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October 18, 2024

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Regulators Worry Data Centers Consume Too Much Clean Energy

The growing trend of pairing power-hungry data centers with clean energy resources is sparking mixed feelings among some regulators. 

On the one hand, the planned reopening of Three Mile Island Unit 1 will supply Microsoft with energy through a power purchase agreement. It’s also likely to supply some energy to the local grid, helping with decarbonization, according to Maryland Public Service Commissioner Michael Richard, who spoke during a WECC webinar on large loads Oct. 2. 

But Richard was more concerned about the Susquehanna nuclear power plant in neighboring Pennsylvania, where Talen Energy wants to amend the interconnection service agreement to send some output to a co-located Amazon Web Services data center rather than to PJM. (See With Three Mile Island Restart, Debate Continues on Co-located Load in PJM.) 

Richard also voiced concern about the possibility of data-center co-location at Calvert Cliffs nuclear plant, which he described as “one of those bedrock, in-state assets that we depend on.” Maryland imports about 40% of its electricity, he noted. 

“As we drive toward decarbonization and cleaner resources, if we lose what we have, and just end up … importing and enabling the continued operation of coal plants and other fossil plants, that really doesn’t advance some of our goals,” Richard said. 

Richard was more enthusiastic about co-location of data centers with potential wind facilities off the Maryland and Delaware coasts, where he said the centers could help make the economics of offshore wind work. 

Resource Shortage

The webinar was part of WECC’s “Reliability in the West” discussion series. The focus of the Oct. 2 session was “large load experiences.” 

Kris Raper, WECC’s vice president of external affairs, said the discussion had hit on a challenge that the West, and perhaps the entire nation, is facing. 

“We don’t have enough resources to meet what is already going on,” Raper said, pointing to electrification and efforts to bring clean resources to the grid. 

Webinar panelist Glenda Oskar, an economist in the Department of Energy’s Office of Policy, said DOE is looking at ways to help new data centers. One possible approach is siting data centers at retired coal plant locations, where existing infrastructure could be used. 

DOE also wants to aid in the commercialization of “clean, firm technologies” that could benefit data centers, Oskar said. Those include next-generation geothermal, advanced nuclear and long-duration storage. 

Webinar panelist Travis Metcalfe, energy projects manager at Amazon Web Services, said not all data centers are the same. 

At some centers, customers might simply be looking for a place to back up their data once a day without using much energy. 

“Then you have … AI and machine-learning models, which might be using enormous amounts of electricity,” Metcalfe said. 

Back-up Generation

Even though Northern Virginia, the world’s largest data center market, is just across the Potomac River from Maryland, Richard said he didn’t encounter data center issues at the Maryland PSC until recently. 

In 2023, a data center developer filed for an exemption from the PSC’s certificate of public convenience and necessity (CPCN) requirement for 168 backup diesel generators totaling 504 MW. 

Initially, the commission rejected the request. But recognizing the state goal of promoting data center development, the commission later approved a waiver for 25 generators totaling about 70 MW — enough for the first phase of the project, Richard said. 

The issue then ended up before the Maryland legislature. A bill requested by the governor (SB 474/HB 579) was introduced this year to remove the CPCN requirement for backup power at “critical facilities,” which include hospitals, health care facilities and data centers. 

The legislature passed the bill, which took effect July 1. 

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EEI Projects Need for 42.2M Charge Ports by 2035

The Edison Electric Institute has ratcheted up its projections of U.S. electric vehicle adoption, and with it the number of charging ports and grid upgrades that will be needed. 

EEI on Oct. 2 released “Electric Vehicles Sales and the Charging Infrastructure Required Through 2035,” an update of a 2018 report that looked as far ahead as 2030. 

The 2018 edition predicted that 18.7 million light-duty EVs would be on U.S. roads by 2030 and said they would need an array of 9.6 million charge ports to keep running. 

After six years of rapid EV sales growth, the updated report predicts 34.4 million light-duty EVs will be on the road in 2030 and 78.5 million in 2035. To support them, it calculates a 2035 need for 42.2 million charge ports. 

EEI based the new numbers on four independent forecasts analyzed by the National Renewable Energy Laboratory. In announcing the new report, EEI said significant infrastructure upgrades to support this change already are underway, but more are needed. 

EEI

The Edison Electric Institute in a new report projects there will be 78.5 million light-duty electric vehicles on U.S. roads by 2035. | EEI

EEI Senior Vice President of Customer Solutions Phil Dion said in the news release: “We are excited to continue working with our members around the country to evaluate grid capacity and other infrastructure needs due to the growing number of EVs in their service territories. Our members remain committed to supporting policies, especially those focused on proactively enhancing the energy grid, to ensure the transition to EVs is done in a cost-effective way that is also convenient, equitable and seamless for all drivers.” 

The report does not factor in the substantial need for additional public charging infrastructure that would be created by large-scale electrification of medium- and heavy-duty vehicles. 

The report indicates that electric companies are preparing for this demand in many ways, including developing make-ready infrastructure for site hosts that will procure the charging equipment, installing and owning the charging infrastructure themselves, offering rebates to defray the costs of buying and installing charging equipment, offering time-of-use rate structures, requiring demand response capability for charging equipment and educating EV drivers and charger site hosts.  

