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November 5, 2024

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Grid Upgrades Challenging but Needed, OSW Supporters Say

ATLANTIC CITY, N.J. — States can reap long-term savings by upgrading their onshore grids and coordinating transmission development to serve multiple offshore wind projects, but they’ll also face higher upfront costs, supply chain challenges and ratepayer concerns, speakers at a New Jersey conference said Oct. 11. 

Planned and coordinated transmission upgrades could save billions of dollars across the OSW sector, but the complexity and extensive planning needed to bring different stakeholders and states together to craft solutions could take more than a decade, speakers at the Time for Turbines 7 conference in Atlantic City said. 

New Jersey’s use of the State Agreement Approach (SAA) to create $1.07 billion in transmission upgrades that can deliver 6,400 MW of OSW generation to the PJM grid is a prime example of the benefits of planning, speakers told conference attendees. 

Yet time is of the essence for all states, according to Abraham Silverman, assistant research scholar with the Ralph O’Connor Sustainable Energy Institute at Johns Hopkins University. The global market for transmission equipment is competitive, and developers need to line up their supply chain now to ensure equipment is available years ahead of when it’s needed, Silverman told the 150 developers, government officials, environmentalists and other stakeholders at the conference.  

Abe Silverman, Johns Hopkins University | Christian Fiore

“States are making procurement decisions today that are going to be delivered in the early 2030s,” he said. “2030 is today. 

“So if you are going out and buying it, [and] thinking about offshore wind, you need to have all the major questions answered” around what’s being built, voltage levels and suppliers, Silverman said. “And I think, frankly, a lot of us see what happens when developers don’t have their supply arrangements totally locked up, and we end up in real problems, and you get delays.” 

Projects in Germany and Scotland are “going ahead and procuring their HVDC equipment and stockpiling it for future use,” said Janice Fuller, former Mid-Atlantic president at Anbaric, which specializes in developing transmission for OSW projects.  

“The projects aren’t awarded, but they’re buying [the equipment], and they will have it ready,” Fuller said. “So that also puts us a little bit further behind in that global supply chain.” 

Planning Initiatives

Procurement is just one challenge conference speakers said is facing New Jersey and other states as they try to prepare their grids for the 60% increase in transmission capacity needed to bring about widespread electrification, according to Princeton University’s 2021 Net-Zero America report. 

The New Jersey Board of Public Utilities (BPU) says ratepayers will save $900 million from its project to upgrade onshore transmission infrastructure to link OSW projects to the grid. The BPU and PJM created the project under the SAA, and the BPU in February sought FERC approval to use the SAA in a second solicitation but later put that plan on hold. 

“Essentially, what we are trying to do is avoid a bunch of individual onshoring efforts and to minimize environmental impacts, minimize community impacts, minimize project risk and risks of delays that may come from a bunch of one-offs coming in,” said BPU Executive Director Robert Brabston. 

FERC Order 1920, approved in May, also offers “exciting” potential for promoting much-needed long-term planning, Brabston said. (See FERC Issues Transmission Rule Without ROFR Changes, Christie’s Vote.) 

The order requires RTOs and ISOs to undertake long-term transmission planning — with a 20-year time frame, taking into account anticipated load growth, state laws and generation retirements. The plans must be updated every five years.  

Brabston said New Jersey can benefit from Order 1920’s planning requirements by addressing the “vastly different networks in the state.” These range from the well-developed infrastructure in the north to areas in the south that were “built to cobble together the agricultural part of the state and the population centers.” While southern areas have the space to house data centers and grid-scale solar projects, the grid there “wasn’t built for it, it’s not ready for it,” he said. 

“So we need to be able to do things like pursue grid-enhancing technologies, because you can’t just build all new pipes and wires for infrastructure,” he said. “If you’re going to modernize utilities, you’ve got to modernize the utilities. It’s not just new wires. It’s reconductoring. It’s all kinds of other stuff.”  

That means “getting this project selection criteria updated so it takes more factors into account and is more transparent,” he said. 

Collaborative Strategy

Long-term planning was also central to New Jersey and nine other East Coast states in July establishing the Northeast States Collaborative on Interregional Transmission to explore mutually beneficial interregional transmission to increase the flow of electricity among ISO-NE, NYISO and PJM, as well as assessing offshore wind infrastructure needs. (See 10 Northeastern States Sign MOU on Interregional Transmission Planning.) 

“The theory is, if it saves $900 million when New Jersey does it alone, how much is it going to save when we work with Maryland, New Jersey and Delaware, or New York and New England and all the other places?” asked Silverman, who helped put together the coalition. He noted New York had also studied the benefits of creating an “offshore wind backbone” similar to New Jersey’s and found it would save ratepayers $500 million. 

Silverman said it’s not just about the savings, but also improved reliability, faster interconnection times and “derisking” of projects “so that when we ask developers to put billions of dollars of capital at risk, they really feel comfortable coming to that table.” 

