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November 15, 2024

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NJ BPU Updates Proposal for Storage Incentives

New Jersey’s Board of Public Utilities (BPU) on Nov. 7 released an update to its proposed Storage Incentive Program (SIP) that changes how the subsidies for utility-scale, or “grid supply,” projects are determined as the state shoots for 2,000 MW of total capacity by 2030.

The proposal is a revision of a draft released in September 2022. It retains the original version’s segmented structure, with different incentives for grid supply projects and those behind the meter. (See NJ Seeks Stakeholder Input on Pending Storage Program and New Jersey Offers Plan to Boost Lagging Storage Capacity.)

But the original version would have paid utility-scale projects through an “administratively determined fixed incentive plus performance incentive structure” based on the amount of carbon emissions abated through their operation. In the new version, “grid supply energy storage systems will be awarded fixed incentive payments through an annual competitive bidding structure.”

“Grid supply storage resources will initially receive only a fixed upfront incentive, as the [program] will defer an avoided emissions-based performance mechanism until suitable datasets become available,” the proposal says.

The grid supply segment would be launched early in 2025, while the BTM incentives, to be set administratively by the BPU, would begin in 2026.

According to the proposal, the board based its decision to change the structure in part on “the number of storage projects that have remained in the PJM interconnection queue following the imposition of stricter readiness requirements.”

Under the competitive structure, “the board would release a solicitation with the specific amounts, or ranges of amounts, being sought for a given fiscal year. The solicitation would ask participants to identify the level of fixed incentive needed to support project revenue requirements,” the proposal says.

Another change is that the fixed payments for both segments would be paid upfront, as soon as the project begins commercial operations, rather than spread out over 10 to 15 years as was stipulated in the previous proposal.

“Upfront incentives provide a lower level of risk to system owners and developers and reduce the overall administrative burden of the program,” the proposal states.

There will be a public hearing on the plan on Nov. 20.

The BPU’s goal is to encourage the development of storage systems that charge using clean, off-peak energy and improve system reliability. The proposal anticipates a reduction in costs as “New Jersey’s deployment of storage systems increases.”

“Energy storage resources are critical to bolstering the resilience of New Jersey’s electric grid, reducing carbon emissions and enabling New Jersey’s transition to 100% clean energy,” the proposal says.

A BPU spokesperson said the state currently has 560 MW of installed storage, but those projects will not be counted toward the 2,000-MW goal. And the proposed incentives will not be retroactive, according to the proposal. “Only energy storage projects placed into service after the date of the board order establishing this program will be eligible for incentives.”

BTM Incentives

Incentives in the distributed segment would be allocated using a “declining block structure,” in which the BPU would establish an initial capacity of storage sought, measured in megawatt-hours. Once that block is fully subscribed, the board would set a lower incentive for the next block, according to the proposal.

“If a block remains unsubscribed or under-subscribed, the board would have the option to increase the incentive,” according to the proposal. The system would give the BPU “flexibility to establish block sizes, reset incentive levels (if necessary) and adjust programmatic elements on an annual basis, as needed, to meet policy goals and budgetary considerations.”

To evaluate an appropriate incentive level, a consultant hired by the BPU conducted a “gap analysis” of the “revenue and savings potential of behind-the-meter storage projects for a variety of different building types, rate classes and tariffs associated with the New Jersey” utilities, according to the proposal.

The results showed a “consistent shortfall” of revenue of about $220 to $330/kWh, which amounted to between 37 and 47% of the cost of the systems. In response, the proposal suggests a starting incentive of $300/kWh for a small storage system (less than 100 kW) and $200/kWh for a medium project (100 to 500 kW). A large project (over 500 kW) would get an incentive of $150/kWh.

On top of that, distributed projects could get performance incentives, which would be awarded when they respond to dispatch events.

To further encourage developers to build in overburdened communities, the proposal suggests an additional incentive of $100/kWh for small, $67/kWh for medium and $50/kWh for large projects.

“Distributed storage plays an important role in reducing emissions and enhances the resilience of the electric grid — both important factors in meeting Gov. [Phil] Murphy’s environmental justice and equity directives,” according to the proposal. “Because distributed storage resources are customer-sited, energy storage projects serving overburdened communities will provide improved energy resilience to the local communities and may help offset ‘dirtier’ backup generation options during emergency conditions.”

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ISO-NE Updates Plans for Capacity Reforms for CCP 19 and Beyond

ISO-NE has reiterated its plans not to include in its capacity auction reform (CAR) project the development of ambient temperature modeling capabilities or a new simultaneous seasonal auction clearing engine. 

Presenting to the NEPOOL Markets Committee (MC) on Nov. 13, the RTO said it instead plans to consider these reforms for a second phase of work, targeting implementation after the 2028/29 capacity commitment period (CCP 19).  