The report states that EV charging will not only create unprecedented growth in demand, but also may create localized pinch points, particularly along highway corridors, where large charging stations would be needed if there is a wholesale switch to EVs for long-distance travel. 

The authors cite recent studies by National Grid, Xcel Energy and other electric companies showing that grid upgrades and proactive planning should begin as soon as possible to meet future demand. (See Study Projects Power Demands of Highway EV Charging Network and DOE Funds Studies of Heavy-duty EV Charging Network Needs.) 

The authors noted that The Electric Power Research Institute has launched its EVs2Scale2030 initiative to start working toward the “unprecedented” coordination of diverse stakeholder groups that will be needed to enable a national transition to EV travel. 

Notwithstanding the recent fluctuations in the EV industry, most projections call for steadily increasing EV adoption. 

EEI said improvements in battery technology, decreases in vehicle costs and favorable federal/state policy decisions have caused the EV market to expand and caused the growth projections to increase. 

There are unknown variables, including the future popularity of plug-in hybrid vehicles (PHEVs), which combine an internal combustion engine with a battery smaller than those in battery electric vehicles (BEVs).  

PHEVs cannot use DCFCs, the fast-working chargers that cost substantially more to install and place much higher demand on the grid than L1 and L2 chargers. 

If enough American car buyers choose PHEVs over BEVs, fewer DCFC ports will be needed. The report indicates that 15% PHEV adoption could save several billion in capital costs for charging infrastructure compared with 10% adoption. 

The reported projects that 325,000 DCFC ports will be needed in 2035, each with a price tag potentially ranging into the six digits, and they will be critical to soothing the range anxiety that deters some car buyers from considering BEVs. 

But that is less than 1% of the projected total number of ports, the report says. The other 99% are L1 and L2 chargers — 85% at residences, 7% at workplaces or multifamily dwellings and 7% at public charging sites. 

EEI is the industry association for U.S. investor-owned electric companies. 

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MISO: Lower Prices, Fewer Outages and Annual Peak in August

MISO reported relatively lower costs and outages in August while it served its annual peak late in the month.

MISO averaged 86 GW load over August, about 1 GW lower than August 2023’s average, according to MISO’s monthly operations report. MISO’s 122-GW annual peak arrived in the afternoon on Aug. 26 during a heat wave and a maximum generation warning. (See Late August Heat Wave Delivers 122-GW MISO Summer Peak.)

The summertime peak was lower than 2023’s 125-GW peak, which was set nearly a year to the date earlier during a separate heat wave and maximum generation warning.

Average daily generation outages were down year over year, at 30 GW, an 8 GW improvement over last August.

Real-time locational marginal prices also were down year over year, at $26/MWh from $33/MWh. However, natural gas and coal prices remained static from 2023 at $2/MMBtu. The pricing was a far cry from 2022, when August saw average real-time prices of $87/MWh and $8/MMBtu coal and natural gas prices.

Natural gas delivered the greatest share of terawatt hours this August, at 28 of the month’s total 62 TWh. Coal supplied 17 TWh, a stark contrast from the 26 TWh coal managed in August 2021.

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DOE Funding 4 Large Tx Projects, Releases National Tx Planning Study

The U.S. Department of Energy has announced two actions to support the expansion of the transmission grid: investing up to $1.5 billion in four specific projects around the country and releasing the final National Transmission Planning Study. 

The $1.5 billion investment from the Transmission Facilitation Program was authorized by the Infrastructure Investment and Jobs Act. DOE is giving the money upfront to four projects, which eventually can sell it to actual users, at which point the department will get its money back to use on future transmission projects, Deputy Energy Secretary David Turk said on a call with reporters Oct. 1.

“Like many things about the clean energy transition, building new transmission is extremely challenging, and it’s also extremely urgent,” Turk said. 

DOE announced the first three lines under the TFP last fall; all three have signed deals with the department, Turk said. In total, the TFP should help build more than 3,000 miles of new transmission by early next decade. (See DOE to Sign up as Off-taker for 3 Transmission Projects.) 

Avangrid Network’s Aroostook Renewable Gateway in Northern Maine will negotiate for DOE for funding of up to $425 million to build the 111-mile project that seeks to link up to 1,200 MW with ISO-NE. The region lacks direct connections with the rest of New England, and the line would help three mature wind projects connect to the market, with the potential for more wind and solar development. 

Invenergy’s Cimarron Link Transmission is negotiating for TFP funds of up to $306 million to build its 400-mile HVDC line running from Oklahoma’s panhandle to Tulsa in the east, opening 1,900 MW of transfer capacity that can deliver wind and solar to load centers.

Pattern Energy’s Southern Spirit Transmission project also is up for negotiations for $360 million to help get the 320-mile, 525-kV HVDC line that would connect ERCOT to the Southeast. The line can ship up to 3,000 MW of renewables from Texas to the Southeast and can ship power the other way if demand spikes in Texas. 

