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November 18, 2024

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MISO Wants Hybrid Resources’ Separate Market Participation

CARMEL, Ind. — MISO says it is leaning towards a simple and existing method to handle the market participation of a growing number of combined battery storage and renewable energy resources.

The grid operator last week released a draft market participation model under which hybrid resources’ components will be required to register and participate separately by resource type.

MISO currently maintains two definitions for resources that share a point of interconnection: “co-located” or “hybrid.” While co-located resources participate in the market separately, hybrid resources would participate in the market as a single resource. (See MISO Prepares Hybrid Participation Model for Unknown Numbers.)

Bill Peters, a market design adviser for the RTO, told a Market Subcommittee meeting Thursday that there are advantages to requiring components of a hybrid resource to operate individually. He said renewables can still confidently use MISO’s forecasts for intermittent resources, and storage components of hybrid resources are free to clear as operating reserves. He said a single-offer hybrid participation limits MISO’s visibility into the capabilities of the multiple resource types that comprise the hybrid resource.

“As we learned from Ghostbusters, this will help prevent us from crossing the streams, which we know is bad,” Peters joked.

He said MISO’s proposal will prevent storage assets from being “shackled” to renewable resources and storage will be free to operate independently and “capture otherwise curtailed or clipped renewable generation.” Peters said resources sharing physical infrastructure already can be dispatched and settled separately.

The RTO has about 1 GW of hybrid resources projects that have executed generator interconnection agreements, though none are coming online over the next year.

MISO’s hybrid IC queue numbers may underrepresent the number of hybrids that eventually will materialize in the footprint. Staff has said interconnection customers sometimes request separate applications for the storage and generation components; others request surplus IC capability for storage that is added later. Clean energy advocates have been pressing MISO for several years to make its markets friendlier to hybrid resources.

Staff said that it is challenging to build a singular hybrid-participation model because any number of resource combinations are possible.

MISO is unable to provide forecasts for partial intermittent resources, Peters said, and wouldn’t know when hybrid resources are operating under a generation designation or a dispatchable intermittent resource designation.

Peters said MISO staff went over a “legal reading of the tariff” and found few clear answers as to how hybrid resources should participate in the markets. “It becomes clear that when a lot of answers are ‘maybe,’ that’s maybe not the best,” he said.

Peters said if MISO’s idea works well, it may “obviate” the need to work out a comprehensive participation model for hybrid resources.

“This may be the best way to operate these resources,” he said.

Peters said MISO might want to update software so it can create a “family relationship” to make sure resources are maintaining the megawatt limit of a shared interconnection point. Market systems currently lack the capability to manage shared interconnection limits.

Peters asked for stakeholders’ input on the “good, the bad and the ugly” of the proposal. They have until March 16 to weigh in.

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MISO Defends Energy Exports During December Storm

CARMEL, Ind. — MISO last week continued to defend its decision to export power to its neighbors that played a role in tipping the RTO into emergency procedures during the December winter storm.

Staff told stakeholders their emergency operating procedures allow MISO to deploy load-modifying resources to “assist neighbors who are in a comparable or worse operating state.” The RTO exported up to 5 GW at times Dec. 23 to SPP, the Tennessee Valley Authority, Associated Electric Cooperative Inc. and the Southeast planning region.

“So, we did meet that condition during [Winter Storm] Elliott,” John Harmon, senior director of operations support, said during a Reliability Subcommittee meeting on Feb. 28.

MISO entered a three-hour maximum generation event during Dec. 23’s evening hours. Staff and stakeholders debated the lengths the grid operator should go to assist neighbors at the expense of its own reliability and adverse pricing impacts. (See MISO Actions During December Storm Spark Debate, MISO Data Show Steep Gas-fired Outages During Winter Storm.)

Market design adviser Dustin Grethen said MISO was able to partly repay its neighbors after years of relying on neighboring regions’ exports during various maximum generation events.

“It’s good to know that we can sometimes step in and help others when it’s necessary,” he said during a Market Subcommittee meeting on Thursday.

The RTO experienced operating reserve deficits on Dec. 23 and hit its $3,500/MWh price cap during several intervals.  

MISO energy and operating reserve pricing (MISO) Content.jpgMISO energy and operating reserve pricing on Dec. 23 | MISO

 

“There was plenty of pain all around tied to the pricing,” Grethen said.

MISO Executive Director Market Operations J.T. Smith said MISO, PJM and TVA all missed on load forecasts “in pretty outstanding fashion.”

Smith said MISO’s Independent Market Monitor will likely propose that the grid operator create joint operating agreements with the TVA and other nearby non-RTO members so that it can hold its own load harmless from exports’ pricing impacts.

“I strongly support what MISO did, but I think there needs to be some way to make whole the load that was exposed,” Minnesota Public Utilities Commission staffer Hwikwon Ham said.

Grethen said high prices during the event drove higher settlements and thus “higher credit exposures,” but MISO was able to work with its market participants to avoid any defaults.

MISO said its credit team ultimately issued 101 exposure warnings. It issues such warnings when a market participant’s exposure is greater than 90% of its combined posted collateral and credit line.

