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January 20, 2025

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First FERC Filings Shed Light on New England OSW Tx Project

The transmission companies behind a major project to preemptively build two offshore wind interconnection points in New England have submitted their first FERC filings for the project, outlining the potential benefits of the project and the significant risks that could derail its development. 

The Power Up New England Project, a collaboration among the six New England states, Eversource Energy, National Grid and Form Energy, was selected in 2024 to receive $389 million from the U.S. Department of Energy’s Grid Innovation Program. (See DOE Announces $2.2B in Grid Resilience, Innovation Awards.) 

The project would create two interconnection points, located in Massachusetts and Connecticut, each capable of accommodating up to 2,400 MW of offshore wind capacity. Power Up also proposes to build a first-of-its-kind 100-hour battery in Maine. (See Form Energy to Develop First Multiday Storage Project in New England.) 

National Grid plans to develop its interconnection point at Brayton Point in southern Massachusetts (ER25-866), while Eversource proposes to build its portion of the project at the Huntsbrook Junction in eastern Connecticut (ER25-747).  

In the initial FERC filings for the project, the transmission owners requested that the commission authorize the full recovery of all prudently incurred costs if the project is canceled because of factors beyond the companies’ control. They said they likely would need approval of this request to proceed with the project. 

“It is highly unlikely that National Grid would be able to develop and construct NGPUP in the absence of firm assurance that it can recover its full prudent investment in the project in the event of termination, cancellation or abandonment outside of National Grid’s control,” said Andrew Schneller, vice president of New England electric regulation and strategy at National Grid. 

Eversource also requested a 50-basis-point adder for giving ISO-NE control of the facility when built. 

The New England States Committee on Electricity (NESCOE) has expressed support for the Eversource and National Grid requests. In a filing supporting Eversource’s request, NESCOE wrote that the cost recovery assurances are justified because the project features a lower profitability and additional risks of cancellation relative to a typical project. 

The transmission owners will not be able to earn a return on the portion of the project investment covered by the federal grant and have agreed to give NESCOE the right to cancel the project if the costs exceed the original estimate. 

“Although NESCOE would ordinarily be skeptical of a request for an incentive that would allow a transmission developer to recover 100% of its prudently incurred costs for its abandoned plant, NESCOE agrees with [Eversource] that the full abandoned plant incentive is just and reasonable here given the uniqueness of the Huntsbrook Project,” NESCOE wrote. 

Power Up also faces unique limits on its development timeline. It must be in service within eight years of the finalization of the federal funding agreement, which National Grid wrote is likely to occur in early 2025.  

“Eight years is a tight schedule for a project like NGPUP in the best of times,” Schneller said, noting that worker shortages and supply chain delays for transmission equipment have increased since the COVID-19 pandemic. 

He added that the project faces political risks at the state and federal level. 

“A reduction of federal tax incentives for renewable energy development or a slowing of federal regulatory review of offshore wind generation licenses could lead the states to re-evaluate the feasibility or benefits of new projects,” Schneller said, adding that the project could face a funding shortfall if one of the New England states rescinded its support.  

Potential Benefits

While the project features substantial risks, the states and transmission owners expect it to bring significant cost, reliability and emissions benefits if it is successfully built.  

According to DOE’s Grid Deployment Office, the project would provide an estimated $1.55 billion in wholesale energy costs savings. Eversource estimated “the offshore wind enabled by the Huntsbrook Project will reduce wholesale energy supply costs borne by New England customers by approximately $498 million (2023 real dollars) over a 10-year period.” 

Benjamin D’Antonio, director of economic analysis and transmission strategy at Eversource, testified that the project would help reduce the risks associated with offshore wind interconnection, lowering “the risk premium that an offshore wind developer may include in their clean energy supply offer in the solicitation context.” 

The additions of offshore wind also would provide significant reliability benefits to the region’s grid, D’Antonio said. He estimated the addition of 2,400 MW of offshore wind at Eversource’s proposed interconnection point would reduce energy shortfall by 187,000 MWh over a worst-case, 21-day winter scenario.  

“ISO-NE has shown that offshore wind can provide significant resilience benefits to the New England electric and gas systems during extreme cold weather events by reducing both stress on gas pipelines and reliance on other fossil fuels such as oil,” D’Antonio said. (See ISO-NE Study Highlights the Importance of OSW, Nuclear, Stored Fuel.) 

The 2,400-MW injection of offshore wind also would reduce carbon emissions by at least 3.6 million tons annually, D’Antonio noted.  

NESCOE wrote that its own analysis “showed similar results to Mr. D’Antonio’s analysis of the Huntsbrook Project.” It added that it projects Power Up to provide net benefits even with a 150% cost overrun, 50% decrease in benefits and three-to-five-year delay in offshore wind deployment. 

“Due in large part to the significant benefits provided by the DOE grant, net benefits remained positive unless NESCOE assumed that offshore wind projects were delayed by several decades,” NESCOE wrote.  

