A marine acoustic study underway in the Empire Wind project lease area will be extended through 2028.
The study by Empire Wind and the Wildlife Conservation Society (WCS) is monitoring large whales in the New York Bight and is expected to yield data that will aid in protection of wildlife before, during and after construction.
The offshore wind farm will be built across 80,000 acres 15 to 30 miles south of Long Island and will generate 2.1 GW.
Two moored acoustic monitoring buoys have already compiled more than 2,000 days of monitoring data and detected more than 18,000 sounds from fin, humpback, sei and North Atlantic right whales. The most frequent sound has been a low-frequency song note produced by fin whales. Detections have tended to peak in early winter.
The partners on the project say the acoustic data, combined with sighting data from aircraft and surface vessels, are providing important baseline information on whale activity in and near the Empire Wind lease area. This will guide efforts to minimize the project’s impacts on them.
Empire Wind is a joint venture of Equinor (NYSE:EQNR) and bp (NYSE:BP). WCS is working with the Woods Hole Oceanographic Institution, which invented and operates the acoustic buoys. WCS began the monitoring in 2016, and Equinor began supporting it in 2019.
“As a new industry, it is crucial that we establish best-in-class practices throughout the development phase of our projects from the start,” Siri Espedal Kindem, president of Equinor Wind US, said in a news release Wednesday announcing extension of the program.
“The data from this acoustic monitoring and our analyses clearly demonstrate that several large whale species are seasonally present, and some for extended periods of time in the New York Bight,” said Howard Rosenbaum, the project principal investigator and director of WCS’ Ocean Giants Program.
“We applaud Equinor and the Wildlife Conservation Society for expanding their partnership and ongoing commitment to environmental stewardship and understanding marine life — setting a strong example for how strategic collaboration can mitigate potential risks and support responsible project development,” said Doreen Harris, president and CEO of the New York State Energy Research and Development Authority.
VALLEY FORGE, Pa. — The PJM Market Implementation Committee narrowly rejected a proposed issue charge from curtailment service provider CPower Energy Management that would have sought to expand access to data from retail demand response customers.
Stakeholders cited pending legislative efforts at the state level and concerns about utilizing statistical sampling instead of collecting data from households directly. (See NJ Eyes Rules to Protect, Gather Advanced Metering Data.)
Paul Sotkiewicz, of E-Cubed Policy Associates, questioned if statistical sampling could be an adequate substitute for direct household data and said that the belief that residential use tends to be homogenous may be a poor assumption. If sampling was to become standard, he said that could discourage states from pushing smart metering technology down to the residential level.
“I don’t find it very appealing that either because somebody didn’t do their due diligence … that PJM and the rest of its membership should be beholden to that and have to settle for statistical sampling,” he said.
Two Alternatives on VOM Advance to MRC
Two competing proposals from PJM and Constellation Energy to address variable operations and maintenance costs advanced to the Markets and Reliability Committee meeting on Sept. 21.
The PJM proposal, which passed with more than 70% support, would include default adders for minor maintenance and operating costs, clarify the definitions of major and minor maintenance, create a new review process and timeline, and clarify the requirements for supporting documentation.
The Constellation package, which passed with 54%, contains the same provisions as the PJM document, but it would include nuclear refueling costs and associated major maintenance under a generator’s capacity offer rather than its VOM energy offering.
Constellation’s Jason Barker said that defining refueling as a variable cost is inconsistent with how maintenance is conducted on nuclear units.
“This is a significant change in that respect because they are deeming most, if not all, the maintenance done in a reactor fueling as variable,” when nearly all of it is fixed, he said. (See “Variable Operations & Maintenance Cost Development,” PJM Market Implementation Committee Briefs: Aug. 10, 2022.)
Rather than vote for their preference of the two proposals, Barker encouraged stakeholders to vote against them both, pushing the revisions back to the Cost Development Subcommittee for additional rewriting. He said those meetings tend to see less participation and said a better package could be formed there through input from more voices. Instead, the MRC will consider both proposals.
IMM, PJM to Collaborate on Manual Revisions Prior to MRC
The MIC endorsed a slate of manual revisions to conform with FERC’s order approving revised energy price formation rules (EL19-58, ER19-1486), but discussion regarding the impact some of the changes will have on hydropower resources led to a request that PJM staff work with the Independent Market Monitor to finetune the language.