Southern Spirit could better help ERCOT make it through a cold snap, avoiding some of the devastation seen during Winter Storm Uri in 2021, White House National Climate Advisor Ali Zaidi said. 

“This buildout is really transformational in breaking down the barrier between ERCOT and the rest of the country, and it feeds into this broader insight that this administration has pushed, which is essentially [that] interregional transmission translates to lower costs for consumers and higher reliability across the system,” Zaidi said. 

Southern Spirit has been under development for years, with FERC finding in 2014 that it would not trigger federal regulation over ERCOT, according to a fact sheet from Pattern. 

Phase 2 of Grid United and Black Forest Partners’ joint Southline Transmission Project would add a 108-mile, 345-kV line capable of delivering 1,000 MW of capacity across New Mexico, helping to support electricity delivery in the Southwest. It is up for $352 million. Southline Phase 1 was in the first set of projects announced last year. 

“You need only to look at the recent devastation of Hurricane Helene to know how the climate crisis is already straining our existing grid infrastructure at the precise moment when we need that infrastructure to be larger, stronger and more reliable,” White House Senior Advisor John Podesta said.

National Transmission Planning Study

The National Transmission Planning Study features a set of long-term planning tools and analyses that examine potential scenarios through 2050, including various interregional transmission expansions. 

It shows the highest level of grid reliability can be maintained at the lowest cost by coordinating interregional transmission. The study was developed by the DOE Grid Deployment Office alongside the National Renewable Energy Laboratory and the Pacific Northwest National Laboratory, who said they want other planners to use it in their efforts. 

A substantial expansion of the transmission system throughout the entire contiguous U.S. delivers the largest benefits of up to $270 billion to $490 billion through 2050. Every dollar invested in transmission leads to returns of $1.60 to $1.80 in system costs saved, the study found. 

Being able to coordinate resource adequacy across better connected regions lowers systems costs by $170 billion to $380 billion, the study found. 

The use of HVDC transmission technologies with multiple terminals — meaning power can be sent bidirectionally and from multiple entry and exit points in regions — was shown to be the most cost-beneficial way to stitch together a macrogrid across the Lower 48. 

“When translating zonal scenarios to nodal network models, HVDC was found useful for transferring power over long distances and between interconnections, but AC network expansion will continue to be the best solution for a large portion of transmission additions,” the study said. “Large interregional HVDC network solutions will also require additional strengthening of the regional AC networks they interconnect.” 

DOE has been working on the NTP since 2022. Its goal was to identify pathways that maintain current levels of reliability and saving costs while meeting local, regional and national interests, Grid Deployment Office Director Maria Robinson said on a call with reporters. 

“This study goes down to the nodal level, instead of at the zonal/regional level, and that means that this is a tool that utilities can actually use to help them determine what kinds of investments that they might want to make,” Robinson said. 

So far, interregional transmission plans have been limited, with Robinson pointing to MISO and SPP’s Targeted Interconnection Queue Study as a rare example of it actually happening. 

“So, this is why we think it’s important to make sure that these tools are available, so that it is easier for those folks who are looking to do so, and also so that we’re able to use the best-in-class modeling available from the National Laboratories,” she added. 

DOE is not going to tell FERC how to do its job, she added. Chair Willie Phillips has said the commission could look at interregional planning in the future, noting that NERC’s interregional transfer capability is due at the end of the year. (See Webinar Examines How FERC Could Use Interregional Transmission Study.) 

The department has provided some technical assistance to NERC on its interregional transfer capability study and offered updates on what was being developed in the NTP, Robinson said. 

“Of course, while doing coordination, it doesn’t mean that the exact thing will happen in both places,” Robinson said. “So, we are really looking forward, as everyone else is, to seeing the ultimate results come out of that study. But a lot of the fundamentals are relatively similar, and it’s just nice to see this greater interest in interregional transfer capacity, understanding that it can be so important in times like right now in extreme weather events.” 

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CAISO Launches Phase 2 of Pricing Issues Initiative

CAISO on Sept. 30 launched Phase 2 of its Price Formation Enhancements Initiative, aimed at addressing issues specific to market power mitigation, scarcity pricing and fast-start pricing in its markets — including the Western Energy Imbalance Market and Extended Day-Ahead Market.

“These enhancements aim to improve the accuracy of our market clearing prices, provide better market price signals, and enhance incentives for resources to perform,” James Friedrich, CAISO lead policy developer, said during a meeting to launch the effort. “It is the general view of the [Price Formation Enhancements] working group that enhancements in these areas could help the market become a more effective steward of reliable outcomes.”

Phase 1 of the initiative hosted 18 working group meetings and resulted in a FERC-approved tariff change that allows hydroelectric and energy storage resources to bid above the ISO’s $1,000/MWh soft offer cap. (See FERC Approves CAISO Request to Lift Soft Offer Cap for Hydro, Storage.)

Scarcity Pricing

Scarcity pricing, a mechanism to determine market prices when supply falls short of demand, came into focus for CAISO following grid emergencies during the summers of 2020, 2022 and 2023, Friedrich said.