If successful, the project could serve as a model for additional projects focused on interconnecting the resources needed to meet load growth and decarbonize the grid. ISO-NE estimated in October that the region would need to add an average of 1,293 MW of offshore wind, 268 MW of onshore wind, 955 MW of solar and 952 MW of batteries per year to meet state goals. (See ISO-NE Study Lays Out Challenges of Deep Decarbonization.) 

“The success of the Huntsbrook Project in establishing an onshore interconnection hub for offshore wind resources will offer a replicable model for any region aiming to integrate large-scale renewables like offshore wind,” Eversource wrote. 

However, the incoming Trump administration appears likely to attempt to roll back DOE funding for transmission projects, which would hurt the state’s chances at receiving additional funding for similar efforts over the next four years. The Heritage Foundation’s “Project 2025” calls for the Grid Deployment Office and the DOE Loan Program to be “eliminated or reformed.” (See How Much of the IRA Can be Saved in 2025?) 

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NERC Board Invokes Section 321 Authority for Cold Weather Standard

As snow and freezing temperatures enveloped the Central and Southeastern U.S. on Jan. 10, NERC’s Board of Trustees met virtually to exercise for the second time their authority to streamline the ERO’s stakeholder approval process in hopes of passing a cold weather standard before a FERC-imposed deadline in March. 

The board voted unanimously to invoke Section 321 of NERC’s Rules of Procedure, as recommended by the organization’s Regulatory Oversight Committee at its own special meeting before the board’s. The trustees’ decision was not a surprise, as NERC management has previously warned that the normal ballot and revision process was unlikely to produce a suitable revision to EOP-012-2 (Extreme cold weather preparedness and operations) in time to satisfy FERC’s directive. (See NERC: Board’s 321 Authority on the Table for Cold Weather Standard.) 

FERC approved EOP-012-2 (itself a revision ordered by the commission to address shortcomings of EOP-012-1) in June 2024, but it ordered additional “targeted modifications” to be completed by March 27, 2025. Although NERC has been working on the revisions since then, the replacement standard, EOP-012-3, garnered only a 44.54% segment-weighted vote for approval in its most recent formal ballot round that concluded Dec. 20. 

Board Chair Kenneth DeFontes had noted that the result was “not even close to reaching the required two-thirds [required] approval under our normal process, and the clock is ticking.” He said the ballot results indicated an “impasse” that will likely not be cleared through NERC’s normal processes. 

The board’s resolution directs NERC’s Standards Committee to work with stakeholders and ERO staff to prepare a standard that satisfies FERC’s order. If the committee is unable to draft a suitable standard, or determines that NERC’s management would be better suited to do so, then ERO management will write the standard. The standard will then be posted for a 45-day public comment period no later than Jan. 29. 

After the comment period, NERC management will bring the standard, along with all public comments, to a special meeting of the board in March to vote on adoption or consider other steps. No further ballots will be held, although the board’s resolution called for continued stakeholder involvement in the drafting and commenting process. 

This procedure differs from the last time NERC’s board invoked Section 321, to accelerate the development of PRC-029-1 (Frequency and voltage ride-through requirements for inverter-based resources) at its Aug. 15 meeting in Vancouver. (See “Board Invokes Standards Authority to Meet IBR Deadline,” NERC Board of Trustees/MRC Briefs: Aug. 15, 2024.) In that case, the board ordered the SC to conduct a technical conference to gain industry input on the proposed standard, then revise it and submit it for stakeholder ballot. 

Under Section 321.2-321.4, a standard needs only a 60% segment-weighted approval to pass; for this reason, NERC staff have informally dubbed the plan used for PRC-029-1 the “60% path.” The process proposed for the cold weather standard is found in Section 321.5; because it resembles a rulemaking procedure more than a normal balloting process, NERC Vice President of Engineering and Standards Soo Jin Kim said staff have called this the “NOPR option,” referring to federal Notices of Proposed Rulemakings. 

Trustee Sue Kelly noted that NERC already held a technical conference for this standard after it received a 42.29% segment-weighted approval vote in its first formal ballot round and that even though the conference had more than 400 attendees, the favorable vote only increased by just over 2%. Because of this, she said it seemed unlikely that enough industry support could be rallied in time to meet FERC’s requirement, even with another technical conference. 

“I … looked at the summation of the comments from the last [ballot] round, and honestly, I was a little distressed to see that many of them are what I would describe, at this point in the game, as being off-topic,” Kelly said. She cited comments that said market forces should be enough to drive utilities to the right level of winterization, or that NERC did not have the statutory authority to create the standard “because it would have competitive implications for generators.” 

“I found those comments pretty distressing, because when you step back and look where we are in this process — back in January 2014, NERC wanted to do a mandatory standard, and industry said, ‘No, let’s do a guideline,’” Kelly continued, noting that since that time, several severe winter storms have hit the U.S. with significant impacts to the grid. “We are way down the road at this point: We are being asked to [meet] specific FERC directives, [and] we’ve been told we have a time frame, and I believe that we … need to meet that challenge.” 

