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November 8, 2024

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PSEG Planning for EV, Data Center Growth

Public Service Enterprise Group is seeing “slow but steady” electric vehicle growth in New Jersey but has yet to turn down any interconnection requests for EV chargers to handle the increase, CEO Ralph LaRossa said in the utility’s second-quarter earnings call July 30.

“We have the capacity,” he said. “But we’re upgrading that last mile. So that’s really playing out exactly the way we expected it to.”

Because of the unique “condensed nature of our housing and our commutes” in New Jersey, he said, EVs “have not had the same challenges and pressure that maybe the rest of the country has seen as far as the expansion that was expected.”

New Jersey last year put an additional 62,426 new EVs on the road, a 68% increase over 2022, which has prompted some advocates to suggest the state is in reach of its goal of having 330,000 EVs in the state by 2025. The rise occurred as some analysts say EV uptake elsewhere around the nation is slowing.

The New Jersey Coalition of Automotive Retailers says the state’s affluent population is less bothered than drivers in some states by the higher price of an EV, but the organization is skeptical the target can be reached. (See NJ EV Incentives Target Low-income Buyers.)

LaRossa said the rise in EV charging, along with growing interest from developers in putting data centers in the state, “is expected to drive load growth and system investment in these in the future.” Responding to a question from an analyst, he said he sees little risk in investing for continued EV growth, even if former President Donald Trump is re-elected.

“The only question, and we’ve talked about this before, is will you have 100% EVs by 2035, or will we get a 50% on that test?” he said. “And a 50 on that test is still going to be quite a bit of market penetration for the electric vehicle industry here.”

Data Centers

LaRossa said the utility is heavily focused on positioning itself to take advantage of interest from data centers in locating in the state, and especially those interested in co-locating next to the three nuclear plants owned and operated by PSEG in South Jersey.

He said the utility has “experienced an increase in new business requests and feasibility studies from potential data center customers across our service area compared with 2023 activity, which, combined with increased electric vehicle charging, is expected to drive load growth and system investment in these in the future.”

PSEG takes proposals seriously once the developer has moved beyond the engineering phase, he said. He added that “we’re seeing several hundred megawatts of data centers that are moving into that scenario here in New Jersey,” and two or three times as many projects that are in earlier stages.

LaRossa noted that Gov. Phil Murphy (D) on July 25 signed a law (S3432/A4558) creating a $500 million program to offer tax credits to encourage artificial intelligence companies to locate in the state.

He said a co-located data center has two benefits for the state’s economic development ambitions.

“It’s not necessarily just that it’s co-located,” he said. “It’s the fact that it’s a hyperscale data center. It’s going to provide a clear signal to AI companies that are looking to locate here in New Jersey and in the region, that the infrastructure is here up and running and ready to go for their businesses to thrive,” he said.

Talen Controversy

LaRossa said his attitude has not changed in response to the recent controversy over Talen Energy’s deal to divert capacity from its Susquehanna Nuclear Plant to serve a data center on the same site.

The project, which Talen developed next to its northeastern Pennsylvania plant and sold to Amazon Web Services, has drawn protests at FERC from parties who argue that it could siphon power meant for other clients, shifting costs and threatening reliability. (See Talen Energy Deal with Data Center Leads to Cost Shifting Debate at FERC.)

“That’s not shifting us in any way, shape or form,” LaRossa said, adding the utility will be guided by its commitment to supporting Murphy’s economic development plans.

“I will say this to you. I’m a little bit concerned about co-located load as it impacts other industries,” he said. “If you really think about co-located load, that doesn’t just apply to data centers. That’s for combined-heat-and-power plants; it’s for cogeneration units.

“So, depending upon where this goes, while I’m concerned about data centers, I’m just as concerned about everything from rooftop solar behind the meter to cogeneration that might be taking place.”

Still, he added in response to a question from an analyst, whatever outcome emerges from the Talen case would not affect, or even delay, any proposal that might emerge for co-locating a facility next to PSEG’s three nuclear plants.

“Every deal is going to be very specific. I think the way our nuclear facilities are configured will be different than a nuclear facility down the street.” he said. “So, each one of those will be looked at differently, whether it’s by PJM, in its current rules that coexist for co-located load, or FERC when they come out with some sort of a process, if they do under the current challenge that’s there.”

