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November 18, 2024

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A Nuclear Renaissance in the Making?

The nuclear industry descended on D.C. last week to make the case for advanced reactors, both large and small, with some so small that they could be built at existing industrial sites to supply behind-the-meter dedicated power and heat.

On Monday, The Atlantic Council, working with the United States Nuclear Industry Council (USNIC), webcast an eight-hour live program featuring more than 30 speakers in a half-dozen discussion panels.f

And on Wednesday, the International Atomic Energy Agency began a three-day conference in D.C. focusing on the rebirth of nuclear energy in the U.S. and around the globe, in part as a reaction to Russia’s decision to cut natural gas exports to Europe and to address the plight of nearly 1 billion people globally who have no electricity, participants said. U.S Department of Energy leaders played prominent roles.

Once in a Lifetime Financial Boost from Federal Legislation

Beyond the situation created by Russia, which some participants at the events repeatedly called a “global energy crisis,” the passage of the Inflation Reduction Act (IRA) earlier this year as well as the Infrastructure Investment and Jobs Act (IIJA) in 2021 have galvanized U.S. nuclear proponents to look for ways to make nuclear power more competitive. It has also catapulted the reputation of the U.S. as a global leader in nuclear technologies.

The IRA will provide production tax credits to reactor owners, even to owners of existing reactors. The PTCs will be similar to what wind and solar have received for years. The zero-emission nuclear production tax credit provides up to $15/MWh — assuming labor and wage standards are met — from 2024 through 2032.

DOE in September stirred more interest in building advanced nuclear with the release of a study concluding that 157 sites of former coal-fired power plants would be suitable sites for nuclear plants. And because nuclear reactors are designed to run without interruption, giving them a high capacity factor, the nukes would not have to be as large as the original coal plants. The study also found that 237 operating coal plants could be considered for a nuclear replacement.

Existing nuclear plants are also getting new attention. The IIJA contained a provision that would create a $6 billion Civil Nuclear Credit Program, providing cash supplements to reactor owners who would otherwise be forced to shut down.

Awards have yet to be made but the first applications — totaling about $81 billion — are now under review.

8 Hours with the USNIC

The Atlantic Council’s multiple panel discussions began with a review of the renewed global interest in nuclear power, including interest from nations preferring to work with U.S companies and the U.S. government rather than state-owned enterprises connected to Russia or China.

The predominant focus was the rebirth of nuclear power as the best technology to address climate change while simultaneously providing national energy security.

“We have a renaissance in investment in the nuclear industry today, with record amounts of private capital being invested …  about $4 billion last year,” said André Pienaar, CEO of C5 Capital, a venture capital firm with offices in London, Washington and Luxembourg.

C5 focuses on cybersecurity, space and nuclear energy. Investors are looking across “the whole spectrum of innovation, from small modular nuclear companies, all the way through to the promise of nuclear fusion,” Pienaar said.

The mention of fusion was a reference to U.S.-based developers of fusion reactors, which create energy by fusing helium atoms rather than splitting enriched uranium.

More immediately, Pienaar was referring to fission reactors of 300 MW and smaller, down to those as small as 50 MW, some using technology like the large traditional light water reactors now in commercial service, others designed around more exotic technologies with passive safety systems to make them “walk away safe.”

Small modular reactors (SMR) are factory-built, enabling the manufacturer to increase quality control while providing faster installation than traditional large reactors at a lower cost.

“The investments in SMRs are not limited to private capital,” Pienaar said, referring to NuScale Power (NYSE:SMR), an early developer of small modular reactor design. NuScale has been publicly traded since its merger last spring with Spring Valley Acquisition, a special purpose acquisition company created by banks, institutional funds and private investment groups.

“We’ve also seen significant cross-border investment. Constellation Energy invested in the Rolls Royce SMR consortium in the UK,” Pienaar said, adding that Cameco and Brookfield Renewable Partners this month purchased Westinghouse Electric in a deal valued at $7.87 billion.

Cameco (NYSE: CCJ) is a Canadian uranium mining company. Brookfield (NYSE: BEP) is a publicly traded limited partnership headquartered in Canada that owns hydroelectric, wind, solar and power storage facilities in North America as well as South America, Europe and Asia.

Westinghouse manufactures equipment for nuclear reactors operating around the globe and provides services to U.S. reactors as well. 

Competition Among SMR Makers

At this point, NuScale appears to be ahead of competitors striving to market a working SMR. The Nuclear Regulatory Commission approved NuScale’s design in August, opening the door for the company to begin selling them rather than building demonstration projects.

Founded in 2007, NuScale designed a self-contained 77 MW pressurized water reactor. Up to 12 of these factory-built “modules” can then be configured in a “multi-module” container and operated from a single control room.

X-energy, a Maryland company that has designed a gas-cooled high temperature SMR, is aiming at providing reactors that the company says cannot meltdown to private industry in need of reliable power and on-site heat. The company’s basic reactor, the Xe-100, is rated at only 80 MW but can be “scaled” into a four-pack, 320-MW power plant. X-energy won a $1.1 billion matching grant through the IIJA.