The committee endorsed by acclamation revisions to manuals 11, 27, 28 and 29. But before it did, the Monitor raised concerns that the Manual 11 changes were inconsistent with the Operating Agreement’s provisions and would limit the amount that hydro resources could offer as reserves.
The Monitor did not have proposed revisions to present, and some stakeholders expressed frustration that its presentation was only posted the day prior to the meeting. Barker noted that the tight time frame before the Oct. 1 implementation of the manual revisions could make it challenging for hydro operators, such as Constellation, to get a firm understanding of any changes before they’re responsible for compliance.
PJM and Monitor staff pledged to work together, with input from hydro stakeholders, on a friendly amendment that the Monitor would offer at the MRC when the revisions are brought up for a vote at that committee.
Other MIC Business
Because other agenda items ran over their allocated time (See related story, PJM, Monitor Debate Black Start Fuel Requirements Proposals.), work on an IMM proposal addressing capacity offer opportunities for generation with co-located load was postponed. A special session of the MIC will be scheduled to continue discussion of the issue.
The MIC also reviewed PJM’s proposed capital budget, which would increase spending to $45 million, a $3 million increase over current funding. The budget was first presented at the Planning Committee the day before and was also shown to the Operating Committee the next day. (See related story, “Planning Committee Reviews Capital Budget,” PJM Planning Committee Briefs: Sept. 6, 2022.)
Finally, the committee endorsed routine revisions to Manuals 18 and 18B, deleting outdated information, correcting and clarifying existing provisions or practices, and adding administrative updates.
PJM Chief Information Security Officer Steve McElwee briefed the Operating Committee last week, saying that cyberattacks against the U.S. and its allies remain a principal concern. Although attacks from Russia and associated entities have declined, Iran has been increasing its offensives, he said.
Among the major forms of attack seen recently are ransomware, which encrypt a computer and lock users out of data and functionality, and distributed denial of service attacks, essentially bombarding a server with requests to overwhelm a network.
PJM has been hardening its systems by retiring weak encryption tools, blocking international and anonymous traffic and prioritizing external vulnerability remediation, McElwee said.
Committee Endorses Maximum Emergency Package
The committee overwhelmingly endorsed a package from PJM addressing the supply chain for generators and concerns regarding the impact of increased environmental restrictions on maximum emergency generation actions. The PJM option received 92% support over a second package from the Independent Market Monitor, which would have added clarifications and changed references to “fuel” to “fuel and consumables.”
The IMM proposal also would have allowed for resources with less than 10 days of fuel and consumables inventory to be made unavailable for economic dispatch, with a penalty equal to the daily capacity values.
Renewable Dispatch Proposal Vote Delayed
The OC agreed to postpone voting on a joint PJM/Monitor proposal intended improve the dispatch of renewable generators after several stakeholders expressed concern about certain elements.
The proposal would require intermittent resources with capacity commitments to offer economic maximum megawatts equal to or greater than their hourly forecast. Several stakeholders said this could result in renewable output being held back by an under-forecasted value being used.
Other stakeholders were concerned about the elimination of the curtailment flag, which PJM uses to indicate to generation operators that their units have been curtailed and that they should adjust their output accordingly. The proposal would instead use existing basepoints to reflect the RTO’s desired dispatch.
Several committee members said they did not share these concerns but that they would not oppose delaying a vote to address them.
PJM staff agreed to send the proposal back to the DER & Inverter-Based Resources Subcommittee for work and bring it back to the committee for a vote at its meeting next month. They said a one-month delay on approval would still allow for implementation before the second quarter of 2023.
Delays to Scheduled Go-live Date for PPL DLR
The scheduled go-live date for PPL’s dynamic line ratings has been moved out by two weeks, with implementation now slated for Sept. 27 for the day-ahead market and Sept. 28 for real-time. PPL had already delayed rollout from July to this week because additional work was needed for changes to its energy management system with its vendor. (See “PPL Delays DLR Implementation to September,” PJM Operating Committee Briefs: July 14, 2022.)
Review of IROL-CIP Solution Postponed
Discussion of creating a mechanism for generators to receive reimbursement for compliance with NERC reliability standard CIP-002-5.1 was postponed because of concerns raised by the Monitor.
The PJM proposal would have allowed generators deemed critical to interconnection reliability operating limits by NERC to submit their capital and recurring costs to PJM and the Monitor for review and possible monthly payments. According to the problem statement, designation as a critical generator can carry a “significant additional cost burden.”