PSEG’s second-quarter results this year fell short of those in 2023. The company reported net income of $434 million ($0.87/share), compared with $591 million ($1.18/share). It brought in about $2.4 billion in total revenue during the quarter, a slight increase over last year.

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PJM Capacity Prices Spike 10-fold in 2025/26 Auction

PJM capacity prices increased nearly tenfold in the 2025/26 Base Residual Auction (BRA) as a trifecta of load growth, generation deactivations and changes to risk modeling shrank reserve margins. 

The clearing price for most of the RTO jumped to $269.92/MW-day, far above the $28.92/MW-day for the 2024/25 auction. Two regions surged to their price caps, reaching $466.35/MW-day in the Baltimore Gas and Electric (BGE) zone and $444.26/MW-day in the Dominion zone. (See PJM Capacity Prices Jump in 5 Regions.) 

“The significantly higher prices in this auction confirm our concerns that the supply/demand balance is tightening across the RTO. The market is sending a price signal that should incent investment in resources,” PJM CEO Manu Asthana said in a July 30 announcement of the BRA results. 

PJM forecasts a peak load of 153,883 MW for the 2025/26 delivery year, up 3,243 MW from the previous year. The auction procured 135,684 MW of capacity at a record $14.7 billion to serve that load, with an additional 10,886 MW supplied through fixed resource requirement (FRR) plans. 

The total installed capacity was around 182 GW, resulting in an 18.5% reserve margin, just over the 17.8% installed reserve margin (IRM) target. The Dominion and BGE zones landed just under their reserve requirement and are transmission-constrained, causing prices to jump to the zonal cap. 

PJM Executive Vice President of Market Services and Strategy Stu Bresler said the auction procured adequate supply and sent a signal that investments in capacity are needed for future delivery years. He cautioned that capacity costs remain just one component of consumers’ bills and the results should not be read as causing a multifold increase in retail rates. 

“Auction prices were significantly higher in this auction and those steep increases, we believe, do signal the need for investments,” he said during a press conference July 30. 

The auction followed a yearslong trend of declining supply, with around 6.6 GW retiring or being approved for a must-offer exemption, which signals their intent to deactivate. Bresler said the tension between supply and demand demonstrates the reliability concerns the RTO highlighted in a February 2023 Energy Transition in PJM white paper. (See “PJM White Paper Expounds Reliability Concerns,” PJM Board Initiates Fast-track Process to Address Reliability.) 

Bresler said PJM is searching for solutions to speed the generation interconnection process to facilitate new resource development; however, 38 GW of resources have cleared the generation interconnection process but have yet to enter commercial operation. 

“Interconnection process reform is proceeding, but hurdles remain for many projects outside of our process,” Bresler said in the announcement accompanying the auction results. “We are considering ways to accelerate those who can successfully overcome those challenges and build.”  

In addition to tighter supply and demand, Bresler said the cost increase was driven by a shift in how PJM models reliability risks and matches them with resources accreditation (ER24-99). (See FERC Approves 1st PJM Proposal out of CIFP.) 

The changes use PJM’s marginal effective load-carrying capability (ELCC) framework to accredit all resources, except energy efficiency, and rely on its hourly probabilistic modeling to calculate capacity needs through the reserve requirement study. The new approach concentrated reliability risk into the winter and led to several resource classes seeing reduced accreditation. (See “Revised Reserve Requirement Study Values Endorsed,” PJM MRC/MC Briefs: March 20, 2024.) 

Auction Conducted After Several Delays

The timing of the auction has been repeatedly delayed from the original May 2022 schedule to implement several market changes, including reversing an order establishing a forward-looking energy and ancillary services (EAS) offset, followed by the Critical Issue Fast Path changes. (See FERC Approves PJM Capacity Auction Date Changes.) 

An additional delay approved in February pushed the opening of the auction from June 12 to July 17 to grant market participants more time to understand how the RTO will calculate effective load-carrying capability (ELCC) ratings to accredit the capacity resources can provide. (See FERC Approves PJM Capacity Auction Delay.) 

EPSA Says Increased Prices Reflect Increased Risks, Manufacturers Skeptical

Electric Power Supply Association (EPSA) CEO Todd Snitchler said the increased capacity prices are an encouraging first step in meeting the mounting reliability risks PJM has identified. 