The storm resulted in $23 million of price volatility make-whole payments charged to load-serving entities. That was offset by $54 million of revenue neutrality uplift credits because of revenue surpluses from load, unit and export deviations in the real-time market. A net uplift of $32.4 million was credited to load-serving entities in the footprint, distributed through a load ratio share. MISO uses its revenue neutrality uplift mechanism to balance charges and credits, ensuring it remains revenue neutral across operating hours.

The grid operator said it plans to improve how it communicates emergency alerts to its market participants. Some stakeholders complained they didn’t receive notifications until after the event unfolded.

Other than the December emergency, “winter continues to be mild,” Harmon said.

MISO averaged 75 GW of load in January, with load peaking at 93 GW Jan. 31. It had projected peak demands of 102 GW under typical winter conditions and 109 GW should an arctic blast descend on the footprint. (See MISO: Diminished Emergency Possibilities this Winter.)

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NY Regulators Get Comments on How to Speed up Tx Construction

The New York Public Service Commission’s work implementing the Accelerated Renewable Energy Growth and Community Benefit Act won praise in comments filed last week, but parties said much more work is required to increase the transmission capacity needed to meet the state’s clean energy goals.

The act was meant to improve and streamline the process for building renewable projects around the state. It included setting up a new Office of Renewable Energy Siting and to help speed up the development of needed transmission.

The Alliance for Clean Energy New York, New York Offshore Wind Alliance, Advanced Energy United and the Natural Resources Defense Council submitted joint comments saying that expanding transmission is critical to the cost-effective integration of renewables and praising the PSC for its actions so far. But they said the rate of transmission development needs to speed up to affordably meet the requirements of the Climate Leadership and Community Protection Act, which calls for a carbon-free grid by 2040.

“If not, renewable energy projects will be delayed, leading to the state not complying with the CLCPA mandates,” the groups said.

The PSC recently approved utilities spending $3.5 billion on 62 transmission upgrades meant to open up transmission capacity for renewables, but many of the projects will not be built until the end of the decade, or even beyond. (See NY PSC Approves 62 Tx Upgrades Totaling 3.5 GW.)

The longer it takes to build transmission, generator developers are more likely to price higher risk premiums into their offers for renewable energy credits (RECs).

“These risk premiums are necessitated by the uncertainty surrounding the developers’ ultimate cost obligation and local transmission owners’ construction time frames for system upgrades revealed through interconnection cost studies undertaken by the TOs and the NYISO,” the groups said.

Developers only get solid estimates of the transmission costs they face after they submit bids, which means they have to price such risks into their RECs. The groups argued that the PSC should ensure transmission is built before new power plants to limit those risks, which can work for both offshore and onshore resources.

EDF Renewables, which has built five projects in the state so far and has more in the pipeline, agreed, saying in its own filing that renewable projects will continue to experience congestion and curtailments until the new transmission infrastructure come online in 2029.

“Given the ambitious CLCPA targets throughout 2040, and the long lead time for transmission upgrades, it is critical that the state continues to explore effective transmission solutions and ensure they are approved in a timely manner,” EDF said.

Consolidated Edison (NYSE:ED) urged the PSC to continue leveraging local utilities’ expertise in expanding the grid to advance the state’s clean energy transition. Regulators should prioritize “multi-value projects” that connect clean energy to the grid while also improving reliability and cutting costs.

The utility wants the PSC to approve the “Coordinated Grid Planning Process” it recently filed along with the state’s other utilities. (See NY Utilities Propose Plan to Coordinate Decarbonization Efforts.) The proposal represents an end-to-end holistic process to identify and approve local transmission investments needed to achieve the state’s climate goals.

The four trade groups and EDF also want to see the CGPP approved, though they suggested changes including making it run every two years instead of three.

While the CGPP would help, the PSC should continue using NYISO’s Public Policy Transmission Planning Process to complement it and procure all the needed transmission to eliminate emissions from the power sector. EDF argued that the ISO’s process should be used to supplement the PSC’s 62-project package with infrastructure around the city of Watertown east of Lake Ontario and in the Southern Tier to ensure the grid can accommodate all of the new renewable projects being built.

LS Power urged the commission to avoid relying too heavily on the utilities, arguing that many of its actions implementing the law have lacked competition and transparency.

“As a result of [this] process, New York ratepayers will be responsible for billions of dollars of investment in transmission projects,” LS Power said. “Continued approval for the majority of this construction outside of a competitive process does not provide the best result for ratepayers.”

The commission should rely on competitive processes to build out the needed transmission because that has already benefited consumers in the state by lowering costs and accommodating more renewable generation, the company said. The PSC should look to maximize the use of existing NYISO processes and avoid approval of bulk transmission that does not come out of competitive planning processes.

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FERC Gives ISO-NE Homework on Order 2222

ISO-NE has work to do to make itself compliant with Order 2222, FERC said in an order late Wednesday (ER22-983).

