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June 23, 2024

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NY Sets Strategy to Reach 6 GW of Energy Storage

New York has approved a framework to reach its 6-GW energy storage goal by 2030 and will take steps to ease factors that have limited its deployment to barely 400 MW of operational capacity so far (18-E-0130).

The Public Service Commission’s vote June 20 on a 6-GW roadmap is the culmination of a lengthy period of planning and review after Gov. Kathy Hochul doubled the goal from 3 GW.

If successfully executed as planned, the roadmap would create infrastructure that would reduce future investments needed in the grid, replace more of the high-emissions peaker plants and potentially meet at least 20% of the state’s peak load.

Storage is an indispensable part of the grid New York wants to build, in which intermittent wind and solar generation provide an increasingly large portion of the power portfolio. Department of Public Service staff estimate a need for 12 GW of storage by 2040, when the state reaches its statutory deadline for a zero-emissions grid, and the 2030 goal is seen as an important market signal needed to build momentum toward this.

The PSC order establishes an interim goal of 1.5 GW of storage by 2025.

Revenue uncertainty and rising costs have limited the storage buildout in the state. As of April 1, approximately 396 MW of storage was operational in New York; 581 MW was under contract; and 300 MW has been procured but not under contract.

The PSC’s order attempts to address this. Among the highlights of the roadmap:

    • 3 GW of new short-duration (up to four hours) bulk storage will be procured through a new competitive index storage credit mechanism.
    • 5 GW of new retail storage (up to four hours) and 200 MW of new residential storage (up to two hours) will be supported through expansion of existing regional incentive programs through the New York State Energy Research and Development Authority.
    • At least 35% of program funds will support projects that benefit disadvantaged communities by targeting fossil fuel peaker plant emissions reductions; there will be specific carve-outs for the New York City region because of the concentration of peaker plants and disadvantaged communities there.
    • Electric utilities must study the potential for storage projects to provide cost-effective transmission and distribution services not available through existing markets.
    • Investment will be prioritized in the development of reliable, long-duration storage technologies.
    • Prevailing wages will be a programmatic requirement for energy storage projects with a capacity of 1 MW or greater.
    • Contract duration will be a maximum of 15 years for bulk lithium-ion battery projects and 25 years for other technology.
    • A one-time inflation adjustment will be allowed.
    • Retail storage projects will be capped at 20 MWh.

The New York Battery and Energy Storage Technology Consortium (NY-BEST) welcomed the news.

“The roadmap represents the largest investment in energy storage in the nation, with proposed investments estimated between $1.2 billion and $1.9 billion, distributed across bulk, retail and residential programs,” Executive Director William Acker said.

The trade group Alliance for Clean Energy New York also celebrated the move.

“This is an important milestone in our clean energy progress,” Executive Director Marguerite Wells said. “Battery energy storage plays a pivotal role in improving grid reliability, stabilizing electricity prices, harnessing the full power of renewable energy, reducing New York’s reliance on fossil fuels and transitioning to a modernized electric grid, and is an important part of reaching our clean energy and climate goals.”

“Long-duration energy storage is a vital resource in meeting peak loads as traditional peaking plants retire due to the” Climate Leadership and Community Protection Act, the Independent Power Producers of New York said. “However, batteries, as load modifiers, and not generators themselves, are risky due to the need to decide when to charge and when to discharge into the system. However, we still need new dispatchable resources in the future, whatever qualifies as net zero under the CLCPA, to keep the grid running during events like the heat we have had this week.”

The PSC vote was not unanimous. Commissioner Denise Sheehan, who previously was associated with NY-BEST, recused herself, and Commissioner John Maggiore concurred rather than vote to approve.

“Advancing the energy storage sector through this program once again positions New York as a leader for others to follow. That said, I’m skeptical about how we’re funding this program,” Maggiore said.

He specifically faulted the roadmap for relying on funding through utility bills and for benefiting some disadvantaged communities at the expense of others through the downstate carveouts.

The analysis performed for the roadmap estimates the total cost of the incentive program at $1.29 billion to $2.01 billion, a very wide range because of the uncertainty of wholesale energy and capacity payments.

It estimates 6 GW of storage by 2030 would have a net value in averted grid expenditures of $1.94 billion in net present value through increased delivery of renewables and decreased reliance on more expensive firm capacity. It did not attempt to quantify further societal benefits such as improved air quality.

In 2030, when the program cost is expected to be highest, monthly bill impact of the retail/residential storage incentives is estimated to range from an average of $1.07 for residential ratepayers to $22.43 for commercial ratepayers to $2,307.50 for industrial high-load factor ratepayers.

On top of that would be the bulk storage program impacts: $1.05, $22.14 and $2,277.13 per month for the same three classes of customers, respectively.

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DOE Announces $900M to Kick-start Small Modular Nuclear Pipeline

Two weeks after visiting Georgia to celebrate the completion of two new reactors at the Vogtle nuclear power plant, Energy Secretary Jennifer Granholm was on stage at the American Nuclear Society (ANS) Conference in Las Vegas, announcing $900 million in federal funding to support the buildout of a pipeline of new, smaller-scale nuclear plants. 

The Westinghouse AP1000 reactors now producing power at Vogtle were the first new nuclear plants built in the U.S. since 2016 and came online seven years behind schedule and cost more than double the original estimate of $14 billion. The new federal funding, authorized in the Infrastructure Investment and Jobs Act, is aimed at building market confidence that the U.S. industry will be able to incorporate the lessons learned at Vogtle to deliver a new round of safer, more efficient small modular reactors (SMRs) on time and on budget. 