“While there is still work to be done, these price signals recognize the situation PJM faces and should begin to incentivize the investment needed to deliver a reliable system in PJM and in other U.S. markets,” Snitchler said in a statement. “Reliability watchdogs, regulators, policymakers and PJM itself have been sounding the alarm that the misalignment of power resource retirements and additions poses a serious reliability risk to the grid — especially in the face of rising demand spurred by data center and manufacturing growth among other factors like electrification, extreme weather and policy choices.” 

Ryan Augsburger, president of the Ohio Manufacturers’ Association, said in a statement that auction delays will translate to higher capacity costs for consumers. 

“Markets work — but after years of delay of PJM’s critical capacity auction, prices are rising to attract generation in a hurry. PJM’s capacity auction will yield billions more for generators that locate in its territory to serve healthy customer electric load, but customers will bear the brunt of PJM’s costly auction delays,” he said. 

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WEIM Yields $365M in Q2 Benefits with Hot Start to Summer

CAISO’s Western Energy Imbalance Market (WEIM) provided its 22 participants with $365.04 million in economic benefits from April to June this year, down 4% from the same period a year ago. 

Cumulative benefits since the 2014 launch of the real-time market have hit $5.85 billion, according to CAISO’s second-quarter WEIM benefits report, released July 30. 

June saw an extremely hot start to summer for most of the West. During that month, the solar-heavy CAISO area was the WEIM’s leading net exporter, sending more than 1.1 million MWh of energy to other market participants, up 7% from June 2023. In the WEIM, a net export represents the difference between total exports and total imports for a balancing authority area during a particular real-time interval. 

“The transfers helped balance supply and demand when some of the WEIM entities were experiencing higher electricity usage due to a heat wave that saw temperatures climb 7 to 16 degrees above normal for several days across the West,” CAISO said in a press release accompanying the report. 

The ISO also was the biggest net exporter over the full quarter at 2.86 million MWh, followed by PacifiCorp’s East and West BAAs’ combined exports of 584,555 MWh, NV Energy at 464,133 MWh and Salt River Project at 395,542 MWh. 

The largest net importers were Powerex (965,287 MWh), the Balancing Authority of Northern California (BANC) (534,382 MWh) and SRP (473,319 MWh). 

CAISO also was the location of the largest volume of wheel-through transfers during the quarter at 736,433 MWh, followed by Arizona Public Service (508,707 MWh), the Western Area Power Administration’s Desert Southwest Region (DSW) (430,880 MWh) and PacifiCorp-West (419,025 MWh). WEIM participants currently receive no financial benefits from facilitating wheel-throughs through the market, with only the source and sink of the transfers benefiting, although stakeholders have discussed the possibility of changing that in the future. 

“More recently, subsequent to the June 30 closing of the second quarter, the real-time market also provided an important platform for energy trading during the record-setting heat wave in July that caused triple-digit temperatures across much of California and the West,” the ISO said. “Market participants provided similar assistance with robust energy transfers throughout the region.” 

DSW, which joined the WEIM in 2023, reaped the greatest economic benefit during the second quarter, at $50.57 million. DSW this year withdrew from participating in the second phase of developing SPP’s Markets+ — a potential competitor to the WEIM — after finding it would see few benefits from participating in either Markets+ or CAISO’s Extended Day-Ahead Market. (See WAPA DSW Cites Lack of Benefits in Markets+ Withdrawal.) 

BANC realized the second-largest share of benefits ($49.9 million), followed by CAISO ($36.02 million), NV Energy ($33.65 million) and the Los Angeles Department of Water and Power ($30.52 million). 

CAISO’s report said WEIM operations in the third quarter also helped market participants avoid 55,921 metric tons of greenhouse gas emissions through reduced curtailments of emissions-free resources. The market has prevented over 1 million MT of emissions since 2015, the ISO estimates. 

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MISO in June: Unchanged Pricing, Lower Peak than Expected

June brought MISO a peak 2 GW lower than anticipated and unchanged real-time and fuel prices from last year, the RTO said in its monthly operations report.

MISO encountered a 113-GW peak on June 24 as a sustained heat wave sent temperatures into the high 90s across the Central and South portions of the footprint. However, the month’s peak was lower than MISO’s 115-GW probable demand forecast for June that it published in the days leading up to the season.

The peak demand for June this year was higher than last year’s 111-GW apex but well below 2022’s 121 GW. Load averaged 82 GW, slightly higher than last June’s 81-GW average.