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WEIM Q3 Prices Down Despite Increased Loads, CAISO DMM Finds

Prices in CAISO’s Western Energy Imbalance Market fell sharply in the third quarter of 2024 compared with a year earlier, as declining gas costs outweighed the impact of increased summer loads, the ISO’s Department of Market Monitoring (DMM) found. 

Fifteen-minute market prices across the WEIM averaged about $40/MWh, down 31% from Q3 2023, while the five-minute price average fell by 32%, according to the DMM’s Q3 Report on Market Issues and Performance, which also touched on two issues supporters of SPP’s Markets+ raised late last year in one of a series of “issue alerts” comparing the SPP market to CAISO’s Extended Day-Ahead Market (EDAM). 

Day-ahead prices, which currently apply only to CAISO’s balancing authority area, fell by 28% year over year, the DMM found.

“Lower gas prices … brought electricity prices down with them,” Ryan Kurlinski, senior manager in the ISO’s Market and Policy Analysis Group, said during a Jan. 9 call to discuss the DMM report. 

Kurlinski noted that Q3 gas prices were down 37 and 58%, respectively, at the PG&E Citygate and SoCal Citygate delivery points in California and fell by 60% at the Sumas hub in the Pacific Northwest. 

Northwest hydroelectric output also increased by 15% compared with a year earlier, making the region a net exporter on average during all-in hours for the quarter. 

In the WEIM’s 15-minute market, prices averaged $47.50/MWh in California (down 27%), $35.60/MWh in the Desert Southwest (down 27%) and $33.30/MWh in both the Intermountain West and Pacific Northwest (down 23% and 30%, respectively). Powerex average prices declined by 60% to $37.90/MWh. 

“The [greenhouse gas] costs in California were the main contributors to elevating prices in California balancing areas relative to other WEIM balancing areas,” Kurlinski said.  

He added that “significant congestion” on WEIM transfer constraints into the Powerex and Bonneville Power Administration BAAs led to relatively higher prices there relative to other non-California BAAs.  

The DMM also found that WEIM 15-minute market prices in the Northwest and Southwest were “significantly lower” than bilateral market day-ahead prices for power traded on the Intercontinental Exchange for the Mid-Columbia and Palo Verde hubs. In contrast, prices for day-ahead power traded in CAISO’s integrated forward market (delivered in the Pacific Gas and Electric and Southern California Edison areas) tracked more closely with 15-minute prices, reflecting the kind of price convergence that organized markets are designed to achieve. 

In Q3, average hourly prices continued an ongoing pattern of following net load, with the highest prices occurring during net peaks accompanying evening ramps and — to a lesser extent — morning peaks.  

Loads, Renewable Output up

The DMM found load in the WEIM increased 4% compared with the third quarter of 2023 and had more hours with high system load (over 110 GW) and fewer hours with low system load (below 80 GW). 

The Monitor additionally determined that peak load in most WEIM BAAs did not coincide with the market’s overall system peak load of 135 GW occurring July 10, which Kurlinski noted was much lower than the sum of the peak load for each individual BAA: 146 MW. 

“This 11-GW difference is one way of describing the benefit of multiple balancing areas [having] peak loads occurring on different days and times and being in one market,” Kurlinski said. 

The report showed WEIM hourly transfers averaged about 4,560 MW, down 10% from a year earlier. 

“During mid-day solar hours, the majority of regional transfers were from the CAISO area to the Pacific Northwest and non-CAISO California areas. During morning and evening hours, the Desert Southwest was the major exporting region,” the report said. 

Average hourly generation from WEIM renewable resources increased by 4,110 MW (11%), with solar accounting for more than 60% of the increase. Meanwhile, average output from coal-fired generators in the Intermountain West fell by 1,220 MW (27%) while gas generation increased by 810 MW (28%).  

Batteries played a much greater role in operations compared with a year earlier, as average hourly battery discharge in California and the Desert Southwest increased by 550 MW (87%) and 310 MW (130%), respectively. (See Batteries, Energy Transfers Support ‘Uneventful’ Summer in West.) 

Kurlinski pointed out that 10 WEIM entities opted into the market’s assistance energy transfer program for at least one day during Q3, with seven receiving additional transfers after failing the WEIM resource sufficiency evaluation (RSE) ahead of a delivery interval. Public Service Company of New Mexico, which failed the RSE’s upward flexibility test during 1% of intervals, was the largest recipient of assistance transfers. 

Special Issues

The DMM report additionally touched on two matters raised by supporters of Markets+ in a November “issue alert” that took aim at CAISO’s dual roles as operator of and participant in the EDAM, which will expand the scope of the WEIM to include day-ahead trading. (See Markets+ ‘Alert’ Covers CAISO’s Dual Roles as Market Operator, BA.) 

