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January 10, 2025

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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 create 700 construction jobs and 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. 

Total agreed to stipulate to some of the facts FERC laid out, but it neither admitted nor denied the allegations that it manipulated natural gas markets. 

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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. 

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No Grid Impact from LA Fires, CAISO Says

The rapidly spreading brush fires that have devastated multiple communities around Los Angeles are not expected to affect California’s broader transmission grid, CAISO said Jan. 8.

“There’s been no impact to the power grid from the Southern California wildfire activity,” a CAISO spokesperson told RTO Insider in an email. “The bulk electric system is stable and we’re not seeing any forecasted supply interruptions, so no particular concerns. We are monitoring the potential effects and are in close coordination with state agencies and local power providers.”

At the time of publication of this article, four significant fires were burning in the L.A. metro area, including the Palisades (nearly 12,000 acres), the Eaton (more than 10,500 acres), the Hurst (more than 500 acres) and the Woodley (50 acres).

The fires, the first three of which ignited Jan. 7, have been fanned by unusually strong Santa Ana winds that at times gusted to nearly 100 miles per hour in some areas. The extreme winds prevented local fire departments and the California Department of Forestry and Fire Protection (Cal Fire) from deploying aircraft to fight the blazes, which spread quickly from house to house in a densely populated area that has seen just a fraction of its normal rainfall since the start of the water year in October.

The Hurst Fire is burning in L.A.’s Sylmar area, location of the Sylmar Converter Station, which constitutes the southern terminus of the Pacific DC Intertie, a high-voltage transmission line capable of transmitting up to 3,100 MW of electricity between Southern California and Bonneville Power Administration’s territory in Oregon. The substation is owned jointly by the Los Angeles Department of Water and Power (LADWP) and Southern California Edison (SCE).

“There is no imminent threat to the Sylmar Converter Station or any other transmission line. The Pacific DC Intertie was impacted last night but has been up and running,” LADWP spokesperson Michelle Figueroa said in an email.

“From a grid operations standpoint, it hasn’t presented any system-wide disruptions,” CAISO’s Anne Gonzales said.

Utility Responses

Both LADWP and SCE initiated public safety power shutoffs (PSPS) before and during the fires. By the afternoon of Jan. 8, nearly 183,000 of SCE’s 5 million electricity customers were subject to shutoffs, and almost 420,000 were under PSPS alerts.

LADWP reported that, as of 1 p.m., more than 155,000 of its 1.5 million customers were without power due to storm damage, while about 105,000 had been restored since the start of the storm.

“Currently, customers experiencing a power outage should expect that it could take up to 48 hours before our crews are able to respond. High winds and fire conditions continue to present hazards for our crews and can affect response times and restoration efforts,” the utility said in a statement.

The fires so far have caused two deaths, destroyed more than 1,000 structures and forced thousands of residents to evacuate their homes, with many reports of people having to abandon cars and flee on foot after becoming stuck in gridlocked traffic. At publication time, all four blazes were still 0% contained, with the cause of each still under investigation, according to Cal Fire.

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IRS Issues Low-income Clean Electricity Rules

Rules and guidance for the federal Section 48E(h) Clean Electricity Low-Income Communities Bonus Credit have been finalized and will be published shortly. 

The Department of the Treasury and Internal Revenue Service released the details Jan. 8 and said applications will be accepted starting Jan. 16. 

The 48E(h) program will provide a 10 or 20% adder on top of the 30% investment tax credit to 1.8 GW of clean electricity generation annually from 2025 through at least 2032. 

It is an expansion of the 48(e) program created by the Inflation Reduction Act. 

During its first year, 48(e) received more than 54,000 applications from 48 states, four territories and the District of Columbia. The approved applications are expected to generate investments of $3.5 billion in low-income communities and $270 million in annual offset energy costs. 

In the second year, more than 57,000 applications were submitted. Approved applications are expected to generate investments of roughly $4 billion and offset nearly $350 million a year in energy costs. 

The final 48E(h) rules contain some changes from 48(e): 

    • The range of eligible zero-emissions technologies is expanded beyond solar and wind to include hydropower, marine, geothermal and nuclear. 
    • The list of qualified housing programs has been expanded and the financial value that projects must provide to low-income households has been clarified. 
    • To steer benefits to small businesses, there is a pathway for emerging clean-energy companies to receive priority treatment of their applications. 
    • The annual 1.8-GW maximum capacity allocation is divided among four categories — 200 MW for facilities on Indian lands, 200 MW for low-income residential building projects, 800 MW for low-income economic benefit projects and 600 MW for facilities in low-income communities. 
    • This last category is subdivided — 400 MW for behind-the-meter residential facilities and 200 MW for front-of-the-meter or nonresidential behind-the-meter facilities. 