“We’ve seen success within individual states or even on a regional basis, like New England. But we also need to get states talking to each other and cross over some of these artificial barriers.” 

Cost Allocation Straitjacket

However, that kind of collaboration raises questions about technology standardization, Fuller said. 

As generators bid their projects and suppliers try to determine how to prepare for projects that won’t break ground —or water — for another decade, it’s crucial for both sides to agree on uniform standard for the technology being used, she said. 

“That plays into your ability to have mesh-ready projects, projects that could be brought together in the future and connected together,” she said. 

Janice Fuller, former president, Mid-Atlantic, Anbaric | Christian Fiore

Another ongoing issue is who pays for the projects, Brabston said. 

“One of the key things from a New Jersey perspective is trying to get out of this straitjacket of: If it’s a state policy thing, the state has to pay 100% by itself,” he said, which fails to account for the fact that “all states stand to benefit from this to a greater or lesser extent. We should be talking about cost allocation, not an all-or-nothing kind of thing,” he said. 

Fuller called the New Jersey initiative the “canary in the coal mine” for other states and stakeholders, particularly because it received 80 bids from 13 developers. (See NJ BPU OKs $1.07B OSW Transmission Expansion.) 

“I think the industry stood up, and other states stood up, and said, ‘Oh, that’s real. They got a real robust response with really creative solutions, and it’s going to have a tremendous ratepayer impact,’” she said. 

One challenge is communicating the benefits to the public, Fuller said. She said renewable development often prompts skeptics to say, “Why do we need to do this? It’s going to impact our electric bills, and the ratepayers aren’t going to be able to tolerate that.”  

But infrastructure upgrades can produce multiple benefits, including realizing substantial savings for consumers and reducing the number of cables and beach crossings needed, she said. 

Fuller suggested using the phrase “benefit allocation” to make projects more palatable to the public. 

“We always talk about cost allocation,” she said, but changing the term could show “it’s not just fair sharing of the cost, it’s understanding where the benefit lies, and so you’re paying your share of the benefit.” 

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ISO-NE Refines Scope, Schedule for Capacity Auction Reforms

ISO-NE is not planning to pursue development of simultaneously clearing seasonal capacity auctions as part of its capacity auction reform (CAR) project, Chris Geissler of ISO-NE told the NEPOOL Markets Committee (MC) on Oct. 16, updating stakeholders on the RTO’s most recent plans for its multiyear effort to overhaul its capacity market.

The CAR project encompasses ISO-NE’s ongoing work to improve resource capacity accreditation, reduce the time between auction and capacity commitment periods (CCPs), and split the annual CCPs into distinct seasons. The RTO aims to complete the project in time for the 2028/2029 CCP (CCP 19) and has delayed its next forward capacity auction for three years to develop the reforms. (See FERC Approves Additional Delay of ISO-NE FCA 19.)

ISO-NE previously had floated the possibility of simultaneously running the seasonal auctions for each year to enable generators to account for fixed annual costs and submit bids that are contingent on clearing in both seasons.

However, Geissler said the RTO is concerned that developing a simultaneous auction design could jeopardize the timeline of the CAR project.

“The time and resources needed to pursue such a design would take away from other parts of CAR, including the RAA modeling and accreditation efforts,” Geissler said, adding the RTO has “concluded that the risks of pursuing this approach for CCP 19 outweighed the benefits.”

Power generators and consumer groups have pushed for a simultaneously clearing seasonal auction, arguing that the design could reduce risks for generators and overall costs for consumers.

In comments submitted to ISO-NE in the summer, Calpine wrote it has “grave concerns” with a seasonal auction that does not account for generators’ annual costs, adding that “simultaneously clearing seasonal auctions, with offers for each season and the entire commitment period, must be in [the] CAR scope.”

Geissler said ISO-NE will consider developing a simultaneous seasonal auction design after the CAR project is complete.

ISO-NE is also not planning to include in the project a focus on correlated outages and resource start times, or reforms to how the capacity market treats retained resources, although the RTO may consider these aspects for development after CCP 19.

Modeling resource start times in the resource accreditation process has been a priority for some storage developers, but ISO-NE found “it is not feasible to consider resource start times for CCP 19 due to technical limitations,” Geissler said.

ISO-NE similarly determined it is infeasible to model correlated outages, citing data availability challenges and the limitations of the RTO’s resource adequacy modeling platform. Geissler noted that ISO-NE’s proposed approach to accounting for the region’s gas constraints will account for correlated outages stemming from limited gas availability.

While New England gas generators often struggle with fuel availability during cold days, outages due to extreme cold weather also pose a significant reliability risk. On Christmas Eve in 2022, resource outages during the evening peak triggered a capacity shortfall event, and ISO-NE said the outages “were caused by cold temperatures or mechanical problems, and not due to inadequate fuel supplies.”

