas Day, Con Ed and National Grid likely would have been interrupting gas customers because the pipelines were losing pressure,” Robb added. “The restoration of a major natural gas system like the one serving New York City — we would likely still be in the process of lighting pilot lights.” 

Regarding the electric system, recent studies from ISO-NE projected out through 2032 have indicated Everett may not significantly increase the reliability of the grid under extreme winter weather conditions. Despite these findings, RTO officials have indicated it would be wise to retain the facility to hedge against uncertainty in the future energy mix. (See NE Stakeholders Debate Future of Everett at FERC Winter Gas-Elec Forum.) 

Phillips and Robb echoed these concerns about uncertainty, noting that if ISO-NE’s assumptions regarding load growth, new resources and transmission, and retirements prove to be wrong, “ensuring reliability and affordability could become challenging in the face of a significant winter event.” 

They said ISO-NE and stakeholders should pursue reforms to incentivize generators to procure the necessary fuel to keep the grid running during extreme storm events. 

“To the extent that Everett or other infrastructure plays a role in supporting electric reliability by making needed energy supplies available, in the near term or the future, such reforms should consider how to ensure that any needed reliability contributions are appropriately valued,” Phillips and Robb wrote. 

ISO-NE declined to comment on the joint statement.  

The Mystic Agreement — through which New England ratepayers cover the costs of Everett’s main customer, the Mystic Generating Station — is set to expire after this winter, coinciding with the retirement of the plant. Negotiations between Constellation (which owns both Everett and Mystic) and the local gas distribution utilities to keep Everett open have yet to produce an agreement. 

Speaking at the June forum, Carrie Allen of Constellation told FERC that “the future of the facility is not ensured” and that “we’re just running out of time.” Allen added that even if an agreement is reached to keep Everett open, there still likely would be a nine-month regulatory process. 

“There is no hard-and-fast drop-dead date,” Allen said, adding that “normally, I think we would have the supply procured at this point.” 

New Hampshire Consumer Advocate Donald Kreis, who has been a vocal opponent of propping up Everett through electric rates, called the statement from Phillips and Robb “disappointing and a bit puzzling.” 

While Everett may be needed for Massachusetts gas distribution companies, Kreis told RTO Insider, ISO-NE studies show the facility is not necessary for grid reliability and therefore its costs should not be charged to the region’s electric ratepayers. 

He called Phillips’ and Robb’s comments “potentially an unhelpful scare tactic” that could “cause people to feel a sense of alarm without any basis for doing so.” 

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PJM Recommends $5B in RTEP Transmission Projects

VALLEY FORGE, Pa. — PJM has proposed around $5 billion in transmission upgrades to address data center load growth and generation deactivations primarily in the northern Virginia region identified in the third window of the 2023 Regional Transmission Expansion Plan (RTEP). (See PJM Shortlists 3 Scenarios for 2022 RTEP Window 3.) 

PJM Senior Vice President of Planning Ken Seiler told the RTO’s Transmission Expansion Advisory Committee (TEAC) the proposal would meet energy needs through the 2027/28 delivery year while providing long-term benefits to the grid by facilitating interconnection of new resources. 

Ken Seiler, PJM | © RTO Insider LLC

“It’s well-documented that there’s going to be a lot more transmission required as we go through the energy transition, and this is an area that’s a prime example of that,” he said. “We’re going to need a number of projects to meet those needs.” 

The proposal largely tracks the 500-kV combination proposal PJM presented during the Oct. 3 TEAC meeting, which would build new 500-kV lines from northern Virginia out to the Peach Bottom substation to the northeast, the 502 Junction substation to the northwest and the Morrisville substation to the south.  

PJM created the combination proposal by merging portions of the 72 proposals it received in the competitive planning process and directing some upgrades to infrastructure to address needs not resolved by any of the proposals. The final product includes work assigned to Dominion, FirstEnergy, Exelon, LS Power, NextEra, Transource and the Public Service Enterprise Group (PSEG). 

The largest portion of the work is centered on “Data Center Alley” near Dulles Airport in Loudoun County, with over $1 billion of projects assigned to Dominion in that region. The scope includes two new 500/230-kV substations and upgrades to the Mars substation. PJM’s Sami Abdulsalam said the lines between those substations would form a ring around Data Center Alley to feed energy into the facilities. 