The first of those matters deals with “load conformance,” a WEIM process that allows a participating BA to adjust its demand forecast in the hour-ahead scheduling process (HASP) and 15-minute market to better position itself for a real-time interval.  

In the alert, Markets+ supporters contended that, among WEIM entities, CAISO has a “unique” history of making unusually large upward adjustments to its demand forecasts during morning and evening peaks “to acquire flexible capacity through additional energy imports rather than explicitly purchasing flexible capacity itself.” CAISO has contested the second part of that contention, while pointing out that the adjustments carry a financial price for the ISO. 

While the DMM’s Q3 report didn’t wade into that specific controversy, a “special” section within the report notes that “[t]he size and frequency of CAISO balancing area operators’ use of imbalance conformance in the 15-minute market made it an outlier amongst WEIM areas” in the third quarter and resulted in increases in average hourly imbalance conformance adjustments in the hour-ahead and 15-minute markets relative to Q3 2023, especially during evening ramps. 

“Imbalance conformance over the evening peak net load hours continued to be significantly larger in the hour-ahead and 15-minute markets than in the five-minute market. This contributes to higher prices in the 15-minute market than in the five-minute market over these hours,” the DMM said. 

The second matter in the November issue alert dealt with CAISO’s decision in 2023 to block WEIM transfers into the ISO in the HASP and 15-minute market — but not real-time — during net peak load hours from July to November. The Markets+ supporters pointed out that the DMM itself had determined the practice “created a significant, systematic modeling difference between the 15-minute and five-minute markets,” which negatively “impacted market results in several ways.”  

CAISO countered that it imposed the limits after large volumes of WEIM transfers scheduled in the HASP began failing to materialize in real time. 

The DMM report noted that CAISO didn’t resume the practice at all last summer.  

“California ISO balancing area operators did not implement peak hour dynamic WEIM transfer restrictions into the CAISO area during any hours of the third quarter of 2024,” it said. 

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Benefits of Fast-start Pricing Questionable, CAISO DMM Says

Establishing a fast-start pricing mechanism in CAISO and the Western Energy Imbalance Market (WEIM) is complex and would bring few benefits compared with other potential market enhancements, the head of CAISO’s Department of Market Monitoring (DMM) said Jan. 10.

Though other organized markets have introduced the mechanism, doing so in the WEIM would be complex because WEIM has “some very unique features,” such as a flexible ramping product and multi-interval optimization, that do not exist in the other markets, said Eric Hildebrandt, executive director of CAISO’s DMM, during a presentation to a meeting of the Western Energy Markets Body of State Regulators.

Hildebrandt said fast-start pricing should not be prioritized over other potential market enhancements such as a “new or better real-time product for managing uncertainty and ramping capacity.”

“We have a 15-minute flexible ramping product in the real time market,” Hildebrandt said. “But frankly, it doesn’t do much, because it only looks out 15 minutes and the operators really need to look one to two hours out in terms of positioning units so that we have enough capacity to ramp up and meet uncertainty.”

Out of the six FERC-jurisdictional organized markets, CAISO alone doesn’t use fast-start pricing, a mechanism that factors the cost of starting and operating gas-fired peaking units into the wholesale market price.

In December 2023, CAISO presented its own analysis of fast-start pricing and sought stakeholder feedback for developing its scope.

Proponents have argued that fast-start pricing can decrease bid cost recovery and support new investments in new supply and ramping capacity, among other benefits.

The issue has also turned up in the competition between CAISO’s Extended Day-Ahead Market (EDAM) and SPP’s Markets+, with Markets+ supporters such as Powerex and other Northwest entities faulting the ISO for not including fast-start pricing in the EDAM’s initial design.

But Hildebrandt said data reveals that bid cost recovery for gas peakers is already low in the CAISO balancing area. For example, bid cost recovery paid to fast-start combustion turbines in the CAISO balancing area totaled about $32 million in 2022, or about 16% of total bid cost recovery payments to gas resources, according to DMM.

The numbers are lower in the WEIM footprint. Approximately $1 million was paid out in 2022, or about 3% of total bid cost recovery payments to gas resources in WEIM areas.

The 15-minute locational marginal pricing is usually sufficient to cover the startup minimum load energy costs of the peakers that are committed, Hildebrandt said.

“At least in our markets, there doesn’t seem to be significant benefits there, in terms of decreased bid cost recovery,” he added. “And I think that is reflection that they’re not used. These units are not usually being dispatched where there’s a big disconnect between the prices and their costs.”

Similarly, data does not support claims that fast-start pricing will lead to significant investments in new generation resources, according to Hildebrandt.

“You can argue anything that raises prices increases investment in new supply and ramping capacity,” Hildebrandt said. “But again, I think some of the data show that the increase from fast-start pricing is not going to have a significant impact on that.”

“In all the markets in the West, new investment comes from resource adequacy,” he added. “You know, utility planning, resource planning, and not from energy market revenues. So we question the benefits there.”