Geissler also provided additional information on how the reformed capacity market will treat resources that are retained due to local transmission security concerns. He said resources operating under reliability-must-run contracts “are expected to offer into the day-ahead and real-time energy markets in a manner similar to other capacity resources” and “are economically committed and dispatched based on their energy supply offers.”

In an Oct. 9 memo, ISO-NE said it is not planning to change its current approach to pricing retained resources at $0 in the capacity supply curve.

Geissler noted that if ISO-NE finds a future need for resource retentions for energy security reasons, it “commits to simultaneously assessing and including a different pricing mechanism for stakeholder consideration.”

CAR Schedule

ISO-NE said it is planning to begin discussions with stakeholders on the detailed design of the prompt market and resource retirement reforms in early 2025, with the intention of filing this portion of the reforms in late 2025.

The RTO is planning to begin discussions on resource accreditation and the seasonal market design in late 2025 after the first phase of the project is complete.

Geissler emphasized that both filings will need to stand on their own given the uncertainty of FERC’s response.

Votes

The MC unanimously voted to approve a set of revisions to the RTO’s manuals to conform with ISO-NE’s day-ahead ancillary services initiative, which is progressing toward a March 1, 2025 implementation. (See FERC Approves ISO-NE’s Day-Ahead Ancillary Services Initiative.)

The committee referred to the NEPOOL Generation Information System (GIS) Operating Rules Working Group a request from the Massachusetts Department of Energy Resources to update the GIS to include information “regarding when a facility became eligible under Massachusetts clean, alternative and renewable energy standards.”

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NERC Standards Committee Briefs: Oct. 16, 2024

Committee Approves Errata to IBR Standard

Despite last week’s acceptance of PRC-029-1 (Frequency and voltage ride-through requirements for inverter-based resources) by NERC’s Board of Trustees, the ERO isn’t quite finished with the ride-through protection standard, the organization’s Director of Standards Development Jamie Calderon told NERC’s Standards Committee. 

The board approved the new standard in a special meeting Oct. 8 after it passed its final industry ballot with a weighted segment average of 77.48%, following a sometimes-rocky development process that saw the board exercise its authority to bypass parts of the stakeholder approval process to meet FERC’s deadline for the standard. (See NERC Examining Lessons from IBR Standard Development.) 

Calderon explained to the SC’s monthly conference call Oct. 16 that NERC staff had identified “some minor errata” in the standard and its implementation plan after they were submitted to the board, necessitating a few small wording updates: 

    • changing the word “manufacture” to “manufacturer” in PRC-029-1 
    • adding an effective date for the definition of “ride-through” in the implementation plan 
    • removing the term “voltage” from the description of IBRs that cannot meet ride-through requirements in the implementation plan 

The errata passed the committee’s vote unanimously. No further industry comment or ballot is necessary; the corrected version will be filed with FERC in the petition for approval of PRC-029-1. 

Claudine Fritz of Exelon, noting the “rushed” development of the final standard, asked that NERC make sure to reserve time in the future for proofreading so such errors can be caught and corrected before board approval. Chair Todd Bennett of Associated Electric Cooperative explained that the ERO is conducting an internal effort to identify lessons learned from the development of PRC-029-1 and other IBR-related standards, as NERC Vice President of Engineering and Standards Soo Jin Kim previously told the board.  

More Standards Actions

Other actions approved by the SC this week include authorizing the posting of proposed standard EOP-012-3 (Extreme cold weather preparedness and operations) for a formal comment and ballot period. The comment period began Oct. 17, along with the opening of ballot pools. Voting will open Oct. 31 and close Nov. 5 along with the comment period. 

This is NERC’s second time revising its cold weather standard in response to a FERC order. The commission accepted EOP-012-1 in 2023 but ordered revisions to be completed by this year. Those revisions resulted in EOP-012-2, which FERC accepted in June, with an order of additional changes to be completed by March 2025. (See FERC Orders Further Cold Weather Standard Modifications.)  

The new standard is intended to address shortcomings identified by FERC in its predecessor, which include ensuring entities can understand the generator cold weather constraint criteria, allowing NERC to confirm the validity of cold weather constraints and clarifying implementation deadlines for corrective action plans.  

NERC Manager of Standards Development Alison Oswald said the team is pursuing a shortened comment and ballot period — 20 days rather than the usual 45 — to improve its chances of meeting FERC’s deadline. At least two more ballots are planned after this. 

In addition, the committee authorized appointing 12 members, including chair and vice chair, to the standard drafting team for Project 2024-02 (Planning energy assurance).  

This is one of two teams working on this project, which is intended to create requirements for performing energy reliability assessments. The team approved at this week’s meeting will address assessments for the planning time horizon, while another team tackles assessments on the operational planning time horizon. 

Elections on the Horizon

With 10 committee members’ terms expiring at the end of the year and one member resigning, the SC will hold elections to select their replacements in December. 