Marcy Sanderson, a nuclear engineer and vice president at X-energy, said the reactor operates at a little over 1,000 degrees F. Today’s conventional reactors operate at roughly 550 degrees (boiling water reactors) to 600 degrees F (pressurized water reactors).

Rather than fuel rods as in conventional reactors, the Xe-100 uses “pebbles,” small balls of extra-enriched uranium., an arrangement that allows the reactor to “ramp” up and down, something conventional reactors are not good at doing.

“The inherent characteristic of our design is exceptionally well-suited to what we consider an … opportunity right now, trying to take meaningful, tangible steps to decarbonize heavy industry, support the carbon challenge, support the climate crisis that we all know is in front of us,” Sanderson said.

Because the fuel “has been hailed as the safest fuel on earth, we can talk about doing something like siting a nuclear power station next to a chemical facility,” she said.

The facility in question is owned by Dow Chemical.

Dow and X-energy have announced a preliminary agreement to install an Xe-100 at one of Dow’s Gulf Coast facilities to provide heat and power, said Kreshka Young, a Dow business director, in another panel.

“We’re looking for high-temperature, high-pressure steam to support our heat needs at our sites. And by high temperature I mean in pretty much all cases [temperatures] greater than 500 Celsius [932 F], and then it goes up from there.”

Young said Dow is also looking for reliability.

“For steam, we’re really relying on our on-site generation, whether that’s from a gas turbine, from a boiler, or in this case from a reactor. Whatever the source of that steam, it must be reliable,” she said.

“And when I mean reliability, I don’t mean the 95% reliability. When we say reliability for steam, we need 99.995% reliability,” she said.  “We need a backup, and then maybe even a backup to a backup. The modularity of X-energy’s design … combined with the steam temperatures that it can reach made it one of the technologies we thought would be a really good fit for us.”

Dow additionally has emissions reductions goals, she said.

“We’ve already reduced our carbon emissions since 2005 by 15%. We have a goal to reduce them another 15% by the end of this decade, and to be net zero by 2050.”

Nuclear Capital symposium Panel 1 (Atlantic Council) Content.jpgFrom left: Kurt Scherer, managing partner, C5 Capital; Marcy Sanderson, X-energy; and Kreshka Young, Dow Chemical | Atlantic Council

Globally, the company currently produces about 7 GW equivalent of power and steam for use at its manufacturing sites, with any excess sold to the market. “That’s produced with over 50 gas turbines and gas-fired boilers. That energy production is about 50% to 55% of Dow’s total carbon emissions,” Young said.

Another SMR competitor is TerraPower, an engineering company founded in 2008 by Bill Gates specifically to design advanced nuclear reactors. Company CEO Marcia Burkey also argued in another panel discussion that investors have decided nuclear energy has a role to play.

“There is a growing recognition that nuclear power must be part of the mix. It’s a small footprint. It’s a very dense energy form. It certainly addresses energy independence, and that’s a growing concern and preoccupation, not just of providers [of generated power] but of investors.”

TerraPower is planning to build a 345-MW advanced reactor in partnership with GE Hitachi on the site of a Wyoming coal-fired power plant scheduled to shut down. The reactor will be cooled by liquid sodium rather than pressurized water as in traditional large commercial reactors, enabling it to run at lower pressures.

The reactor power plant will include a molten salt storage system, allowing operators to store the heat from the reactor core rather than use it immediately to make electricity as conventional reactors now do.

Burkey said her company has raised funds globally in anticipation of building small advanced reactors around the world. She said the company had recently spent time with potential investors in a drive to raise $750 million in new private capital.

“I would say that strategics [strategic industries] were very interested because they could see the potential to bring into their operations a carbon-free source that helps them meet their own goals, and [to] participate in the supply chain and help us to accomplish our goals. I would say private equity was very interested,” she added.

Another speaker also mentioned that the interest in small U.S.-designed reactors is international.

Rick Springman, senior vice president at SMR, a maker of SMRs and now a division of the privately held Holtec International Company, said overseas clients are interested in the company’s technology and are calling to ask whether Holtec can manufacture an SMR with a design that meets specific regulations in their countries. He said operating regulations should be at least “harmonized” as the demand for SMRs continues to grow.

“I think harmonization is a key and needs to be connected to financing. Because if you take a U.S. technology with the U.S. regulation and you go abroad and you change it, you’re going to end up with a different plant, period. If you apply different codes and standards you’re going to end up with a different plant.”

In another panel discussion, Rafal Kasprow, CEO of Orlen-Synthos Green Energy, a joint venture in Poland of Synthos Green Energy and PKN Orlen, the largest multi-energy company in central Europe, said his company is a good example of private capital and the international nuclear renaissance.

Earlier this month his company signed a master services agreement with Laurentis Energy Partners, a Canadian company with European operations, to build and deploy a fleet of SMRs designed by GE Hitachi.  The small reactors are rated at 300 MW and designed with passive safety systems, making them less likely to suffer catastrophic failures.  Kasprow said U.S.-designed nuclear technology is in high demand.