The CAR project encompasses ISO-NE’s work to improve capacity accreditation, reduce the time between capacity auctions and CCPs, and break up annual CCPs into distinct seasonal periods. The initial CAR changes are intended to take effect for CCP 19, with more work planned for CCP 20 and beyond. 

In previous MC meetings, representatives of the generation and end-user sectors expressed interest in developing a simultaneously clearing seasonal auction format allowing bidders to incorporate annual costs into their seasonal bids. (See ISO-NE Refines Scope, Schedule for Capacity Auction Reforms.) 

Implementing simultaneous seasonal auctions “would require the development of a new clearing engine and new offer/bid parameters to allow resources to offer separately into each season as well as across the year,” said Chris Geissler, ISO-NE’s director of economic analysis. 

No other RTO has developed a comparable clearing engine, Geissler said, adding that it would be challenging to complete development in time for CCP 19.  

He noted that ISO-NE is still considering how to account for generators’ annual costs within a sequential seasonal format and “will spend time with stakeholders discussing competitive offer prices and mitigation … as part of the seasonal accreditation reforms.” 

Regarding ambient temperature adjustments, Geissler said ISO-NE will base capacity accreditation on resource performance at 90°F for the summer and 20°F for the winter and will model the effect of temperature on winter gas availability. However, the RTO is not planning to include any further temperature adjustments in the CAR project.  

Clean energy advocates have argued that ISO-NE should model correlated outages associated with ambient temperatures, noting that forced outages pose risks to the grid during periods of extreme cold weather.  

Geissler said the RTO is constrained by its modeling capabilities and “limitations in data availability related to audited, temperature-based output ratings for applicable resources.” 

Instead, ambient temperature adjustments have been added to the RTO’s post-CAR road map, which also includes consideration of a simultaneous auction clearing mechanism, he said.  

“Evaluating this as part of the post-CAR road map will allow the ISO and stakeholders more time to thoughtfully assess the various approaches to ambient temperature adjustments that could be considered, including the pros and cons associated with each approach,” Geissler added.  

Capacity Accreditation Concerns

Prior to the MC, the clean energy trade association Advanced Energy United, along with 12 renewable developers, issued a memo expressing concern that ISO-NE has not allotted enough time in the CAR project to reviewing the resource accreditation changes.  

ISO-NE had already completed substantial work with stakeholders on proposed capacity accreditation reforms prior to pausing accreditation discussions and broadening the scope of the project to include changes to the auction format. 

However, clean energy developers had substantial concerns about the accreditation framework at the time, as impact analysis results released prior to the pause showed a significant loss of revenue for battery storage resources. (See ISO-NE: RCA Changes to Increase Capacity Market Revenues by 11%, ISO-NE Capacity Accreditation Reforms Spur Energy Storage Concerns.) 

“We believe accreditation will continue to be the most complex and impactful piece of the CAR project,” the groups wrote.  

They advocated for stakeholder sessions in early 2025 to discuss resource adequacy modeling and marginal reliability impacts and called on ISO-NE to conduct its final impact analysis earlier in the process to provide time for more changes if needed. ISO-NE plans to resume accreditation work with stakeholders in late 2025, aiming to file the accreditation aspects of the CAR project with FERC in late 2026.  

“While we recognize that aspects of accreditation cannot move forward without an informed prompt and seasonal design, there are many aspects of the current accreditation framework that will remain relevant and applicable,” the groups added. 

Geissler said ISO-NE is still evaluating how accreditation in the CAR project will compare to the previous resource capacity accreditation (RCA) framework and said the RTO “will bring items related to accreditation to stakeholders as soon as they are ready for discussion” and “will prioritize explaining how the design is the same or how it has evolved since the RCA presentations.” 

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MISO to Devise Express Lane in Queue for Generation Projects that Keep Lights On

CARMEL, Ind. — MISO said it will design an expedited resource adequacy study process so generation projects in the interconnection queue that are needed for capacity sufficiency will get grid treatment sooner.

MISO Director of Resource Utilization Andy Witmeier said MISO “needs a way to get generation online faster” because its capacity forecasts warn of shortfalls within a few years. The RTO told stakeholders to expect more details in coming weeks on how it will expedite the queue approval process for generation needed for resource adequacy.

“We really need generators to get a [generator interconnection agreement] faster to get them online to meet resource adequacy needs that are coming in the next three to five years,” Witmeier told stakeholders at a Nov. 13 Planning Advisory Committee meeting.

MISO said the expedited avenue for RA projects would be a temporary measure and would be discontinued when MISO’s queue processing is cleaned up enough that urgent projects can reach the construction phase quicker. Witmeier said MISO may retire the study process sometime in 2028 or 2029, when queue processing might be closer to one year instead of the current three to four years.