Similarly to how it has responded to other RTOs’ compliance filings on the landmark rule requiring RTOs to open their markets to distributed energy resource aggregations (DERAs), the commission accepted some of ISO-NE’s effort and rejected other parts.

The order makes ISO-NE responsible for several follow-up compliance documents containing revisions, with various deadlines between 30 and 180 days.

Renewable energy groups and others in New England had criticized ISO-NE for not going far enough to remove barriers for DERs to participate in wholesale markets, and some of those complaints were addressed by FERC.

“We find that ISO-NE has failed to demonstrate that its proposed energy and ancillary services market participation models for DERAs accommodate the physical and operational characteristics of behind-the-meter DERs, because behind-the-meter DERs participating under those participation models may be unable to provide all services that they are technically capable of providing through aggregation.”

The federal agency flagged ISO-NE’s choice to require measurement of behind-the-meter DERs at the retail delivery point for most DERs, rather than allowing sub-metering.

The commission sent back several other items for ISO-NE to revise or, in some cases, further explain.

ISO-NE had proposed five existing and two new models for DERs seeking to participate in the markets. (See NEPOOL PC Approves Tariff Changes for Aggregated DERs.)

FERC challenged the RTO’s requirement limiting the storage participation model — comprised of a binary storage facility or continuous storage facility — to load-serving entities (LSEs).

“ISO-NE fails to cite to any tariff provisions that establish this LSE requirement and therefore has not demonstrated that this LSE requirement is an existing requirement applicable to all resources in order to provide wholesale energy withdrawal service in ISO-NE’s energy market,” FERC wrote, requiring the RTO to explain it further as part of a 60-day compliance filing.

“The commission has given a pretty good overview of why ISO’s proposal isn’t reasonable and doesn’t meet the requirements of Order 2222,” said Caitlin Marquis, managing director of Advanced Energy United, the clean energy trade group that has been one of ISO-NE’s most vocal critics on the issue.

“One of our biggest issues with ISO’s filing is that it failed to accommodate behind-the-meter DERs, so I was pleased to see that the commission also felt that ISO had failed to accommodate the physical and operational characteristics of behind-the-meter DERs,” she said.

“We are pleased that the commission accepted most of our compliance filing, with a few things left to work on, which is common in these types of orders,” said ISO-NE spokesperson Matt Kakley. “We’ll be reviewing the decision and then responding as directed.”

Commissioners’ Commentaries

In a sharply-worded concurrence, Commissioner Allison Clements noted that the ISO-NE proposal was “almost universally panned by prospective market participants seeking to integrate behind-the-meter resources into its markets.”

She described the grid operator’s response as being especially deficient when compared to other RTOs, for example in its approach to submetering. She said that the other grid operators have figured out how to manage that question without blocking DERs from participating at all.

“ISO New England is like an architect declaring that it is impossible to construct higher than a 50-story building, even as competitors have already built the Empire State Building and Sears Tower, and are making plans for One World Trade Center,” she wrote.

She called on the grid operator to use its follow-up compliance filings to “roll up its sleeves and pursue a problem-solving approach to integrating behind-the-meter resources,” rather than “rigidly defend a status quo metering framework that stymies this critical opportunity to improve reliability.”

The commission’s two Republican commissioners both took the opportunity to bash Order 2222 itself: James Danly wrote that he dissented against it, and Mark Christie said he would have if he was on the commission at the time it was approved. But they took different approaches to the compliance filing, with Danly concurring with the majority and Christie dissenting.  

“I do not envy ISO-NE and NEPOOL the compliance task we imposed upon them. One hundred percent compliance probably is impossible in a first, or perhaps even second, attempt. We shall see,” Danly wrote, calling 2222 “intrusive interference into the administration of RTO markets and distribution-level systems.”

Christie offered a similar take.

“The problems and complexities of complying with Order No. 2222 are extreme,” he wrote. “This is no surprise to anyone who has studied Order Nos. 2222 and its progeny.”

He chastised the majority for taking issue with ISO-NE’s metering proposal.

“After all of the effort and expense invested by ISO-NE and all of the various state entities and market participants, to require even more detail on the compliance proposal when the record makes clear to me that the proposal has met the requirements imposed by Order No. 2222, is not something I can support,” Christie wrote.

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MISO Foresees Uneventful Spring Operations

CARMEL, Ind. — MISO said a spring under typical demand and generation outages shouldn’t prove much trouble.

That’s according to the RTO’s annual spring capacity outlook, which finds that its firm resources should be enough to cover peak demand in March, April and May.

Executive Director Market Operations J.T. Smith said MISO is well-positioned for spring operations coupled with generator maintenance season.

“System conditions look like we’ll be fine, even with higher load,” Smith told stakeholders at a Market Subcommittee meeting on March 2. “Overall, it’s looking like it’s going to be a pretty normal spring adventure.”

However, the grid operator acknowledged that a slim chance of simultaneous high load and high generation outages may “strain system conditions in April and May.”

MISO said it anticipates about 90 GW of peak demand in March with 109 GW of generation available to it and demand peaking around 84 GW in April with 102 GW available.