Hildebrandt also argued that CAISO should not be swayed by the fact that other ISOs have fast-start pricing, saying the Eastern ISOs introduced the pricing mechanism more than 10 years ago when they still had old and “very lumpy peakers.”

“They were more geared toward hourly prices rather than the five- or 15-minute prices that we’ve really kind of based the markets on out here in the West due to the higher penetration of renewables,” Hildebrandt said.

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Constellation to Acquire Calpine for $29.1B

Constellation Energy Corp. will acquire Calpine Corp. in a deal that will create the largest U.S. fleet of zero- and low-emission power generation. 

The $29.1 billion acquisition announced Jan. 10 is expected to have a net purchase price of $26.6 billon when the transaction closes. 

Constellation owns the nation’s largest nuclear fleet. Calpine has the largest geothermal fleet and the largest lower-emissions natural gas fleet in the U.S., along with a robust effort to develop energy storage and carbon capture/sequestration capacity. 

During a conference call Jan. 10, Constellation CEO Joe Dominguez said the deal will create the largest, cleanest and most reliable power portfolio in the nation — nearly 60 GW — with a 40-state footprint ideally suited to meet what is expected to be a soaring national demand for electricity. 

He noted Microsoft’s recent announcement that it expects to spend $80 billion on new data centers in 2025 alone. 

Analysts on the call were impressed with the terms of the transaction. 

Constellation stock closed 4.6% lower in heavy trading Jan. 8, as word of the pending agreement began to circulate. The U.S. stock market was closed Jan. 9, but the stock price soared in early trading Jan. 10, after details of the transaction were released. 

Constellation stock closed 25.2% higher in very heavy trading Jan. 10 while the broader markets took a beating on newly released economic data. 

Calpine’s Jack A. Fusco natural gas-fired power plant southwest of Houston is shown. | Calpine

Constellation said the acquisition will create the nation’s leading competitive retail electric supplier and allow it to offer its 2.5 million customers a broader array of solutions with a range of carbon intensities customized to their budgets and sustainability goals. 

Constellation expects its customer mix to remain 90% commercial and industrial. 

Dominguez noted that most projections show a substantial increase in power demand and show large quantities of renewables being built to meet that need. The high capacity factor of nuclear and natural gas generation provides a steadier alternative to the intermittent nature of renewables. 

Dominguez emphasized that Calpine’s fleet is weighted toward more efficient technologies. It has twice as many combined-cycle and cogeneration plants as simple-cycle facilities. 

“Calpine’s low carbon natural gas assets are not only incredibly well run, but they are some of the newest, lowest emitting and most efficient in the nation,” he said. “And critically for us, Calpine owns no coal. It has no residual coal plant liabilities.” 

Further, Dominguez said, Calpine is involved in developing carbon capture and sequestration technology that will extend the operational lives of the gas plants, taking advantage of abundant U.S. natural gas resources while reducing their carbon footprint. 

The $29.1 billion deal involves Constellation paying $16.4 billion in cash and stock to the private owners of Calpine and assuming $12.7 billion in Calpine net debt. Cash generated by Calpine between the signing and closing of the deal and the value of Calpine tax attributes is expected to bring the net purchase price down to $26.6 billion. 

Constellation expects an immediate and strong boost to its financials after the deal closes, including a more than 20% jump in 2026 earnings per share. 

CFO Dan Eggers said Constellation will not need to issue new debt to finance the acquisition, although subsequently it may issue new debt to retire more-expensive Calpine debt. 

The transaction is expected to close within 12 months but faces extensive regulatory review — the U.S. Department of Justice, Federal Communications Commission, FERC and the Canadian Competition Bureau must sign off on it, as well as utility regulators in 22 states. 

After the deal was announced, analysts at Jeffries called the terms favorable but said regulatory approval is a key hurdle. They wrote: “Given the increased political and overall attention on power demand, we would expect a protracted process and likely opposition from stakeholders, including regulated utilities.” 

Constellation said it would propose asset sales in PJM territory to mitigate any potential market power concern. 

An analyst asked for details. 

Dominguez said the forward-looking financials being offered reflect an “aggressive amount of divestiture” but held off on specifics. 

Chief Legal and Policy Officer David Dardis said the acquisition is complementary because Constellation and Calpine assets are concentrated in separate markets for the most part, which will make the regulatory review more straightforward. 

The exception is PJM, particularly eastern PJM, where there is more overlap. So Constellation is moving proactively to address this, Dardis said, and its filings in the next week or so will reveal more details. 

As they stand now, PJM accounts for 69% of Constellation’s footprint and only 14% of Calpine’s footprint, which is concentrated heavily in ERCOT and CAISO. Constellation projects 49% of the combined business will be in PJM, 23% in ERCOT, 10% in CAISO and 8% in NYISO.

An earlier version of this story misstated the anticipated net purchase price of Calpine, which is projected to be $26.6 billion.