The RTO’s average natural gas and coal prices did not budge from last June, staying about $2/MMBtu. Similarly, real-time LMPs reflected no change year over year, hovering at $28/MWh.

MISO matched a 6.2-GW all-time solar peak it set in May on June 14, when the collective panels of the footprint managed about 12% of load for a brief period.

The RTO’s approximately 56 TWh of production for the month were supplied 39% by natural gas generation, 28% by coal generation, and about 14% apiece by wind and nuclear generation. Hydro and solar power each contributed almost 3%.

Daily generation outages stood at an average of 35 GW, lower than 2022 and 2021’s 40 GW and 2023’s 38 GW.

MISO ultimately issued conservative operations instructions for its North region on June 25 and for its North and Central regions on June 28 because of above-normal temperatures.

However, MISO has yet to issue emergency instructions this summer. Although MISO issued a capacity advisory for its North and Central regions and conservative operations for the entire footprint on July 15, the combination of forced generation outages, hot weather and transfer capability issues did not rise to an emergency level.

MISO is navigating a capacity advisory for its Central and North regions and conservative operations for the entire footprint through July 31 because of heat, forced generation outages and higher-than-forecasted load.

On July 30, MISO relied heavily on its coal (41 GW) and gas (44 GW) resources to meet a 115-GW peak. Prices ranged from $39 to $49/MWh.

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DC Circuit Vacates Pipeline Approval FERC Issued over NJ’s Objections

The D.C. Circuit Court of Appeals on July 30 vacated and remanded an order by FERC approving a natural gas pipeline in New Jersey that state regulators said was unneeded (23-1064).

FERC last year approved Transcontinental Gas Pipe Line Co.’s Regional Energy Access Expansion Project to boost gas delivery by 829,400 dekatherms/day to bring gas from Pennsylvania into New Jersey over the objections of New Jersey regulators and others (CP21-94). (See FERC Approves Pipeline Expansion Despite New Jersey’s Worries.)

Before the gas project came to FERC for approval, the New Jersey Board of Public Utilities opened a proceeding on the future of natural gas in the state, which determined it did not need more pipeline capacity through at least 2030. That proceeding was opened in February 2019; Transco applied to FERC in March 2021; the BPU issued a final order in the proceeding in June 2022; and FERC approved the pipeline expansion in January 2023.

About 73.5% of the project’s gas was destined for customers who signed contracts in New Jersey, but the rest was for Delaware, Maryland and Pennsylvania.

The New Jersey Conservation Foundation, New Jersey Division of Rate Counsel, New Jersey Attorney General’s Office and others challenged FERC’s approval after the commission upheld it on rehearing.

The court found that FERC failed to make a significance determination when it came to the project’s greenhouse gas emissions and failed to discuss mitigation measures.

FERC quantified the emissions associated with the project, finding construction could add 43,548 metric tons of CO2 equivalent, while operation would add 562,044 metric tons per year. Using the fuel downstream from the pipeline would add just over 16 million metric tons. The higher estimates are the project would use 39% of the total annual emissions budgets of New Jersey and Maryland.

The commission said counting the emissions was enough and it did not have to weigh their significance for the project as it had an open proceeding looking into such issues generically.

FERC “did not explain, however, how the pendency of that generic proceeding affects its ability in the meantime to make a case-specific determination here, when it was able to do so in Northern Natural,” the court said, referencing the first time the commission assessed the greenhouse gas emissions of a proposed natural gas infrastructure project and its impact on global climate change. (See FERC Assesses Climate Impact of Gas Project for 1st Time.)

“The anticipated emissions from this project are more than a hundredfold higher than the 100,000 metric tons per year of CO2e that the commission’s interim guidance suggests as a significance threshold,” the court said. Even if FERC was not obliged to make a determination, choosing not to do so on the basis of an arbitrary explanation is a violation of the Administrative Procedure Act, it said.

The court also found FERC acted arbitrarily in granting the certificate under the Natural Gas Act because it failed to explain why it discredited New Jersey’s study finding no need of new pipelines for the rest of the decade. It also failed to give weight to the state’s climate law that requires sizeable and continuous cuts in natural gas use by utilities.

FERC criticized the New Jersey study for relying on the continued availability of 619 million dekatherms/day of off-system peaking resources that are not under long-term, firm contracts.