PJM staff noted that they have adequate time to explore other avenues.
Committee Approves Slate of Manual Revisions
The committee approved several changes by acclamation, with little discussion and no debate:
tariff and manual changes to streamline the process of scheduling internal network integration transmission service; (See “Issue Charge OK’d on Internal NITS Process,” PJM Operating Committee Briefs: July 14, 2022.)
revisions to Manual 14D and Manual 13 to conform with NERC standards EOP-011, IRO-010 and TOP-003; and
changes to Manual 10, 12 and 13, associated with reserve price formation.
VALLEY FORGE, Pa. — PJM and its Independent Market Monitor got into lengthy debates at two different committee meetings last week over each other’s proposed fuel requirements for black start resources (BSRs) as they tried to win last-minute stakeholder support.
Voting on the proposals opened online after the Operating Committee’s meeting concluded Thursday and will close Tuesday at 5 p.m. ET. In a unique situation, voting is open to both the OC and Market Implementation Committee; stakeholders who are members of both need only participate in one committee’s vote, and PJM will remove any double votes. A special joint teleconference of the committees is scheduled for Friday to review the results.
Because the issue was assigned to both committees, each heard identical presentations from PJM and the IMM last week — and sat through nearly identical debates on the proposals’ merits among RTO staff, Monitor Joe Bowring and stakeholders who were confused by certain elements. Both Wednesday’s MIC and Thursday’s OC meetings threatened to run long, but the committees’ respective chairs deferred or shortened other items on their agendas to keep things on schedule.
Both proposals are the culmination of a four-year-long process intended to ensure that BSRs are available when they are needed. They would create two tiers of service, the higher of which provided by fuel-assured BSRs. While the criteria of “fuel assured” varies by resource, they can include dual-fuel capability, on-site fuel storage and connections to multiple gas pipelines.
Each transmission zone would be required to have at least one fuel-assured BSR. Such resources would be selected based on their level of fuel assurance. Also included are additional reliability criteria to mitigate extreme cases in which the unavailability of non-fuel-assured BSRs would result in a large increase in zonal restoration time.
The main differences between the proposals were highlighted at last month’s committee meetings. The Monitor’s plan, for example, would not allow intermittent resources, other than run-of-river hydro, to be BSRs because they cannot currently meet the requirements. (See Members near Vote over PJM, IMM Black Start Fuel Requirements.)
At last week’s meetings, Bowring argued that PJM’s package of revisions — jointly proposed with Brookfield Renewable and the D.C. Office of the People’s Counsel — could result in overpayment for BSRs, as an existing hypothetically “perfect” BSR — one that meets all the physical standards to be fuel assured — would not be required to offer to provide the higher-tier service and meet the performance obligations that came with it; therefore, PJM would not recognize its fuel-assured status.
In such a scenario, Bowring argued that PJM would be required to select another fuel-assured BSR in the same zone in the procurement process, resulting in customers paying twice for the same service. He said all resources that already meet the physical standards to be fuel-assured should also be required to meet the proposed requirements to be designated as such, report on their current status and not receive payment if they cannot not provide the service.
“Customers are already paying these resources to be fuel assured,” Bowring said. “PJM should simply require those resources to meet that obligation.”
Several stakeholders took this to mean that the Monitor was proposing that all existing BSRs become fuel assured. Bowring repeatedly clarified that was not in the proposal, though he did state that all new black start resources should be required to be fuel assured.
PJM staff noted that every transmission zone already has at least one fuel-assured BSR. They acknowledged that the Monitor’s hypothetical scenario was possible, but they argued it was highly unlikely, as the RTO would not necessarily be required to procure another fuel-assured resource and that it could look for other mitigation steps. Bowring responded that the fact that it’s possible “makes my point for me.”
“The zones meet the fuel-assurance requirement based on resources that already meet all the physical standards to be fuel assured but that are not required to become formally fuel assured under PJM’s proposal,” he said. “That is the ‘paying twice’ problem.”
If approved the proposals would go before the Markets and Reliability Committee for a first read next week and voted on at the committee’s meeting next month.
LANSING, Mich. — Gov. Gretchen Whitmer on Friday fired a major shot boosting efforts to reopen the now-shuttered Palisades Nuclear Plant along Lake Michigan’s shores by telling the U.S. Department of Energy the state will take steps toward finding state funding and “facilitating” a power purchase agreement with the generating plant if it wins a federal grant.