MISO pledged to craft an express lane for priority generation projects after it finalized a proposal to place an annual megawatt cap on its interconnection queue cycles.

The queue cap proposal is set to go before FERC this month without an exemption for generation projects that state regulators deem essential to a solvent supply. Some regulatory staff have implied states cannot support a cap without a regulator exemption. (See MISO Queue MW Cap to be Filed Sans Regulator Exemption for RA Generation Projects.)

The regulator exemption “is not the solution that would get projects studied in a matter of months instead of years and get them started on building to meet those RA needs,” Witmeier said. He explained that the scrapped exemption only guaranteed RA projects’ entry into the queue and didn’t address the queue’s “accumulating backlog, or time it takes to do studies,” leaving critical generation projects languishing in the queue for three to four years.

Witmeier said MISO will ask stakeholders to suggest “the proper gates” that will get a generation project expedited treatment. He said MISO might consider projected zonal capacity deficiencies or known load growth.

“I myself want to limit this process to known, ready projects that need to be built,” Witmeier said.

Witmeier said the study structure could take a page from MISO’s expedited project avenue available to transmission projects that need to begin before MISO’s annual approval of its Transmission Expansion Plans (MTEPs). MISO also could use MTEP modeling to inform studies, he said.

Invenergy’s Arash Ghodsian asked if the resource adequacy fast track is a reaction to FERC’s Order 2023, which aims to streamline grid operators’ interconnection processes.

“It’s a reaction to reality,” Witmeier responded. He said MISO years ago aspired to shorten queue processing time down to a calendar year; instead, the sheer volume of projects coming in cycle after cycle has spawned numerous project dropouts, queue restudies and a wait time that can last as long as high school.

Ghodsian said he harbored concerns that the new framework might lead to “queue jumping on either interconnection customers’ side or the transmission owners’ side.”

Witmeier said MISO could limit eligibility to load-serving entities’ projects that need to be commercially operable in the next three to five years and are recognized by regulatory authorities as essential to resource adequacy.

MISO will host two stakeholder workshops on how it will craft expedited resource adequacy studies on Nov. 18 and Dec. 6.

At last count, project proposals in MISO’s queue totaled about 300 GW, and projects that have signed generator interconnection agreements but are still unbuilt have grown to about 57 GW.

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Public Utilities Urge DOE to Respect BPA’s Day-ahead Decision Process

The Bonneville Power Administration should be allowed to decide on a day-ahead market without outside federal interference, a group of Northwest publicly owned utilities (POUs) that favor SPP’s Markets+ told the U.S. Department of Energy in a Nov. 12 letter. 

The letter, addressed to DOE Deputy Secretary David Turk, seems intended to head off any DOE attempt to lean on BPA to either delay the agency’s May 2025 market decision or withhold its $25 million share of funding for the Phase 2 implementation stage of Markets+ as developments play out around the governance of CAISO’s Extended Day-Ahead Market (EDAM). (See Pathways Backers Express Confidence on Calif. Legislation.) 

“We respectfully request your support for BPA’s independent decision-making as it considers market options. Enabling BPA to act without external pressures will ensure its continued alignment with its statutory responsibilities and enduring mission to serve the Northwest,” the utilities said in the letter. 

As a federal power marketing administration, BPA is housed within DOE but self-funds its operations from the revenue it earns from selling low-cost power from Northwest’s extensive, federally owned hydroelectric system and operating around 70% of the region’s transmission. The letter’s signatories include the vast majority of BPA’s base of “preference” customers for that power, composed mostly of rural municipal utilities and public utility districts.

A representative for the signatories told RTO Insider the “primary intent” of the letter is “to remind DOE and the [Northwest] Congressional Delegation of the important role of BPA customers in BPA decision-making.”

“Although many are interested in BPA’s decision on markets and count themselves among BPA’s stakeholders, not all stakeholders are similarly situated,” the representative said in an email, which noted that BPA is unlike other taxpayer-funded federal agencies because it is “financed entirely” through funding from customers who have “invested heavily in the agency and the Federal power system to ensure that BPA can continue to provide power and transmission services to its customers and timely repay its Treasury obligations.”

“BPA’s customers – and not other stakeholders – will ultimately bear the economic consequences of BPA’s decisions on market participation,” the representative said.

The letter comes nearly two weeks after BPA released the results of a production cost model study conducted by Energy+Environmental Economics (E3) showing that, under most scenarios across multiple market footprints, the agency stands to realize significantly greater financial benefits from participating in CAISO’s Extended Day-Ahead Market (EDAM) than SPP’s Markets+. (See BPA Sticks to Markets+ Leaning Despite Study Showing EDAM Benefits.)  

BPA officials have played down the significance of those findings, saying production cost models don’t provide the full picture of market benefits that are harder to predict or quantify. 