MISO doesn’t expect peak load to reach 100 GW until May; it predicts it will have 110 GW worth of probable capacity on hand by then.

But MISO said a more unlikely high outage, high demand scenario could result in a 92-GW peak demand in April with only 89 GW readily accessible or a 109-GW peak in May with about 105 GW available. In both cases, MISO would likely declare a maximum generation emergency so it can call up some of its 13 GW of load-modifying resources and operating reserves.

MISO’s spring maintenance season normally crests in April at an average 41 GW of generation unreachable. The RTO, however, contemplates outages up to 54 GW in its high-risk scenario.

MISO relies in part on the National Oceanic and Atmospheric Administration for its seasonal outlooks. The agency is forecasting normal temperatures in the RTO’s North region and normal to above normal temperatures in the Central region. MISO South is set for a greater chance of warmer temperatures.

NOAA also predicts an active precipitation pattern for most of MISO Midwest through May.

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SPP Moving Quickly on Markets+’s Development

SPP said Thursday that it has executed eight funding agreements with Western Interconnection entities for the first phase of its Markets+ energy market, clearing the way to begin its development a month early.

The entities serve more than 250,000 GWh of net energy for load (NEL) annually in the Western Interconnection, representing more than 40 GW of peak demand. Their resource mix is heavy on hydropower (48%), followed by natural gas (21%) and nuclear (14%).

Markets entities fuel mix (EIA) Alt FI.jpgMarkets+ entities’ fuel mix | EIA

 

Those signing agreements with SPP were Arizona Public Service, Bonneville Power Administration, Chelan County (Wash.) Public Utility District, NV Energy, Powerex, Puget Sound Energy, Salt River Project and Tucson Electric Power.

SPP said several nongovernmental organizations, public interest organizations, power marketers and other interested stakeholders have signed similar agreements with the RTO. Parties can continue to sign agreements through April 1 and be able to participate in forming the Markets+ stakeholder process.

The grid operator has already begun Markets+’s first development phase, which had been scheduled to begin April 1. During this phase, staff will work with potential market participants and other stakeholders to draft tariff language and protocols and to establish the governance structure’s main components consistent with its final service offering before filing them with  m.

A formal kickoff for the first phase has been scheduled for April 18-19 in Westminster, Colo.

SPP had defined the project’s critical mass as 150 GWh of NEL and at least two contiguous balancing authorities.

Paul Suskie 2022-06-22 (RTO Insider LLC) FI.jpgPaul Suskie, SPP | © RTO Insider LLC

“We had a minimum goal of who would sign up for phase 1. We have exceeded that goal,” SPP General Counsel Paul Suskie said at the Energy Bar Association Western Chapter’s annual meeting in San Francisco on Thursday.

He also told the audience that the amount of load signing for the first phase would exceed SPP’s existing RTO footprint. The grid operator set a new peak demand mark of 51.1 GW last July.

“Reaching critical mass for phase 1 participation is a monumental step in bringing Markets+ closer to reality,” CEO Barbara Sugg said in a statement. “A regional market will mean reduced costs for members, improved reliability, improved grid efficiency, increased trading opportunities and progress toward renewable integration goals. … We look forward to continued collaboration in the months ahead.”

“We’re excited about the potential benefits that Markets+ could generate for our customers,” Erik Bakken, Tucson Electric Power’s vice president of energy resources and chief sustainability officer, said in a statement. “Expanding market options in our region can improve our ability to integrate renewable resources without compromising reliability.”

During a regularly scheduled web meeting shortly after the announcement, SPP staff said they have begun work to compress the first phase’s 21-month timeline down to 12, as requested by several Western participants. Options include staff drafting the governing rules rather than beginning the process within the working groups; leverage “boilerplate” market-design elements where possible; and identifying design elements that can be postponed to the second phase or later.

“We’ve been looking hard at the phase 1 scope that came out of the final service offering,” SPP’s Carrie Simpson said, “and trying to identify ways to reduce the scope but also still delivering the product everyone wants, just in a much faster timeline.”

Compressing the timeline would mean filing at FERC in the first quarter next year, rather than the fourth.

Mark Holman, a managing director with Powerex, said his organization is a strong proponent of “go-faster, get-there-sooner.”

It’s “great to see the announcement today and that we’re getting going on this phase early. I think 12 months is reasonable,” he said.

SPP has budgeted $9.7 million for drafting the tariff and protocols and filing them at FERC. Accelerating the work will only accelerate the spend, Simpson said.

The grid operator has proposed Markets+ as a day-ahead and real-time market that helps Western utilities not yet ready for full RTO membership to centralize unit commitment and dispatch. SPP is also developing its RTO West market on another track.

Suskie told the EBA meeting that he thought RTO West would be implemented first, noting that Markets+ is a novel program. Because FERC is familiar with the RTO concept, he said, its approval of the latter could come sooner.

Hudson Sangree contributed to this report from San Francisco.

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NRC OKs Exemption to Keep Diablo Canyon Running During License Renewal

The Nuclear Regulatory Commission on Thursday approved Pacific Gas & Electric’s (NYSE:PCG) request to keep Diablo Canyon Power Plant’s two reactors running past their license expirations in 2024 and 2025 to address reliability concerns.