The proposal also includes upgrades to several 230-kV lines and substations in Virginia running between the Dooms and Gordonsville substations, as well as to the Summit D.P.-Ladysmith CT 230-kV line. The work also includes a 500-kV line from the Otter Creek facility to the High Ridge substation. 

Abdulsalam said the RTEP window includes a significant number of deactivations, including the 1,295-MW Brandon Shores generator outside Baltimore. Given the lack of resources in the interconnection queue to replace Brandon Shores, new lines will be needed to prevent reliability issues in the Baltimore Gas and Electric (BGE) zone, he said. 

“If the transmission is delayed, something will have to give. Either load needs to be dropped … or some generation shows up. We don’t currently have any generation in the queue” that would come online in time, he said. 

About 11 GW of generation is expected to retire within the Window 3 time frame, which extends to 2028, while 7.5 GW of new data center load will come online. 

The proposal is expected to cost about $4.9 billion based on the cost estimates included in project submissions, while the independent estimates of those projects amount to $5.4 billion. 

Consumer Advocates Frustrated

A second first read of the proposal is scheduled for the Dec. 5 TEAC meeting, after which PJM plans to bring the recommendation to the Board of Managers for approval. 

Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), said advocates had been frustrated when previous RTEP windows were approved by the board in July with little time after the second read for stakeholders to submit comments. 

“There was significant frustration about the time given after the second read and what is the purpose of a second read,” he said. 

Philip Sussler, of the Maryland Office of People’s Counsel (OPC), said the RTEP process could be improved by creating a clearer way for comments to be submitted and for more documents to be public. Several members of the public requested information about how to write letters to the Board of Managers during the meeting. 

Residents who live along the proposed pathways questioned whether several aspects of the work would require new rights of way and expressed doubt about the feasibility of multiple transmission owners requiring certificates of public convenience and necessity (CPCNs). Maryland ratepayers also questioned why needs primarily in Virginia were being solved with transmission buildout across Maryland. 

PJM’s Augustine Caven said staff considered several factors in forming the proposal, including siting and permitting challenges. Other factors include cost containment provisions, constructability, outage coordination, development on new versus disturbed land and scheduling risks such as land and material procurement. 

“PJM recognizes the need for working the permitting process, the regulatory process in four states and that’s something that we’ll definitely have to tackle … but I think the idea here is to move forward with those conversations as quickly as possible and recognizing that it will be a parallel process trying to get the permitting in all four states,” Caven said. 

PJM said that much of the transmission work to the west would be brownfield, while the majority in the east would require new land or expanded rights of way. 

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Stakeholders Call for Structural Changes to CAISO’s Resource Adequacy Program

FOLSOM, Calif. — CAISO stakeholders last week questioned if the ISO’s resource adequacy fleet is sufficient to meet its needs.

At a Nov. 1 meeting of CAISO’s Resource Adequacy Modeling and Programming Design Working Group, Stephen Keehn, a senior adviser at Southern California Edison, said a change in the fleet requires a change in the way RA sufficiency is analyzed, and participants spent the bulk of the meeting dealing with how to adjust the framework.

Participants highlighted what they felt was a lack of visibility of non-RA resources, those resources that aren’t committed to serve an RA obligation of a load-serving entity within CAISO. Without transparency on what non-RA resources exist, what they’re being used for or whether they are under contract, market participants lack information on available capacity, therefore calling into question the efficiency of the RA program as a whole.

CAISO and its stakeholders are still in the early stages of grappling with how to redesign the RA program to account for changing conditions on the grid. The changes include a looming shortage of resources, increasing variability in energy supply and demand, and the evolving nature of resource planning frameworks in California and across the West.

The ISO is also contending with the rapid growth of energy-limited resources — such as batteries — on its grid, as well as the emergence in California of community choice aggregators (CCAs) as major LSEs, whose expansion has fragmented the landscape from a reliability perspective.

Representatives from CalCCA, Pacific Gas and Electric, Northern California Power Agency and the California Public Utilities Commission’s Public Advocates Office called for increased visibility into non-RA.

Lauren Carr, senior market policy analyst with CalCCA, said that while CAISO has visibility into all the resources in its footprint, it’s unclear what a resource is being used for if it’s not included in an RA showing.

“We don’t know, when we look at that list of non-RA resources, if it’s just that they’re not in a showing but could be dedicated to CAISO … or if they’re under contract or dedicated for some other use like substitution,” Carr said. “We think increased visibility into where supply that’s not on an RA showing is dedicated to would be useful.”

