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.
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.”
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.
“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.
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.
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.”
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.”
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.”
California’s new climate reporting requirements may precede the U.S. Securities and Exchange Commission’s proposed rules, but they are being carefully designed to minimize duplication of efforts once the SEC catches up, panelists said at an Oct. 31 webinar hosted by Ceres.
Gov. Gavin Newsom last month signed two landmark climate disclosure bills into law: Senate Bill 253, the Climate Corporate Data Accountability Act, which requires annual reporting of Scope 1, Scope 2 and eventually Scope 3 greenhouse gas emissions; and Senate Bill 261, the Climate-Related Financial Risk Act, which requires biannual reporting of financially material climate risks.
“The California laws are crucial, first-of-their-kind mandatory disclosure standards” in the U.S., said Jake Rascoff, director of climate financial regulation with the Ceres Accelerator for Sustainable Capital Markets.
An estimated 5,300 companies globally will be required to report emissions under SB 253, including at least 75% of Fortune 1000 companies, while about 10,000 will need to report climate risks under SB 261.
All companies, private and public, are required to follow the reporting requirements if they meet the criteria. That includes having annual revenue above $1 billion to comply with SB 253 and above $500 million for SB 261, as well as being categorized as doing business in California, defined as having sales exceeding $610,395 or having property or payroll exceeding $61,040 in the state.
Some other key details:
The rules apply to companies based in any location that do business in California, including those based in other parts of the U.S. or other countries.
Reporting takes place at the parent company level and with global, not California, totals.
Reporting begins in 2026 for all but Scope 3 emissions, which begin in 2027.
Emissions reporting will require third-party verification.
Climate risk reports need to be publicly available, not submitted to the state.
An annual administrative fee will be charged and is expected to be about $1,000 to $1,500.
The ball now is in the court of the California Air Resources Board, which will develop and adopt regulations for corporate emissions disclosures, contract with a climate organization and adopt regulations for administrative penalties.
If the California emissions disclosure requirements sound familiar, it’s because they nearly mirror disclosures the SEC has been planning for some time, as well as the recently adopted European Union reporting requirements.
Avoiding Duplication of Disclosures
While groundbreaking for the U.S., the California requirements follow the EU’s Corporate Sustainability Reporting Directive, which was finalized in December 2022 and begins coming into effect in 2024. Those rules will affect about 50,000 EU companies and 10,000 others, one-third of which are U.S.-based. California, the EU and the proposed SEC reporting rules all draw from the widely accepted GHG Protocol’s definitions of Scope 1, 2 and 3 emissions.
The California reporting requirements are harmonized with other reporting requirements to minimize the burden on companies while ensuring key climate data are disclosed. By focusing the reports on full global emissions, affected companies will not need to separate out California-specific emissions, and the reports for California may be identical to those created for the EU and the SEC.
Sarah Sachs, Western state policy manager at Ceres, credited this harmonization to California State Sen. Scott Wiener, who authored SB 253.
“He and his team made a huge amount of effort to ensure that California was not reinventing the wheel with this bill and was creating a standard that was aligned with broader global best practices around emissions disclosure, and this is why the bill identifies the GHG Protocol, which is the most widely used global framework for emissions disclosures.
“The goal of this is to reduce any duplicative reporting that you all might feel like you might have to undertake,” Sachs said.
One Step Ahead of the SEC
The California laws were passed while the markets are in a holding pattern awaiting a final SEC rule. The SEC requirements will affect all SEC registrants, about 8,000 companies with U.S. public equity listings, including foreign private issuers, but will not cover privately held companies.
“Everything in the SEC proposed is very much through the lens of financial materiality for the most part; basically, how are climate risks impacting companies’ operational and financial well-being?” Rascoff said. The driver of the SEC requirements are very different, however. “The commission has zero climate policymaking role whatsoever. This is just about providing investors with consistent, comparable, decision-useful information.”
With its eye on informing investors, the proposed SEC reporting has some nuances that extend beyond the California requirements. Most notably, Rascoff said, “the SEC has proposed a footnote to audited financial statements calling out where climate-related metrics have moved any individual financial statement line 1% in either direction, so companies can explain how climate risks and metrics are actually flowing through the audited financial statements.”