NRC regulations require that owners of nuclear plants file applications to extend their licenses five years before expiration. But citing the “public interest,” the NRC granted PG&E an exemption allowing it to continue operating the reactors beyond their license expirations as long as it files new extension requests by the end of this year. The agency will continue its regular inspections of the facility while the extension is in place.

Diablo Canyon, the state’s last nuclear generator, produces 2,300 MW of power — the largest source of emissions-free power in California.

The utility had started the renewal process in 2009, but withdrew its application, based partly on the state officials’ determination that the plant would not be needed to meet future demand for electricity. The California Public Utilities Commission approved its decision to retire the power plant in 2018.

PG&E sought to reopen that process after a law passed last year reversed the PUC’s decision, but NRC denied the request in January, saying PG&E must open a new license renewal case. (See PG&E Must Seek New Diablo Canyon License.)

“We are pleased the NRC approved our exemption request,” PG&E Senior Vice President and Chief Nuclear Officer Paula Gerfen said Thursday. “Aligned with Senate Bill 846, PG&E will continue on the path to extend our operations beyond 2025 to improve statewide electric system reliability and reduce greenhouse gas emissions as additional renewable energy and carbon-free resources come online.”

In August 2020, California saw its first rolling blackouts since the energy crisis of 2000-1, as demand spiked during extreme temperatures. It came close to losing power late last summer in another heat wave.

The state has lost other resources — mainly natural gas plants — because of its restrictions on once-through cooling, a technique also used by Diablo Canyon. Once-through cooling draws water from the ocean to cool the steam used to turn the plant’s turbines, which is then discharged back into the sea — raising temperatures enough to damage the local environment.

The California Energy Commission earlier this week unanimously voted to approve a report finding Diablo Canyon would be needed until 2030. If granted, the NRC’s license extensions would give the plant another 20 years of operations.

The California PUC has approved procurements of 22,241 MW of new capacity through 2028, largely solar and batteries, which the CEC found would be enough to meet the minimum reliability standards for the rest of the decade.

“However, there are uncertainties both in the ability of California [load-serving entities] procuring sufficient resources to meet the current ordered procurement and the determination that procurement would be sufficient to ensure reliability in extreme events,” the CEC’s report said.

For the state to stay on schedule, the PUC’s procurements would need to be rolled out at a pace never seen before. That might be possible, but the industry is also contending with supply chain risks and could see projects delayed in the permitting process, the CEC said.

The potential delays add to concerns over the extreme weather that California has seen increasingly in recent years.

The CEC said the state might not have sufficient capacity to maintain reliability in a coincident event, “such as a West-wide heat event resulting in unprecedented load and greater competition throughout the West for available resources, extreme drought impacting hydroelectric output, and one or more wildfires impacting transmission. …

“These dynamics are not just impacting California,” the CEC added. “The Western states as a whole are seeing tighter availability of resources, causing increased competition for existing resources, as well as related costs, making resources such as imports harder to come by. Given California’s historical dependency on imports to meet resource adequacy, the dynamics of the Western states’ resource adequacy market issues pose additional risk to maintaining reliability.”

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NJ Outlines OSW Research Projects amid Ocean Enviro Anxiety

A presentation by New Jersey officials on the planned expenditure of $26 million in developer contributions to monitor the impact on coastal marine life from the state’s offshore wind farms drew skepticism Monday from ocean environmentalists worried that the projects are advancing too quickly.

Representatives of the New Jersey Board of Public Utilities and the state Department of Environmental Protection said the Offshore Wind Research & Monitoring Initiative (RMI) has already approved 11 projects for funding, some of which have started. The program, jointly administered by the two agencies, is funded with contributions of $10,000 for each megawatt of capacity from the two projects approved by the BPU in the state’s second OSW solicitation.

The approved RMI projects include studies of passive acoustic monitoring for whales, acoustic telemetry for commercial and recreational fish, and the socioeconomics of recreational fisheries, officials from the BPU and DEP told a 90-minute hearing convened to solicit stakeholder input. The agencies said they are seeking stakeholder input on how to spend the money, which is contributed by the Ocean Wind 2 and Atlantic Shores projects, and what issues should be prioritized.

Another approved project studied the surf clam sector, which is concerned that its business will be dramatically impaired by the turbines. In that case, project researchers helped design a new, smaller clam dredge that could maneuver between the turbines than the larger traditional dredge. A list of eight additional projects that are under discussion but have yet to get the greenlight include a project to tag sea turtles and study their biological health; a study of the impact of turbine foundations on the Cold Pool area of the Jersey Coast; and an initiative to conduct tagging of whales for satellite monitoring.

The hearing unfolded as the first of the state’s three approved OSW projects, Ocean Wind 1, faces opposition from local residents, the commercial fishing sector and local governments. Meanwhile, the BPU is preparing to increase the state’s wind portfolio. According to its agenda, the board will consider whether to approve the opening of a new round of solicitations, which is expected to be larger than the first two.