In a letter to U.S. Energy Secretary Jennifer Granholm — herself a former Michigan governor — backing a proposal by Holtec International for a Civil Nuclear Credit Program grant, Whitmer said reopening the plant, closed last spring, “is a top priority” for the state as it provides hundreds of jobs, paying on average more than $117,000 a year and producing as much as 800 MW of “reliable, clean power.”
“I will do everything I can to keep this plant open, protect jobs, increase Michigan’s competitiveness, lower costs and expand clean energy production,” Whitmer said in the letter.
Less than two full months after the nearly five-decade-old Palisades closed, Holtec in July proposed a plan to remove radioactive materials. That proposal was controversial because it called for using Great Lakes barges.
Whitmer had said little about nuclear energy in the state in the early days of her administration and as it worked on a net-zero-emissions plan. Shortly before the plant’s closing, Whitmer expressed support for seeking federal aid to keep it open.
While nuclear energy is a controversial topic among environmentalists, keeping the plant open was cited by many as critical to the state’s goal of reach net zero before 2050.
The plant was closed on May 20, 11 days before its May 31 decommissioning date, when its fuel supply ran out and a PPA the plant had with CMS Energy ended. Holtec took possession of Palisades from Entergy this past June.
With Palisades closed there are currently two nuclear plants operating in Michigan: the Cook plant, operated by American Electric Power subsidiary Indiana Michigan Power, and Fermi 2, operated by DTE Energy.
Holtec CEO Kris Singh said Whitmer’s support has been “instrumental” in the company’s efforts to win the federal grant to reopen Palisades.
Whitmer said that while the state and company wait for an answer from DOE, the state will “continue to efforts to diversify economic opportunities in Southwest Michigan through the Michigan Department of Treasury’s Energy Transition Impact Project,” as well as other economic development programs.
MISO’s final 2022 Transmission Expansion Plan (MTEP 22) clocks in at 384 new projects and about $4.3 billion in construction costs.
MTEP 22’s $4 billion value is a marked increase over a 2021 plan that included 335 projects worth $3 billion, but more in line with the 2019 and 2020 cycles’ spending. The draft MTEP 22 called for $3.8 billion in spending over 364 new transmission projects. (See MISO Annual Transmission Package Nears $4B.)
The plan comprises 40 baseline reliability projects at $535 million; 67 projects to accommodate generator interconnections at $523 million; and $3.3 billion in 275 “other” projects for reliability, load growth and addressing aging facilities. MTEP 22 also includes two market participant-funded projects at $7.7 million.
MISO will recommend the MTEP 22 report for the Board of Directors’ approval in early December.
The plan’s costliest project is the $120 million for new static synchronous compensators necessary to reinforce the system in preparation for Ameren Missouri’s retirement of its 1.2-GW Rush Island coal power plant. The project’s expense is tied with Entergy Arkansas’ new $120 million Sandy Bayou 500/230-kV substation, which will tap into its existing Driver-Shelby 500-kV line to accommodate the state’s load growth.
Four of the other 10 most expensive projects are in East Texas to meet increasing load there.
Enviros: Plan for Growing Load, Aging Infrastructure
During a Thursday West Subregional Planning meeting, Clean Grid Alliance’s Natalie McIntire said MISO and stakeholders should have a better understanding of which aging infrastructure needs replacement sooner so the grid operator can pursue larger, more cost-effective projects that could supplant the need for future projects.
“It seems when you have an asset that has such a long life, you should have a better idea of when a replacement is necessary more than a year or two in advance,” she said.
McIntire asked why stakeholders don’t get more notice of projects addressing age and condition before the release of MTEP reports. Staff responded that transmission owners likely inspect facilities on a rotating basis, making it difficult to get a sweeping picture of aging elements.
“We’ve been asking for this for years, and it doesn’t seem that we’re going to get a good answer. … You can’t inspect all of your facilities in a year, but you should have a clearer picture of … when assets are getting to the end of their life, maybe five to 10 years in advance,” McIntire said. She said it appears MISO is giving its transmission owners too much deference in assessing system needs.
Iowa Office of the Consumer Advocate’s Tim Tessier also called for more transparency from transmission owners on aging facilities so the RTO can plan more comprehensive upgrades.