CAISO publishes monthly non-RA showings, though, leaving some confused about the lack of visibility.

“The ISO should have visibility into every resource within its operational footprint,” said Brian Theaker, vice president of Western regulatory and market affairs with Middle River Power. If a resource isn’t included in a showing, he explained, it’s likely because of substitution or holding back capacity for planned outages, which is a problem of its own.

Larger Structural Issues

In line with Theaker’s thinking, Chris Devon, director of energy market policy with Terra-Gen, suggested that the lack of visibility into non-RA resources is representative of broader structural issues such as modeling and planned outages that, if addressed, would eliminate the larger problem.

“I think that this issue of needing to increase visibility of non-RA is a symptom of the California RA overall,” said Devon.

Stakeholders also suggested addressing the default planning reserve margin before discussing visibility of non-RA. Sibyl Geiselman, market policy adviser with Public Generating Pool, questioned whether the PRM was high enough to both ensure reliability and meet a one-in-10 loss-of-load expectation, adding that an increased PRM could decrease the need for backstop procurement of non-RA resources.

“If you fix the upstream issue of making sure that the program is truly providing an adequate fleet,” said Geiselman, “then some of these downstream issues become hopefully less critical and less challenging because you have enough resources.”

While stakeholders went further into the weeds discussing the plausibility of multiyear contracts for RA resources, counting rules and backstop procurement, they consistently returned to the theme of needing to address CAISO’s entire RA modeling structure.

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Infrastructure and Coordination Hot Topics at NECBC Conference

The U.S. and Canada must increase interregional ties and cooperation to ensure reliability and affordability in the clean energy transition, government officials and industry executives from both sides of the border said at the New England-Canada Business Council’s 31st Annual Executive Energy Conference. 

Speakers at the conference, which met in Boston on Thursday and Friday, highlighted the potential co-benefits of offshore wind and hydropower, arguing that increasing the bidirectional connections between New England and Eastern Canada would boost the reliability and affordability of the future grid. 

Two days prior to the start of the conference, the U.S. Department of Energy announced it will become the anchor off-taker for the 1,200-MW Twin States Clean Energy Link project, which will connect Vermont and New Hampshire to Québec. (See DOE to Sign up as Off-taker for 3 Transmission Projects.) The line will allow for the bidirectional flow of electricity, enabling New England to import hydropower from Québec and export excess offshore wind energy depending on regional needs. 

Maria Robinson, director of DOE’s Grid Deployment Office, said at the conference the project will “enhance the capacity of the grid here in New England as well as provide additional resilience, reliability and efficiency between our two countries.” 

“The line will certainly deliver clean energy from Canada through hydropower to New England, and potentially at some point soon to Canada through solar and offshore wind here in the United States,” Robinson added. 

Serge Abergel of Hydro-Québec touted the potential benefits of using hydropower to balance out wind power and reduce curtailment instead of simply using hydropower as baseload. 

Hydropower “can essentially follow the patterns of wind,” Abergel said. “There is the potential for us to optimize and not send 24/7 but send energy when needed and get back excess power when there’s too much [in New England].” 

Hydro-Québec on Thursday announced its plans to spend about $100 billion to increase its production and grid capacity. The company is hoping to add up to 4,200 MW of hydropower production capacity, from both new dams and renovations to existing facilities. 

A Difficult Transition

Throughout the conference, speakers emphasized the vast amount of infrastructure that will be needed to meet the energy transition, as well as significant costs and regulatory challenges. 

“On the broader permitting side, very few people, I fear, appreciate the scope of what net zero looks like,” said Christopher Guith, senior vice president of the U.S. Chamber of Commerce’s Global Energy Institute, citing the need for new transmission lines and pipelines to move carbon dioxide or hydrogen. 

Guith said there’s bipartisan acknowledgement the permitting process needs major changes, and Democrats and Republicans in the Senate ultimately will need to “sit down like big boys and big girls and figure out how to get the 60 votes.” 

“It is so much easier to make targets than actually achieve them,” said Monica Gattinger, professor of political studies at the University of Ottawa. “There is a growing recognition of ‘holy crap, this is a lot more complicated than we realized.’” 

Gattinger added that navigating the sometimes competing needs for decarbonization and affordability is proving to be a challenge for policymakers across Canada. 

“We do a lot of tracking of public opinion at the University of Ottawa, and when people have their hats on as citizens, they are all for climate action,” Gattinger said. “But if they put on their hats as consumers … affordability and issues around siting start to become much more important.” 