The increased risk that comes with declining reserves and a rising loss-of-load expectation should translate into the market’s willingness to pay more for additional reserves to maintain reliability. And while the ISO already relies on a number of different scarcity pricing mechanisms — including the scarcity reserve demand curve, the flexible ramping product and bidding above the soft offer cap — ISO staff and stakeholders saw a need to improve on those mechanisms to ensure more efficient market outcomes and maintain grid reliability.

“It’s important to note that while these mechanisms provide a good foundation for scarcity pricing in our markets, this initiative considers potential enhancements to ensure that they accurately reflect scarcity conditions across the entire market footprint and across all market intervals,” Friedrich said.

Staff and stakeholders have identified four key issues around scarcity pricing.

First, the market is inconsistent in how it procures ancillary services, a function not applicable to the WEIM or EDAM. The real-time market only procures incremental ancillary services for the CAISO balancing authority area (BAA), rather than fully re-optimizing them, Friedrich said. The market also doesn’t re-optimize in the five-minute market, leading to less efficient scarcity pricing outcomes and procurement.

Second, prior working groups also identified potentially outdated penalty prices, which currently are tied to the market bid cap and may not accurately reflect the true reliability value of a resource during scarcity events, Friedrich explained. Stakeholders also expressed concern the prices may be too low to provide effective incentives.

The third issue relates to potential disconnects between market prices and grid conditions during emergencies. The current market design may not adequately reflect the severity of emergency conditions in market prices, Friedrich said, leading to situations in which prices don’t align with the actual scarcity level indicated by emergency operator actions.

The last problem centers around insufficient scarcity signals. The scarcity reserve demand curve and power balance constraint violations in the market only get triggered during actual shortages, Friedrich said, which can result in price spikes that are “volatile and unpredictable.”

“Collectively, these issues point to the need for reform of our scarcity pricing mechanism, and by addressing these problems we aim to improve market efficiency, enhance reliability and provide more accurate price signals that reflect real-time grid conditions,” Friedrich said.

Elaborating on the initiative’s main objectives, Friedrich highlighted three main goals:

    • to improve market signals during tight supply conditions so that prices accurately reflect the true state of the grid;
    • to incentivize resource performance and demand reduction; and
    • to align prices with real-time grid conditions across the WEIM.

But two significant hurdles stand in the way of achieving these goals, Friedrich said. The first is the need to address discrepancies in how scarcity pricing applies across different balancing authorities in the market, while the second is the need to identify a “consensus-driven method to scale and anchor penalty prices.”

Market Power Mitigation

Friedrich said CAISO also must change rules around market power mitigation, which prevents the exercise of structural market power when a BAA is price-separated from CAISO.

Three main problems were identified in prior working groups: structural market power may be overestimated in individual BAAs; the CAISO BAA is excluded from the market power mitigation test; and the frequent mitigation during off-peak hours with low prices raises questions about current triggers.

The top priority is to ensure competitive pricing while refining mitigation mechanisms for WEIM and Extended-Day Ahead Market (EDAM) BAAs.

Fast-start Pricing

Friedrich also gave an overview of fast-start pricing, which integrates commitment costs of fast-start resources into market prices.

“Fast-start pricing recognizes that fast-start resources may serve as the marginal resource used to meet the next increment of energy or operating reserves demand,” Friedrich’s presentation said. “However, they often have output levels that prevent them from being fully dispatchable and thus are often ineligible to set the LMP.”

Phase 1 included a stakeholder-requested analysis to determine the potential market impact of fast-start pricing and whether it should be implemented. The analysis demonstrated a “generally moderate” impact, and some stakeholders saw value in continuing to prioritize the topic in discussion, while others didn’t. While members of the working group haven’t reached consensus, they mostly supported a deeper analysis of fast-start pricing.

Supporters of SPP’s Markets+ have pointed to the absence of fast-start pricing as a shortcoming of the EDAM.

The working group’s next Phase 2 meeting is tentatively scheduled for Oct. 23, and the target date for a straw proposal is May 25, 2025.

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FERC Rejects Mabee’s 2021 Supply Chain Complaint

FERC on Oct. 1 rejected a three-year-old complaint by security gadfly Michael Mabee requesting the commission order an audit of the electric grid looking for potentially harmful equipment manufactured in China and reliability standards requiring any new Chinese equipment to be tested for harmful capabilities (EL21-99). 

Mabee filed his complaint in August 2021, citing contemporary reports from media outlets and government officials that China had conducted “a campaign of cyberattacks” against critical U.S. infrastructure, including the energy sector. Specifically, he warned that U.S. electric utilities bought equipment made in China and installed it on the grid. 

This “could facilitate a cyberattack” by the Chinese government, Mabee asserted, particularly because — as he said — there were no requirements by the U.S. government or in NERC’s standards that entities inspect Chinese equipment for cyber risks and vulnerabilities either before or after installation. 

To address these supposed risks, Mabee requested the commission direct NERC to: 

    • survey all registered entities in the electric grid to find out “what Chinese equipment or systems” are in use; 
    • submit a proposed reliability standard for “testing and security of Chinese equipment or systems” that are in use on the bulk power system or purchased in the future; and 
    • work with state regulators to encourage adoption of the proposed standard or a state equivalent on the parts of the grid under state jurisdiction. 