In a news release, Deputy Secretary of the Treasury Wally Adeyamo described the revisions as a pathway to greater equity: “Expanding the Clean Electricity Low-Income Communities Bonus Credit will help lower energy costs in communities that have been overlooked and left out for too long and empower developers to work alongside communities to provide tailored solutions to meet their energy and economic needs.” 

A Department of Treasury analysis of the first year of 48(e) found its results to be in line with the supply-side economics framework on which it was designed. 

“Investment in underserved people and places can lead to disproportionately higher rates of return for the nation’s economy,” Treasury said Sept. 4, “and federal investments — like the ones provided by this program — will simultaneously promote economic growth and help address inequality.” 

Some highlights from the first-year analysis: 

    • More than 54,000 applications were submitted for more than 7.2 GW of capacity; allocations went to 49,246 proposals totaling 1.475 GW and the 325 MW of eligible capacity that was not allocated was rolled over to the second program year. 
    • All of the allocations were for solar projects — few applications were submitted for wind power generation, and none were approved. 
    • More projects were awarded to applications in areas of high energy burden as defined by the Climate and Economic Justice Screening Tool than were awarded to applications in Persistent Poverty Counties. 
    • Awards were made predominantly in states with established solar markets and supportive regulations; other awards went to states with emerging solar markets, and those states are expected to make up a growing portion of the program over time. 
    • Many of the facilities that exceed 1 MW capacity will be subject to the prevailing wage and apprenticeship requirements of the Inflation Reduction Act. 
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LS Power Completes Purchase of Algonquin Power’s Renewables

LS Power has completed its $2.5 billion acquisition of Algonquin Power & Utilities Corp.’s renewable energy business, adding to its existing fleet of over 23,000 MW. 

Algonquin’s fleet includes renewables, energy storage and natural gas, along with a deep pipeline of projects at various stages of development. Generation from the deal is spread across CAISO, MISO and PJM. 

“By substantially increasing our generation capacity and pipeline of new renewable projects, we will continue to help meet rising power demand while advancing the energy transition,” LS Power CEO Paul Segal said in a statement. “We see great opportunity to deliver renewable projects at scale across the country, and this transaction furthers our plan to execute this vision.” 

The sale leaves the Canada-based Algonquin with a smaller, fully regulated profile that still includes its hydropower assets. 

“This transaction, coupled with the recent sale of our 42.2% ownership stake in Atlantica Sustainable Infrastructure plc on Dec. 12, 2024, achieves a pivotal step in our journey to transform AQN into a pure-play regulated utility with reduced complexity,” Algonquin CEO Chris Huskilson said. “Though there is still work to be done, passing this milestone should enable a greater focus on increasing the pace of this transition.” 

LS Power is forming a new subsidiary company called Clearlight Energy to manage the acquired operating wind and solar assets that are spread across the United States and Canada and include 44 projects with more than 3,000 MW. It will be run by Jeff Norman, who previously was president of renewables at Algonquin. 

Algonquin had 8,000 MW of renewable and storage projects under development around North America. Clearlight Energy will work on 1,800 MW of those, which include the Canadian projects and those that are co-located with existing assets. REV Renewables, a previously existing LS Power subsidiary, will get the other 6,200 MW of development projects in the United States, bringing its development pipeline to more than 21,000 MW. 

“The acquisition of these additional development projects complements REV’s objectives to develop renewable energy solutions that will transform our electric system,” REV Renewables CEO Ed Sondey said. 

The deal won approval from FERC in an order issued in December (EC24-111), which found the deal would be in the public interest. PJM’s Independent Market Monitor filed a report saying the combined firm would have market power in a subregion of the RTO, but the commission rejected its use. 

The IMM also wanted some behavioral requirements to mitigate the alleged market power, but FERC declined to impose them. FERC said the monitor’s issues were aimed more generally at its merger evaluations and market power protections in PJM, not the specific deal in front of it. 

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FERC Denies SPP’s Timing Waiver Request

FERC has denied SPP’s waiver request to allow the RTO’s interconnection customers without a pending request to ask for interim interconnection service during a period when the study queue cluster’s window is closed.

In an order issued Jan. 3, the commission rejected SPP’s contention, saying its request did not meet FERC’s criteria for granting waivers (ER24-2863).

The commission found SPP’s request does not address a concrete problem because the proposed waiver would not permit entities without an interconnection request to ask for interim interconnection service. It said SPP did not seek a waiver of the term “interconnection customer,” putting it in conflict with tariff language that applies specifically to interconnection customers.

SPP filed the timing waiver request in August 2024. Clean energy associations and investor-owned utilities supported the grid operator’s request, saying it would help SPP clear its interconnection queue backlog in a fair, efficient and expeditious manner and could help provide greater certainty to interconnection customers.