Renee Reilly, a DEP research scientist, said a team from both agencies compiled the list by identifying potential impacts to marine life, assessing whether each would have a significant impact, and working with “regional research entities and subject matter experts to develop project concepts” and plans to execute them.

The agencies are trying to ensure the program has a “rigorous scientific approach” that meets “our mandate to protect and responsibly manage New Jersey’s coastal and marine resources” while also responding to climate change and protecting the area economy and environment for the future, she said.

“This really is a balance of developing something that’s going to help in the long term [while] ensuring that we’re doing it in a responsible way,” she said, encouraging hearing attendees to “understand how delicately we have tried to balance those two needs.”

Baseline and Potential Risk

Several speakers, however, focused on why the OSW projects are advancing to construction when the impact studies are still in the infant stage.

“We do feel that there is too much too fast, and that the scope, scale and magnitude is reckless at this stage,” said Cindy Zipf, executive director of Clean Ocean Action, referring not only to New Jersey’s projects but others along the East Coast. “We feel that actually that the baseline studies that need to be completed haven’t really even been identified completely. There was obviously a list, but there are many, many more that are needed.

“It’s so critically important for us to have a real sense of what the baseline studies are and what the potential risks are — not project by project, but cumulative — in order to determine what the next phase of study should be done for construction,” she said, adding that that phase is going to “have a much greater impact on the marine environment.”

Swarna Muthukrishnan, water quality research director for Clean Ocean Action, said that only seven of the approved RMI projects have started, and she has been unable to get much sense of their progress, outcome and how the results will be evaluated.

“There are many data gaps,” she said. “My big concern is how can permitting decisions be made accurately if this information, the fundamental information, are lacking.”

The debate over the offshore wind projects has highlighted a split in the state’s environmental community. About half the nine or so speakers at Monday’s hearing were tied to Clean Ocean Action, which has deep concerns about the projects. But most other environmental groups, none of whom spoke at the hearing, vigorously support the projects, seeing it as a key plank in the fight to head off climate change.

Whale Death Impact

New Jersey has approved three offshore wind projects in two solicitations: the 1,100-MW Ocean Wind 1 in the first, and the 1,148-MW Ocean Wind 2 and 1,510-MW Atlantic Shores in the second. The third solicitation could award between 1.2 and 4 GW, and perhaps higher, according to the BPU’s solicitation guidance document.

The agency on Feb. 24 released a new request for stakeholder input for the third solicitation, seeking comments on various issues to be addressed in the final guidance document, including timeline details and aspects of the financial and investment commitments that developers should make for their project.

Ocean Wind 1 has received the most public scrutiny. The BPU on Feb. 17 approved the second of two easements sought by Denmark-based Ørsted on which to run cables from the project offshore through Ocean City on the Jersey Shore to connect with a sub-station nearby. The property owner of the land at issue in one of the easements, Cape May County, opposed the approval and released a statement a week later saying it is reviewing the BPU’s decision “and will likely be appealing to the Appellate Division of the Superior Court shortly.” (See NJ BPU Grants Second Easement for OSW Project.)

“The county is not opposed to wind-generated electricity, but there is too much at stake not to take the time to get it right,” the county’s attorney, Michael J. Donohue, said in a statement that urged the BPU to pause the projects until “the interests of all stakeholders, including all of our local tourism businesses and fisheries, are addressed.”

Donahue also cited the deaths of at least nine whales washed up on the New Jersey shores in recent months, which project critics have highlighted as a reason to conduct more study of the impacts of the projects before they go ahead. They have mounted several protests against the wind initiatives, raising questions about the cause of the whale deaths and suggesting they may be related to preliminary sonar work on the offshore wind projects.

The mayors of 30 communities in the shore area have in recent weeks signed a letter calling for a moratorium on work on the projects and a federal investigation into whether the deaths are linked to the OSW work, according to local press reports.

Government researchers at the Marine Mammal Commission, an agency created by Congress to promote the conservation of marine mammals and their environment, have dismissed any ties to OSW, however. A note on the MMC’s website says that 16 humpback whales have stranded along the Atlantic Coast this winter, but “despite several reports in the media, there is no evidence to link these strandings to offshore wind energy development.”

“As the Gulf of Maine stock of humpback whales continues to grow, more young animals are choosing to overwinter along the Atlantic Coast where they are vulnerable to being struck by ships and becoming entangled in fishing gear,” the note said.

Still, speakers at the hearing on RMI studies said the deaths show the need for studies.

Donna Repoli, who said she is an independent researcher and a member of Clean Ocean Action, referred to the “whales experiencing mass mortality events” off the New Jersey Coast, and said the BPU and DEP should put a priority on the acoustic monitoring of whales.

“We are starting to see some actual problems arising with the marine mammal migrations right now as a direct result of surveying and sonar mapping from the wind farms,” she said. “I’m not against clean energy. But I think there needs to be a middle ground; there needs to be a way where we can do [OSW development] while causing the most negligible amount of risk to the environment and the local wildlife as possible.”