While the officials noted the study results will weigh in BPA’s final decision, they’ve said they’re holding to a staff recommendation that the agency choose Markets+ over EDAM for more qualitative reasons, such as a governance framework independent from California state influence and a market design BPA contends is rooted in that independence — a stance causing increasing consternation among the Northwest’s EDAM supporters. (See Rising Tensions Evident at BPA Day-ahead Markets Workshop.) 

The Nov. 12 letter to Turk reiterates BPA’s perspective and elaborates further by pointing to “unforeseen” consequences the POUs could face from the agency’s decision. 

“While production cost models can offer some broad insights, they also suffer considerable deficiencies,” the letter says. “First, they are limited in scope because they cannot assess critical governance and market design risks that impact BPA’s long-term reliability and cost-effectiveness. Second, production cost models that rely on oversimplified inputs produce imprecise results, failing to capture the complete costs and benefits of day-ahead market decisions. A risk-informed governance evaluation is essential to protect BPA and its customers from unforeseen risks.” 

The letter reinforces another repeated contention by BPA officials: that the agency must continue to fund Markets+ so BPA — and the rest of the West — have two “viable” markets from which to choose.  

The POUs note that they have encouraged the agency to fund the next phase of Markets+ “as a prudent investment for BPA’s long-term strategic goals and the only path that aligns with BPA’s mission. Only Markets + offers both a competitive, independently governed structure and a fair market design alternative to CAISO EDAM.” 

New Angle?

The letter’s signatories also see an apparent longer-term benefit in two Western markets sitting side-by-side. 

“The existence of both Markets+ and CAISO EDAM fosters a competitive environment in which governance and market design can evolve in ways that will ultimately yield more balanced outcomes for Western utilities and their customers,” the utilities said. 

But the letter makes clear that for the POUs, the key element comes down to governance — and continued “autonomy” for BPA within a market framework.  

“Markets+ is uniquely positioned to support BPA’s autonomy while addressing these governance factors,” the letter says. “It also offers fair market design elements that ensure durable and equitable outcomes for BPA’s preference customers and the region. This has been evident throughout the development of Market+; stakeholders have adopted design elements that enable BPA to meet its statutory obligations yet remain accessible to all participants.” 

The letter appears to introduce an angle to the Western market debate that has not been publicly aired before: that BPA’s preference customers would reexamine its relationship with BPA if they are dissatisfied with the agency’s market decision. 

The letter contends that the publicly owned utilities “have been the foundation of BPA’s funding, entirely supporting the agency through rates” for 80 years.  

“This historic partnership has enabled BPA to fulfill its mission and meet statutory commitments to its customers, the region and the U.S. Treasury. BPA’s sensible stewardship of our investments that aligns with our communities’ needs is critical to our continued willingness to sustain the agency financially,” the utilities wrote. 

Asked whether that meant the POUs would seek alternative power supplies if BPA chose EDAM, a representative of the letter’s signatories said, “Not at all. The statement emphasizes the foundational role of BPA’s alignment with the priorities and needs of its preference customers in sustaining a strong, collaborative partnership.”

“It does not suggest that we are considering other sources of generation if BPA were to join EDAM. On the contrary, we are focused on ensuring the long-term stewardship of BPA’s resources for the benefit of our ratepayers for generations to come,” the representative said.

Seattle City Light, a POU and BPA preference customer that has publicly supported the agency joining EDAM rather than Markets+, told RTO Insider that it disagrees with the letter’s assertion that BPA customers will be better served in Markets+.   

Noting the results of the recent E3 study, the utility said in an email that “BPA’s analysis found that EDAM or opting for WEIM-only participation would result in considerably greater economic benefits than Markets+, and it is unlikely that Markets+ governance or market design will produce better outcomes.”   

“City Light continues to believe our customers are best served with an efficient, well connected and integrated market, and should not rely on misrepresentations about the risks of EDAM market design and governance to obscure the results of its economic analysis. BPA’s end-use customers deserve a day-ahead market decision that does not ignore the physics and economics of the grid, and the impacts on their rates,” the utility said. 

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White House Releases Plan to Triple US Nuclear Power by 2050

The Biden administration on Nov. 12 rolled out a new plan to triple nuclear power in the U.S. by 2050, with a multipronged strategy of building new large and small modular reactors, adding power to and extending the life of existing plants, and bringing recently closed installations back online.

The U.S. has 94 reactors in operation at 54 sites in 28 states, most of them built in the 1970s and 1980s, the plan says. But the Department of Energy estimates the country will need 200 GW of new nuclear capacity “to keep pace with future power demands and reach net-zero emissions by 2050,” according to a Nov. 12 blog accompanying the release of the report.