NERC responded to Mabee’s complaint in 2021, arguing that FERC should deny his request on the grounds that several existing Critical Infrastructure Protection (CIP) standards already required entities to assess risks to the grid when acquiring applicable electronic systems. The ERO said that if the CIP standards identified a specific foreign nation by name, as Mabee requested, it might be harder to apply them to “other nation-states that may pose a threat.” (See “NERC Argues to Dismiss Supply Chain Complaint,” NERC Seeks FERC Approval to Fund Office Move.) 

Other commenters were more sympathetic to Mabee, FERC noted in its order. The Secure the Grid Coalition — a security-focused think tank to whose website Mabee has contributed several articles — suggested FERC conduct a technical conference, possibly in conjunction with a special task force, to “determine the potential threat posed [to the grid] by Chinese transformers and other grid control and monitoring systems.” 

The Foundation for Resilient Societies — a nonprofit aimed at “boosting critical infrastructure resilience and recoverability” — also requested that FERC, NERC and other agencies conduct an investigation into the threat posed by Chinese equipment. In addition, several individuals filed comments expressing support for Mabee’s position and urging the commission to take the threat of Chinese infiltration into the power grid seriously. 

Mabee himself has followed up his original complaint with multiple subsequent filings prodding FERC to take action. His most recent filing was this February, when he submitted data from the Census Bureau purportedly showing the U.S. imported 449 transformers of more than 10,000 kVA from China between 2006 and 2023. 

FERC Sides with NERC

FERC agreed with NERC that “the relief sought [by Mabee] is duplicative of existing reliability standards, as well as past and ongoing efforts by the commission and other federal agencies.” 

In addressing Mabee’s request for an audit of electric utilities for Chinese equipment, FERC observed that NERC can “assess the risks associated with foreign owned suppliers” through existing means such as NERC Alerts. It cited two such alerts, issued in 2019 and 2020, requesting information from registered entities on exposure to cyber risks from equipment manufactured in China, Russia and other foreign adversaries. 

FERC also sided with NERC in its defense of the CIP standards, and noted its own activities, along with other federal agencies, to address the risks posed by equipment manufactured overseas. Since Mabee’s complaint, FERC has held two technical conferences in 2021 and 2022 covering cyber risk management in the power sector and supply chain security challenges in the power grid. 

Concerns over China’s cyber prowess in recent years have focused more on its capabilities in software than in hardware. Last year Volt Typhoon, a cyber actor connected to China by the Cybersecurity and Infrastructure Security Agency and other security organizations, was accused of infiltrating U.S. critical infrastructure organizations disguised as legitimate users. 

In a congressional hearing this year, FBI Director Christopher Wray called China’s cyber posture “the defining threat of our generation” and warned that the country’s hackers were preparing “to wreak havoc and cause real-world harm to American citizens and communities.” (See China Preparing to ‘Wreak Havoc’ on US, Cyber Officials Warn.) 

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OSW Industry, Advocates See Hope in NE Multistate Procurement

Even as the offshore wind industry continues to struggle, stakeholders’ hopes have been buoyed by the recent multistate procurement in New England, they said during a webinar held by the Northeast Energy and Commerce Association on Oct. 1. 

Massachusetts selected up to 2,678 MW of offshore wind capacity in early September, while Rhode Island selected 200 MW. (See Multistate Offshore Wind Solicitation Lands 2,878 MW for Mass., RI.) 

“I think Massachusetts was pretty bold in doing procurements of this size, and I think that’s going to help get offshore wind back on track,” said Ken Kimmell, chief development officer at Avangrid Renewables. 

Kimmell said he is “starting to see the ship righting itself” in the wake of the price shocks that caused a wave of project cancellations in 2023. 

Massachusetts and Connecticut are in talks for Connecticut to purchase the remaining 400 MW of the Vineyard Wind 2 project in exchange for Massachusetts purchasing some power from the Millstone nuclear plant, which currently is propped up by a contract with Connecticut. 

The rapidly increasing costs of offshore wind have caused some trepidation from New England lawmakers; the 2,678 MW selected in the multistate procurement fell significantly short of the 6,000 MW initially sought by the three states. 

While the prices for the procurement will not be announced until the contracts are filed with state utility regulators, the cost of offshore wind per megawatt-hour has roughly doubled in just a few years. 

“The last couple years have been hard for the offshore wind industry … but I think the future is bright,” said Moira Cyphers, director of Atlantic offshore and eastern state affairs at the American Clean Power Association. “This is a resource that we absolutely have to have. The climate goals and the reliability goals don’t happen without offshore wind.” 

Despite the current cost pressures, Cyphers said procuring projects at scale “is really what’s going to bring down costs over time.” 

Cyphers added that the first line of projects will shoulder costs associated with building up the domestic supply infrastructure, ports and shipping capabilities, which “future projects will then build on.” 

Kimmell echoed the need to improve the domestic supply chain and added that increasing global demand for offshore wind has exacerbated the recent cost increases. 