According to a notice of intent (NOI) the Department of Energy issued June 17 ― following Granholm’s announcement in Las Vegas ― the IIJA dollars will be split into two “tiers.” The First Mover Team Support tier will provide up to $800 million for two next-generation light-water SMRs, or GenIII+ SMRs, being developed by teams that include a utility, the reactor manufacturer, a construction company and end users or off-takers.  

The teams must have signed contracts in hand and must be committed “to deploying a first plant while at the same time facilitating a multireactor GenIII+ SMR orderbook,” the NOI says. 

The Fast Follower Deployment Support tier will split the remaining $100 million between three types of projects that together could help streamline and accelerate project development. The three “sub-tiers” include: 

    • siting initiatives that “lead to multireactor orderbooks of advanced SMRs” 
    • initiatives to support the buildout of a cost-competitive nuclear supply chain 
    • initiatives that help GenIII+ SMR projects set and meet their time and cost targets 

The NOI also sets out a tentative schedule, beginning with an informational “Industry Day” and meetings with prospective applicants this summer, followed by the opening of the application process. The deadline for applications could be by year’s end, and awards could be announced by summer 2025. 

The federal support is intended to “ensure nuclear power ― the nation’s largest source of carbon-free electricity ― continues to serve as a key pillar of our nation’s transition to a safe and secure clean energy future,” Granholm said in a DOE press release. The goal is to “support early movers in the nuclear sector as we seek to scale up nuclear power and reinforce America’s leadership in the nuclear industry.” 

But U.S. leadership in nuclear development ― at home and abroad ― has waned as the cost and time overruns of Vogtle have cast a pall over the market, creating a “commercial stalemate,” according to the NOI. “Utilities and end users/off-takers recognize the benefits of and need for nuclear power, but perceived risks of cost and timeline overruns and project abandonment have limited committed orders for new reactors.” 

Anticipated growth in power demand could help break that stalemate, said Patrick White, research director of the Nuclear Innovation Alliance.  

DOE’s efforts to build an SMR pipeline is “part of a larger conversation about how different energy end users are going to think about trying to meet their clean energy targets,” White said. “I think we’re seeing a lot of conversations about what does it take for a utility to reach net zero? What does it take for things like tech companies that have increasing energy requirements from data centers, from AI computing?” he said. 

“There are more and more conversations about how a Generation III+ SMR could help meet those energy needs. So, I think this is another piece of the puzzle of trying to align all the different stakeholders so we can have a reactor technology ready when a project developer, a constructor and an end user are ready to commit to a project and move forward.” 

State of the Stalemate

The new Vogtle reactors ― referred to as Units 3 and 4 ― are classified as GenIII+ reactors, which is industry shorthand for the generation of nuclear reactors developed since the mid-1990s, White said. The first generation of reactors was developed in the 1950s and ‘60s, and the second generation ― many of which still are online today ― in the ‘70s and ‘80s. 

But the 1,000-MW size of the AP1000 “might limit its application for some utilities … and that total cost of the project might be prohibitive for some smaller utilities,” he said. “And so there was a recognition by advanced reactor developers and by companies that there might be a niche here for using that Generation III+ technology, but on a smaller scale.”  

DOE has been funding other advanced SMRs through its Advanced Reactor Demonstration Program (ARDP), which has provided $2.5 billion in IIJA funds to two projects using new technologies. TerraPower’s 345-MW Natrium reactor is designed to be a sodium-cooled fast reactor. The Bill Gates-funded company broke ground on the project June 10 at a site in Wyoming, near a soon-to-retire coal plant owned by PacifiCorp, which is planned to be the primary off-taker for the Natrium plant. 

X-energy’s Xe-100 reactors are designed as high-temperature, gas-cooled generators. X-energy is working with Dow Chemical, which plans to install four of the reactors at its Seadrift plant in Texas. 

A key difference between the ARDP projects and the GenIII+ SMRs is the fuel they use. GenIII+ SMRs use the same low-enriched uranium (LEU) that powers existing reactors. But both Natrium and the Xe-100 are designed to use high-assay, low-enriched uranium (HALEU), which has a higher concentration of uranium-235, close to 20% versus 3% to 5% for the LEU that fuels most commercial reactors.  

Until recently, Russia was the only source of uranium for HALEU, but the war in Ukraine has spurred DOE efforts to develop domestic supplies. A demonstration plant was opened in Ohio in November of 2023, with the goal of eventually producing enough HALEU for both ARDP projects, which are not expected to come online until the end of the decade. 

The GenIII+ SMRs now available or in development in the U.S. are mostly sized at 300 MW: for example, the Westinghouse AP300, a smaller version of the AP1000, and GE Hitachi’s BWRX 300. Holtec also is developing a 300-MW GenIII+ SMR, with plans to deploy two of the reactors at its Palisades plant in Michigan, which is in the process of restarting. 

The Palisades restart received a conditional commitment for a $1.52 billion loan from DOE’s Loan Programs Office in March. (See LPO Announces $1.52B Loan to Restart Palisades Nuclear Plant.) 

But, as DOE notes, the pipeline of committed projects is thin. Billed as the first GenIII+ SMR deployment in North America, the Province of Ontario and Ontario Power Generation (OPG) plan to install four GE Hitachi BWRX 300s at an existing OPG nuclear plant.  

The Tennessee Valley Authority also says it wants to install a BWRX 300 at its Clinch River site. CEO Jeff Lyash has spoken about developing a fleet of up to 20 reactors by 2050. (See Making the Case for Nuclear at NARUC.) 

Nuclear Capacity Needed

In addition to Vogtle Units 3 and 4, the 93 nuclear reactors in operation across the U.S. provide close to 18% of the nation’s electricity and 45.5% of its carbon-free power, according to the Nuclear Energy Institute, an industry trade group.   