The White House wants to jumpstart a “nuclear deployment ecosystem” by getting 35 GW of new nuclear power online or under construction by 2035 and then build to a steady pace of deploying 15 GW per year in the U.S. and globally by 2040 ― targets the report calls “ambitious yet achievable.”

For example, the report notes that “uprating” existing plants ― increasing their capacity through plant upgrades and the use of advanced fuels ― could increase their power output by 10% to 20%. Other DOE research suggests building new reactors at existing plants could add 60 GW or more of new capacity.

DOE also supports the development of SMRs through its Advanced Nuclear Reactor Demonstration Program, which received $2.5 billion in the Infrastructure Investment and Jobs Act. The department’s Loan Programs Office in September announced a $1.52 billion loan to Holtec to support the reopening of the 800-MW Palisades nuclear plant in Michigan.

Nuclear currently provides about 20% of all U.S. power and close to half of its carbon-free electricity, and interest in the clean, 24/7 power that reactors produce has intensified as companies like Microsoft, Google and Amazon look for power for their hyperscale data centers.

In October, Google signed a first-of-its-kind contract to buy power from a series of SMRs being developed by Kairos Power, and Microsoft is partnering with Constellation Energy on the controversial reopening of a reactor at Three Mile Island. (See Constellation to Reopen, Rename Three Mile Island Unit 1.)

The report notes that “a diverse set of technologies” will be needed to meet the different needs of customers and calls for “customers with large power needs and carbon-free commitments to work creatively with utilities to help share project risks commensurate with resulting benefits of successful deployment.”

The Need for Standardization

The report also makes an argument for nuclear expansion as critical for national security.

The majority of new reactors built worldwide in the past decade have been either Russian or Chinese, the report says. “It is imperative that the United States and allied countries compete effectively to supply the world with clean and safe nuclear energy. Yet, countries abroad typically want new reactor technologies demonstrated in the supplier country before building them in their own country.

“Domestic deployments will enable exports and provide a pathway for the United States to regain leadership in the international nuclear energy market and supply chain.”

According to DOE, a majority of existing U.S. nuclear power plants could add up to 60 GW of new capacity with large-scale light water reactors. | DOE

A major challenge moving forward, for both large-scale and SMRs, will be overcoming investor and utility concerns about time and cost overruns, with the report calling for better standardization of reactor designs.

The existing U.S. nuclear fleet did not move down the cost and time curves “in large part because most plants were built with unique, bespoke designs,” the report says. “The 94 currently operating reactors in America represent over 50 different combinations of reactor types, nuclear steam supply systems, models, power levels, containment types and balance-of-plant architecture.”

The next generation of reactors “must feature greater standardization, along with integration of modern design, project management and construction techniques, and a wealth of lessons learned from past deployments,” the report says.

Out but not Down

Any plans by the Biden administration would appear to be moot given the incoming Republican administration, but nuclear energy is one of the rare points of bipartisan agreement, as exemplified by the passage of the Accelerating Deployment of Versatile, Advanced Nuclear for Clean Energy Act of 2024 (S. 870), signed by President Joe Biden in July.

The law aims to accelerate the licensing of new reactors with provisions that reduce licensing fees for SMRs and require the Nuclear Regulatory Commission to streamline licensing for microreactors and cut the timelines for licensing new reactors planned for existing plant sites.

The report lists 30 actions the U.S. government can take “within existing statutory authorities,” along with recommendations for industry and customers. The NRC has issued its own License Renewal Roadmap to streamline reactor relicensing, but the report encourages plant owners to coordinate with the commission on the timing of their relicensing applications “to produce a more consistent workload for NRC … and ensure resources are in place and priorities are shifted as necessary.”

The administration also is following through on a U.S. commitment to the Declaration to Triple Nuclear Energy made by more than 20 countries in 2023 at the 28th U.N. Climate Change Conference of the Parties (COP28) in the United Arab Emirates.

Speaking at COP29 in Azerbaijan on Nov. 11, White House Senior Adviser John Podesta acknowledged that President-elect Donald Trump would pull the U.S. out of the Paris Agreement again, but that would not stop states, cities and businesses from continuing their commitments to cut emissions to limit global warming to 1.5 degrees Celsius.

“The economics of the clean energy transition have simply taken over,” Podesta said in a White House release. “New power generation is going to be clean. The desire to build out next generation nuclear is still there. … The hyperscalers are still committed to powering the future with clean energy, including safe, reliable nuclear energy. … All those trends are not going to be reversed.”

Trade associations sought to focus on the economic and bipartisan appeal of nuclear in their reactions to the report.

“Nuclear generation is uniquely positioned to help the United States achieve our climate and national security goals, while creating a reliable energy system to meet growing demand,” said Maria Korsnick, CEO of the Nuclear Energy Institute. “We look forward to continuing to advance strategies that extend the lives of existing nuclear reactors, usher in a new era of advanced technologies and support a global marketplace for U.S. exports.”