“I think that there’s a recognition now of the geopolitical risks associated with doing business with Russia or China,” Kasprow said, adding that demonstrating the economics of nuclear energy is no longer a problem.

“People are calling every day, from meat-packing companies, from chemical businesses and other businesses, asking ‘Do you have SMRs? Can you deliver? We will pay cash,’” he said.

Bridge to Bankability

Whatever the advantages that nuclear offers, the new SMR technology is competing with numerous other technologies, all hungry for investor — and tax — dollars in what has become a rush away from conventional fuels.

In a one-on-one interview with the Atlantic Council’s Landon Derentz, Jigar Shah, head of DOE’s Loan Program Office, provided a frank evaluation of the hectic activity his office now faces from U.S. companies and entrepreneurial groups competing for the billions of dollars in tax credits, production credits, loan guarantees and matching grants across a broad spectrum of energy technologies, including nuclear.

The function of the loan office, making loans to companies involved in promising technologies but risky market penetration is often described as building a “bridge to bankability” in the sense that if these companies can achieve full market acceptance they will qualify for conventional financial banking.

“We’re building a lot of bridges these days here in the United States. I think when you look at sectors that are actually at scale today, solar wind, EVs, lithium-ion battery storage, you’re looking at a minimum of $100 billion in private sector capital before they [can achieve] real market acceptance from the commercial banking sector,” Shah said.

“There are lots of technologies that are in different phases of getting support — hydrogen, carbon sequestration and storage, nuclear and others — that are coming to the Loan Programs Office,” Shah said. “There’s some rhyme or reason but not a lot. It’s not based on the readiness of technology.

“It’s based on who’s promoting the technology, who that CEO is and their ability to raise capital right in the marketplace, some of which comes from their previous roles and experience and some of which comes from who their sponsors are and where that support is coming from.”

“But how does that translate into brass tacks when industry wants to approach you?” Derentz asked. “What do you need from them to articulate that because each company is bringing its particular interest. Do you need a comprehensive view? Do you need a consortium view or viewpoint? What is the most helpful for approaching the loan office?”

Shah responded: “A supply chain investment doesn’t work unless they’re supplying something to somebody. Right? If they have one order for something, and then they come into the Loan Programs Office for a loan, I’m saying, ‘Who would you supply next? Who would be two, three and four?’

“I think nuclear is one of the hardest conversations because of this private sector-led, government-enabled approach that we have here in the U.S. The U.S. has a challenge around figuring out who goes first. And I do think that the Department of Energy can play, and is playing today, a critical role in facilitating those conversations.”

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MISO’s $4B MTEP 22 Clears 1st Board Vote Despite Criticisms

MISO’s 2022 transmission planning portfolio cleared its first vote before the Board of Directors, though some stakeholders have lodged complaints over the package.

During a teleconference Tuesday, the board’s System Planning Committee voted unanimously to send the $4.3 billion, 382-project 2022 Transmission Expansion Plan (MTEP 22) to a full board vote in early December.

MTEP 22 earned just four votes in favor of recommendation and five abstentions from MISO’s 11 stakeholder sectors. (See Stakeholders Endorse MISO’s Final MTEP 22.) The Transmission Developers sector voiced complaints over a lack of a meaningful project alternative process, while the Environmental sector said MTEP planning cycles need to incorporate more preparation for grid-enhancing technologies, increasingly common extreme weather events and advance notice when transmission owners’ age and condition projects are going to come due.

The Environmental sector also said it had concerns over MISO’s wording in MTEP 22 that carbon-reduction goals alone are driving the footprint’s resource transition and that gas generation can help navigate the changeover.

Vice President of System Planning Aubrey Johnson said the “vast majority” of projects to address age and condition of existing equipment — which represent the largest spending share of MTEP 22 — are not conducive to alternative project proposals. He said lower-voltage lines simply need replacement in many cases.

Johnson said MISO believes it has a comprehensive and transparent planning process and that he didn’t notice members taking exception to any projects in particular. He said MISO’s separate long-range transmission planning process resolves many of the Environmental sector’s concerns over MTEP being too shortsighted.

Some members have asked if the vote tally was concerning to MISO and whether the RTO needs to reassess this year’s transmission spending package.

“I think the vote indicates that many feel that there’s still a need to improve the MTEP report,” Clean Grid Alliance’s Natalie McIntire told board members. She said MISO should remove MTEP 22’s references to natural gas generation being able to provide a reliable backstop to renewable generation’s output and that the RTO needs to keep with its practice of being resource agnostic.

But Prairie Power’s Karl Kohlrus said MISO hasn’t adequately factored in its planning how removal of all Illinois’ fossil generation by 2045 under the state’s Climate and Equitable Jobs Act will affect system reliability.

“MISO is heading for a major train wreck,” he warned.

Kohlrus has previously said during planning meetings that he was concerned that the RTO isn’t reflecting enough future baseload retirements in its 20-year models used for transmission planning.

Johnson said stakeholders’ comments are expected, given the accelerating resource shift.

MISO Director Nancy Lange said MISO’s review of age and condition projects should consider “factors that all these regions are grappling with.”