In its recent Pathways to Commercial Liftoff: Advanced Nuclear report, DOE estimated that to meet President Joe Biden’s goal of a net-zero economy by 2050, the U.S. will need 550 GW to 770 GW of clean, firm power by 2050. Advanced nuclear could provide 300 GW of that total if the industry can triple its fleet’s 100-GW capacity, the report says.  

While some environmental groups, such as the Sierra Club and Greenpeace, remain opposed to the development of any new reactors, nuclear energy has become a rare point of common ground for Democrats and Republicans in Congress. A new bill aimed at streamlining and accelerating nuclear permitting (S. 870) cleared the Senate by a vote of 88-2 on June 18 and is on the way to President Biden. The House passed the bill in May with a strong 393-13 vote.  

But will DOE’s $900 million be enough to provide the momentum needed to overcome the legacy of Vogtle and activate the pipeline of orders the NOI envisions? 

Again, drawing on the lessons of Vogtle, DOE will prioritize projects that are reliable, licensable and commercially viable, according to the NOI. Teams also must be able to show they’ve agreed on a “preferred reactor technology with a replicable design.” 

Catherine Prat, a nuclear engineer and member of ANS, cautioned: “I don’t know if anyone in the design phase of a mega-project would say that any finite amount of money is enough. It certainly helps offset some of the risks, but still requires significant investment from utilities and reactor vendors to develop and deploy the technology.  

“It is a significant step for DOE to recognize that some level of government support is necessary, and I think it’s fair to say the industry is appreciative of that,” Prat said in an email. “Let’s not let perfection (enough money) be the enemy of good (some money [and] movement in the right direction).” 

Getting a pipeline of projects over the post-Vogtle hump will require “really trying to align the business models and business requirements for all the different commercial players that are going to need to work together,” White said.  

DOE “is trying to help kind of create a framework or a way to have incentives for these different companies to come together and say, ‘What is a business model that makes sense for these first movers and for fast followers?’ Does providing this additional funding help them to retire risk related to design, related to siting, related to licensing, related to supply chain, or is it a way to just help maybe reach alignment faster? 

“How do you get to five reactors? How do you get to 10 reactors that really help lower the cost of all the technologies overall?” 

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NY Opens Land-based Renewable Energy Solicitation

New York launched its eighth large-scale renewable energy solicitation June 20, seeking proposals for land-based projects to help the state meet its emission-reduction goals.

The New York State Energy Research and Development Authority (NYSERDA) said eligibility applications are due July 15; bid proposals are due Aug. ; and initial award notifications are expected by Sept. 30.

The 2024 Renewable Energy Standard request for proposals — RESRFP24-1 — will result in NYSERDA procuring Tier 1 renewable energy certificates from renewables that enter commercial operation before Nov. 30, 2026, with a possible deadline extension to Nov. 30, 2029.

A productive RFP would help NYSERDA continue to refill the state’s renewable energy pipeline, which suffered a major setback in late 2023 as 81 projects canceled Tier 1 contracts totaling 7.5 GW of nameplate capacity because of rising costs that made it financially untenable to proceed to construction.

As the pipeline collapsed and chances of the state reaching its goal of 70% renewable energy by 2030 grew increasingly remote, NYSERDA launched RESRFP23-1 on Nov. 30, 2023.

On April 29, it announced the 2023 solicitation had yielded tentative contracts for 24 projects totaling 2.4 GW of capacity, all of them mature proposals and many of them party to previously canceled contracts.

For RESRFP24-1, NYSERDA is encouraging all project developers to submit proposals, including new market entrants. The solicitation includes the inflation-indexing provisions that have been included in other recent renewable solicitations in the era of spiraling costs.

It also includes requirements to ensure the state’s societal goals beyond climate protection are addressed, including labor provisions, stakeholder engagement requirements, disadvantaged community commitments and agricultural land preservation.

“Private renewable energy developers are ready and willing to invest billions of dollars into New York, providing jobs and tax revenue for our local municipalities,” Marguerite Wells, executive director of the Alliance for Clean Energy New York, said in the state’s announcement of RESRFP24-1. “We expect numerous quality responses to this RFP, and we look forward to NYSERDA awarding projects that will be built expeditiously to bring benefits to New Yorkers as soon as possible.”

NYSERDA has scheduled a webinar for prospective bidders on June 27.

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OMS-MISO RA Survey: Potential 14-GW Capacity Deficit by Summer 2029

A relatively low turnout of constructed capacity in recent years could continue and deepen a potential 1-GW capacity deficit in summer 2025 to more than 14 GW by summer 2029, MISO and the Organization of MISO States revealed in their five-year resource adequacy projection.

According to the pair’s 11th annual joint survey, the footprint could either enjoy a 1-GW capacity surplus or contend with a nearly 3-GW deficit by next summer. Much depends on how quickly developers can overcome obstacles to get new resources into commercial operation.

This year’s survey assumed MISO will realize only about 2.3 GW/year in accredited capacity from new builds and did not designate projects with signed generator interconnection agreements as a foregone conclusion in committed capacity totals. The survey also didn’t account for the size of MISO’s record-breaking 300-GW interconnection queue and used a 9.2 to 9.6% planning reserve margin requirement over the next five years.

At the 2.3-GW/year rate — which is the historical average of what developers were able to connect in the past three years — a 5-GW capacity shortfall in planning year 2026/27 widens to 7.4 GW by 2027/28 and nearly 12 GW by 2028/29. Last year’s survey anticipated a 9.5-GW shortfall by the 2028/29 planning year. (See OMS-MISO RA Survey Signals Potential for 9-GW Shortfall by 2028.)