“Supply and demand are out of whack,” Kimmell said. “We are at a real disadvantage relying so much on European suppliers.” 

Kimmell also voiced his support for longer contracts for offshore wind resources. 

“It [would] reduce prices to ratepayers if Massachusetts were to extend the length of contracts,” Kimmell said, noting that the current generation of turbines will last “quite a bit longer than 20 years.” 

Cyphers said more flexibility regarding economic adjustment mechanisms could help improve future solicitations. 

“I think flexibility is going to become a lot more important at this stage in development,” Cyphers said, noting that Connecticut, Massachusetts and Rhode Island each took slightly different approaches to the inflation indexation options they gave to developers. Ultimately, no indexed project bids were selected. 

“I think to the extent that we can work to identify other ways to introduce flexibility, and make sure these procurements become more standardized, we’ll see more success in the future,” Cyphers said. 

Ben D’Antonio, manager of transmission strategy and economic analysis for Eversource Energy, stressed the need to develop transmission solutions to add “certainty and clarity” to the process of interconnecting offshore wind projects. 

He expressed hope that state-level efforts to reform permitting and siting procedures, coupled with FERC’s new interconnection requirements, eventually will help to speed up development timelines, which currently take about a decade for offshore wind projects. 

While developers have limited insight on where the best places to interconnect are, D’Antonio advocated for a more proactive transmission development approach. He floated the idea of charging a fixed fee for projects to interconnect so developers could “know ahead of time what it’s going to cost to interconnect.” 

“We want to try out this ‘build it and they will come’ approach,” D’Antonio added. “There’s no transition without transmission.” 

This year, FERC approved a proposal from ISO-NE and the New England states that would enable the states to make transmission investments to meet long-term needs, including needs associated with new offshore wind generation. (See FERC Approves New Pathway for New England Transmission Projects.) The six New England states also recently won a $389 million Department of Energy grant that largely will be dedicated to building substations to connect offshore wind to the grid. (See DOE Announces $2.2B in Grid Resilience, Innovation Awards.) 

Kimmell echoed D’Antonio’s comments about the need for proactive transmission planning, saying a line-by-line approach to transmission solutions makes sense for the initial projects coming online, but not for the next wave. 

“We certainly embrace the idea of shared transmission and planned transmission,” Kimmell said, advocating for the socialization of some of the costs associated with building transmission for offshore wind. 

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Re-ballot Underway for IBR Ride-through Standard

[Editor’s note: A previous version of this article incorrectly stated that PRC-029-1, addressing IBR frequency and voltage ride-through requirements, passed a ballot round that concluded earlier this week. The standard that passed that ballot round was actually PRC-024-4 (Frequency and voltage protection settings for synchronous generators, type 1 and type 2 wind resources, and synchronous condensers). PRC-029-1 is undergoing a re-ballot that will end Oct. 4 at 8 p.m. ET. The text below has been updated to reflect this.]

NERC’s proposed reliability standard addressing ride-through protection for inverter-based resources (IBRs) is undergoing a re-ballot in hopes of gaining enough industry support for passage, as the ERO’s Board of Trustees prepares to meet next week to formally adopt the five proposed IBR standards needed to meet a FERC deadline.

The ballot for PRC-029-1 (Frequency and voltage ride-through requirements for IBRs) was originally scheduled to end on Sept. 30 but was extended to Oct. 4 to allow industry more time to review revisions, summarized in a memo on the project’s NERC webpage.

A ballot for the standard’s implementation plan will also close Oct. 4. The implementation plan also covers PRC-024-4 (Frequency and voltage protection settings for synchronous generators, Type 1 and Type 2 wind resources, and synchronous condensers), which was developed by the same drafting team as the ride-through standard.

PRC-024-4 did close its final ballot round Sept. 30, with industry stakeholders, voting by segment, casting 184 votes in favor of the standard, compared with 34 negative votes with comments, while 53 members of the ballot body either abstained or didn’t cast a vote. NERC weights its standards voting by segment participation so that industry segments with fewer voters will count less in the final tally. Therefore, the final segment-weighted value is 86.41% in favor, well over both the two-thirds majority needed for approval.

At its August meeting, NERC’s board exercised for the first time its authority to streamline the ERO’s regular stakeholder approval process, after PRC-029-1 did not receive industry approval after multiple ballot rounds. Board Chair Kenneth DeFontes warned this put the ERO in danger of failing to meet FERC’s deadline, imposed last year, to submit reliability standards addressing IBR performance requirements, disturbance monitoring data sharing and post-event performance validation by Nov. 4, 2024. (See NERC Board of Trustees/MRC Briefs: Aug. 15, 2024.)

The board ordered NERC’s Standards Committee to convene a technical conference to receive input from industry and other ERO stakeholders on the ride-through standard in order to shape a version palatable to enough ballot body members to get across the finish line. At the conference, which was held Sept. 4-5 in D.C., representatives from a range of industry segments — including NERC, original equipment manufacturers and utilities — discussed their issues with the proposed standard. (See NERC, Industry Discuss IBR Issues in Technical Conference.)