Multiple speakers emphasized the importance of community engagement to ensure tangible local benefits, and education to connect new infrastructure needs and rising electric bills to climate change and emissions reductions, as a way to help bridge this gap. 

“It isn’t engineering that’s our issue in Canada, and I don’t think it is in the United States either” said Jacob Irving, CEO of the Energy Council of Canada. “The No. 1 most difficult thing is public acceptance of these projects.” 

Irving, along with most of the Canadian panelists and presenters, spoke about the importance of strong relationships with indigenous communities. Several of the speakers acknowledged the historical disregard that energy developers have often had for indigenous communities, although no indigenous groups from either country were represented among the conference’s speakers. 

“If you do not have sufficient partnership with indigenous communities, you do not have a project in Canada,” Irving said. 

More Gas?

Asked whether New England needs to increase its gas import capacity to meet growing demand on the grid, Stephen Woerner, president of National Grid New England, and Joseph Purington, CEO of Central Maine Power, said gas may be needed until clean energy can displace it. 

“Any shortage of fuel to make electricity jeopardizes reliability, and if we’re going to become more dependent on the [electric] system, we have to make sure that that doesn’t happen,” Woerner said. “Cost-effective long-term storage can help, but it doesn’t eliminate the need for fuel.” 

“We need the bridge to get from where we are today to where we’re going to be,” said Purington. “I think that’s going to have to be part of that solution as it is right now. Especially if we’re continuing to stumble out of the gate.” 

From left: Paul Hibbard, Analysis Group; Heather Chalmers, GE Canada; Joseph Purington, Central Maine Power Company; Stephen Woerner, National Grid New England | © RTO Insider LLC

Enbridge announced earlier this fall it’s pursuing a project to expand pipeline capacity into New England to address projected demand increases from both the gas network and the grid. The project has been heavily criticized by local climate and environmental groups. (See Enbridge Announces Project to Increase Northeast Pipeline Capacity.) 

Meanwhile, Jamie Van Nostrand, chair of the Massachusetts Department of Public Utilities, expressed concern in September about the state’s gas utilities continuing to add connections to the distribution network, saying it seems to be “business as usual in the natural gas industry with respect to new residential hookups and continuing levels of load growth.” 

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FERC Environmental Justice Chief Explains Commission’s Efforts

The National Association of Regulatory Utility Commissioners hosted a webinar last week with FERC Senior Counsel on Environmental Justice and Equity Conrad Bolston, who explained how the commission has been stepping up its work around environmental justice since 2021.

Bolston took over the role in March after Montina Cole, the first person with the job, left late last year. Working out of the Office of the General Counsel, Bolston leads a small team focused on the subject.

“My primary mission is to provide leadership and steer implementation of environmental justice and equity policies, principles, practices and procedures at the commission,” he said.

Sometimes “Diversity, Equity and Inclusion” is conflated with environmental justice, but Bolston’s work is focused on the latter exclusively.

“On a day-to-day [basis], that might mean assisting in reviewing and editing documents, from NEPA [National Environmental Policy Act] documents to orders, draft rules [and] policies, or holding trainings and outreach like the one we’re having here today,” he added.

Environmental justice has a number of definitions, but Bolston said it means ensuring citizens are treated fairly regardless of their racial, economic and national backgrounds, or any other attributes when it comes to environmental regulation.

President Joe Biden in April issued Executive Order 14096 on recommitting the U.S. to environmental justice, which it defines as “the just treatment and meaningful involvement of all people, regardless of income, race, color, national origin, tribal affiliation or disability in agency decision-making and other federal activities that affect human health and the environment.”

The order explains the goal will be achieved when everyone enjoys the same degree of protection from environmental and health hazards, and equal access to the decision-making process.

As an independent agency, FERC voluntarily has complied with that and related executive orders, with both Chair Willie Phillips and his predecessor, Richard Glick, making it a priority, Bolston said. Under Glick, FERC released an equity action plan, which laid out its goals for improving equity and environmental justice in its processes.

A related term is “energy justice,” which has been defined by the Department of Energy as “the goal of achieving equity in both the social and economic participation in the energy system while also remediating social, economic and health burdens on those disproportionately harmed by the energy system,” Bolston said.

“I think if there’s a common theme, it’s that some communities face systemic barriers that are either procedural or substantive that might result in inequitable regulation,” he added. “And I think that achieving fair regulation and just regulation necessitates acknowledging the systemic barriers and tackling them head on.”