MTEP 22’s inclusion of several late additions by Cleco and Entergy for substation work in MISO South raised some eyebrows among clean energy advocates, who have said the region needs more cohesive transmission planning.
Cleco applied for expedited treatment to include the $15 million, 230-kV Marthaville substation and the $15 million, 138-kV Vernon substation in western Louisiana. Entergy requested the go-ahead to install two additional 230-kV breakers into its existing Legend substation near the Louisiana-Texas border. It also asked to construct a new 230-kV substation for about $1 million in the same area and a $32.6 million, 115-kV substation in northern Mississippi.
Both transmission owners said the substation projects are necessary to accommodate industrial load growth and can’t wait for the MTEP 23 cycle.
Southern Renewable Energy Association (SREA) Executive Director Simon Mahan said that though MISO allows stakeholders to propose study alternatives for expedited projects, the stakeholder community generally lacks insight into the grid operator’s and TOs’ analyses to suggest substitutions. He said stakeholders are in the dark regarding the extent of study alternatives, and he said he’s unaware of the RTO ever opting for a stakeholder-proposed alternative to an expedited project request.
SREA’s Andy Kowalczyk asked whether all the late industrial load growth applications in one cycle should prompt MISO to embark on a planning study on MISO South’s projected load growth. He said he is concerned over the length of agreements with industrial customers and the possibility of stranded costs for transmission facilities.
“Is this the most economical way to be planning?” he asked during a Wednesday South Subregional Planning meeting.
Edin Habibovic, MISO’s senior manager of expansion planning, called Kowalczyk’s query “a good question,” saying market competition makes it difficult to get early data from industrial customers about their expansion plans and energy needs. He also said TOs are often bound by non-disclosure agreements about load-growth projects.
MISO will review the MISO South expedited requests with stakeholders again during October’s Planning Advisory Committee meeting.
Stakeholders Ask for Special MTEP 23 Studies
The RTO has also been gathering input from stakeholders on the special studies it should conduct under MTEP 23.
Last month, MISO project manager Sandy Boegeman warned that the grid-operator’s long-range transmission planning (LRTP) is currently drawing a lot of manpower and resources, possibly limiting the ad hoc planning studies for MTEP 23. MTEP 22 didn’t contain any supplementary studies for the same reason.
The Organization of MISO States has asked the RTO to continue concentrating on LRTP planning and pay special attention to finding projects that expand the Midwest-South transfer constraint.
Other stakeholders have asked MISO to study the historic levels of congestion in MISO Midwest, potential impacts from widespread adoption of energy storage, and future thermal generation retirements in Illinois under of the state’s Climate and Equitable Jobs Act.
California agencies will start soliciting applications early next year from private entities seeking a share of National Electric Vehicle Infrastructure (NEVI) funds to build public EV charging stations throughout the state.
The agencies plan to issue 20 solicitations during 2023 and 2024, which will encompass at least 864 DC fast chargers at 143 sites. The proposals will be solicited in four rounds, starting in the first quarter of next year and then spaced six months apart.
The solicitations were the subject of a pair of workshops last week hosted by the California Energy Commission (CEC) and the state’s Department of Transportation (Caltrans). The agencies are seeking public feedback before finalizing details of the solicitations.
The goal of the NEVI program is to establish a nationwide network of public EV chargers along “alternative fuel corridors.” California is expecting to receive $384 million in NEVI funds over five years.
‘A Big State’
California has about 6,600 miles of alternative fuel corridors, including interstates, U.S. highways and state routes. Caltrans and CEC decided to first break the corridors into segments. Segments were then divided into 20 corridor groups, based on factors including location, gaps in the existing charging network and estimated future demand. Each NEVI solicitation will cover one corridor group.
“California’s a big state,” said Mark Wenzel, manager of the light-duty electric vehicle infrastructure and analysis office at the CEC. “To fully build out the network to NEVI standards will take hundreds of sites and thousands of chargers. It is not possible for us to design and competitively bid each site. We just don’t have the time and capacity for that.”
The NEVI program requires charging stations to be 50 miles apart or less and within one mile of a highway, although states can request exceptions.
Another NEVI program requirement is that each charging site must have at least four fast chargers and site power of at least 600 kW to support 150 kW per charging port.
California is planning to require more than four chargers at some sites, based on a demand forecast from the EVI-RoadTrip tool. The agencies’ goal is to build out the corridors to at least half of the charger demand expected in 2030.