While welcoming the report’s aggressive targets, Judi Greenwald, executive director of the Nuclear Innovation Alliance, said the “next steps are up to the incoming administration and Congress. We look forward to continuing bipartisan and public-private cooperation to build on our shared accomplishments and increase investment and innovation in the next generation of advanced nuclear energy.”

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NERC: Board’s 321 Authority on the Table for Cold Weather Standard

NERC Vice President of Engineering and Standards Soo Jin Kim on Nov. 12 said the ERO’s ongoing cold weather standards project could supply the next opportunity for the Board of Trustees to exercise its authority to streamline the normal stakeholder approval process. 

Speaking at a technical conference about Project 2024-03 (Revisions to EOP-012-2), Kim acknowledged “there’s a little bit of industry fatigue” around the effort. She was referring to the fact the cold weather standard is undergoing its second set of revisions after FERC approved the original version, EOP-012-1 (Extreme cold weather preparedness and operations), in 2023 and its successor, EOP-012-2, this year but ordered changes each time. (See FERC Orders Further Cold Weather Standard Modifications.) 

The deadline for the FERC-ordered revisions to EOP-012-2 is next March, but the replacement standard EOP-012-3 recently failed to gain industry approval in its first formal ballot period that concluded Nov. 5. The standard received 70 supportive votes from industry stakeholders but 129 negative votes with comments; 55 respondents either abstained or did not vote. The result was a segment-weighted 42.29% in favor of passage, well short of the two-thirds majority needed to put it before the board. 

A similar situation caused the board to invoke for the first time its authority under Section 321 of NERC’s Rules of Procedure at its last open meeting in August. On that occasion, the failure of PRC-029-1 to receive industry approval led the board to direct the Standards Committee to host a technical conference in September to hear industry feedback on the proposed standard. Convening a tech conference is among the options in the section available to the board if stakeholders do not pass a proposed standard directed by FERC or NERC. 

In the case of PRC-029-1, FERC had ordered NERC to develop standards governing inverter-based resources. (See “Board Invokes Standards Authority to Meet IBR Deadline,” NERC Board of Trustees/MRC Briefs: Aug. 15, 2024.) Following the conference, NERC used the input to revise the standard, and it subsequently passed a final ballot, which was submitted to FERC along with four other standards governing IBRs. 

Following the success of the new process, NERC indicated it might convene technical conferences for other projects that have faced difficult ballot processes, in hopes of proactively addressing stakeholder concerns. At this week’s conference, Kim said additional action — including another use of the Section 321 powers — has not been ruled out. 

“I have gotten a lot of questions with regard to [whether] this project [would] be a candidate for 321 action,” Kim said. “The answer is ‘yes.’ We do feel this risk is very critical, and this is one of those projects where, if we are at an impasse … would be a candidate for 321 recommendations.” 

Kim emphasized that NERC’s board has not made any decision about whether to invoke the Section 321 authority at this point and will “probably” not discuss the issue at its open meeting in December; the standard’s “next ballot will be the determining factor,” she added.  

She explained she wanted to be “very transparent” about the possibility of special action after NERC received feedback from industry that the ERO had not been forthcoming about its consideration of using Section 321 for the IBR standards.  

“I don’t want anyone to ever come back and say that we were not very upfront about whether or not this is a potential risk for us moving forward,” Kim said. “We are very concerned [about] making sure that industry is able to mitigate these risks with regard to certain timelines.” 

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SouthCoast Wind Nears Federal Approval with FEIS Release

The U.S. Bureau of Ocean Energy Management (BOEM) issued the final environmental impact statement (FEIS) for SouthCoast Wind on Nov. 8, bringing the project one step closer to final approval.  

The project’s construction and operations plan would allow for the development of up to 2,400 MW of power on a 127,388-acre lease area south of Massachusetts. Rhode Island and Massachusetts recently selected 1,287 MW of power from the project’s first phase of development in a coordinated solicitation. (See Multistate Offshore Wind Solicitation Lands 2,878 MW for Mass., RI.)

SouthCoast Wind developer Ocean Winds, owned by EDP Renewables and ENGIE, predicts that SouthCoast Wind 1 will come online by 2030. It recently received several key state environmental approvals from Massachusetts, where the project will interconnect to the grid. 

“Completing this environmental review represents another major milestone in the [Biden] administration’s commitment to achieving clean energy objectives that will benefit local communities,” said BOEM Director Elizabeth Klein. 

BOEM plans to publish the notice of availability of the FEIS in the Federal Register on Nov. 15. That will be followed by a 30-day waiting period before the agency can issue a final record of decision. 