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FERC Approves $147K Penalties in SERC, RF

FERC approved penalties on Thursday totaling $147,000 against University Park Energy of Illinois and Broad River Energy of South Carolina, as part of a package of settlements concerning violations of NERC’s reliability standards filed in NERC’s monthly spreadsheet Notice of Penalty (NP23-11).

The commission indicated in a filing that it would not further review the settlements that the utilities reached with ReliabilityFirst and SERC Reliability, respectively, leaving the penalties intact. FERC also approved a settlement concerning an infringement of NERC’s Critical Infrastructure Protection (CIP) standards filed along with the SNOP on Jan. 31 (NP23-10); the utility and regional entity involved were not identified, in keeping with NERC and FERC’s policy on CIP violations.

Broad River Settles Over Communication Issues

SERC’s settlement with Broad River stems from violations of VAR-002-4 (Generator operation for maintaining network voltage schedules) and PRC-005-1b (Transmission and generation protection system maintenance and testing). The settlement carries a $115,000 penalty.

Broad River brought the VAR-002-4 violation to SERC’s attention via a self-report, though SERC noted that the utility submitted the report only “after receiving notice of an upcoming spot-check” and the RE thus did not consider the report a mitigating factor. Similarly, mitigating credit was denied for the report of the PRC-005-1b violation because Broad River “reported the violation through the self-certification process.”

According to the filling, SERC had planned the spot-check to begin Oct. 21, 2019, and asked Broad River ahead of time for proof of VAR-002-4 compliance between Aug. 1, 2015, and Oct. 18, 2019. The utility ran a complete voltage profile for the entire period, matching it against the generator voltage schedule provided by the transmission operator (TOP); requirement R2 of VAR-002-4 requires generator operators to maintain the TOP’s schedule or inform the TOP why it cannot be met.

Examining the voltage schedules, Broad River identified 419 events in which its generator facility “was outside of the voltage schedule for 30 minutes or longer.” Operators only notified the TOP about 57 of these excursions, a violation of the standard.

SERC determined that the violation began on Aug. 5, 2015 — the first time the utility experienced an excursion and failed to notify the TOP — and ended March 7, 2019, the last time such an event occurred. The RE attributed the violation’s cause to “inadequate communication between third-party plant and asset manager and senior management, and [between] plant management and employees responsible for compliance.”

The violation of PRC-005-1b — and its successor PRC-005-6 (Protection system, automatic reclosing, and sudden pressure relaying maintenance) — relates to requirement R2 of the earlier standard and R3 of the latter, which describe the minimum maintenance activities timelines for protection systems and the acceptable evidence for completion of the activities.

Broad River informed SERC on June 11, 2020, that it could not confirm it had completed all required testing under PRC-005-6. The utility said that while the previous operator of its generation facility had a schedule for performing the tests, Broad River did not have documentation that they actually had been done.

To assess the extent of the noncompliance, Broad River performed a complete walkdown of its facility and found 435 devices that were included under the standard’s requirements but for which it did not have proper evidence of testing. In some cases, the lack of supporting documents began as early as Dec. 27, 2012, the date it registered as the operator of the facility; as a result, SERC determined that the violation spanned the earlier standard as well.

To address the noncompliance, the utility tested all devices for which it had no records; the final test was completed on Nov. 5, 2021. SERC concluded that the cause of this violation — as with the VAR-002-4 infringement — was organizational silos that prevented adequate communication between parties responsible for compliance.

The RE said it aggravated the penalty for both infringements based on “the number of instances and long duration for the violations [which] indicated the prior management’s ignorance of the violations.” However, it did award mitigating credit for cooperation and timely responses, and because Broad River agreed to settle, “thereby avoiding a hearing on this matter.”

RF Faults Utility for Maintenance Schedule Slips

University Park’s $32,000 settlement with ReliabilityFirst involved PRC-005-2 (i) (Protection system maintenance). Requirement R3 of the standard establishes the schedule by which transmission owners, generation owners, and distribution providers must maintain their protection system components.

The utility informed ReliabilityFirst on May 15, 2020, that it had discovered, as part of a third-party review of its NERC compliance program, that “not all components were being maintained/tested, or maintenance and testing activities were not being documented, as required.” The problem encompassed multiple classes of equipment at its generator facility.

University Park attested that the violation began on Oct. 1, 2015, when the facility was required to comply with the standard, and continued until May 21, 2021, when it completed its mitigating activities. These included developing a preventative maintenance work plan to “identify the maintenance required and its frequency for all applicable equipment.” The utility also reviewed the violation with all applicable staff members.

The RE said it awarded mitigating credit to the utility for coming forward voluntarily because it “seeks to encourage this type of self-reporting.” However, it also noted previous compliance issues with PRC-005-1, saying this should serve as an aggravating factor in the penalty because the utility “failed to sustain the mitigating actions … in response to those prior issues.”

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DOE Opens IIJA Nuclear Credit Program to Recently Closed Plants

A closed nuclear plant in Michigan could be eligible for federal funding to help it reopen under new guidelines for the second round of the Civil Nuclear Credit Program that the U.S. Department of Energy released Thursday.