FERC has been increasing its work in the area broadly, not just on the team Bolston leads in the Office of General Counsel. The Office of Public Participation (OPP), founded in 2021, reaches out to the general public, and the Office of External Affairs is the chief contact with Congress, states, tribes and other levels of government. The Office of Energy Projects, which reviews natural gas and hydropower infrastructure, has its own groups dedicated to public outreach and environmental justice, Bolston said.

OPP is focused on community outreach and engagement, education and technical assistance, lowering barriers to public participation before the commission and internally advocating for improved public accessibility. The office is non-decisional, which means its staff can talk about all the issues before the regulator, Bolston said. The office helps everyday citizens better understand the complex issues FERC deals with so they can be better involved in its work.

The recent focus on these issues has made a mark on FERC’s NEPA documents, its environmental reporting and even the orders it issues, Bolston said.

“That’s not to pat the commission on the back and say that ‘we’re done with our work’; it’s just more of a way to level set for anyone out there that hasn’t seen any of these analyses, or maybe hasn’t seen the evolution,” Bolston said.

One of the more high-profile steps FERC has taken on the issue was to hold an environmental justice roundtable this year, on which it has taken comments. (See FERC Gets Advice, Criticism on Environmental Justice.)

“Those comments are not going to lie in some docket and never be seen,” Bolston said. “We actually read all the comments. We’re in the process of ingesting those comments and summarizing them. We’re in the process of taking those comments and adjusting our policies, practices and procedures, both internally and potentially externally.”

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Dominion Highlights Successful Offshore Wind Development on Q3 Call

Dominion Energy reported third-quarter earnings Friday, with executives focusing on why its offshore project is successful and on its business review that is nearing completion. 

“Our fully regulated offshore wind project is on time and on budget and is expected to save customers more than $3 billion in fuel costs over the first 10 years of operation while creating hundreds of jobs and millions of dollars of local economic benefit,” CEO Robert Blue said. 

The Coastal Virginia Offshore Wind (CVOW) project is being built off the coast of Virginia Beach and is planned to have 176 turbines producing a nameplate capacity of 2.6 GW. The wind plant won final approval from federal regulators earlier in the week and saw the delivery of the first monopiles to a nearby port facility in late October. (See BOEM Approves Coastal Virginia Offshore Wind.) 

“The next transport ship for monopiles is expected to be loaded at the factory later this month and delivered to the port in December,” Blue said. “Also worth noting is that turbine blades and the cells remain on track with a fixed production schedule and mature existing manufacturing facilities.” 

The monopile delivery included a ceremony with politicians from across the spectrum in the commonwealth, with Blue noting the project has “bipartisan support” a few days before an election that could give the Republican Party control over both chambers of the legislature and the governor’s office for the first time in years. The polling in the election shows a very close race. 

The project has a priority position in the offshore wind supply chain, and Dominion has proven successful at getting approvals from the required regulators, Blue said. 

The firm expects to complete CVOW by the end of 2026, and most of its $9.8 billion in costs already are fixed. 

“We updated the project expected [levelized cost of energy] in our filing earlier this week to approximately $77/MWh, as compared to our previous range of $80 to $90,” Blue said. “The decrease reflects updated and refined estimates around production tax credit, cost of capital and [renewable energy credit] values.” 

The project’s total lifetime costs are expected to come in well below the ceiling set by the legislature when it approved the development. 

Dominion will have invested $3 billion into CVOW by the end of the year, and the rest of the $9.8 billion is 92% fixed, with just the costs of interconnecting the project to the transmission grid, some commodities such as fuel used for construction, and installation and project oversight costs yet to be nailed down, Blue said. 

“We’ve been very clear with our team and with our vendors that delivery of an on-budget project is the expectation,” he added. 

Dominion has been in talks with counterparties to sell a minority share in CVOW to help raise the remaining equity. Blue said those talks have generated much interest. 

“It’s in the long-term best interest of our customers and shareholders that we make the right, not just the expedient, decision,” Blue said. “A properly structured partnership with the optimal counterparty is an attractive option. But only if the terms of a potential transaction make sense for our customers and shareholders.” 

A decision picking a counterparty for the wind project is the last part of Dominion’s ongoing business review, which has seen it sell its share of the Cove Point LNG project and exit the natural gas utility business, Blue said. The firm expects to make a choice in the next few months. 