Those with expiring terms are: 

    • Amy Casuscelli, Xcel Energy (Segment 1) 
    • Charles Yeung, Southwest Power Pool (Segment 2) 
    • Vicki O’Leary, Eversource Energy (Segment 3) 
    • Patti Metro, National Rural Electric Cooperative Association (Segment 4) 
    • Jim Howell, Treaty Oak Clean Energy (Segment 5) 
    • Justin Welty, NextEra Energy (Segment 6) 
    • Venona Greaff, Occidental Chemical (Segment 7) 
    • Philip Winston, independent (Segment 8) 
    • William Chambliss, Virginia State Corporation Commission (Segment 9) 
    • Steve Rueckert, WECC (Segment 10) 

In addition, Peter Yost of Con Edison, whose term representing Segment 6 was to have expired at the end of 2025, has stepped down from the SC due to retirement, said Bennett, of Associated Electric Cooperative.  

Nominations will be accepted from Oct. 21 to Nov. 12, NERC Standards Developer Dominique Love said, with the election held from Dec. 4-13. For Segment 6, the recipient of the most votes will serve the full two-year term, while the runner-up will serve out the remainder of Yost’s term.

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FERC Sets MISO TOs’ ROE at 9.98%, Again Eliminates Risk Premium Model

FERC continues to fiddle with the return on equity MISO transmission owners can earn, this time setting the base amount at 9.98% while once again eradicating the risk premium model from the calculation.  

The Oct. 17 order is the latest in a yearslong string of adjustments to the MISO TOs’ ROE and might represent a step closer to settling the more-than-decade-old debate over which rate inputs are appropriate (EL14-12, et al.).  

FERC said when examining the case, it found no evidence that investors use the risk premium model, a conclusion it came to once before in 2019. The commission insisted it made “a principled and reasoned decision supported by the evidentiary record.” 

By ousting the risk premium model, FERC again is down to relying on two models — the discounted cash flow (DCF) and the capital asset pricing (CAPM) — to establish a zone of reasonableness and set the ROE at its midpoint. FERC said the new zone of reasonableness is between 7.39 and 12.58%. 

FERC ordered MISO TOs to adopt the 9.98% base ROE effective near the end of September 2016 and provide refunds to customers with interest for a 15-month refund period beginning with the date of the initial complaint Nov. 12, 2013.  

The commission has tinkered with and set an assortment of ROEs for MISO TOs in recent years: In 2013, it was using a 12.38% rate; after the complaint from MISO transmission customers, it landed on a 10.32% rate in 2016, which was reduced to 9.88% in 2019 and then upped to 10.02% in 2020. FERC said in the latest order that it continued to find the circa-2013, 12.38% base ROE excessive.  

FERC has cut the risk premium input once before, when it set the 9.88% base ROE, then changed course when it established the new ROE in 2020 under a Republican majority of commissioners. When formulating an ROE for the privately held MISO TOs, the commission attempts to formulate their stock price as if they were publicly traded. The risk premium model tries to emulate the cost of equity using the premium that investors would expect to earn on a stock investment over the return they would expect to earn on a bond investment. 

FERC found the ROE case back on its docket because of the risk premium model’s inclusion since 2020. The D.C. Circuit Court of Appeals in 2022 vacated FERC’s 10.02% value. The court said it didn’t understand why FERC would spend pages describing the risk premium model’s shortcomings, circular nature and scarce use only to reinstate its application in 2020. (See DC Circuit Sends FERC Back to Drawing Board on MISO ROE.)  

FERC left the other two models alone and continued to find a DCF zone of reasonableness at 6.97 to 12.07%, and the CAPM’s range is 7.80 to 13.09%. 

While this time FERC said no further changes to the ROE methodology are necessary, it left the door open to including the risk premium model once again if parties can show that potential benefits outweigh concerns with the model.  

The commission said it understood that cutting the risk premium model reduces the “diversity of inputs” and increases the weighting for the CAPM and DCF model. FERC said it could be open to using “a blended historical and forward-looking risk premium in the CAPM in future proceedings as a potential means to mitigate volatility concerns with the commission’s ROE methodology.”  

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5th ‘Alert’ Touts Markets+ Support for Clean Resources, GHG Policy

Proponents of SPP’s Markets+ argue in their latest “issue alert” published Oct. 16 that the framework allows more flexibility for integrating greenhouse gas emission reduction programs across various states than CAISO’s Extended Day-Ahead Market (EDAM).

The alert is the fifth in a series of seven notices highlighting the purported advantages of Markets+ over EDAM and the Western Energy Imbalance Market (WEIM). The first covered differences between how the two markets would be governed, the second focused on reliability, the third compared pricing practices, and the fourth tackled market seams.

The contributing parties include Arizona Public Service, Chelan County Public Utility District (PUD), Grant County PUD, Powerex, Public Service Company of Colorado, Salt River Project, Snohomish PUD, Tacoma Power, Tri-State Generation and Transmission Association, and Tucson Electric Power.

In their fifth alert, the proponents argue that Markets+ is better positioned to address risks associated with market price formation, deliverability and congestion that can “materially impact the feasibility and expected value of investments in clean energy that can be brought to load.”