Authorized by the Infrastructure Investment and Jobs Act, the program received $6 billion to be used to help existing plants at risk of closure stay online. The first round of funding was limited to plants that had publicly announced their intention to close, ultimately awarding up to $1.1 billion to the Diablo Canyon nuclear plant in California, which had been scheduled to close in 2025.

The plant has now received permission from the Nuclear Regulatory Commission to stay open beyond that date. (See related story, NRC OKs Exemption to Keep Diablo Canyon Running During License Renewal.)

The second round, which could provide up to $1.2 billion in credits, will be open to “owners or operators of nuclear reactors that are at risk of closure by the end of the four-year award period, including such reactors that ceased operations after Nov. 15, 2021,” according to a DOE press release.

The four-year award period runs from Jan. 1, 2024, to Dec. 31, 2027. The Nov. 15, 2021, qualifying date is the day President Biden signed the IIJA into law. The 800-MW Palisades Nuclear Generating Station on Lake Michigan, west of Kalamazoo, is the only U.S. nuclear plant that has closed since that date.

“Preserving the domestic nuclear fleet is critical to reaching America’s clean energy future,” Energy Secretary Jennifer Granholm said in the press release. “Expanding the scope of this [IIJA] funding will allow even more nuclear facilities the opportunity to continue operating as economic drivers in local communities that benefit from cheap, clean and reliable power.”

The U.S. nuclear fleet now includes 92 plants that provide about 20% of the country’s electric power and 50% of its carbon-free power. Thirteen other plants, including Palisades, have closed in the past decade, according to a recent report from the National Association of Regulatory Utility Commissioners.

Many plants still in operation were built in the 1970s and 1980s, and either face decommissioning or must be recommissioned to extend their licenses. They have also faced competition from cheap natural gas and renewables that have made them economically difficult to keep in operation.

Illinois, New Jersey and New York now provide zero-emission credits to help keep their nuclear plants online.

Dollars for Nukes

Maintaining and expanding the U.S. nuclear fleet has become a critical part of the Biden administration’s strategy for decarbonizing the U.S. electric grid by 2035. In addition to the CNC program, the IIJA includes close to $2.5 billion for DOE’s Advanced Reactor Demonstration Program to support the deployment of two advanced reactors within a seven-year time frame.

The Inflation Reduction Act offers nuclear developers either a 30% investment tax credit or $30/MWh production tax credit, according to the NARUC report.

DOE’s Loan Program Office has also provided ongoing support for the two reactors still waiting to go online — six years late and extremely overbudget — at Southern Co.’s Vogtle plant in Georgia. The plant received a total of $12 billion in loan guarantees: $8.3 billion during the Obama administration and another $3.7 billion during the Trump administration. (See Making the Case for Nuclear at NARUC.)

Echoing Granholm, Matt Crozat, executive director of of strategy policy development at the Nuclear Energy Institute, welcomed the new CNC guidelines, saying they would create “more opportunities for the current fleet to apply to for the [program].”

The CNC and other federal funding will, Crozat said, “provide a strong financial foundation for the continued investment into these nuclear plants.”

The CNC is a more targeted program, with $1.2 billion in credits per year for five years, beginning in 2022 and ending in 2026. According to a DOE fact sheet, to qualify for the program, an owner or operator must “demonstrate that the reactor competes in a competitive electricity market and that DOE, to the maximum extent practicable, must determine that a reactor is projected to cease operations due to economic factors, that air pollutants will increase if the reactor retires and that the U.S. Nuclear Regulatory Commission has reasonable assurance that the reactor will operate consistent with its current licensing basis and that it poses no significant safety hazards.”

For last year’s funding cycle, DOE required applicants to have publicly announced the closure of a plant and provide official documentation such as a filing with the NRC or Securities and Exchange Commission. This time around, the guidelines simply require applicants “to provide a narrative explanation, with supporting documentation, of the likelihood that a nuclear reactor operating as of Nov. 15, 2021, is projected to close (or has ceased operations).”

Qualified applicants also submit bids for the amount of credits they are seeking, based on the difference between a reactor’s costs to operate and its revenues. Credits are paid annually at year-end, with the amount depending on a reactor’s actual output. For example, Diablo Canyon will qualify for amounts ranging from $266 million to close to $289 million per year for the next four years, according to DOE figures.

Palisades changed owners just as it was closing, with former owner Entergy selling the plant to Holtec International, a company specializing in providing parts for nuclear plants. Holtec applied for CNC funding in the first round but was turned down.

In a Dec. 19 Facebook post, the company announced its determination to reapply for the second round of CNC funding.

“The repowering of Palisades is of vital importance to Michigan’s clean energy future,” it said. “As Michigan transitions from fossil fuel generation to renewables and emerging advanced technologies, baseload nuclear generation is an essential backstop. Based on the supportive feedback we have received, Holtec will be reapplying for the next round of funding through the U.S. Department of Energy’s Civil Nuclear Credit Program to support the repowering of Palisades.”