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NERC Report Highlights Data Center Load Loss Issues

As the number of data centers, cryptocurrency mining operations and other large loads has grown on the North American electric grid, the chance for “large amounts of voltage-sensitive load loss” also has increased, according to an incident review released Jan. 8 by NERC.

The review covered an incident last year in the Eastern Interconnection that, in the ERO’s analysis, illustrates the potential dangers of simultaneous loss of large loads. Details about the incident, such as the location and the utilities involved, was not included in the report, a common practice in NERC’s Lessons Learned reports and other incident reviews.

The incident began around 7 p.m. ET on July 10, 2024, when a lightning arrestor on a 230-kV transmission line failed. This led to a permanent fault that locked out the transmission line. In the following 82 seconds, the line’s auto-reclosing control launched three auto-reclose attempts at each end of the line, resulting in six system faults with voltage depression that the protection system detected and cleared. Fault durations ranged from 42 to 66 milliseconds.

While the six faults were occurring, the same local area experienced 1,500 MW of load reduction. All of the affected load was “data-center type load,” the ERO said, of which there is “a high concentration” in the area of the disturbance, and “was disconnected on the customer side by customer protection and controls.”

The load loss caused frequency to rise as high as 60.047 Hz, settling back to 60 Hz in about four minutes. Voltage rose to 1.07/unit at the highest level, indicating a voltage 7% higher than the base voltage of 230 kV; the system fell back to normal operating values within a few minutes after operators removed shunt capacitor banks in the area.

Following the disturbance, grid operators held discussions with data center owners to determine the cause of their load reductions. They found that in response to the initial disruption, the data centers transferred their loads to their backup power systems.

“Data center loads are sensitive to voltage disturbances,” NERC noted in the report. “The data center protections and controls are designed to avoid equipment outages for voltage disturbances. … To ride through voltage disturbances on the electric grid, data centers employ uninterruptible power supply (UPS) systems that will instantaneously take over providing power to the data center equipment when a grid disturbance occurs.”

Data centers may employ different UPS designs with differing characteristics, the ERO continued. A static centralized UPS uses power electronics upon the detection of a grid disturbance to switch load to a battery bank that can provide power to operate either until the disturbance is cleared or until a backup generator can be started. These systems will transfer the load back to the grid automatically if the voltage returns to normal quickly.

By contrast, a dynamic/diesel rotary UPS, or DRUPS, uses a flywheel both to provide uninterruptible power and to start a diesel generator in the event of a grid disturbance. In this case the load typically must be transferred back to the grid manually no matter how quickly normal voltage is restored.

The data center owners also identified another protection scheme that affects the response of data center loads to voltage disturbances. This scheme takes effect if a certain number of voltage disturbances are detected within a set period of time; if the condition is met, the center’s load is transferred to the backup system and must be reconnected to the grid manually. The typical triggering threshold is three voltage disturbances within a minute.

While no significant operating issues were encountered as a result of the incident, NERC noted that “the potential exists for issues in future incidents if the load is not reconnected in a controlled manner.” If more data centers had gone offline at the same time or tried to reconnect simultaneously when the disturbance was over, it could have presented challenges to balancing authorities and transmission operators.

“This incident has highlighted potential reliability risks to the [grid] with respect to the voltage ride-through characteristics of large data center loads,” NERC said. “Similar incidents have occurred in other interconnections with cryptocurrency mining loads as well as oil/gas loads. While these loads are different than the data center loads in this incident, they present the same challenges to the operators and planners of the BES [bulk electric system]. Understanding the changing dynamic nature of load is critical to the future operation of the BES.”

NERC’s latest Long-Term Reliability Assessment, released Dec. 17, 2024, identified data centers and industrial applications as a rapidly growing sector that could cause reliability issues, especially when coupled with the move from traditional generation resources to renewable energy. (See NERC Warns Challenges ‘Mounting’ in Coming Decade.)

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LPO Offers $1.76B Loan Guarantee for Compressed Air Energy Storage

An advanced compressed air energy storage facility proposed in California has won a conditional commitment for a federal loan guarantee of up to $1.76 billion. 

The Willow Rock Energy Storage Center is expected to bolster reliability of the California grid with 500 MW/4,000-MWh of long-duration storage. 

Parent company Hydrostor of Canada expects to start construction later in 2025 and commission the facility in 2030. The proposal is in permitting review with the California Energy Commission. 

The company said in a Jan. 8 news release that if finalized, the loan guarantee would give the U.S. a leadership position in deployment of a novel long-duration energy storage technology. 

The Department of Energy’s Loan Programs Office (LPO) said in its Jan. 8 news release that the advanced design of Willow Rock resolves two key shortcomings that have limited conventional compressed air energy storage (CAES) technology to less than 50% round-trip efficiency and therefore limited its commercial appeal. 

First, Willow Rock will incorporate a proprietary thermal storage system to capture and reuse heat generated during compression, rather than wasting it and then burning new fuel to create optimal working temperatures during discharge. 