For example, Markets+ uses fast-start pricing and graduated scarcity pricing approaches, which, according to the proponents, send “transparent price signals to encourage investment and use of clean and flexible resources and storage when they are needed most.”

The alert also points to the flow-based dispatch used in Markets+, which the proponents claim will increase “the deliverability of resources across the [balancing authority]-to-[balancing authority] and [transmission service provider]-to-[transmission service provider] seams within the footprint, resulting in less congestion and more delivered clean energy than the EDAM design.”

Additionally, Markets+ provides enhanced protection from congestion costs by allocating congestion revenue to firm transmission rights holders in proportion to the congestion costs incurred on their specific transmission paths, according to the alert.

“This approach provides an opportunity for remote resources to hedge congestion costs and reduce the price risk of delivering clean energy investments to load,” the alert stated. “In contrast, the EDAM congestion revenue structure increases the financial risk for those delivering remote clean resources as the congestion revenue allocation is split between the market operator (at BAA boundaries) and EDAM entities (internal congestion).”

“This bifurcation creates significant uncertainty that the allocation methodology selected by each EDAM entity may not allocate congestion costs on an individual transmission path basis, preventing those delivering remote resources from being able to accurately forecast or hedge against congestion,” the alert added.

GHG Pricing, Tracking and Reporting

The alert also touts Markets+’s greenhouse gas emissions pricing features and tracking and reporting system.

It says the “Type 1A” option in Markets+ would ensure that external supply contracted to serve load in a GHG pricing zone will be attributed to that zone if dispatched.

“This provides load-serving entities with an increased ability to hedge their exposure to GHG costs through advanced contracting of clean supply,” it says. “It is our understanding that the same functionality is not currently available in EDAM.”

Additionally, a “Type 2” option allows a market participant located outside a GHG pricing zone to economically offer its own surplus clean energy to be attributed to a GHG pricing zone, allowing it to “retain the clean supply needed to serve its load obligations while providing an opportunity to be compensated for its surplus clean energy.”

The alert says also that the Markets+ reporting and tracking mechanism allows the market to quantify emissions associated with “residual” dispatched energy not “otherwise claimed by load-serving entities in the market.”

“The design enables participants to determine how energy is attributed to meeting their own load and how unattributed surplus energy is accounted for in residual energy reporting,” it says.

“We are pleased to have worked closely with a diverse group of Western entities to meet each state’s GHG tracking and reporting needs with the development of M+ GHG protocols,” Lisa Tiffin, senior vice president of energy management at Tri-State, said in a statement. “GHG tracking, including from energy markets transactions, will be critical for Tri-State as we progress in the energy transition.”

“CAISO also has recently proposed to develop a GHG tracking and reporting framework based on stakeholder requests and the Markets+ approach may serve as a starting point,” the alert says. “This development highlights how the existence of two competing organized markets provides greater opportunity for both markets to continuously evolve with improved products, services and market design.”

Reached for comment, CAISO said its Western Energy Imbalance Market already supports renewable integration across the West “by efficiently optimizing low-cost renewable generation and dispatching it to serve demand in the middle of the day when it is most abundant, reducing the costs of serving load for utility customers. The Extended Day-Ahead Market (EDAM) design, approved by the Federal Energy Regulatory Commission (FERC), builds on those proven advantages.”

The issue alert follows the release of a white paper by The Brattle Group, published in early October, offering a point-by-point comparison of CAISO’s Extended Day-Ahead Market and SPP’s Markets+ that leans in favor of EDAM but stops short of endorsing either market. (See Brattle Study Likely to Fuel Debate over EDAM, Markets+.)

Regarding greenhouse gas pricing mechanisms, the Brattle study notes that EDAM builds off the Western Energy Imbalance Market, saying EDAM benefits from this tried and tested approach.

“The experience of the last ten years and our own forward-looking simulation analysis indicates that the WEIM/EDAM approach is effective at delivering customer savings while limiting leakage, which could otherwise reduce the effectiveness of GHG regulations,” according to the Brattle study. “Therefore, stakeholders in EDAM have more certainty that the GHG pricing mechanism will achieve efficient outcome while minimizing leakage.”

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MISO to Request Year Deferral on FERC Order 1920

CARMEL, Ind. — Though it’s largely compliant with the directives of FERC’s Order 1920 on regional transmission planning, MISO intends to seek a yearlong extension of the June 2025 compliance deadline. 

MISO said it expects to file an extension request with FERC at the end of this month to give it more time to describe how it meets all planning directives.  

At an Oct. 16 Planning Advisory Committee, Director of Expansion Planning Jeanna Furnish said that though MISO believes it’s “directionally compliant” with Order 1920 through its work on long-range transmission planning (LRTP), “much work and assessment is still needed to show compliance.”  

Some stakeholders said it seemed strange MISO would need a year to demonstrate to FERC that it’s already planning projects in general accordance with the order.  