“The commission did not, however, identify any past event in which such resources — despite being subject to short-term contracts — were unavailable when needed,” the court said. “In fact, the commission recognized that ‘downstream capacity has been available to New Jersey shippers in the past through short-term peaking contracts and may be available in the future on the same short-term basis.’”

The project had contracts for the new capacity. Normally such precedent agreements are used to show a market need, but the court faulted FERC for failing to respond to challenges to its reliance on those. While New Jersey local distribution companies signed up for capacity, it is not guaranteed they will use it to serve their customers.

“If ratepayers assume the cost even when they do not need the capacity, LDCs can afford to contract for additional unneeded capacity, which they can then resell at a profit, even in a soft capacity market,” the court said. “Because the commission failed to respond to that challenge to its reliance on precedent agreements with LDCs who subscribed to a majority of the pipeline’s capacity, the commission acted arbitrarily.”

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NREL Examines Gulf of Mexico OSW Transmission Needs

A National Renewable Energy Laboratory report offers insight on transmission infrastructure needs for future offshore wind development in the Gulf of Mexico. 

NREL said the needs are significant but have not been researched previously.  

Offshore wind development in the Gulf presents challenges beyond those facing present-day efforts along the northeast U.S. coast. And developers so far have shown little willingness to meet those challenges — the Gulf wind lease auction planned for later this year was canceled for lack of interest. 

But the Gulf is believed to hold 37% of the nation’s potential offshore wind generation capacity, and federal leaders hope to exploit it. 

NREL’s report looks at some of the steps that would need to be taken well in advance of wind turbine construction so their megawatts of power could be brought ashore. 

A key takeaway: The oil and gas industry already has infrastructure and personnel in the Gulf. Shared transmission systems and workforce could support offshore wind. 

Also, about 18,000 miles of abandoned pipelines remain on the seabed and could be used to transmit clean hydrogen — generation of which is a potential use of offshore wind energy. 

But the NREL report also suggests that offshore wind transmission planning in the Gulf is not so different from other regions: Planners will have to limit the impact of their projects on existing communities, industries and ecosystems while navigating local, state, federal and tribal regulations and sensibilities. 

The report’s authors identify some gaps in existing planning and knowledge needed for buildout: 

    • RTOs and utilities have not incorporated Gulf of Mexico offshore wind power in their long-term transmission planning. 
    • Siting considerations for offshore wind transmission routing in the region have not been identified in published literature. 
    • Focused community and workforce engagement on stakeholder priorities has been lacking. 
    • Engagement and research would inform how offshore wind transmission would fit into the region’s energy generation portfolio and how it serves the needs of industries in the Gulf Coast states. 

The NREL report recommends the Department of Energy and Bureau of Ocean Energy Management convene a Gulf Coast version of the Atlantic Offshore Wind Transmission Study workshop series they began hosting in 2022. 

The Biden administration, as part of its push to build a new emissions-free power sector, envisions fixed-bottom wind turbines in shallower parts of the Gulf and floating turbines in deeper areas. 

But slower average wind speeds punctuated by severe winds from hurricanes and tropical storms present a significant engineering challenge for designers of the wind turbines to be placed in the Gulf. (See Hurricane Threat to OSW Turbines Quantified.) 

In 2023, the first of four planned Gulf wind energy area auctions drew only three bids from two bidders on one of the three areas offered. The single sale came at a rock-bottom price. (See Gulf of Mexico Wind Energy Auction Falls Flat.) 

The planned 2024 auction drew early interest from only one potential bidder and was called off. (See BOEM Cancels Gulf of Mexico Wind Lease Auction.) 

As the 2024 auction was heading to cancellation, however, another developer submitted an unsolicited request to BOEM for two other lease areas off the Texas coast. 

And Louisiana has been advancing offshore wind development in state waters closer to shore. The Climate Action Plan developed during the administration of Gov. John Bel Edwards (D) set a goal of 5 GW of offshore wind capacity by 2035, and the state signed agreements with two developers in late 2023, during the closing days of his administration. 

A previous NREL study identified 25 plausible points of interconnection for offshore wind export cables but concluded that, as in other regions, many of them would need significant upgrades to handle gigawatt-scale injections. 

The new NREL report was funded by the DOE’s Wind Energy Technologies Office and Grid Development Office. 