This year’s lower rate of assumed capacity additions spurred debate between MISO staff and stakeholders about what developers realistically can accomplish. That stalled the announcement of the survey results by a week.

During a June 20 teleconference to discuss the results, David Schoon, MISO resource adequacy engineer, said the RTO reflected a “new paradigm” from its interconnection queue in the survey. He said MISO’s current 50-GW backlog of unfinished generation that’s been approved to connect to the system but still is waiting in the wings influenced the survey’s new method of evaluating capacity additions.

Schoon said MISO felt it needed to reflect the stubborn trends from the “COVID slowdown, such as continuing supply chain bottlenecks, commercial uncertainty and permitting and labor delays,” despite what interconnection customers claim will be brought online.

“We’ve got to get out of that guessing game,” Schoon said of the queue’s annual yields. He said it’s not realistic to assume developers can bring an “explosion” of resources online in a single year.

However, Schoon said MISO and OMS also contemplated that circumstances mend over time, and the footprint experiences an influx of skilled labor, a less fraught supply chain, expedited permitting and commercial viability of new technologies. In that alternative projection, MISO might connect more than double its three-year historical rate, at a little more than 6 GW annually.

At 6.1 GW/year, MISO could enjoy a 4.6-GW surplus by summer 2029.

However, MISO added a caveat that large, spot-load additions could balloon over the next five years and threaten a more than 30-GW shortfall under the 2.3-GW/year scenario and a nearly 10-GW shortfall even under the 6.1-GW/year rate.

“The situation is changing very rapidly around us,” said Senior Director of Resource Adequacy Durgesh Manjure, referring to generation retirements and a resurgence in load growth through new data centers.

“Immediate actions are needed to expedite the addition of new capacity, coordinate resources for new load additions and potentially moderate the pace of resource retirements,” Schoon said.

Josh Byrnes, OMS president and member of the Iowa Utilities Board, said RTO members’ actions over the next year will matter a great deal. “We need to quickly move to make sure that new load doesn’t outpace generation additions,” he said.

Byrnes said the RTO should focus on ushering new capacity through its interconnection queue expeditiously and “use the expansive MISO footprint to the fullest” through regional transfers.

In a press release accompanying survey results, Byrnes stressed that as the region faces “tightening capacity reserve margins compounded with rapid and large load additions, it is imperative for everyone from developers (new load and generation), economic development authorities, utilities, regulators, MISO and other stakeholders to work in close coordination.”

WEC Energy Group’s Chris Plante asked if MISO has considered that load-serving entities with planned data centers in their territories will take pains to ensure they can cover the large load additions with new capacity or purchases.

MISO’s Scott Wright said OMS and the RTO deliberated on the steps utilities and local governments will take to spur economic development.

“But we’ve also noted that laying it out this way highlights the fact that … a lot of these are un-resourced loads,” Wright said.

Michigan Public Power Agency’s Tom Weeks asked if MISO or its consultants mulled quantum computing emerging in time for the new decade, which could make data center energy consumption “plummet by orders of magnitude.”

Schoon said such breakthroughs weren’t included as possibilities in survey results.

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Study Claims Powerex Backing Markets+ to Benefit from Divided West

A new study commissioned by Renewable Northwest (RNW) adds a contentious new wrinkle to the debate about the potential impact of market seams if the West ends up divided between CAISO’s Extended Day-Ahead Market (EDAM) and SPP’s Markets+.

The study, conducted by Grid Strategies, comes about five months after release of a report from the Western Power Trading Forum and Public Generating Pool that cautioned that seams between Western day-ahead markets would create a different set of challenges from those seen at the boundaries between the full RTOs in the Eastern Interconnection. (See Western Market Seams Issues to Differ from East, Study Finds.)

The Grid Strategies study partly expands on that theme, finding that effective “market configuration” — meaning a market based on the widest footprint possible — outweighs the importance of market design. It also warns that lessons from the Eastern Interconnection show that market seams there continue to be a “persistent drag on efficiency” despite the mechanisms MISO, PJM and SPP have implemented to mitigate their impact.

The study also delves into the specific challenges a two-market scenario could pose in the Pacific Northwest, where neighboring and closely interconnected balancing authority areas — such as those operated by the Bonneville Power Administration and PacifiCorp — fall into separate markets, creating a winding and complicated boundary.

BPA, which controls about 75% of transmission in the Northwest, has made it clear its decision on a day-ahead market will not be driven by concerns about seams and has argued such issues can be resolved by seams agreements. (See Seams Concerns Won’t Drive Day-ahead Market Decision, BPA Says.)

The Grid Strategies study finds that “while experience in other markets support BPA’s argument that a seams agreement is necessary, experience also shows that seams agreements do not reduce barriers to transacting across market seams and will not address the detrimental impact of market seams on consumers.”

‘Hard to Achieve’

But the most controversial aspect of the new study is the contention that Vancouver, British Columbia-based energy marketer Powerex has backed the development of Markets+ because it stands to make more money trading in a divided West than in a single market with no seams.

That’s an assertion other Western electricity sector stakeholders have shared with RTO Insider but have been reluctant to put on the record.

“Well, to the detriment of my dreams to retire in Canada, I decided to go on the record,” RNW Executive Director Nicole Hughes joked in an email to RTO Insider. RNW is a renewable energy trade group that long has advocated for the development of a single organized market in the West and is a key supporter of CAISO’s EDAM.

Hughes was referring to a June 14 opinion piece she wrote for the Seattle-based publication Clearing Up.