The Union of Concerned Scientists’ Sam Gomberg said that “at first blush,” a yearlong extension seems excessive. A former FERC commissioner has said MISO is ahead of the pack on transmission planning initiatives and acknowledged the commission modeled the order largely on planning taking place within the footprint. (See MARC 2024 Displays Mixed Feelings on Transition Feasibility.)  

Stakeholders asked if MISO planners were getting a jump on drafting a compliance plan should FERC reject a delay.  

“We are trying to get the extension request in as soon as possible so we can manage that timeline,” MISO’s Jeremiah Doner said.  

Meanwhile, MISO has put out a call for transmission study ideas from stakeholders for its 2025 Transmission Expansion Plan (MTEP 25). MISO, as it has with other recent MTEPs, warned it will be limited in what new studies it can accommodate because much of its planning bandwidth is dedicated to LRTP.  

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FERC Finalizes Order 1977 on Backstop Transmission Siting

FERC acted on rehearing requests for Order 1977 on Oct. 17, finalizing the rules it will follow under limited backstop siting authority for transmission lines. 

The major change FERC made to the original proposal, which was approved this year alongside Order 1920 on transmission planning, was to require projects seeking rights of way on Tribal lands to include their proposals in Tribal engagement plans. Developers will have to describe how they will work with Tribal landowners on right-of-way issues. 

“We at FERC are focused on Tribal engagement,” FERC Chairman Willie Phillips said in a statement. “It is important that project sponsors work closely with Tribal landowners on these right-of-way issues as part of their overall engagement with Tribes on transmission matters.” 

The order lays out how FERC will handle backstop siting applications in National Interest Electricity Transmission Corridors. They were established by the Energy Policy Act of 2005, but for much of that time, the authority was hobbled by a court decision. Congress updated the law in 2021 to say FERC could overrule a state that denies a transmission line’s application that would go through NIETC if approved by the Department of Energy. 

DOE announced preliminary NIETCs this spring a few days before FERC’s initial order but has yet to finalize corridors where the commission’s backstop siting authority could be used. (See On the Road to NIETCs, DOE Issues Preliminary List of 10 Tx Corridors.) 

The new rule includes a Landowner Bill of Rights, codifies an Applicant Code of Conduct as a way for applicants to show good faith engagement with landowners and directs applicants to develop engagement plants for outreach to environmental justice communities and Tribes. 

The New York PSC filed for rehearing, arguing FERC should be able to step in only a year after a complete application has been filed with a state regulator. FERC agreed a final application is an important consideration for the process but declined to include the requirement the PSC sought. 

The pre-filing process requires developers to inform FERC of the status of any state applications and allows state regulators to raise issues around their review when any application is being debated before the federal regulator. The commission will look at issues case by case, the rehearing order said. 

The Louisiana PSC asked that FERC give deference to state decisions and presume they are correct, with the burden of proof on developers to overcome state decisions. FERC said it would take the state decisions into account but that they are not determinative under the law. 

“If the commission finds that the statutory criteria under section 216(b) have been met, it may issue a permit to construct or modify electric transmission facilities in a national corridor notwithstanding a state’s denial of the same,” FERC said. “The commission’s consideration, as described in the final rule, of whether an application meets the statutory criteria for commission jurisdiction does not improperly intrude upon state authority.” 

A group of public interest organizations argued that FERC should automatically include all of a state docket’s information as it reviews a line for backstop siting. FERC rejected that request, saying while it will consider relevant information from state proceedings, some of the filings could be irrelevant to the federal process. 

The public interest groups argued the lack of automatic filing could set a procedural trap to keep relevant information out of the FERC proceeding, noting the start of a pre-filing process and the filing of an actual application with the commission are intended to encourage stakeholder participation and disseminate information about the case. Applicants must make a good faith effort to notify “any known individuals or organizations that have expressed an interest in the state siting proceeding,” the order said. 

The Pennsylvania PUC wanted rehearing on the Landowner Bill of Rights, arguing that states should be able to help develop such documents and the current version ignores state siting authority, which could misinform landowners. 

FERC said having multiple versions of the Landowner Bill of Rights could lead to confusion and inefficiencies. 

“Requiring applicants to provide affected landowners with a copy of the Landowner Bill of Rights — a generic document developed by the commission and intended to provide information about the federal permitting process in a broad and consistent manner — does not preclude an applicant from providing additional information to landowners about additional rights under state law or ongoing state siting proceedings, if applicable,” FERC said. 

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Amazon Moves to Accelerate SMR Development

Amazon is stepping further into the nuclear energy market, announcing multiple agreements surrounding advanced reactor technology that could provide carbon-free electricity for its operations.

The Oct. 16 announcements are the latest display of nuclear interest by energy-intensive data crunchers. Just two days earlier, Google announced a pioneering agreement to support Kairos Power’s development of its small modular reactor (SMR) and then buy power from the first few units built. (See Google, Kairos Sign 500-MW Nuclear PPA.)