After the conference, NERC revised the standard to address attendees’ concerns, including the clarity of the definition of “ride-through,” criteria for frequency ride-through performance and exemptions to ride-through criteria for equipment with hardware limits.

If it passes this ballot round, PRC-029-1 will not be posted for the customary final ballot, another result of the streamlined process approved at the August board meeting. At their meeting Oct. 8, trustees will vote on PRC-029-1 and PRC-024-4, along with the other IBR standards that are subject to FERC’s November deadline and were approved in previous ballot rounds:

    • PRC-028-1 — Disturbance monitoring and reporting requirements for inverter-based resources.
    • PRC-002-5 — Disturbance monitoring and reporting requirements.
    • PRC-030-1 — Unexpected inverter-based resource event mitigation.

If PRC-029-1 does not receive a two-thirds segment-weighted vote in favor, the board may still consider it approved if it receives at least 60% of the vote. In that case, the board must solicit written public comment on the proposed standard and may convene an additional technical conference. If the board is satisfied that the standard is just, reasonable, not unduly discriminatory or preferential, and in the public interest, it may then file the standard with FERC for approval.

In the event that the standard does not receive at least a 60% segment-weighted majority, the board has other options available, including directing the Standards Committee or NERC management to prepare another draft standard, convening another technical conference, and approving the standard after a 45-day public comment period but without a formal ballot.

Also on the board’s agenda next week are revisions to the charter of NERC’s Reliability and Security Technical Committee (RSTC) that are intended to improve the balance of industry representation at meetings. The new rules will allow a sector to seek a special election to fill an open seat representing it, rather than have that seat convert to an at-large member as the current charter provides.

In addition, they will remove the numerical cap on the number of representatives from a sector that can serve as at-large members and will direct the RSTC Nominating Subcommittee to prioritize balanced sector representation.

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Exelon Asks FERC to Weigh in on Co-location Dispute with Constellation

Exelon on Sept. 30 filed a petition for a declaratory order from FERC on its dispute with Constellation Energy over the latter’s effort to co-locate major loads at two of its nuclear plants (EL24-149).

The two firms, which used to be one before Exelon spun off its generation and competitive retail businesses into Constellation, have been on opposite sides of the debate on co-location from a purely policy level. (See Talen Energy Deal with Data Center Leads to Cost Shifting Debate at FERC.)

But Exelon’s petition lays out the actual business dispute. Constellation is seeking to co-locate new loads at its Calvert Cliffs Nuclear Power Plant in Maryland and Limerick Nuclear Power Plant in Pennsylvania. Those plants are connected to the grid owned by Exelon’s Baltimore Gas & Electric (BGE) and PECO Energy utilities, respectively.

Neither the petition, nor the legal correspondence filed alongside it, mention data centers specifically with the modifications. But Exelon argued that Constellation’s moves could harm new and existing customers, including data centers. The economics of co-locating data centers at nuclear plants are lucrative, as a deal with Microsoft was enough to get Constellation to reopen the recently retired unit at Three Mile Island, Exelon said.

“Constellation has wrongly claimed that the existing interconnection agreements between the petitioning utilities and predecessors of Constellation (and, in the case of Calvert, PJM) entitle it to connect new end-use load without regard to the purpose and terms of the existing interconnection agreements or to the retail nature of the interconnection and requested services involved,” Exelon said in its petition.

Exelon wants FERC to find that PJM’s generator interconnection procedures under Order 2003 only apply to end-use generation, not load. FERC also should declare that interconnection of end-use load is a matter of state, not federal jurisdiction, the company argued.

Under the Federal Power Act, FERC is required to respect states’ role to regulate retail rates, Exelon said. Order 2003 itself was aimed at ensuring fair competition for generation, and FERC should make clear that it does not apply to end-use customers, it argued.

Exelon also asked FERC to find that a request to reconfigure existing generator interconnections to accommodate the co-located large, new loads would require modification of the relevant interconnection agreements to reflect the new interconnection facilities and the changed nature and purpose of the interconnection. That requires the consent of all the parties to such deals, the company argued, urging FERC to declare that as well.

The company said it supports the efforts of retail customers who chose to co-locate at generators when that can be accomplished safely and reliably and when load pays for its fair share of the costs of the electric grid, as defined by the applicable state and federal rates.

“Fortunately, the standard process of adding end-use load to the system is well understood and can be accomplished quickly while protecting system reliability and other customers,” Exelon said. “That process requires only that the load becomes a retail customer of the relevant distribution utility or cooperative, pay rates under existing tariffs, and that the interconnection be studied for safety and reliably.”

Changing the interconnection agreements to include large new loads transforms such deals into three-legged arrangements connecting end-use load, generation and the grid, which is significantly different from plugging a generator on its own to the grid, Exelon said.

Both BGE and PECO received requests for such co-locations, and they asked questions that would reflect the standard process for load additions, in which the customer itself or its agent asks the local distribution utility for service and describes the nature of the load and other factors.

Constellation took exception to those requests, saying the two utilities were not allowed to “condition performance of [interconnection agreement] obligations,” Exelon said. Constellation argued it was not required to arrange for retail service for the co-located load deals it is pursuing, according to Exelon.