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AEP Planning for 15 GW of Data Center Load

American Electric Power executives say they’re embracing large loads and, fortunately for them, they say they have firm commitments for more than 15 GW of load coming from just data centers by 2030.

AEP told financial analysts during its July 30 second quarter earnings call with financial analysts that it’s seeing “unprecedented” load growth, split primarily between Texas and its PJM footprint. Commercial load has increased 12.4% over the second quarter of last year as new data processing facilities came online, the company said.

“We continue to see strong interest in Ohio and Texas, as well as several of our vertically integrated states, from customers looking to develop new data processing facilities,” interim CEO Ben Fowke said during the company’s call. “Affordability remains top of mind, and we’re working to ensure that the investments made in the grid to support this increased demand are allocated fairly and provide benefits to all customers.”

Noting AEP’s system-wide peak at the end of last year was 35 GW, Fowke said the company continues working with data center customers to meet their increased demand, but also ensuring contracts and new initiatives are “fair and beneficial” for all customers. He said AEP would provide details on its generation and transmission capital investment necessary to meet demand later this year.

“I want to emphasize that it’s critically important that costs associated with these large loads are allocated fairly and the right investments are made for the long-term success of our grid,” Fowke said.

AEP subsidiary Public Service Co. of Oklahoma (PSO) in June announced it will seek regulatory approval of an agreement to purchase Green Country, a 795-MW natural gas facility. Peggy Simmons, executive vice president of utilities, said the transaction will help PSO meet SPP’s higher planning reserve margin, which was increased to 15% from 12%.

“This was a very proactive approach that the team took to go out and find some affordable assets that we can bring onto the system,” she said.

AEP reported second-quarter earnings of $340 million ($0.64/share), down from 2023’s second quarter earnings of $521 million ($1.01/share). The company reaffirmed its 2024 operating earnings guidance range of $5.53-$5.73/share and its 6%-7% long-term growth rate.

Incoming CEO Bill Fehrman, who takes over AEP’s top job Aug. 1, did not participate in the call. Fehrman replaced Julie Sloat in June after his predecessor parted ways with AEP in February following just one year as CEO. (See AEP Selects Industry Veteran as Next CEO.)

“With Bill’s expertise and diverse background, you can anticipate a smooth transition and continuity of strategic direction. Expect more focus on execution,” said Fowke, who served as interim CEO and will advise Fehrman during a transition period.

The company’s share price rallied late July 30 to close at $98.14, up $1.07 from its previous close.

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ISO-NE Capacity Accreditation Reforms Spur Energy Storage Concerns

As ISO-NE undertakes major capacity market accreditation reforms, New England storage developers are voicing concerns that potential flaws in the RTO’s modeling methodology could discourage new investments in storage resources. 

The resource capacity accreditation (RCA) project has been in motion for more than two years, and the development process could continue into 2027 following the RTO’s three-year delay of its 19th capacity auction, which applies to the 2028/29 capacity commitment period. (See NEPOOL Markets Committee Restarts Work on Capacity Market Changes.) 

The RCA project is intended to better align the capacity procurements with real-world reliability benefits, mirroring similar reform efforts in MISO, NYISO and PJM.  

Prior to FERC’s approval of the full three-year delay — which will give ISO-NE time to reform the timing of the capacity auction process along with accreditation — the RTO published RCA impact analysis results that painted a dire picture for storage resources. (See FERC Approves Additional Delay of ISO-NE FCA 19.) 

While the analysis indicated that the accreditation changes would increase the overall pool of capacity revenue by 11%, it showed a 37% revenue reduction for storage resources, equivalent to about $58 million. (See ISO-NE: RCA Changes to Increase Capacity Market Revenues by 11%.) 

While these results are subject to change as ISO-NE refines the methodology and accounts for the transition from a forward annual capacity market to a prompt-seasonal capacity market, the analysis served as a wakeup call for many of storage companies participating in the capacity market. (See ISO-NE Moving Forward with Prompt, Seasonal Capacity Market Design.) 

The concerns about storage accreditation derating come as several New England states are looking to rapidly ramp up the deployment of storage resources; Connecticut, Massachusetts, Maine and Rhode Island all have storage targets in the hundreds of megawatts. 

State programs also are a key revenue component for storage developers, as the current levels of revenue from ISO-NE wholesale markets alone are not enough to support the resources, said Alex Chaplin of New Leaf Energy, adding that “storage provides significant reliability benefits to New England which need to be adequately measured and compensated for in the ISO-NE markets.” 