California’s proposed corridor groups range in size from five to nine sites, with 20 to 166 chargers.
Caltrans and CEC also ranked the 20 corridor groups in order of priority. Priority was determined from a wide range of factors, including the percentage of the corridor that is in a disadvantaged community and the number of fast chargers needed to meet 2030 demand according to the RoadTrip tool.
The highest priority groups will go out to bid first.
The highest priority group is proposed corridor group No. 7, which includes eight new charging stations and 73 new chargers along State Route 58 and interstates 15 and 40 in Southern California.
Who Can Apply?
Applicants for California’s NEVI funds must be private entities that agree to build, operate and maintain the charging stations. But public entities, such as local governments, may still be part of a project team.
And the team must include an experienced charging network provider. The agencies will be looking for a company or organization with a proven track record of overseeing DC fast charger projects at three or more different locations and for three or more different customers in California since January 2018.
The NEVI program requires that applicants chosen to receive funding provide at least a 20% match. The California agencies have proposed increasing the required funding match to 50% for 13 of the 20 solicitations.
Caltrans and CEC are estimating total project cost based on $250,000 per charger. For example, a project with 24 chargers would have an estimated cost of $6 million, and a successful applicant would receive $3 million in cases where a 50% match is required.
Projects eligible for NEVI funding include new chargers at new stations, or additional chargers at existing stations. In addition to the costs of charging equipment, the funding may be used for solar panels or energy storage systems to power the EV chargers.
Extended warranties and maintenance agreements of up to five years are also eligible costs. Applicants for the NEVI funds must have a five-year operations and maintenance plan, and chargers will be required to be functional at least 97% of the time.
The agencies also plan to require restrooms at the NEVI-funded EV charging stations. The restrooms would need to be open at least during business hours, while the chargers must be available around the clock. No decisions have been made on restroom specifications, such as size and number.
Wenzel noted that proposed program requirements are still subject to change and feedback on the proposals is welcome. Changes are also still possible at the federal level, where NEVI regulations have been proposed but not finalized.
Buy America requirements that apply to federally funded projects are another variable for the NEVI program. The Federal Highway Administration (FHWA) has proposed phasing in the requirements for EV chargers in 2023. The agency is accepting public comment on the proposalthrough Sept. 30.
States File NEVI Plans
The NEVI program is part of the federal Infrastructure Investment and Jobs Act signed into law in November 2021.
All 50 states, Puerto Rico and the District of Columbia met the Aug. 1 deadline to file their NEVI plans with the FHWA. (See States File Plans on Deadline for Federal EV Charging Funds.) The FHWA now has until Sept. 30 to review and approve the plans.
More information on California’s NEVI plan is available here.
As it moves toward implementing the cybersecurity requirements added to its budget this year, the U.S. Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA) said Friday that it will seek public comment on the best approach to their execution.
CISA’s draft request for information — set to be published in the Federal Register on Monday — stems from the Cyber Incident Reporting for Critical Infrastructure Act of 2022 (CIRCIA), part of the omnibus spending bill passed by Congress and signed by President Biden in March. The bill requires entities “in a critical infrastructure sector, as defined in Presidential Policy Directive 21” — which includes the energy sector — to report relevant cyber incidents to CISA within 72 hours after they occur, as well as when they make a ransom payment to the perpetrators of a ransomware attack. (See Budget Mandates Cyber Reporting for Critical Infrastructure.)
Authority for several key areas within the law is designated to CISA’s director, including defining which incidents are subject to reporting and which additional sectors, if any, are covered by the requirements. CISA must issue a Notice of Proposed Rulemaking within two years regarding the matters left to the director’s discretion, with a final rule to follow after another 18 months that will also specify what content entities must include in their cyber incident and ransom payment reports, as well as the data preservation requirements.
In a statement, CISA said comments received in response to the RFI “will inform the agency’s development of the proposed regulations.” Members of the critical infrastructure community, as well as the public, will have 60 days from the publication of the RFI to submit their feedback.
CISA’s suggested topics for respondents to address include:
definitions, criteria and scope of regulatory coverage, including the meaning of “covered entity”; the number of entities likely to be identified with that label; the meaning of “substantial cyber incident,” “ransom payment” and “ransomware attack”; and the number of ransom payments likely to be made every year;
report contents and submission procedures, such as what information should be required for inclusion in reports, the format of reports and when the deadline for reporting ransom payments begins;
other reporting requirements and vulnerability information sharing; and
additional policies, procedures and requirements.