Johnson said transmission projects related to age and condition and load growth provide the foundation for long-range transmission planning to accommodate the resource transition. He said there’s “a lot of connective tissue” between MTEP and long-range transmission planning.

“We’re in a state of transition right now. It’s taking a tremendous amount of effort from all parties to do this foundational work,” he said.

“It’s not surprising that we’re having a lot of differences of opinion,” MISO Director Phyllis Currie said, adding that the board and MISO take stakeholders’ concerns seriously.

During an Advisory Committee teleconference Oct. 26, the Union of Concerned Scientists’ Sam Gomberg asked if MISO was weighing whether to open an inquiry into MTEP 22’s scant support to avoid conflict with approving the transmission package later this year.

“It’s certainly something that raised my eyebrows, personally,” Planning Advisory Committee Chair Cynthia Crane said.

WEC Energy Group’s Chris Plante also said he thought the voting results were “concerning.”

MISO Senior Director of Transmission Planning Laura Rauch said the comments explaining why some MISO sectors withheld support of the plan are “helpful.”

Rauch said the vote “did not mean stakeholders weren’t active and engaged” in this year’s planning process. She said MISO looks for ways to continually improve the MTEP process.

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ERCOT Stakeholders Wait on Bylaw Amendment Changes

ERCOT stakeholders have submitted comments on proposed amendments to the grid operator’s bylaws that have been sitting with the Board of Directors since September.

The amendments, drafted by staff at the board’s direction, would no longer require members’ approval of such changes. It would require that members be provided notice and the chance to comment on any proposed amendments or other “fundamental actions.”

Members had until Sept. 30 to comment on the revisions. The board was to discuss the amendments during its October meeting but did not do so in a public forum.

Jupiter Power’s Caitlin Smith filed comments on behalf of 26 other members, saying it is “imperative to emphasize the chilling effect the proposed amendments could have on decisions to enhance and maintain the health and reliability of the ERCOT grid, including continued investment in generation.”

“A successful energy-only market requires that its participants have a vested interest in the activities of the organization,” Smith said, referring to the development and refinement of market policy and rules.

“Corporate members must vote to amend the ERCOT bylaws,” she said. “Eliminating this right of ERCOT stakeholders is a clear signal to investors of regulatory and market uncertainty, which sends a negative investment signal that, all else equal, will impact operations, reliability and the provision of energy to consumers within the state.”

Smith said that if the proposed amendments are adopted, ERCOT’s governance structure will “most closely resemble” CAISO’s.

ERCOT Assistant General Counsel Jonathan Levine was unable to clarify the board’s next steps on the amendments during the Technical Advisory Committee’s short, virtual meeting Oct. 26.

“It’s a pretty fluid situation at this point. It’s up to the board and the board chair of what they want to do,” he said. “I apologize for not having any better information about where we’re heading on the bylaws amendment. I’m just a mouthpiece here.”

The Protocol Revision Subcommittee said it is working on a priority revision process that TAC shared with the board’s Reliability and Markets Committee in October. A draft will be presented during TAC’s Dec. 5 meeting. (See “TAC Shares Changes with R&M,” ERCOT Board of Directors Briefs: Oct. 18, 2022.)

Combo Ballot Approves TAC’s Annual Review

TAC’s combination ballot last week included the results of its annual structural and procedural review, two nodal protocol revision requests (NPRRs), a revision to the Load Profiling Guide (LPGRR), an other binding document request (OBDRR) and a change to the Retail Market Guide:

    • NPRR1128: would set a 1-cent/MW lower ancillary service (AS) offer floor for fast frequency response (FFR) responsive reserve (RRS), thereby allowing, depending on relative AS offers, FFR procurement up to the current limit without proration with other RRS categories in the ancillary procurement process.
    • NPRR1148: would resolve protocol gaps found during emergency contingency reserve service’s creation of its system change requirements.
    • LPGRR069: would add Lubbock Power & Light’s service address zip codes to the guide and updates the ERCOT service territory map to include Lubbock County. The LPRR also corrects zip code counts that were omitted in the count column.
    • OBDRR043: would align the operating reserve demand curve’s methodology with NPRR1148.
    • RMGRR170: would define the inadvertent gain/loss (IAG) process and an IAG; clarify its appropriate use; and clarify the IAG process’ appropriate use.
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PSEG Faces Final Decision on NJ Ørsted Project

Public Service Enterprise Group (NYSE:PEG) is mulling whether to remain a 25% partner with Ørsted in the Danish developer’s Ocean Wind 1 project in New Jersey, CEO Ralph LaRossa said Monday as he laid out the company’s future clean energy plans in its third-quarter earnings call.

The company acquired the share shortly after the New Jersey Board of Public Utilities (BPU) in 2019 picked Ørsted’s 1,100-MW project to be the state’s first offshore wind project. LaRossa spoke in his first earnings call since he took over from his predecessor, Ralph Izzo, on Sept. 1.

“We are approaching a final investment decision [FID] on Ocean Wind 1 in New Jersey to determine if we will proceed to the construction phase,” LaRossa said. “We are reviewing our options related to our 25% equity investment as well as our option to purchase” 50% of Ørsted’s Skipjack Wind 2 project in Maryland, he added.