Second, water in an above-ground reservoir will maintain constant pressure in the below-ground cavern where the compressed air will be stored, avoiding the fluctuations of air pressure and power generation that otherwise would occur. 

Water is in high demand in California’s Central Valley, but Willow Rock is expected to be a net water producer — moisture that condenses during the air compression process will be captured and reused. 

Conventional CAES historically has needed to use salt caverns, LPO said, but an estimated 80% of U.S. geology would be suitable for the type of underground air storage proposed by GEN A-CAES, a subsidiary of Hydrostor USA Holdings. 

CAES presents other advantages, LPO noted: Facilities use readily available equipment that is not heavily reliant on the critical minerals batteries rely on; generally have lower capital and operating costs; may have operating lifetimes exceeding 50 years with minimal degradation; and can deliver critical grid-supporting ancillary services. 

Hydrostor co-founder and CEO Curtis VanWalleghem said in the news release: “We’re thrilled to reach this conditional commitment with the DOE, which is a huge vote of confidence in Hydrostor’s technology, and shows how important energy storage will be as we prioritize the reliability and resiliency of the grid for years to come.”

The project is expected to employ 700 people during the peak phase of construction and create up to 40 full-time operational jobs. LPO noted that those operational jobs would entail skillsets similar to the oil and gas jobs that have been an important part of the Kern County economy. 

The loan guarantee would involve approximately $1.5 billion of principal and $280 million of capitalized interest and would be offered through the LPO’s Title 17 Clean Energy Financing Program. The project also would benefit from the 48E investment tax credit. 

The DOE must complete an environmental review and the company must satisfy technical, legal, commercial, financial and other requirements before DOE decides whether to enter definitive financing. 

California Energy Commission records indicate Willow Rock would occupy 87 acres in an agricultural district north of Rosamond. It would consist of four nominal 130-MW air turbine systems outputting a maximum of 500 MW to Southern California Edison’s Whirlwind Substation via a new 19-mile 230-kV generation-tie line. 

Hydrostor brought the world’s first commercial advanced CAES — the 2-MW Goderich Energy Storage Centre in Ontario — into service in 2019. It is contracted to the Ontario Independent Electricity System Operator for peaking capacity, ancillary services and full participation in the merchant energy market. 

Hydrostor now has three much larger facilities in development in Australia, California and Ontario, plus a pipeline of earlier-stage projects. 

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OMS Stresses Need for Data Coordination Under Order 2222; MISO Extends DER Task Force

Representatives of the Organization of MISO States advised MISO it needs a central data sharing platform for the participation of DER aggregators in its wholesale market, warning the existing piecemeal, Excel spreadsheet exchanges won’t cut it in a post-Order 2222 era.

During a Jan. 9 teleconference of the DER Task Force, OMS Director of Legal and Regulatory Affairs Brad Pope said “the clock is ticking” on transmission to distribution coordination needs and said MISO requires a “centralized and standardized” framework to share DER data as aggregators enter the wholesale market in a matter of months.

Pope said OMS conducted interviews with organizations involved in integration of DER aggregation into wholesale markets and said respondents called out the need for a central communication platform.

“Several noted a piecemeal approach to coordination is highly inefficient, costly and administratively burdensome,” Pope said, stressing the need for something “instead of exchanging Excel files in a manual process that’s ripe for error.”

Erik Hanser, the Michigan Public Service Commission’s energy markets manager, said respondents recommended MISO and state regulatory leadership take the lead on devising an “automated, standardized and scalable” data-sharing platform.

“Sharing Excel spreadsheets is not a sustainable method going forward,” he said, calling for “new communication structures and coordination that doesn’t exist today.”

OMS for months has underscored the need for it and MISO to take the lead on creating an information sharing platform for DERs as part of the RTO’s compliance with Order 2222. In board meetings, some OMS members have said MISO’s lack of a standardized system for coordinated data sharing is a glaring omission.

MISO has proposed using a two-phase approach to Order 2222 compliance, first using an existing demand response category in 2026 to get aggregations participating on a limited basis. It still plans for full market participation of aggregations of distributed resources on its original 2030 timeline that FERC deemed too long a wait in 2023. (See MISO Offers 2-stage Plan for DER Aggregations in Markets.)

MISO has said its settlements system needs extensive work to accommodate full Order 2222 compliance.

The grid operator plans to begin registering DER aggregations under its demand response resource participation model on Sept. 1, 2026, with participation beginning June 1, 2027.

FERC appears to be poised to act on MISO’s pending plan soon, with MISO’s proposal on the docket at the Commission’s Jan. 16 meeting (ER22-1640).

MISO plans to host an Order 2222 Coordination Conference on Feb. 18, where it and OMS plan to discuss roles and responsibilities of the entities involved in DER aggregation in wholesale markets and review the complete process.