The op-ed draws on Chapter 9 of the Grid Strategies study, which is headed “Good Configuration is Hard to Achieve Because Some Parties Benefit from Bad Configuration and Inefficient Seams.”

The chapter explains that BPA and Powerex control the largest amount of power supply and transmission in the Pacific Northwest, the latter being “the exclusive marketer of BC Hydro capability in the U.S., holding substantial hydro generation, storage and transmission rights, and is a major energy supplier to the Northwest.”

Powerex’s “mission” in participating in the U.S. market is “to maximize profits” on behalf of British Columbia’s ratepayers, the study says.

“As the exclusive marketer for BC Hydro, Powerex reports that electricity ‘trade provides economic and environmental benefits for British Columbia. All income generated by Powerex is returned to BC Hydro, which helps the utility keep electricity rates amongst the lowest in North America,’” it says, citing Powerex’s description of itself in the “About Us” section of its corporate website.

Last year, the Western Markets Exploratory Group (WMEG) completed a series of studies, conducted by Energy+Environmental Economics (E3), to assess the benefits that would accrue to various electricity market participants in the West under a range of market footprint scenarios.

Grid Strategies cites wording in the WMEG study for Powerex, which found that in a scenario where Northwest utilities join EDAM, Powerex “expects that its most attractive market opportunities would be forward sales,” prompting the company to limit the hourly flexibility of its hydroelectric exports.

But in a situation where Northwest utilities join Markets+, E3 determined Powerex “expects that its most attractive market opportunities will be hourly optimized transactions” and that it would offer the market its full hourly flexibility.

“E3 estimates that the incremental regionwide cost increase attributable to Powerex’s withholding hourly flexibility in these scenarios is approximately $7 million,” Grid Strategies says. “This example shows how positional power and control of transmission can have significant financial consequences for consumers in the Northwest.”

As the competition between EDAM and Markets+ plays out, SPP has found its strongest support among some entities in the Northwest, including BPA and Powerex, and among Arizona utilities Arizona Public Service, Salt River Project and Tucson Electric Power. But other major players in the Northwest, including PacifiCorp, Portland General Electric and Idaho Power, have signaled their intent to join EDAM, with Seattle City Light likely to follow.

Transmission links between the Northwest and Southwest are limited, and the Grid Strategies study notes that “control of key transmission capacity rights connecting the Northwest to the Southwest is highly concentrated, with a meaningful portion controlled by Powerex, who as a power marketer has an objective of maximizing profits, rather than minimizing consumer costs as do load-serving transmission capacity owners.”

“A pivotal supplier exercising market power can manipulate prices, benefiting itself to the detriment of load-serving entities and consumers,” the study continues. “It is very difficult to mitigate this market power in a two-market setting with no centralized oversight of the broader region. If the seams were more efficiently managed internally within a single market, this would be less likely to occur.”

Powerex Points to Governance, Design

In her op-ed, Hughes points out Powerex controls about 20% of transmission capacity rights on the California-Oregon Intertie, a key link between the Northwest and CAISO. She says direct trade with the Desert Southwest would allow Powerex to avoid paying to wheel power through the CAISO system.

“Powerex states that the solution to congestion rents wheeling through CAISO is to build more transmission to the Desert Southwest,” Hughes wrote. “More interregional transmission connectivity between the two regions would definitely benefit customers West-wide. However, several utilities serving major load centers are committed to continuing to operate in CAISO’s WEIM [Western Energy Imbalance Market] and have committed to expanding their commitment by joining its Extended Day-Ahead Market, while BPA is leaning toward leaving the WEIM and joining Markets+.”

Hughes also asserts the WMEG study indicates BPA would benefit from increased transmission revenues in a divided day-ahead market scenario while the rest of the region would see rising transmission costs.

Reached for comment, BPA spokesperson Doug Johnson said the federal power marketing administration was unprepared to respond to the Grid Strategies study or Hughes’ op-ed.

In an email to RTO Insider, Jeff Spires, director of power at Powerex, said that while “attention to seams is important,” the intent of the study “appears to be to distract from the essential governance and market design elements that differentiate the two day-ahead market options.”

“Powerex is just one of numerous entities participating in the development of Markets+, who collectively seek an organized market that provides independent and inclusive governance, an impartial market operator and a market design that achieves competitive market outcomes while balancing the interests of a broad array of participants,” Spires wrote.

Takeaways

The Grid Strategies study concludes with a handful of “key takeaways.” Chief among them is the assumption FERC is “unlikely to mandate good configuration and does not have a template for effective, efficient and equitable seams coordination,” leaving it to Western utilities and regulators “to evaluate customer impacts and make the best decisions for ratepayers” when it comes to day-ahead market decisions.

Another point is that attempts to address market inefficiencies caused by seams in the East have been “largely unsuccessful.”

“Transactions between markets are far below efficient levels, resulting in higher consumer costs,” the study says.

Yet another takeaway has to do with the access issues that would stem from a two-market configuration in the Northwest because of the region’s “heavy reliance” on BPA’s transmission.

“If market seams are developed between the major load centers in the region and the generation and transmission needed to serve these load centers, costs to consumers will increase, and efforts to bring new clean energy generation to load will be hindered,” the report says. “Particular attention should be paid to avoiding development of these seams today, and ample opportunity currently exists to develop a market [that] will minimize negative impacts to customers.”

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ISO-NE PAC Briefs: June 20, 2024

ISO-NE announced its plans to increase the transfer limits of three interfaces in Maine at the Planning Advisory Committee’s meeting June 20. 

The RTO is planning to up the limits of the Orrington-South interface from 1,325 MW to 1,650 MW, the Surowiec-South interface from 1,500 to 1,800 MW and the Maine-New Hampshire interface from 1,900 to 2,000 MW.  