The agency considered how the project proposal and several alternatives would affect local communities and the environment, qualitatively evaluating benefits and adverse impacts. BOEM conducted isolated impact analyses of the project alternatives as well as cumulative impact analyses, which evaluate project impacts within the context of outside stressors including climate change and other planned offshore wind projects.   

Regarding ecosystem and wildlife effects, the report found the proposal would have minor adverse impacts on local birds, bats and sea turtles, and moderate adverse impacts on benthic resources, coastal habitat and fauna, fish habitat, marine mammals and wetlands.  

The statement noted that the habitat of several endangered species of whale, including the critically endangered North American right whale, overlaps with the project area.  

To limit harms to marine mammals, BOEM identified a preferred project alternative that would remove six wind turbine generators (WTGs) from a part of the lease area adjacent to the Nantucket Shoals, which it wrote is “an area of high biological productivity.” 

“The removal of six WTGs in the northeastern edge of the lease area would reduce potential noise disturbance in turbine positions closest to Nantucket Shoals, thus decreasing associated risks to marine mammals, especially [North American right whales], that are known to use this area,” BOEM wrote, adding that the alternative similarly would reduce risks from vehicles in this area.  

BOEM found the preferred alternative would have a moderate adverse impact on whales, but noted the possibility of major adverse impacts on right whales due to the species’ small remaining population and the disproportionate impact a single death could have on the species’ viability. 

The agency found the proposal would lead to major cumulative impacts on the fishing industry, writing that “some fishing operations could experience long-term, major disruptions.” 

The proposal also would affect cultural resources and scenic resources and could have a disproportionate impact on Tribal Nations, BOEM said. The project’s construction also could cause an increase in local air and noise pollution, coastal land use challenges, increased vessel traffic and conflicts with the tourism industry, BOEM found.  

The no-build alternative — which accounts for the effects of climate change and the development of other offshore wind projects — also demonstrated many similar adverse effects, BOEM noted. 

For benefits, the agency found the project would bring employment opportunities and tax revenue associated with the offshore wind industry, port infrastructure improvements, and emissions and climate benefits for displaced fossil generation.  

Offshore wind industry representatives applauded the release of the FEIS, which came at the end of a turbulent week for offshore wind companies in the wake of the U.S. election. 

“With its final approval later this year, the U.S. market will have 11 commercial-scale projects either completed, under development, or ready to break ground, representing more American jobs and tens of billions of dollars in economic activity,” said Liz Burdock, CEO of the Oceantic Network. 

Burdock gave a nod to the first Trump administration for issuing SouthCoast Wind’s lease and emphasized the project’s potential economic and employment benefits.  

Trump took aim at the offshore wind industry in the leadup to the election, but offshore wind leaders hope the industry has enough momentum and support to survive Trump’s second term in office. (See Clean Energy Sectors Brace for Impact of Trump 2.0.) 

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Stakeholder Soapbox: AI, Electric Grid Can be Partners in Equitable Energy Transformation

By Colette D. Honorable

Artificial intelligence, once envisioned only in science fiction, is becoming commonplace in our offices and homes. Ironically, the AI-enabled features of a modern world — from internet searches to chatbots to digital assistants — are all powered by an energy system that has been going strong for over 100 years.

Just as AI may be the most significant technological advancement of this millennium, the energy grid was the most important engineering achievement of the last. It was built to last, and while the way the world produces power has evolved, how energy flows — from power sources then over poles and wires to our homes and businesses — is largely unchanged from when the system was designed.

What has dramatically changed is the demand on that system. Exelon has a number of high-potential data center projects in our pipeline that together would require 11 GW of additional load. To put that in perspective, 1 GW can power close to a million homes. As an example of the magnitude of data center development that already has taken place, in the Chicagoland area alone, Exelon helped launch 20 data centers over the past two years.

We have been modernizing and strengthening our energy grid to meet residential, small business and commercial customers’ electrification needs, and like much of the technology to which we have grown accustomed, the grid has gotten smarter and more complex. Our smart grid provides many benefits to our operations and customers, including the ability to automatically reroute power when there’s damage, improving reliability by shortening repair time and reducing customer outages.

As AI advances, it will bring even more benefits to the energy system that powers it, including predictive maintenance, bolstered cyber security and enhanced employee training. In turn, the grid will be more efficient, more reliable and better able to meet AI’s energy demands.

Exelon is proud to support the expansion of the data centers that house the computer systems, servers and storage needed to sustain AI. We see data centers as key partners, and we are committed to supporting their growth and development, while also meeting the increasing demands for sustainable and reliable electricity.

grid

Collette Honorable | Exelon

Recent proposals for co-location, a practice in which data centers are built next to a power plant, have gained attention, with FERC convening a technical conference on the subject Nov. 1 and rejecting as unsupported a precedent-setting interconnection agreement involving a data center and a nuclear generator. That agreement, which did not conform to standard terms, would have raised electricity bills for residential and other customers.