Amazon itself agreed earlier this year to operate a data center co-located with Talen Energy’s existing nuclear plant in Pennsylvania. The move made news, and waves. (See Talen Energy Deal with Data Center Leads to Cost Shifting Debate at FERC.)

“One of the fastest ways to address climate change is by transitioning our society to carbon-free energy sources, and nuclear energy is both carbon-free and able to scale — which is why it’s an important area of investment for Amazon,” Matt Garman, CEO of Amazon Web Services, said in a news release. “Our agreements will encourage the construction of new nuclear technologies that will generate energy for decades to come.”

Amazon’s latest plans involve three other entities: X-energy Reactor Co., Energy Northwest and Dominion Energy Virginia.

X-energy

Amazon and others will invest $500 million in X-energy to help it complete design and licensing of its Xe-100 SMR and build a fuel fabrication facility.

The reactor’s design will be shippable via highways; it is intended to accelerate construction timelines and create more predictable and manageable construction costs.

Amazon and X-energy hope to bring more than 5 GW of SMRs online in the United States by 2039.

As part of the deal, X-energy and Amazon will develop a standardized deployment and financing model for future projects with infrastructure and utility partners.

“To fully realize the opportunities available through artificial intelligence, we must bring clean, safe and reliable electrons onto the grid with proven technologies that can scale and grow with demand,” X-energy CEO J. Clay Sell said in a news release. “We deeply appreciate our earliest funders and collaborators … we are now uniquely suited to deliver on this transformative vision for the future of energy and tech.”

Energy Northwest

Amazon will partner with Energy Northwest to fund efforts to develop the Xe-100 SMR and deploy it near the public power agency’s Columbia Generating nuclear power station in Washington.

The deal gives Amazon the right to purchase electricity from the first phase (four modules totaling 320 MW) and gives Energy Northwest the option to add up to eight more modules (640 MW).

Energy Northwest said as the owner and operator of the only nuclear facility in the Pacific Northwest, and as a developer of clean energy and storage resources, it is well-suited for this new partnership.

“We’ve been working for years to develop this project at the urging of our members, and have found that taking this first, bold step is difficult for utilities, especially those that provide electricity to ratepayers at the cost of production,” Energy Northwest’s Vice President for Energy Services and Development Greg Cullen said in a news release. “We applaud Amazon for being willing to use their financial strength, need for power and know-how to lead the way to a reliable, carbon-free power future for the region.”

Dominion

The memorandum of understanding between Amazon and Dominion Energy Virginia commits them to exploring commercial and financing structures for SMR development in Virginia.

In July, parent company Dominion Energy sought proposals from SMR developers to evaluate the feasibility of adding an SMR at the company’s North Anna nuclear generating station in Virginia.

An objective of the Amazon MOU is to mitigate potential cost and development risks for customers’ capital providers. Large nuclear reactors have proved extremely expensive to develop in the United States in recent decades, and while SMRs hold the promise of eventual cost reduction through standardization, they are still in development and early projects are expected to be expensive.

The SMRs in development now must still clear numerous technical and regulatory hurdles. And any future scenario in which scores or hundreds of new reactors with smaller safety zones dot the American landscape could be expected to prompt extensive debate and litigation.

But Dominion said SMRs could play a pivotal role in the energy mix in the 2030s. “This collaboration gives us a potential path to advance SMRs with minimal rate impacts for our residential customers and substantially reduced development risk,” CEO Robert Blue said in a news release.

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California Hits Milestones for Batteries, DR Grid Support

California’s battery energy storage capacity has hit 13,391 MW, an increase of 3,012 MW in just six months and a milestone that Gov. Gavin Newsom’s office called “a major victory on the state’s path to 100% clean energy.”

As the growth in battery capacity is accelerating, the new milestone is one-quarter of the way to the state’s projected need of 52 GW of battery storage capacity by 2045.

Industry experts cited the growth of battery storage as a key factor in the Western grid having an “uneventful” summer — despite enduring the hottest weather on record. (See Batteries, Energy Transfers Support ‘Uneventful’ Summer in West.)

Batteries are also key to capturing solar energy that’s produced during the day so it can be used when the sun isn’t shining, Newsom’s office said. Battery discharge to the grid increased from 6,000 MW this spring to more than 8,000 MW over the summer.

“These are the essential resources that we’ll continue needing more of as the climate crisis makes heat waves hotter and longer,” Newsom said in a statement.

According to a CAISO special report on battery storage, battery charging accounted for about 8.3% of load in the CAISO balancing area during peak solar hours in 2023.

“During these hours, batteries help reduce the need to curtail or export surplus solar energy at very low prices,” the report said.

Most of the state’s current battery storage capacity comes from 187 utility scale installations totaling 11,462 MW.

Residential battery storage adds 1,354 MW of capacity in 193,070 installations across the state, according to a California Energy Commission (CEC) dashboard. The remaining 576 MW of capacity is from 3,211 commercial installations.