Dan Schwarting of ISO-NE said the new limits will be incorporated into day-to-day operations, including the wholesale energy markets, in late June or July. 

“Impacts on capacity transfer limits, and any resulting implications for Forward Capacity Market-related activities, will be discussed in future meetings,” Schwarting said, adding that the new limits will also apply to future planning efforts. 

Asset-condition Projects

New England transmission owners discussed proposals for several major new investments to address degrading transmission infrastructure. 

Zach Logan of Avangrid presented a proposal by Maine Electric Power Co. to replace aging poles on a 345-kV transmission line in the eastern part of the state. While the company has determined “the overall condition of the lines are good to fair, and there are no immediate needs for a complete line rebuild,” most of the poles date back to 1969 and are expected to deteriorate at an increasing rate as they pass 60 years of age. 

The company is proposing to replace structures at a rate of about 40 to 50 per year through 2038, at a total estimated cost of $344 million. 

Chris Soderman of Eversource Energy presented a follow-up to the company’s February presentation of a proposed rebuild of a 115-kV line in New Hampshire, projected to cost about $361 million with an in-service date in the fourth quarter of 2026. 

ISO-NE Maine interfaces | ISO-NE

Responding to stakeholder feedback submitted after the February presentation, Eversource analyzed the costs of a partial line rebuild compared to the full rebuild that is currently planned. The company found that partly rebuilding the line would save money in the near term but ultimately increase overall project costs to about $437 million when accounting for subsequent projects that would be needed to replace other aging structures. 

“The bulk of these structures are already 40 years old” and need to be replaced “in a relatively short time frame,” Soderman said. 

Soderman also presented a proposed $5.5 million project to replace 19 structures on a 115-kV line between Maine and New Hampshire, projected to be complete by the end of the year. 

John Babu of Eversource announced a $5 million project to replace eight relays on a 115-kV substation in Harwinton, Conn. Eversource said the manufacturers are no longer producing replacement parts for the relays. 

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NERC State of Reliability Report Notes Progress, Challenges in 2023

Releasing its annual State of Reliability report this week, NERC sounded a note of confidence in the “overall resilience” of the North American electric grid. However, the ERO also observed that the grid continued to face growing challenges over the last year that will require collaboration of multiple stakeholders to address. 

The report reviews the performance of the electric grid over the past year in order to inform regulators, policymakers and stakeholders about the most significant reliability risks, and to describe the ERO Enterprise’s actions in response to those risks. This year’s report comprises an overview, which is a high-level summary of NERC’s findings, along with a more detailed technical assessment. 

With “relatively mild weather [and] enhanced protection measures” across most of the continent, system operators faced fewer stressors during the grid’s peak winter and summer months, John Moura, NERC’s director of reliability assessment and performance analysis, said in a statement. The ERO found that utilities provided 4.69 billion GWh last year, higher than any of the past five years, which was provided by 5,915 conventional generating units of at least 20 MW and delivered by more than 528,000 miles of transmission lines. 

The grid last year also experienced no non-weather-related Category 3, 4 or 5 events; no hours of operator-initiated firm load shedding associated with a Level 3 energy emergency alert; and no unserved energy associated with a Level 3 EEA. By comparison, in last year’s State of Reliability report, NERC reported 56.5 hours of firm load shedding and 96.2 GWh of unserved energy associated with Level 3 EEAs. 

In 2023, the North American electric grid experienced a weighted equivalent forced outage rate of 7.8% averaged across all fuel types, the third highest on record for the past 10 years. | NERC

NERC said one reason the grid performed better last year was that grid operators responded quickly to the kind of severe weather events that have tested the grid in recent years. According to the National Oceanic and Atmospheric Administration, the U.S. experienced 28 “billion-dollar events” last year, defined as weather or climate disaster events that caused damages of at least $1 billion (adjusted for inflation) — well over the five-year average of 20.4 events. 

The ERO acknowledged that the year’s biggest severe weather event was not captured in NOAA’s data — namely, the wildfires in Canada that burned more than 71,000 square miles of forest areas between June 20 and July 26, the record for the country. NERC’s report highlighted the impacts to Quebec, where the largest number of fires occurred. One hundred and one small outage events were reported as a result of the fires; however, these were mostly short, with an average duration of 1.2 hours, and “generally not overlapping.” 

“Transmission metrics were disproportionately impacted by the short-duration outages associated with these wildfires, specifically within the Quebec Interconnection,” NERC said in the report. “However, due to operator actions, as well as the fires’ varied timing and geographical locations, the actual impact on [grid] reliability was minimal.” 

While the ERO was upbeat about the grid’s resilience in the face of extreme weather, it did note that forced-outage rates among conventional and wind generation remained at “historically high levels [in 2023], exceeding rates for all years prior to 2021.” In a media webinar, Jack Norris, an engineer with NERC’s Performance Analysis division, pointed out that the grid experienced a 7.8% weighted equivalent forced-outage rate (WEFOR) in 2023, the third-highest on record for the last 10 years after 2021 and 2022. 

Coal units recorded the highest WEFOR at 12%; this is below the previous two years but still higher than the average of 10% between 2014 and 2022, Norris said. Hydropower also experienced an “unusually high outage rate” of about 7%, he added, which put it above the 10-year average along with natural gas. Nuclear power was the only outage type with a below-average WEFOR, with just under 2%. 

Norris said the outage rates for coal generation are consistent with “increasing WEFOR rates for coal that we’ve been seeing over the last several years and [align] with industry statements [about] reduced maintenance on older coal units as they’re being phased out.” He also noted that utilities have had to cycle coal units on and off more often in recent years “to accommodate variable energy resources,” which strains these units, a likely cause of increased outages. 