On Ocean Wind, “one of the things we’re looking at there is where the costs come in, and what that project looks like from an investment standpoint,” he said. Also part of the consideration are changes in revenue and expenses, he said. Under questioning from investment analysts, CFO Dan Cregg said there is no date stipulated in the contract for the decision.

An “FID moves you to the construction phase of the project, and so it’s when things are ready to move to that phase,” he said. Company officials gave no indication as to whether they would withdraw from the joint venture or remain as a partner.

Offshore Transmission Opportunity

LaRossa said that despite the fact that the BPU last week awarded PSEG only a small part of the work to upgrade the state’s transmission system in preparation to handle energy from the offshore wind projects, the utility believes that it could still get a substantial share of future work.

The BPU on Wednesday voted unanimously to spend $1.07 billion on transmission upgrades to deliver 6,400 MW of offshore wind generation to the PJM grid, saying the projects would minimize costs, environmental impacts and permitting risks (QO20100630). The BPU made its selection from among 80 proposals submitted by 13 developers in response to a solicitation issued by PJM at the BPU’s request under FERC Order 1000’s State Agreement Approach. (See related story, NJ BPU OKs $1.07B OSW Transmission Expansion.)

Among the submissions for the solicitation were proposals by PSEG individually and the Coastal Wind Link, submitted with Ørsted, which would use an offshore mesh system to transmit electricity onshore. Rizzo in May said PSEG could potentially secure projects costing $3 billion under the solicitation, although he also acknowledged the company may also get nothing. (See PSEG Sees Potential $3B OSW Transmission Spending.) LaRossa said that based on the contracts awarded last week, the offshore work potentially available to the PSEG-Ørsted partnership could be between $2 billion and $7 billion.

“We remain optimistic that our emphasis on reliability and resiliency will keep it as a strong contender for any future offshore transmission solicitations to bring regional offshore wind projects onshore,” he said. If the company did pull out of the Ocean Wind 1 project, it potentially could invest more in transmission systems linking the offshore projects, he said, noting that the BPU solicitation sought transmission proposals only for the state’s goal (at the time) of 7.5 GW of offshore wind power by 2035. New Jersey Gov. Phil Murphy on Sept. 21 announced that he had increased the state’s offshore wind target to 11 GW by 2040.

“We’re still hopeful on that offshore transmission and a full mesh network,” LaRossa said. “We think our mesh network is absolutely the most resilient and most robust.”

Nuclear Tax Credits

LaRossa said that the company also expects to benefit from the Inflation Reduction Act, which he said would have “important revenue visibility and price-stabilizing benefits” for the utility’s 3,770-MW nuclear fleet. The act, which was signed by President Biden on Aug. 16, provides production tax credits of up to $15/MWh for certain nuclear plants, from 2024 through 2032.

The credits will “will extend the visibility and stability of cash flows into the next decade,” LaRossa said in an earnings release. “These incentives will lower customer costs over time and support the continued operation of existing nuclear plants — which are New Jersey’s largest carbon-free base load energy resource.”

PSEG reported net income of $114 million ($0.22/share) in the third quarter, compared to a net loss of $1.564 billion ($3.10/share) a year earlier. The 2021 loss was from an impairment charge from the sale of the utility’s fossil assets.

Non-GAAP operating earnings for the third quarter of 2022 were $429 million ($0.86/share) compared to non-GAAP operating earnings of $495 million ($0.98/share) in the third quarter of 2021.

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National Grid to Pay $512k for Standards Violations

National Grid USA must pay $512,000 in penalties to the Northeast Power Coordinating Council (NPCC) for violations of NERC reliability standards, under a settlement approved by FERC on Friday (NP22-33).

According to the agreement, National Grid — which owns about 8,900 miles of transmission lines and 387 substations and serves about 3 million customers in New York and Massachusetts — admitted to three separate violations. Two involved FAC-008-3 (Facility ratings), and the third PRC-023-4 (Transmission relay loadability). All were self-reported.

At issue with the FAC-008-3 violations were requirements R6 and R8 of the standard. R6 requires that each transmission and generation owner have facility ratings for their solely- and jointly-owned facilities that are “consistent with the associated facility ratings methodology” (FRM), while R8 specifies the information that TOs must provide to reliability coordinators and other stakeholders when requested.

National Grid first realized that it might be in violation of the standard while it was preparing for its annual TPL-001-4 planning assessment and “another related project” in September 2019. Specifically, the entity discovered that “six transmission facilities did not have facility ratings … that were consistent with its” FRM. A subsequent extent of condition review, in which National Grid analyzed the facility ratings for all of its 726 bulk electric system elements in New England and New York, revealed similar issues at 100 facilities.

That was not the last time the utility would unearth ratings discrepancies at its facilities. During an asset baseline pilot in 2021 during which National Grid conducted field visits to 20 substations to verify field conditions, the entity found eight more facilities in which the field conditions did not match the ratings on record (another eight had already been flagged during the earlier review).