The review was launched after investors expressed worries about the firm’s earnings, the Virginia regulatory model (which was revised early this year) and its balance sheet, Blue said. 

“The review must comprehensively and finally address the foundational concerns that have eroded investor confidence over the last several years,” Blue said. “This can’t be a series of partial solutions that leave key elements and risks unaddressed. That’s how we’ve approached this top-to-bottom review.” 

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NYISO Stakeholders Question Proposed Interconnection Timelines, Deposit Rules

RENSSELAER, N.Y. — Stakeholders at NYISO’s Nov. 4 Interconnection Issues Task Force meeting expressed reservations about the grid operator’s proposed interconnection queue rules, citing concerns over the length of time to make project decisions and deposit requirements.

Following the ISO’s presentation of proposed study deposits and withdrawal penalties, Troutman Pepper partner Stu Caplan, who represents the New York Transmission Owners, highlighted the uncertainty surrounding the transition to NYISO’s proposed phased cluster approach. “There’s a big variable that we don’t know the answer to yet, the feasibility of the timeframes to complete the [interconnection] studies,” he said.

NYISO’s proposal to comply with FERC Order 2023 would give developers a seven-day window after each phase to decide whether to proceed or withdraw from the queue based on results from the preceding study phase.

The ISO proposes to charge interconnection applicants a non-refundable $10,000 fee, as well as a one-time study deposit ranging from $100,000 to $250,000 based on the size of the proposed project. For capacity resource interconnection service-only projects, the deposit would be $50,000. Additionally, in lieu of regulatory milestones, developers would be required to make commercial readiness deposits to progress through the queue phases, with amounts escalating at each stage: depositing $4,000/MW to enter Phase 1, depositing the greater of either the Phase 1 deposit or 20% of the cost estimate determined in Phase 1 to move into Phase 2, and 100% of a project’s cost estimate to move out of Phase 2.

Proposed study deposits for certain generation facilities seeking interconnection | NYISO

NYISO also outlined penalties for developers who withdraw from the queue: up to 100% of their study deposit, plus 20% of the Phase 2 deposit if they withdraw during the decision period at the end of Phase 2.

Reid Wagner, a clean energy markets analyst with the Alliance for Clean Energy New York, said the ISO’s proposed timelines are too short. “Seven days could be hard for some companies, particularly international ones, to secure the funding in that short period of time,” he said.

ISO attorney Sara Keegan responded that developers would “have ample time to get their ducks in a row” and make decisions about whether to move a project forward through the queue. Project cost estimates would be available “well before the seven-day trigger,” she said.

Wagner then asked if the ISO would consider conducting a “harm test” at the end of each phase, as currently done by MISO, to “test how much harm a withdrawn project has caused to the other queued projects.”

Keegan responded that NYISO is not considering a harm test akin to MISO’s. “It is perhaps overly complicated, and we feel like that would make it incredibly difficult to administer, since we would end up needing a whole department to administer withdrawal penalties,” she said.

Stakeholders also expressed frustration with NYISO’s initial plan to accept only cash for study deposits, rather than allowing the use of credit.

Saad Syed, grid and interconnection manager with OW Ocean Winds, argued for flexibility, saying, “putting up much money in cash in such short intervals seems very difficult, on top of the withdrawal penalties that may occur. So, I strongly recommend using at least an ability to use letters of credit for [these deposits], since otherwise it might become untenable.”

Echoing this sentiment, Abhishek Josh Ghosh, associate director with Cypress Creek Renewables, recommended that NYISO draw insights from PJM, which allows letters of credit in its processes. “It would be nice to have some flexibility in posting these deposits,” he said.

Thinh Nguyen, NYISO senior manager of interconnection projects, acknowledged these concerns and committed to revisiting the payment options. “We are still considering whether a letter of credit is another option. But as you are aware, when we receive letters of credit, that means we have to do some kind of credit check on that entity,” he said. “That’s why we want to make sure that whatever the process we want to use is able to support and meet the very tight defined timelines.”

FERC last month extended the Order 2023 compliance deadline from Dec. 5 to April 3, 2024. (See FERC Extends Interconnection Queue Compliance Deadline.)

Despite the extension, Keegan informed the IITF that NYISO still intends to submit a partial compliance filing by Dec. 1. (See NYISO Plans Early November Filing for Partial Order 2023 Compliance.) The IITF will reconvene Nov. 14.