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Report Shows Wide Range of Data Center Demand Scenarios for Virginia

Growing demand from Northern Virginia’s Data Center Alley could outpace the power industry’s ability to keep up, according to a report released June 20 by Aurora Energy Research.

PJM’s latest 2024 forecast shows 11 GW of demand from new data centers in Northern Virginia alone by 2030, which would represent 40% of Virginia’s peak demand. In the report “Impacts of Virginia data center demand growth on the power system,” Aurora says data center demand could reach as much as 16 GW by the end of the decade.

New supply would be needed to meet such demand, which the report said could drive up to 15 GW of new natural gas capacity because intermittent renewables alone would not provide the reliability that PJM market rules require. Dispatchable resources such as natural gas or battery storage would be needed to reliably serve new data center load, according to Aurora.

The need for new supply could affect data center demand growth, with the report noting new plants take years to get through PJM’s interconnection process and connect to the grid. Relatively high power prices in Virginia and increasing geographic flexibility from data centers could drive them to be built elsewhere.

“Adding the 10 to 15 GW of firm generation capacity needed to supply these data centers and keep the lights on in Virginia will not be easy,” Aurora’s PJM Research Lead Zachary Edelen said in a statement. “It can take three to four years for the transmission organization just to greenlight a new generator, and market prices are currently too low for developers to build the kind of capacity required.”

Renewable capacity grows significantly in PJM under all of Aurora’s scenarios, which forecast a minimum of 40 GW of new nameplate capacity in the region. But renewables are credited well short of their nameplate capacity in PJM’s capacity market and that along with data centers’ need for steady power supplies lead to more need for natural gas plants and batteries.

“As a result, our analyses consistently show that data centers bolster the business case for natural gas generators, meaning state and federal governments will need to do more if they want to decarbonize,” Edelen said.

Northern Virginia’s Data Center Alley is home to 25% of national data center load. Its 4 GW of demand beat that of every country except the U.S. itself and China. Nearly 300 data center facilities are in Northern Virginia, with a cluster around Data Center Alley in Ashburn, according to the report.

Growth was so fast there that Dominion Energy had to pause new connections in 2022 to avoid spiking congestion. Now the utility is implementing grid updates to deal with the bottleneck. Dominion expects 20 GW of new load and plans to invest nearly $5 billion in transmission to deal with that, according to the report.

Data centers are considering behind-the-meter generation as they work to improve efficiency in their operations in the face of high electricity costs in Northern Virginia, according to the report, which also noted the centers increasingly can locate elsewhere as internet connections improve.

Aurora’s demand forecasts range from 10 to 37 GW by 2040; a 24-GW growth scenario is in line with PJM’s load forecast.

Dominion forecasts 11 GW of additional capacity obligations for its footprint by 2030 and plans to buy and import about 59% of that from around PJM. Its transmission spending plans will help enable that.

The RTO will need more capacity to meet the Virginia data center demand because of planned retirements. Aurora forecasts a 12-GW shortfall in “unforced capacity,” which would take 15 GW of new gas plants, or 20 GW of batteries if they hold four hours of charge.

The higher demand is expected to help push up power prices, with the forecast closest to PJM’s adding $3/MWh to the average, but the extreme case of 37 GW by 2040 would add $16/MWh.

Data centers building their own generation could put a cap on how high their new demand drives wholesale prices, the report noted. A combined cycle gas turbine would make sense for big data centers if the generator’s capacity factor is high enough, which would be the case at average data centers that have a load factor of 88%, according to the report.

“A strategy of building one’s own behind-the-meter generation carries risks, including necessitating a long generator lifetime to realize benefits, policy risk (from potential decarbonization rules), outage risk and potential local pushback from neighboring residents,” Aurora said in the report.

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CAISO Kicks off Stakeholder Process for Pathways Initiative

CAISO on June 18 kicked off the West-Wide Governance Pathways Initiative stakeholder process required to shift the ISO’s governance structure to an independent entity within the Extended Day-Ahead Market (EDAM).  

During a conference call, members of the initiative’s Launch Committee presented Step 1 of the “stepwise” approach, which would elevate the “joint” authority over both the EDAM and the Western Energy Imbalance Market that the latter’s Governing Body shares with CAISO’s Board of Governors to “primary” authority. This means the body would be the first to vote on tariff change proposals for both markets. 

The moves are meant to quell fears about the ISO’s state-run governance structure. (See Pathways Initiative to Act Fast on ‘Stepwise’ Governance Plan.) California’s governor appoints members of the ISO’s board, on which the State Senate votes to confirm. 

The stepwise approach was outlined in a straw proposal released June 5. 

“We’re looking to create a structure that can enable the largest footprint possible and include California,” said Kathleen Staks, WWGPI co-chair and director of Western Freedom. “We ultimately want this entity to be able to evolve and add market services up to and including a full regional transmission organization.”  

The first round of stakeholder feedback led Launch Committee members to highlight a focus on respecting state and local authority in the initiative, “ensuring we are creating a structure that respects each individual state’s ability to set and enforce its own energy policies,” Staks said. “We are not looking to create something that is going to enable one state to force its policies on another state and vice versa.” 

Over the summer, committee members and stakeholders will be working on a proposal for Step 2, which would establish a “regional organization” as a legal entity and, after passage of required California legislation, transfer the Governing Body’s primary authority to “sole” authority. 

Stakeholder Comments

Some stakeholders expressed concern that the initiative still doesn’t achieve the level of independence needed to quell concerns surrounding CAISO’s governance structure. 