National Grid determined that the incorrect ratings had begun “on a variety of different dates,” stretching back to 2007 or earlier. NPCC asserted that because of the long duration, multiple versions of the standard were violated, from FAC-009-1, which took effect June 2007, to FAC-008-4, the currently effective standard.

The violations of R8 were discovered during the same planning assessment in 2019, with National Grid reporting to NPCC that it had failed to provide ISO-NE and NYISO accurate facility ratings for six transmission facilities. An extent of condition review found similar discrepancies at 154 facilities, later determined to span a similar time frame as the R6 violations.

NPCC assessed both the R6 and the R8 violations as a serious risk to bulk power system reliability, noting that incorrect facility ratings cause system operators to operate “with a decreased level of situational awareness in real-time and [monitor] contingencies with reduced accuracy.” Mitigation actions are ongoing and not expected to finish until 2025. They include walkdowns of all 175 BES substations and switching stations in New York and New England, with visual inspections of nameplates, transformers and bus conductor types at each station.

National Grid has already updated facility ratings with NYISO and ISO-NE where possible and updated its FRM “to document how global changes to key assumptions will be implemented and/or applied to existing facility ratings.” It has also begun a semi-annual review in New York “to verify that facility ratings updates made within the previous six months were correctly implemented and documented.”

Relay Setting Slip-ups

The utility’s violation of PRC-023-4 involves requirement R1, which details the criteria that TOs, GOs and distribution providers must use on circuit terminals to “prevent [their] phase protective relay settings from limiting transmission system loadability.” Criterion 1 tells utilities to set relays “so they do not operate at or below 150% of the highest seasonal facility rating of a circuit,” while criterion 2 requires relays to be set “so they do not operate at or below 115% of the highest seasonal 15-minute facility rating of a circuit.”

National Grid notified NPCC in July 2019 that it was noncompliant with R1 because 10 of its protective relay settings did not meet criterion 1 for relay loadability. The following year the utility reported an additional relay setting that did not meet criterion 2, and it reported five more violations of criterion 1 in 2021. In all, there were 16 noncompliant relay settings affecting 13 transmission lines. The infringements began in 2010 and had all been corrected by September 2021.

NPCC determined that the violation posed a moderate risk to BPS reliability: While improper protective relay settings increase “the risk that transmission lines would trip prematurely,” the RE also noted that National Grid is a summer peaking system and the feeder loadability issue affects the winter season.

National Grid’s mitigation actions include applying new settings for appropriate relays and implementing a tracking spreadsheet to ensure PRC-023 compliance among applicable relays. The utility also implemented a new training module for the protection engineering team on completing the new spreadsheet, and committed to update the annual training — next scheduled for January 2023 — to “include the different calculations that exist and when to apply them.”

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Eversource Calls on Feds to Prepare Emergency Actions for New England

New England’s largest utility is piling on to calls for winter help from the federal government.

In a letter to President Biden last week, Eversource Energy (NYSE:ES) CEO Joseph Nolan asked the administration to start preparing for possible emergency action as New England stares down what could be a dicey winter for the region’s electric grid.

“As both an energy company CEO and a lifelong New Englander, I am deeply concerned about the potentially severe impact a winter energy shortfall would have on the people and businesses of this region,” Nolan wrote.

He laid out a problem that has become familiar to energy policymakers in the Northeast: pipeline constraints, a lack of fuel storage capability and a volatile LNG market, which together could mean rolling blackouts if the region sees a period of extreme, extended cold.

Nolan pointed to four possible emergency actions that the federal government could take:

      • a waiver of the Jones Act to make it easier for imported LNG to get to terminals in New England;
      • an emergency order under Federal Power Act Section 202c, which allows the secretary of energy to order “temporary connections of facilities and such generation, delivery, interchange or transmission of electric energy”;
      • an emergency order under the Natural Gas Policy Act, which addresses a “severe natural gas shortage”; and
      • using the Defense Production Act to prioritize domestic energy supplies.

Waiting until an emergency arrives would be too late, Nolan wrote, asking the federal government to start making a plan with the region.

“The need for action now is compelling. Many of the solutions require advance planning because they may require actions by regulators, finding new resources, chartering vessels, arranging for additional fuel deliveries and other yet-to-be-identified extraordinary actions,” he said.

Eversource’s request for help follows others in the region, including New England’s governors, who wrote to the Biden administration in August asking for consideration of a Jones Act waiver and work on a new Northeast energy reserve. (See New England Governors Ask Feds for Help with Winter Reliability.)

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Maine Voters to Decide on Upending Utility Landscape in 2023

Maine voters may have the chance to upend the state’s utility landscape and send its two biggest players packing in November 2023.

Our Power Maine, a coalition pushing for a referendum to replace Central Maine Power and Versant Power with a nonprofit, consumer-owned alternative, announced on Monday that it has acquired the signatures necessary to get it on the ballot next year.

The initiative calls for creating a new utility called Pine Tree Power, which it says would be privately operated and controlled by a mostly elected board.

“The company’s purposes are to provide for its customer-owners in this state reliable, affordable electric transmission and distribution services and to help the state meet its climate, energy and connectivity goals in the most rapid and affordable manner possible,” the ballot question would state, if it’s approved by Maine’s secretary of state.