“By its plain terms, PJM’s tariff does not and could not contemplate interconnection of end-use load through the generation interconnection process,” Exelon said. “Moreover, in its letter concerning Calvert Cliffs, Constellation has also declared that it may resort to litigation or referrals, including supposed antitrust claims, if BGE does not immediately take steps to provide the service Constellation requests.”

The controversy reflects a fundamental disagreement on the law, which includes foundational principles of jurisdiction, in the context of matters of serious import, Exelon argued.

It “respectfully request[ed] that the commission issue declarations that will settle this controversy, which threatens to cloud and undermine the jurisdictional and regulatory division between the states and the federal government embodied in the FPA, and which promises widespread, protracted litigation because requests to modify generator interconnections to accommodate co-located end-use load are becoming increasingly common,” Exelon told FERC. “By eliminating any confusion created by Constellation’s attempts to shift costs of co-located load at its generator interconnections, the commission can speed the energy transition, ensure reliability and protect all customers.”

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Newsom Signs Bundle of Grid-related Bills from 2024 Session

California Gov. Gavin Newsom has signed a bill to streamline approval of transmission projects by removing a requirement for regulators to evaluate non-transmission alternatives such as demand-side management. 

Assembly Bill 2292, by Assemblymember Cottie Petrie-Norris (D), is just one in a bevy of bills the governor signed into law in the days leading up to a Sept. 30 bill-signing deadline. Other new laws relate to bi-directional EV charging, industrial energy use and hydrogen fueling stations. 

Proponents of AB 2292 said the bill makes a modest but important change to the California Public Utilities Commission approval process for transmission projects.  

The bill removes a requirement for the CPUC to consider cost-effective alternatives to transmission facilities “that meet the need for an efficient, reliable and affordable supply of electricity.” Those alternatives may include demand-side options such as targeted energy efficiency or ultraclean distributed generation. 

Requiring the CPUC to review alternatives duplicates work done by CAISO in identifying the need for the project as part of its transmission planning process, supporters said. 

The new law comes as the CPUC is updating its General Order 131-D to make the permitting process for transmission projects more efficient and consistent. (See CPUC Works to Revamp Tx Permitting Rules.) 

Bi-directional Charging Bill

Another bill signed by Newsom could lead to a requirement for electric vehicles to be equipped for bi-directional charging. 

Senate Bill 59, by Sen. Nancy Skinner (D), authorizes the California Energy Commission (CEC) to require any size class of battery EV to be capable of bi-directional charging — if there is a “compelling beneficial” use case for both the EV operator and the electrical grid. 

“Bi-directional capabilities in BEVs have the potential to improve customer energy reliability, resiliency and demand management during electric grid stress events while supporting our state’s transition to zero-emission transportation,” Newsom said in a bill-signing message. 

The governor’s message noted the complexities of aligning BEVs with the bi-directional charging equipment, while factoring in electric rates and potential grid effects. 

Another Petrie-Norris bill signed by the governor is AB 2779, which promotes the use of grid-enhancing technologies. The bill requires CAISO to report any new use of GETs that it deems reasonable, along with the cost savings and efficiency of that technology, when it approves a transmission plan.  

GETs are a way to expand the capacity of the grid much more quickly than building new transmission, which can take years. They include advanced reconductoring and other technologies. 

The governor previously signed SB 1006, by Sen. Steve Padilla (D), which requires utilities to study the feasibility of using GETs. (See California GETs Bill Gets Newsom’s Signature.) 

RA Requirements

Another bill signed into law is Petrie-Norris’ AB 2368, which addresses electric system reliability. 

The bill, sponsored by the Clean Energy Buyers Association, requires the CPUC to adopt a 1-in-10 loss of load expectation (LOLE), or a “similarly robust reliability metric,” when setting resource adequacy requirements. (See Clean Energy Buyers Push Passage of New Calif. Reliability Law.) 

The bill also requires the CPUC to determine whether measures are needed to reduce the costs to ratepayers of a resource adequacy program. 

A bill sponsored by the California Nevada Cement Association also received Newsom’s signature. AB 2109, by Assemblymember Juan Carrillo (D), will exempt large industrial customers from paying their utility a departing load charge if they use waste heat to generate their own power. 

The bill will make industrial process heat recovery cost effective and advance the state’s efforts to decarbonize manufacturing, CNCA Executive Director Tom Tietz said in an opinion column. 

Hydrogen Fueling Stations

SB 1418 by Sen. Bob Archuleta (D), which the governor signed, is intended to speed up local government permitting of public hydrogen-fueling stations. 

Cities and counties are already required to streamline the permitting process for EV charging stations. SB 1418 will extend that streamlining by requiring cities and counties to adopt an ordinance and checklist for permitting hydrogen-fueling stations.  

Archuleta noted in a release that the Department of Energy has awarded up to $1.2 billion to California’s hydrogen hub, the Alliance for Renewable Clean Hydrogen Energy Systems (ARCHES). 

“Success hinges on rapidly scaling up hydrogen-fueling infrastructure and vehicle development,” the release said. “California cannot achieve its zero emission goals without success at the local level.”