Chaplin noted that most storage in the region is concentrated in Connecticut and Massachusetts due to their state incentives for storage. Massachusetts’ clean peak energy standard, which is aimed at cutting emissions and air pollution from fossil peaker plants, is a key revenue source for storage resources in the state. (See Panel Provides Update on Energy Storage in Mass.) Decreasing capacity revenue could lead to more pressure on states to support the resources to hit their storage deployment goals and cut emissions. 

“Capacity market revenues are typically an irreplaceable and indispensable source of revenue for the financeability and viability of resources, and storage is no exception,” said Alex Lawton of Advanced Energy United. He added that the energy market and ancillary services market do not provide “the scale or certainty needed for investors to back storage projects.” 

The crux of the issue, Lawton said, appears to stem from how ISO-NE is artificially scaling up load in its model to evaluate the reliability benefits of different resource types, which ultimately will determine how much capacity each resource can sell into the market. This modeling shows capacity scarcity events that significantly exceed the duration of events historically experienced in the region.  

While the longest capacity scarcity condition New England has experienced since the implementation of pay-for-performance rules in 2018 lasted two hours and 40 minutes, the RCA project is modeling events that typically exceed four hours, and — according to a March presentation — 36% of modeled shortfall events lasted more than eight hours.  

“As soon as you exceed four hours in duration — because most storage is between two and four hours — the marginal reliability impact (MRI) of storage just tanks,” Lawton said. 

There is broad consensus that the region’s power grid will face longer-duration periods of shortfall risk in the future as it trends toward a winter peaking system, but there is uncertainty around when these longer-duration risks will show up, and how they should be weighed against higher-likelihood, shorter-duration events.  

Over the long term, ISO-NE has stressed the need for dispatchable resources that can balance intermittent generation over extended periods of time. (See ISO-NE Outlines Economic Challenges of Decarbonization.) 

Frank Swigonski of Jupiter Power said the weighting of extreme winter storms in the methodology compared to more frequent, shorter-duration events “is an open question … that stakeholders should explicitly discuss in this process.” 

Swigonski noted the stakeholder engagement process for PJM’s accreditation reforms did not spend significant time discussing this question, which led to rehearing requests with FERC. 

“It ultimately had a massive impact on the final accreditation numbers,” Swigonski said. “We’re hoping that we don’t have the same experience in New England.” 

Swigonski also disagreed with the notion that shorter-duration storage resources are unable to provide significant resource adequacy benefits during longer-duration events. Storage resources likely still will be able to recharge off-peak during extended events, and operators eventually will gain experience with dispatching storage to avoid depleting all available storage in the first hours of an event, he said. 

Responding to questions about the RCA methodology, ISO-NE spokesperson Mary Cate Colapietro emphasized that the methodology is still a work in progress and that stakeholder engagement is ongoing. ISO-NE recently solicited comments on the scope of its Capacity Auction Reform (CAR) project, which included requests from storage companies for ISO-NE to evaluate the underlying modeling methodology. 

“Establishing a durable capacity market that provides the necessary reliability services as the power system evolves is a vital component of New England’s clean energy transition,” Colapietro said. “While we plan to continue pursuing an accreditation design based on capacity’s marginal reliability impact, the additional time afforded by the delay gives us time to work with stakeholders on possible improvements to that design.” 

Bruce Anderson of the New England Power Generators Association declined to comment on the treatment of specific resource types but stressed the need for ISO-NE to prioritize implementing a “sound market design” that provides efficient signals for resources to enter and exit the market. 

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ERCOT Evaluating RMR, MRA Options for CPS Plant

ERCOT has issued a request for proposal seeking alternatives to a reliability-must-run contract with CPS Energy, compensating for the utility’s planned retirement of a power plant. 

The ISO said in a July 25 market notice that CPS Energy’s decision to retire three aging coal-fired units, with a combined summer seasonal net maximum sustainable rating of 859 MW, would have a “material impact on identified ERCOT system performance deficiencies.” The grid operator’s staff has said the units’ retirement would load existing transmission facilities above their normal ratings under pre-contingency conditions.  

ERCOT’s determination triggered the grid operator’s obligation to issue an RFP for must-run alternatives (MRAs) and begin RMR negotiations with CPS Energy. The San Antonio utility has proposed suspending the three V.H. Braunig units after March 2025. (See CPS Energy Plans to Retire 859 MW of Gas Resources.) 