In addition to written comments, stakeholders may participate in one of 11 public listening sessions, one in D.C. and in each of CISA’s 10 regions. The first listening session will take place Sept. 21 in Salt Lake City, and the last currently on the schedule is planned for Nov. 16 in Kansas City, Mo.; the date of the session in D.C. has not yet been determined.
In the agency’s statement, CISA Director Jen Easterly called the CIRCIA “a game changer for the whole cybersecurity community [that] will allow us to better understand the threats we are facing, to spot adversary campaigns earlier, and to take more coordinated action with our public and private sector partners in response.”
“We can’t defend what we don’t know about, and the information we receive will help us fill critical information gaps that will inform the guidance we share with the entire community, ultimately better defending the nation against cyber threats,” Easterly said. “We look forward to continuing to learn from the critical infrastructure community … to understand how we can implement the new cyber incident reporting legislation in the most effective way possible to protect the nation’s critical infrastructure.”
Nearly 10 years ago, FERC convened a gas-electric conference in Boston to talk about the issues facing New England’s electric grid in the winter.
Last week, the federal agency came to New England again. The room was bigger, and some of the terminology has changed. Energy technology has evolved and, in many cases, improved tremendously.
But the conversation was strikingly similar, according to New England Power Generators Association President Dan Dolan, who was in attendance for both.
“It’s shocking and terrifying how close the notes and talking points we had for that one could be reflected today,” Dolan told FERC commissioners on Thursday at a conference center in Burlington, Vt.
Even the more specific issues around LNG supply have been identified for years, Dolan said, with no tangible action to solve them in the long term.
Experts, analysts and lobbyists laid out the problem for FERC commissioners, who surely knew what it was before they walked into the room: a resource adequacy crisis fueled by New England’s unique geographic and political constraints, which ISO-NE fears will be exacerbated by the states’ push to replace fossil fuels with clean energy.
Largely acknowledged throughout the conversation was that it’s too late to do anything for this winter.
“‘Hope’ is not a strategy,” said Richard Paglia, vice president of U.S. marketing at Enbridge. Later, NERC CEO Jim Robb echoed him: “‘Luck’ is not a strategy.”
But that’s essentially what ISO-NE has accepted as its position for this year: hoping that, like last winter, the region is lucky enough to avoid the most extreme cold, which the grid operator says could lead to rolling blackouts.
An exchange between ISO-NE CEO Gordon van Welie and FERC Commissioner James Danly hinted at one possible move that the commission could make this year: initiating a Federal Power Act Section 206 proceeding to force some sort of action from the grid operator.
But van Welie urged the commissioners to be cautious about that option and only use it if it involves clear direction.
Tomorrow’s Problem
The long-term solution to the region’s challenges depends on who you ask.
The natural gas companies and their allies present at the meeting want to build more gas infrastructure — not necessarily new pipelines, but potential brownfield development, like changing out pipes for larger ones or adding compression, as Paglia suggested.
There was also substantial discussion about making sure that operation continues at the Everett LNG terminal, which ISO-NE highlighted in a recent problem statement, arguing that the facility is vital to the region’s energy security. (See ISO-NE: Reliability Still Depends on Mass. LNG Import Terminal.)
But others say the clean energy transition brings opportunities to maintain grid reliability in the same fell swoop as decarbonization. (See related story, Clean Energy Groups Don’t Buy ISO-NE’s Gas Reliance).
“We’re taking our eyes off the prize,” Liz Delaney, of solar and storage developer New Leaf Energy, told commissioners. “We need to resolve the near-term issue, and it’s complicated, but at the same time we need to focus on the market mechanisms that are going to get us through the energy transition.”
It’s not just long-duration storage that can help, she said.
“Short-duration battery storage does have a role to play in supporting winter reliability. It’s not the end-all and be-all. But we have miles to go in terms of being able to understand how to optimize battery storage,” Delaney said.
Vermont Department of Public Service Commissioner June Tierney also urged policymakers not to skate past demand response as a powerful grid management strategy.
She pointed to the recent energy emergency in California, which saw significant conservation efforts help CAISO avoid rolling blackouts during an unprecedented heat wave. (See related story, California Runs on Fumes but Avoids Blackouts.)