What’s not stated outright in the referendum question, but is a driving force behind the campaign, is that the utilities it aims to push out are some of the most unpopular in the country. In their respective categories in the J.D. Power 2021 Electric Utility Residential Customer Satisfaction Study, CMP and Versant are dead last. Their customers also pay rates that are among the highest in the country.

“It’s this strange inequity where we get what is clearly the worst and least popular service in the nation and pay kind of a lot comparatively for that,” Andrew Blunt, executive director of Our Power Maine, said in a recent interview.

A group of three Maine economists wrote in an op-ed last year that the refinancing and replacement of CMP and Versant would save residents money right away.

Opponents say the initiative would be a costly one for the state.

Versant and CMP have fiercely opposed the initiative; Our Power says the utilities have spent $6 million fighting it. Other business interests in Maine are opposed too.

“This risky $13.5 billion proposal to take over our electric grid will create a tremendously volatile business environment in Maine for years to come,” Dana Connors, president of the Maine State Chamber of Commerce, said in a statement. “Companies will be forced to think twice about investing in our state, and what do customers get in return? Higher rates, a debt three times the annual state budget, unaccountable politicians controlling the state’s critical infrastructure, and no guarantee of better service. Maine businesses depend on safe, reliable, affordable electricity, and we can’t afford to gamble that all away on this proposal.”

CMP parent company Avangrid (NYSE:AGR) has also funded an opposing campaign called No Blank Checks, which also collected signatures in an effort to force a statewide vote on any new government debt over $1 billion, which would apply to the utility buyout, although the exact cost to the state is under debate.

The consumer-owned utility proposal made it through Maine’s legislature in 2021, only for it to be vetoed by Gov. Janet Mills, who claims that her opposition was more about process and specifics of the legislation (which also would have put the question to voters) rather than the underlying idea of replacing the state’s incumbent utilities. (See Mills Tells Maine Legislature to Slow Down on Plan to Replace IOUs.)

“L.D. 1708, hastily drafted and hastily amended in recent weeks without robust public participation, is a patchwork of political promises rather than a methodical reformation of Maine’s complicated electrical transmission and distribution system,” Mills said at the time.

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NYISO OC Approves CY21 Cost Allocations

The NYISO Operating Committee last week approved the class year 2021 (CY21) study report, triggering the 30-day period for generation developers to decide whether to accept or reject their cost allocations for needed transmission upgrades.

Stakeholders expressed some concern over the ISO’s anticipated CY21 schedule, specifically as it relates to whether the additional system deliverability upgrade (SDU) studies for projects will be complete by the 2023 class year’s (CY23) upcoming annual transmission baseline assessment (ATBA) lockdown.

The ATBA is the pre-existing baseline system, which is used to evaluate the addition of the CY projects and identify whether system upgrade facilities (SUFs) are necessary.

Certain stakeholders expressed that they were “unclear” about whether CY21 projects undergoing an additional SDU study would be included in subsequent class years or had “lost their opportunity to participate” in the next class year.

Mark Reeder, representing the Alliance for Clean Energy New York, gave a theoretical timeline of events, attempting to demonstrate how NYISO could not “know what your ATBA base case is if you lock it down” before all the additional SDU study projects in CY21 have accepted or rejected their cost allocations.

Thinh Nguyen, senior manager of interconnection projects, said that “if for some reason the additional SDU studies are not complete in time to join the subsequent class year,” then those projects will need to “pre-emptively request the ISO to join the subsequent class year.” The ISO will not automatically put CY21 projects undergoing an additional SDU study into CY23, and that “projects that don’t request” to be included in CY23 will see their additional SDU study “terminated” when the “subsequent ATBA is locked down.”

Developers who reject their project cost allocation will trigger additional decision rounds in which NYISO will issue a revised study within 14 calendar days that no longer includes those projects. Remaining developers will have an additional seven days to provide the ISO with notice of their election for the revised cost allocations.

This iterative process will continue until all remaining CY21 members accept or reject their cost allocations. Assuming it goes only one decision round, the ISO estimates CY21 ending on Dec. 2 and CY23 beginning on Jan. 3, 2023.

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PJM Stakeholders Reject Clean Energy Requirement for Board

CAMBRIDGE, Md. — PJM’s Members Committee on Wednesday rejected a proposal from the Illinois Citizens Utility Board to require that at least one member of the Board of Managers have clean energy qualifications.

The proposal would have amended PJM’s Operating Agreement to add a qualification that one board member “shall have expertise and experience in the development, integration, operation or management of clean energy resources.” The amendment failed with 32% support, well short of the two-thirds margin required in the sector weighted vote.

Albert Pollard of CUB told the committee in September that PJM’s board needs expertise in carbon-free generation as the grid transitions away from fossil fuels. 

“This is not a proposal to have a clean energy advocate on the board, and I would oppose such a thing,” Pollard said. “This is clean energy expertise. This is someone who, through their leadership, can work with the other experts on the board to call balls and strikes,” he said.