If data centers are connected to the grid — even if their first point of connection is a generator — they should contribute to the cost of the network infrastructure providing those services. Most data centers do just that. However, if co-located data centers are not recognized as network load, we estimate the annual electric bill for residential customers in the surrounding region could increase by up to $214.

Co-locating with an electricity generator also presents important considerations for the data center on how dependent they want to be on a single generator — rather than the entire electric grid — for reliable service. At the FERC technical conference, an advocate for co-location acknowledged this dependence may not be the best choice for a data center running defense critical services given the risk.

Co-location presents an opportunity to support the ongoing nationwide energy transformation and promote economic development in the communities we serve. We are proud that Site Selection magazine once again named two of our local energy companies, ComEd and PECO, to their 2024 list of the “Top 20 utilities in economic development,” based on the number of facility investment projects attracted to their service areas, the capital investment and potential for job creation.

We also agree with the Biden Administration’s desire to operate data centers within U.S. shores, mitigating concerns about foreign control of these critical assets. It is important then to understand and be clear: this effort can and will continue, and we will help facilitate it.

We are committed to continuing our work with data centers to meet their needs, no matter where they are located. And, even with demands that far exceed what the energy pioneers may have envisioned, the energy grid of today is ready to meet the moment, just as it was a millennium ago.

Exelon looks forward to continuing to lead the energy transformation, with future generations in mind, in a way that is equitable for all our customers and communities.

Colette D. Honorable is Exelon’s EVP of public policy and chief external affairs officer.

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MISO to Install Former SoCal Utility Executive on Board of Directors

Former Southern California Edison Senior Vice President Erik Takayesu will join MISO’s Board of Directors beginning Jan. 1 after a vote among its membership.  

Takayesu will be joined by current board members Nancy Lange and Mark Johnson, who also earned sufficient support from MISO members to serve additional terms. (See MISO Board Week Covers Supply Worry, SoCal Utility Exec Addition, $400M Budget.)  

Johnson was allowed to stand for an additional three-year term beyond MISO’s customary three-term limit through a waiver of its bylaws. MISO’s board uses waivers to retain institutional knowledge on the board when necessary.  

MISO’s board members and membership decided they needed to hang onto Johnson’s system planning expertise after it warned that in addition to departing Director Phyllis Currie, other current board members H.B. “Trip” Doggett, Barbara Krumsiek and Todd Raba would hit their three-term limits at the end of 2025. (See Extensions Likely for MISO’s Term-limited Board Members.) 

Lange was up for re-election for her third and final term.   

MISO’s board elections require candidates to earn a majority of votes in support among membership. Members can vote for or against or can abstain from selecting any of the candidates. The elections require a minimum 25% participation among MISO’s approximately 140 voting-eligible members to achieve quorum. The RTO again used VoteNet Solutions to conduct its monthlong membership vote of the candidates.  

MISO’s board and leadership praised Takayesu’s appointment.  

“The continued service of directors Johnson and Lange provides continuity as we manage the changing energy landscape, and Director Takayesu has a wealth of industry experience to help solve the complex problems we’re facing,” MISO CEO John Bear said in a press release. “Overall, our board members bring a cross-section of knowledge to steer us in the right direction.” 

“Director Takayesu is a welcome addition to the board, and directors Johnson and Lange will continue to provide key insight and institutional knowledge as we navigate the energy transition,” MISO Board Chair Todd Raba said. “We appreciate Director Currie’s leadership during her tenure on the board. Her steady guidance served as a model for her fellow directors.” 

While at Southern California Edison, Takayesu led the utility’s business and asset management strategy, system planning, technology demonstration and development and wildfire safety. Takayesu currently serves as a member of the Department of Energy’s Electricity Advisory Committee. 

The Board of Directors will meet for a final time this year Dec. 12 as part of MISO Board Week. 

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Federal Briefs

TVA Approves PPA for Memphis Supercomputer Site

The Tennessee Valley Authority has approved a power purchase agreement with Elon Musk’s xAI supercomputer facility in Memphis. The facility is expected to use up to 150 MW at peak. Any company using more than 100 MW requires TVA approval. The facility is online and using temporary gas turbines for power. 

More: Memphis Commercial Appeal 

FERC Gives Venture Global Permission to Introduce Natural Gas into LNG Plant

FERC has approved Venture Global LNG’s plans to introduce natural gas into its Plaquemines export plant in Louisiana. The company can commission and introduce natural gas into its “fuel gas and warm flare” systems, FERC wrote in its order. It is allowed to introduce gas to other parts of the facility once the company complies with the conditions of the order. The 20 million metric tons per annum Plaquemines LNG plant will be the second-largest U.S. export facility when fully operational. 

More: Reuters