“We appreciate steps forward with the Step 1 proposal to extend [Federal Power Act Section] 205 filing rights and primary authority to the WEIM Governing Body,” said Doug Marker, intergovernmental affairs specialist at Bonneville Power Administration. “But at the same time, as we’ve said, we don’t believe that it by itself achieved the level of independence from any one state’s authority that’s necessary for a regional market. 

“What we’re concerned about is that transition to primary authority could lead to the CAISO Board of Governors being disconnected from WEIM and EDAM issues and possibly increased conflict between the Board of Governors and the WEIM Governing Body.” 

Marker requested that the committee consider elements that could be added to the proposal that could support continued collaboration between both entities.  

“We have a number of [Governance Review Committee] members … who are aware of the perceived and, I think, real value of the increased collaboration that happened moving to the joint authority model,” responded Spencer Gray, committee members and executive director of the Northwest & Intermountain Power Producers Coalition. “While we didn’t touch on the mechanics of whether the two bodies would continue to be jointly going forward, we certainly didn’t want to preclude that approach.” 

A second stakeholder call is tentatively set for July 23. 

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MISO Readies JTIQ Filings, Hints at More Tx Portfolios with SPP

Two years after announcing its $1.8 billion Joint Targeted Interconnection Queue (JTIQ) transmission portfolio with SPP, MISO is putting final touches on its FERC filings to make it happen.  

During a June 18 teleconference to outline its plan, MISO’s Milica Geissler said MISO will begin making filings to FERC at the end of July, starting with an addition that chronicles JTIQ procedure for its joint operating agreement with SPP. Subsequent filings on cost allocation, generator interconnection agreements and rate schedules will follow, Geissler said, and may be standalone or combined. All filings concerning JTIQ will seek a common effective date, she added.  

MISO said it will work with its transmission owners to make the later filings. SPP similarly is finalizing JTIQ details. (See SPP Board Adds Final OK to JTIQ Cost Framework.)  

“We’ve been working on this for four years, and we’re finally able to present a full package,” MISO Director of Resource Utilization Andy Witmeier said, referencing the 2020 announcement that MISO and SPP would try a new approach to interregional planning after years of unsuccessful pursuits for transmission prospects.  

MISO counsel Chris Supino said the JTIQ process — which will replace MISO and SPP’s affected system studies — will allow generation developers to learn their cost responsibility earlier and get projects connected sooner.  

Supino said the first portfolio represents the most “immediate need for beneficial, backbone projects” along the MISO Midwest and SPP seam. He said MISO may focus on MISO South for its next JTIQ portfolio with SPP.  

Witmeier said the first portfolio should dramatically decrease the costs of getting generation online near the seam. He said a recent SPP-affected system study returned $1.4 billion in network upgrades for just 8 GW of projects connecting in MISO. On the other hand, Witmeier said the $1.8 billion JTIQ is expected to enable 28 GW in generation additions.  

MISO and SPP are pursuing a 100% cost allocation to interconnection generation. The two initially planned to use a split entailing 90% to generators and 10% to load, but abandoned the approach after the Department of Energy announced the portfolio would receive $464.5 million from the department’s Grid Resilience and Innovation Partnership program. (See MISO, SPP Ditch 90/10 JTIQ Allocation After $465M DOE Grant.) MISO and SPP’s load will act as a temporary cost backstop for their share of JTIQ costs until enough new generation commits to the lines and picks up the tab for construction.  

Geissler said it’s unlikely that load will have to cover any JTIQ costs permanently because of the sheer numbers of prospective projects in MISO’s and SPP’s interconnection queues. However, construction may begin on the JTIQ projects before they’re fully subscribed. MISO said it will consider JTIQ portfolios fully subscribed when 85% of the megawatts they can enable are spoken for. For the first JTIQ portfolio, that subscription threshold will be a little more than 24 GW in generation projects.  

Witmeier added that MISO load should benefit from lower congestion costs and decreased market-to-market payments once JTIQ projects are built.  

SPP’s interconnection queue boasts 412 projects totaling more than 84 GW; MISO’s interconnection queue could approach 350 GW, if all the 123-GW 2023 class of queue applications are allowed to proceed. (See MISO Reports 123-GW Roster for 2023 Interconnection Queue Cycle.)  

“The existing system was not designed to handle this level of generation,” Supino said.  

MISO expects to begin accounting for JTIQ projects in its generator interconnection queue study modeling sometime next year, after the RTOs’ boards approve the JTIQ portfolio.  

MISO and SPP plan to study generation projects that may rely on JTIQ projects in clusters. MISO said it will screen projects and move those dependent on JTIQ into a “participation group.” Generation projects will enter a “commitment group” once they close in on generator interconnection agreements and will be assessed a per-megawatt JTIQ charge that is billed directly by either MISO or SPP.  

Sustainable FERC Project attorney Lauren Azar asked if MISO is planning to change JTIQ rules to integrate changes stemming from FERC’s recent show cause order issued to MISO and three other RTOs. The commission last week put the grid operators on notice that their policies allowing transmission owners the opportunity to provide initial funding for network upgrades may impede interconnection customers’ right to finance the upgrades they pay for. (See FERC Issues Show-cause Order on TO Self-funding in 4 RTOs.)  

“That’s something we’re still evaluating,” Supino said. “We’re still going to have to determine how this impacts it.”  

But Supino said that unlike normal upgrades that transmission owners can elect to self-fund, the JTIQ involves large projects that are prebuilt by transmission owners assigned by MISO or SPP.   

“I’m not certain it’s going to raise the same questions,” Witmeier said.