Paul Sotkiewicz of E-Cubed Policy Associates said the focus should be on promoting reliability rather than having expertise in any one form of generation, which he said would introduce potential bias and undermine the board’s independence.

“This would lead to some advocates on the board because let’s face it, everyone comes with some bias,” he said.

Pollard said the amendment would not change the composition of the board as there are currently sitting members who already meet the qualifications the CUB was seeking to add. During the MC’s first read of the proposal on Sept. 21, PJM CEO Manu Asthana and General Counsel Chris O’Hara clarified that the measure would not be adding a dedicated seat, but rather a qualification. (See “Board Member with Clean Energy Expertise,” PJM MRC/MC Briefs: Sept. 21, 2022.)

Adrien Ford of Old Dominion Electric Cooperative said that based on her experience on the nominating committee she believes the existing process is sufficient for determining the experience that would create the strongest board composition. Additional requirements would limit the committee’s flexibility, she said.

“The nominating committee really works to make sure we have the core expertise needed on the board [and] has the flexibility … to fill in what additional experience is needed on the board,” she said.

Jason Barker of Constellation Energy said the amendment would reflect the discussions at PJM’s Annual Meeting regarding the challenges posed by the clean energy transition. Ensuring that the board has expertise in the types of resources that will increasingly dominate the grid will be critical to managing reliability, he said.

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Transmission Conference Focuses on Reliability, Interconnection

WASHINGTON — Transmission stakeholders and federal regulators are concerned about extreme weather and clogged generator interconnection queues, but they’re also encouraged by FERC’s many proposed rulemakings to tackle those issues.

“We’ve probably had more headlines this year in MISO related to resource adequacy and the threat of outages than we’ve had in the last five years combined,” Scott Wright, the RTO’s executive director of resource adequacy and resource utilization, said at WIRES’ annual Fall Conference on Thursday. “The risk profile of the grid is changing significantly.”

Variability and uncertainty have always been a part of managing the grid, he said, but both have increased significantly and faster than expected. “So all of our thoughts and plans at MISO had to be reprioritized and changed.”

The two are related in a way: States are seeking to interconnect more renewables to address climate change, which is increasing the frequency of extreme weather events.

Eric Vandenberg 2022-10-27 (RTO Insider LLC) FI.jpgEric Vandenberg, FERC | © RTO Insider LLC

Eric Vandenberg — recently appointed deputy director of FERC’s Office of Electric Reliability, after serving as deputy director of the Office of Energy Policy and Innovation (OEPI) — gave a keynote speech focused on the threat of extreme weather. He stood in for Commissioner Willie Phillips, who could not attend because of a death in family, according to WIRES.

Vandenberg noted that several regions have come to the brink of load shedding just this year, including an early cold snap in MISO and an extended heat wave in California. “Looking forward, ‘extreme’ does not necessarily mean ‘rare,’” he warned.

Since the beginning of the year, FERC has issued several Notices of Proposed Rulemakings on transmission, including one on planning processes and cost allocation (RM21-17), and one addressing interconnection queues (RM22-14). Both came as a result of a wide-ranging Advance NOPR issued last year, the results of which the attendees of last year’s conference were eagerly anticipating. (See Transmission Industry Hoping for Landmark Order(s) out of FERC ANOPR.)

But FERC also issued proposed rules that would update NERC reliability standards and direct transmission providers to report on their policies for assessing their vulnerabilities to extreme weather. (See FERC Approves Extreme Weather Assessment NOPRs.)

Vandenberg said the NOPRs are designed “to raise that floor” of NERC’s standards “for instances of extreme weather” by making utilities address their vulnerabilities.

Meanwhile, “I don’t need to harp on the need for reform here with this audience; I think it’s pretty obvious to everyone that the interconnection queues are generally pretty backlogged,” said Tristan Kessler, an economist in OEPI. He noted the record number of projects submitted to MISO for interconnection just this year. (See MISO: Record 1,000 Interconnection Requests in 2022.) “So I’m excited to be at your fall 2032 panel to talk about interconnection issues as well.”

Amanda Conner, vice president of FERC and RTO strategy and policy at American Electric Power, asked Wright, Kessler and fellow panelist Cynthia Bothwell, an engineer in the Department of Energy’s Wind Energy Technology Office, whether the commission’s proposal goes far enough.

FERC’s proposed rulemaking on queues would create a first-ready, first-served model for interconnection, which has won wide support. But it would also impose stricter requirements on transmission providers in the form of penalties for failing to meet certain deadlines on completing interconnection studies; RTOs and utilities have not been particularly receptive to these.

Wright said “many things in the NOPR are spot-on,” but some “may not help with efficiency or may cause unnecessary work. … Is FERC going far enough? Well, they certainly proposed things related to very definitive penalties [to which] we would say, ‘Don’t go farther.’”

Bothwell answered that FERC “is doing a great job of getting that conversation going, but we know that the system is changing, and to get to this big transformation, it’s going to happen in steps. And we’re going to learn more … and need additional reforms down the road.”

“It’s definitely not the end of the process for us,” Wright said. “A lot of transmission providers have come to us and proposed other changes … and I think the commission is generally supportive of that.”