The SEC is expected to take a lighter stance on Scope 3 emissions, requiring disclosure only if they are material or the company has set a target. This means it will exclude one of the most controversial requirements of the California rule, one that came most under attack by some corporate lobbying groups.
“California’s laws were designed to provide this information not only for investors, but for a broad range of stakeholders,” Rascoff said. “But the investing public still really needs this information in the same place that they get audited financials, risk factors, MD&A [management discussion and analysis] and everything else, and that’s why it’s so important that the SEC move forward to finalize and adopt their rule.”
Climate Reporting Breaks out of ESG/CSR Silo
For companies, climate-related reporting will take on a new weight.
“We’re going to see climate-related disclosures move out of sustainability or corporate social responsibility reports and into legal documents, like SEC filings or like the filings contemplated with the California laws,” Rascoff said. “So companies are going to need to embed their climate disclosure strategy into multiple business units.”
Moving from voluntary sustainability reports to mandatory requirements raises the stakes and opens companies to possible penalties: “potential exposure to liability risk in the case of the SEC or civil penalties in the case of California,” Rascoff said. “This now takes on the same sort of weight and scrutiny within a company that a financial filing does.”
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.”
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.”
Texas voters will finish casting their ballots Tuesday on Proposition 7, a constitutional amendment that would create a nearly $10 billion state fund for dispatchable energy that opponents say amounts to a handout for the natural gas industry.
A result of legislation passed earlier this year, the Texas Energy Fund is a $7.2 billion low-interest loan program intended for the development of up to 10 GW of natural gas plants. Some $5 billion will be set aside for 20-year, 3% interest loans to build new generation with at least 100 MW of fully dispatchable capacity. Power plants that come online before June 29 are eligible for bonus payments.
Another $2.8 billion will be dedicated to grants for infrastructure improvements in non-ERCOT regions and for grants to strengthen resiliency at hospitals, fire stations and other critical facilities through microgrids.
ERCOT considers energy storage as a dispatchable resource, but it is restricted from the program.
Prop 7 is supported by gas heavyweights such as ConocoPhillips, Koch Companies and Valero Energy, along with industrial users. They say the amendment will stabilize a creaky ERCOT grid that has struggled to meet growing demand since the 2021 winter storm.
The opposition, primarily environmental and consumer groups, object to what they call a“cleverly disguised handout to Texas gas companies that are already making record profits.”
“Proposition 7 is the key to building a stronger and more resilient energy infrastructure, ensuring that we always have the electricity we need, when we need it,” state Sen. Charles Schwertner, who guided Senate Bill 2627 through the Legislature, said on X, the social media platform formerly known as Twitter.
“We don’t need to subsidize power plants in a private market with taxpayer funds,” the Sierra Club’s Cyrus Reed countered on X.
During debate over the bill this spring, several generators came out against SB2627. The Association of Electric Companies of Texas said it was concerned about government intervention in the competitive wholesale market. Other company representatives said the loans are similar to other regional programs that create market distortions.
“If you’re a gas power plant developer, why would you ever develop another power plant in Texas without a grant and a low-interest loan? Do Texans need to put up billions more the next time we need more energy?” Stoic Energy CEO Doug Lewin said, while admitting “there’s virtually no chance” Prop 7 will fail.
The amendment enjoys wide public support, according to a poll released last month by the University of Houston and Texas Southern University. The survey found 68% of voters favor the amendment, with 15% opposed and 17% undecided, despite its costs filtering down to ratepayers.
ERCOT called numerous conservation alerts and a Level 2 energy emergency alert during a record-breaking summer this year. The grid operator set 10 records for peak demand this summer, topping out at 85.46 GW after just exceeding the 80 GW threshold in 2022. Four years ago, peak demand was 74.82 GW. (See ERCOT Voltage Drop Leads to EEA Level 2.)
The fund would be endowed with $10 billion taken from the state’s general revenue fund. More money from the revenue fund could be transferred into the Energy Fund.