“Let’s not underestimate the people of the United States. Let’s not underestimate the people of New England,” Tierney said. “If they’re called upon, as millions of Californians were on their cell phones, to reduce demand immediately, they will respond.”
FERC Chairman Richard Glick called for a broader focus too, saying that he would like to see a focus on longer-term fixes like new generation, transmission buildout and energy efficiency.
“If we spend all our time thinking about how we’re going to keep the Everett LNG facility open … today will be a failure,” Glick said.
In the end, both the short-term LNG challenges and longer-term clean energy transition got plenty of air time at the forum. But there’s still significant anxiety in the energy sector and among its regulators about what will happen when the thermometers drop and stay low.
“If the lights go out, we’re all to blame. There’s not going to be any finger pointing because we’re all on the hook,” said Phil Bartlett, chairman of the Maine Public Utilities Commission.
NERC has begun planning for next year’s GridEx VII security exercise and is expecting a boost in attendance after participation in the distributed play portion declined for the first time last year.
Speaking at Thursday’s meeting of NERC’s Real Time Operating Subcommittee (RTOS), Laura Brown, director of engagement and security policy coordination at the Electricity Information Sharing and Analysis Center (E-ISAC), told attendees that planners are “looking for … additional support that industry can provide … the [reliability coordinators] in particular.”
The E-ISAC has developed, managed and delivered each iteration of GridEx since the first one held in 2011.
GridEx VI, held from Nov. 16-18, 2021, consisted of a distributed play the first two days involving more than 3,000 people across 293 organizations, and an executive tabletop featuring almost 200 participants from 88 organizations in the U.S. and Canada. (See NERC: GridEx Lessons Already In Use.)
The number of organizations taking part in the distributed play last year was the lowest recorded since GridEx II in 2013, while the 3,000 individuals participating represented fewer than half of GridEx V’s approximately 7,000. Brown said Thursday that the “dip in participation … was in part due to the pandemic as well as some changes that we made to registration requirements,” referring to the fact that unlike in previous years, participants in GridEx VI were only required to register with the E-ISAC to use the exercise tools or access planning materials.
NERC has previously indicated that the registration changes are likely to remain in place for future installments of the biennial exercise and that “future participation numbers are likely to be more comparable to those recorded for GridEx VI.” However, Brown emphasized that “we do expect to see some of those numbers go back up.” While she did not explain her statement at the time, she was likely referring to the relaxation of travel restrictions among many participating organizations.
E-ISAC Reviews Planning Phases
Accompanying Brown to the RTOS meeting was Jesse Sythe, who recently joined the E-ISAC as GridEx program manager. Sythe provided an overview of the GridEx VII planning process, which involves three distinct groups: sponsorship and management, exercise design and development, and exercise planning and execution.
The first group, sponsorship and management, comprises the executive sponsors — NERC CEO Jim Robb and E-ISAC CEO Manny Cancel — and the planning team, which includes Brown and Sythe. Responsibilities of the planning team, according to Sythe, include “gathering input from … other industry groups, developing exercise materials, training, webinars, exercise tools and then drafting the lessons learned report.”
Next is the exercise design and development group, which Sythe called “the bridge between the sponsorship and management lane and … the exercise participants.” The group is divided into a design team, a reliability coordinator team, a subject matter expert team and a training webinar team, and is meant to provide the planners with perspectives on the challenges utilities face every day.
“We don’t always have day-to-day insight into what utilities see in steady state or emergency situations, so the input that we receive from each team helps us to develop the exercise scenario, the materials and all the training webinars that are most beneficial to planners and players,” Sythe said.
The last group involved in the planning process is exercise planning and execution, which includes the lead planners and planners from each organization who adapt the exercise scenario created by the planning team to their particular circumstances. Players are also considered to be part of this lane because they are the ultimate users of the scenario.
The E-ISAC’s planning timeline for next year’s GridEx VII | NERC
Currently planners are in the initial phase of the project timeline, which Brown and Sythe shared at the meeting. This phase involves setting the goal, objectives and timeline of the exercise and developing an outreach plan, expected to last through the next few months. In the midterm planning phase the team will finalize the scenario and develop exercise materials, followed by the final planning phase when the final exercise materials are distributed and the planner training webinar series is completed. The two phases of the exercise will be conducted in November 2023, with the after-action phase to follow.