Broken down by region, the 93501 and 92225 ZIP codes have the most battery storage capacity: 1,450 MW and 1,051 MW, respectively. Both areas are in the Southern California desert.

Grid Support Program

California’s battery storage milestone comes as the state is seeing growth in a program aimed at maintaining grid reliability during extreme weather events.

The CEC’s Demand Side Grid Support (DSGS) program pays participants to reduce electricity use or send energy to the grid to reduce the risk of rolling blackouts. The program runs from May through October.

Since its launch in August 2022, the DSGS program has grown to 265,000 participants and 515 MW of capacity, the CEC announced Oct. 15.

The program includes what the CEC describes as one of the largest storage virtual power plants in the world, with a capacity of more than 200 MW. The VPPs are a network of customer-owned battery storage systems — usually paired with solar — that send power to the grid.

In addition to storage VPPs, the program has two other ways to participate. Participants may provide non-combustion resources, such as traditional demand response. It’s also open to demand response aggregators participating in the CAISO market.

So far in 2024, the virtual power plant has been activated 16 times and demand response was activated once, “helping to avoid a grid crisis during four separate heat waves from July through the beginning of October,” the CEC said.

The DSGS program also played a role in the September 2022 heat wave, when it reduced electricity demand by 3,000 MWh during the 10-day event.

DSGS is part of the state’s Strategic Reliability Reserve, created in 2022 through Assembly Bill 205. The reserve is intended to expand the resources available to manage or reduce net-peak demand during extreme events.

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FERC Grills Grid Stakeholders on Reliability

Speaking to FERC’s annual Reliability Technical Conference on Oct. 16, NERC CEO Jim Robb told commissioners the challenges of ensuring reliability across the North American power grid are only growing. 

“We have a very simple math problem: the trend lines for electricity supply and demand are moving in the wrong direction to sustain reliability,” Robb said in his opening remarks. He went on to highlight a few of the emerging pressures on supply, including the replacement of conventional generation with renewable resources like wind and solar that rely on inverters to connect to the grid. 

“Replacement generation lacks the abundant reliability characteristics of the retiring resources,” he said. “And as we’ve seen over the past few years, the weather conditions the system operates under are increasingly severe, whether they’re long-duration, wide-area extreme cold or heat events, space-weather driving [geomagnetic disturbance] events … or tropical systems like the devastating hurricanes of Helene and Milton.” 

NERC CEO Jim Robb | FERC

However, despite the increasingly “turbulent” environment, Robb also emphasized that “the state of reliability remains a great story of progress,” with the severity and duration of outages declining and system restoration times shortening. 

Robb was part of the first panel of the day, along with representatives of a range of ERO stakeholders including ISO-NE, MISO, Duke Energy, the American Public Power Association and American Clean Power. The discussion touched on multiple reliability issues, with a large share of attention on generation retirements. 

Asked by FERC Chair Willie Phillips about the “record pace” of retirements and the wind and solar resources coming online to replace traditional generation, Carrie Zalewski of American Clean Power emphasized that the growth of renewable energy does not need to be seen as an inherent risk. Recalling the failure of natural gas generators in Texas during the winter storm of December 2022, she urged commissioners that “resource diversity is the linchpin of reliability.”  

FERC Chairman Willie Phillips | FERC

“No resource is immune to risks or weaknesses, whether it’s weather dependency, limited energy availability, correlated system outages … insufficient fuel supply or environmental limitations,” Zalewski said. “It’s dangerous to run a grid that focuses on one type of resource alone, and we … have all kinds of facts … out of Winter Storm Elliott [about] the over-reliance on a [single] resource.” 

In the second panel of the day, Phillips noted that NERC’s written comments before the conference called for “close, intense collaboration” between regulators and state governments to build a reliable electric system. NERC Chief Engineer Mark Lauby said the ERO has focused on building a shared vision of how the grid will function with the new resources coming online. 

“The partnership has got to be around getting to a point of understanding what is the design basis of this system of the future?” Lauby said. “We’ve been so very comfortable about” the one-day-in-10 years loss-of-load expectation, “and it’s really held [up] well. Very rarely did you see generation lower than demand. And we’re starting to see that now, as we integrate weather-related or weather-dependent resources, as we have an interconnected gas and electric system, and how they work together.” 

Andrew French, chair of the Kansas Corporation Commission, endorsed Lauby’s vision of collaboration, describing some of the ways his organization’s coordination with NERC and FERC have borne fruit. 

“I think the primary area where we have coordinated very well there is in things like setting accreditation policies and setting those ultimate resource adequacy requirements, things like planning reserve margins,” French said. “These are fuel-neutral policies, they are data-driven policies that tell us what an appropriate level of reliability might be and how we might value different resources based on the attributes they provide to the system, but it ultimately leaves to the state what resources they will implement to achieve those resource adequacy requirements.”