MISO’s Kim Sperry said an Order 2222 launch means MISO, transmission owners, distribution companies and aggregators will be “crossing the boundaries between transmission and distribution.”

DER Task Force Prolonged

Meanwhile, stakeholders have decided to prolong the life of the MISO DER Task Force, voting to extend its sunset date from July 31, 2025, to July 31, 2026.

Some stakeholders said the task force will be a helpful outlet as MISO begins accepting DER aggregations in its markets under Order 2222. DTE Energy’s Konstantin Korolyov said the task force’s preservation should be useful in navigating how MISO will fund the system studies it will have to conduct to accommodate DER aggregators.

MISO counsel Michael Kessler said that had stakeholders disbanded the task force, they would have had to decide how to divvy up lingering Order 2222 compliance issues among other stakeholder committees.

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FERC Approves Much Smaller Fine for Total Energy After Lengthy Litigation

FERC has approved a $5 million settlement with Total Gas & Power North American that ends a lengthy enforcement case in which the agency initially sought fines and disgorgement of more than $225 million (IN12-17). 

The commission alleged that the French oil firm’s subsidiary manipulated natural gas markets at four locations in the southwestern United States from 2009 to 2012. The FERC enforcement office alleged that the firm made uneconomic trades at four hubs to influence monthly index prices that benefited other positions it held. 

Total wanted FERC to throw out the case, saying its trades were legitimate and FERC’s enforcement office failed to show any manipulative intent on its behalf. The case was born out of the testimony of two former employees, one of whom Total alleged stole from the company and both of whom were in search of whistleblower compensation of up to $65 million. 

FERC instead opened up administrative law judge hearings on the case in a 2021 order. In 2022, Total appealed the case to a federal District Court in Texas, which eventually led to the settlement announced Jan. 8. 

A Supreme Court decision in June 2024, Securities and Exchange Commission v. Jarkesy, became relevant. That ruling held that the Seventh Amendment of the Constitution entitles a respondent in an administrative enforcement proceeding to a jury trial when the SEC seeks civil penalties for securities fraud, FERC explained in another order in the case issued in September. 

“Because the SEC’s civil penalties for securities fraud are ‘designed to punish and deter, not to compensate,’ they are the ‘type of remedy at common law that could only be enforced in courts of law’ with Seventh Amendment protections,” FERC said. “In short, SEC civil penalty actions regarding fraud are ‘a common lawsuit in all but name’ and therefore the Jarkesy respondents were ‘entitled to a jury trial.’” 

With Jarkesy in place, FERC acted to terminate the hearing proceedings and said it would not impose penalties against Total for the conduct alleged on the basis of an administrative enforcement proceeding before one of its administrative law judges. 

“The commission is examining Jarkesy’s impact on the commission’s existing enforcement procedures and expects to further address its approach to enforcement cases in light of Jarkesy,” it said in the September order. 

The September order did not slam the door on further proceedings in the case, which led to the settlement approved Jan. 8. Once Total makes the $5 million payment, FERC will dismiss with prejudice its claims and allegations in the enforcement matter. 

The payment is not going to FERC or the federal Treasury, but rather to “certain agreed-upon” non-governmental organizations that were not named in the Jan. 8 order. 

In an errata order issued after the ruling, FERC made it clear that Total did not even enter into the standard “neither admit nor deny” kind of settlement. TPGNA and FERC enforcement stipulate that the agreement is made “in settlement and compromise of disputed claims, and is neither an admission of liability by TPNGA nor a concession by Enforcement that its claims are not well-founded,” the errata order said.

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NEPOOL Participants Committee Briefs: Jan. 9, 2025

ISO-NE’s energy market value reached about $1 billion in December — more than double the total value of the market in December 2024 — due to lower temperatures and increased natural gas prices, ISO-NE COO Vamsi Chadalavada told NEPOOL Participants Committee members Jan. 9.  

ISO-NE declared inventoried energy days on Dec. 22 and 23 due to cold weather. Combined payments and charges over the two days totaled more than $2 million, with about $383,000 coming from net spot payments and the rest attributed to base payments, Chadalavada said. The updated projected cost of the program now is just shy of $80 million. 

The system also hit its monthly peak during the evening of Dec. 22 at 19,030 MW, Chadalavada noted. This peak was significantly higher than the December peaks from the previous two years, which were under 1,800 MW. In its 2024 Capacity, Energy, Loads and Transmission forecast, ISO-NE projected the peak for this winter will reach 20,300 MW, part of a broader trend of increasing winter peak loads in the region.  

ISO-NE said in early December it expects to have adequate energy supplies for the winter. (See ISO-NE Says Region Has Enough Resources for Upcoming Winter.) 

Power-system carbon emissions for 2024 remained higher than the previous year by roughly a million metric tons calculated through mid-December, largely due to increased gas generation, Chadalavada’s presentation noted.  

Also at the Participants Committee, members voted unanimously to approve market changes concerning the metering of load assets and storage as transmission-only assets.