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NPCC Gas-Electric Study Details Winter Reliability Challenges

A new study from the Northeast Power Coordinating Council (NPCC) outlines some of the major risks that reliance on natural gas generation poses for the New England power system and emphasizes the need for dispatchable resources to limit potential winter reliability issues. 

NPCC, which conducted the study in coordination with NYISO, ISO-NE, NERC and the Northeast Gas Association, found the gas system to be “fully utilized” throughout a three-day modeled cold stretch. 

However, if the cold snap lasts beyond three days, or key gas network outages occur at the same time, it likely will add “significant stress to the consolidated network of gas pipeline and storage infrastructure in New England and New York,” said NPCC CEO Charles Dickerson, adding that an extended cold stretch could put significant pressure on the region’s oil inventory and replenishment capabilities. 

Additionally, extreme, low-probability events causing the “near or total cessation of natural gas throughput,” such as the outage of a key pipeline or compressor station, may cause “catastrophic impacts for downstream customers,” NPCC wrote. 

During normal operations, the Northeast faces significant gas constraints in the winter, when much of the pipeline system is reserved for heating needs. 

“Since most generators do not have firm transportation entitlements, the ability of pipelines to provide intra-day scheduling flexibility to accommodate the twice-daily ramp during cold snaps should be questioned,” NPCC wrote.  

As renewables proliferate, NPCC found the ramping requirements in both New England and New York could surpass 7,000 MW by 2032. It projected that the increasing ramping needs “can generally be accommodated” in the long term under normal weather conditions. 

New England’s “duck curve” has increased in recent years due to the rapid expansion of behind-the-meter solar. ISO-NE surpassed 100 duck curve days for the first time in 2024, which are defined as days when mid-day demand is lower than overnight demand.  

In the winter, the two major liquified natural gas (LNG) import terminals servicing New England — Repsol’s facility in St. John, New Brunswick, and Constellation’s Everett Marine Terminal (EMT) located just north of Boston — remain “an integral part of the gas-fired generators’ ability to satisfy fuel assurance objectives,” NPCC found.  

LNG deliveries from the facilities “give pipeline operators valuable scheduling flexibility since they displace the need for conventional flows west-to-east into New England,” NPCC added. It estimated the two facilities can provide enough LNG to fuel 8,000 MW of gas generation.   

While EMT is under contract with the Massachusetts gas utilities though May 2030, the future of the import terminal is uncertain after the contract expires. When the Massachusetts Department of Public Utilities approved the contracts in May, it directed the utilities to work to reduce or eliminate their reliance on the facility in accordance with the state’s climate goals. (See Massachusetts DPU Approves Everett LNG Contracts.) 

NPCC singled out the Everett terminal as a particularly important facility for gas and electric reliability, writing that it plays a key role that could not be filled easily by additional imports from St. John or increased oil generation.  

“EMT’s location is ideal because it provides both pressure support and flow on an instantaneous basis, whereas Repsol Saint John cannot,” NPCC wrote. Although Repsol could pack the Maritimes and Northeast pipeline in the hours before an expected need, its facility is not able to provide the same real-time reliability support as EMT, NPCC said.  

While oil generation theoretically could replace the 2,600 MW of gas generation capacity supported by EMT, oil retirements over the next decade, combined with the potential loss of EMT, may increase the likelihood of capacity deficiencies, NPCC wrote. 

The NPCC’s findings echo some of the key results from ISO-NE’s Economic Planning for the Clean Energy Transition (EPCET) study, which the RTO released in October. (See ISO-NE Study Lays Out Challenges of Deep Decarbonization.) 

The EPCET study emphasized the importance of maintaining an adequate amount of dispatchable generation on the grid to balance renewables and ensure reliability.  

“The grid of 2032 and beyond may sometimes require more dispatchable generation (either from stored fuels or an unconstrained fuel supply) than it has in recent winter conditions,” the EPCET study found.  

The EPCET study also found that the winter season likely will be the last to decarbonize due to factors including the high winter peak, need for dispatchable generation and high costs of existing clean firm generation resources.  

ISO-NE is overhauling its capacity market, with the intent of increasing compensation for resources that protect grid reliability during the most vulnerable periods. The reforms likely will add incentives for gas generators to contract for firm fuel, though it is unclear whether these incentives will change generator behavior.  

NCPP’s study also noted that offshore wind “has the potential to materially lessen reliance on oil and gas during the peak heating season.” Multiple New England states also are pursuing large-scale additions of battery storage, which should help lessen the reliance on gas to meet peak demands.  

“Uncertainty about the pace, amount and inevitability of electrification, electric vehicles and offshore wind in the years ahead may intensify operational stresses on the gas infrastructure available to serve gas-fired generation over the medium and long term,” NPCC concluded.