Qualified scheduling entities (QSEs) can submit proposals for one or more MRA resources to address system performance deficiencies more cost effectively than by committing one or more Braunig units through a more expensive RMR contract. QSEs can offer the resources for one or more seasons during April 1, 2025, through March 31, 2027. Eligible resources include types of generation, storage and demand response. 

RFP offers are due Sept. 9. ERCOT will host a workshop Aug. 15 to discuss the RFP and answer questions. After reviewing all proposals, staff will make a recommendation to the ISO’s board during its October meeting. 

An RMR contract would be ERCOT’s first since 2016. The grid operator entered into an agreement with NRG Texas Power over a previously mothballed gas unit near Houston. The RMR contract ended in 2017, thanks partly to transmission facilities that increased imports into the region. (See ERCOT Works to Address Loss of San Antonio Units.) 

$24.4B in Energy Fund Requests

The Public Utility Commission said July 29 it has received 72 applications for loans through the Texas Energy Fund’s in-ERCOT Generation Loan Program. The applications request $24.41 billion to finance 38.37 GW of proposed dispatchable, or thermal, power generation. 

Lawmakers have set aside $5 billion for this TEF program, one of four. 

“Texans have made it clear that they expect reliable electricity today and well into the future, and I am pleased to see industry leaders responding to that call and planning for major investments in dispatchable power for the state,” PUC Chair Thomas Gleeson said in a news release. 

Commission staff will evaluate the applications before the commission determines which projects will proceed to due diligence during the PUC’s Aug. 29 open meeting. The in-ERCOT program will provide low-interest loans to finance up to 60% of new construction or upgrades to existing dispatchable facilities. A proposed project must add at least 100 MW of new generation to the ERCOT grid to be eligible. Approved loans’ initial disbursements will be issued by Dec. 31, 2025.  

The in-ERCOT program and three other TEF programs were established in March because of state legislation passed last year. The PUC says the program can support up to 10 GW of new or upgraded generation capacity in ERCOT. (See Texas PUC Establishes $5B Energy Fund.) 

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Electric Sector Added just 55 Miles of New Transmission in 2023

The U.S. electricity industry added just 55 miles of new high-voltage transmission to the grid last year, despite estimates the system will need to expand rapidly in the near future, Americans for a Clean Energy Grid said in a report released July 30. 

“Fewer New Miles: The US Transmission Grid in the 2020s” was prepared by Grid Strategies with support from ACEG. 

“The findings of this report are a wakeup call. With only 55 new miles of transmission built in 2023, we are not keeping pace with the growing demand for power,” ACEG Executive Director Christina Hayes said in a statement. “The slowdown in new construction not only impacts our ability to meet future energy needs, but also risks increasing costs for consumers and reducing grid resilience. It is essential that we address these challenges to ensure a secure, reliable and affordable energy future for all Americans.” 

The U.S. Department of Energy’s Transmission Needs Study found the grid should expand by 57% by 2035, while Princeton University’s “Net-Zero America Study” found it would need to double or 80% of the potential greenhouse gas cuts from the Inflation Reduction Act would not be met, said the ACEG report. (See Will DOE’s Transmission Needs Study Spur New Regional, Interregional Lines?) 

While 2023 saw few miles of new lines built, the industry spent $25 billion on the grid (a record high), with 90% driven by reliability upgrades and the replacement of aging equipment. The decline has been felt for years, with the country building only 20% as much transmission so far this decade as it did in the early 2010s. 

“This trend began over a decade ago, when the average of 1,700 miles of new high-voltage transmission built per year from 2010 to 2014 dropped to only 925 miles from 2015 to 2019, and has fallen further to an average of 350 miles per year from 2020 to 2023,” the report said. 

So far this year up to May, the industry has completed one major transmission line, adding 125 new miles from completion of the 500-kV Delaney-Colorado Transmission Project that links Arizona and California. 

About 50% of recent spending is based on local planning criteria, which is usually below 345 kV and does not go through regional planning processes. Such lines focus only on reliability, ignoring maximized ratepayer benefits from multivalue projects, the report said. 

The 2010s saw massive greenfield projects, especially in Texas and the Midwest. Texas’ Competitive Renewable Energy Zone program saw $7.5 billion invested in ERCOT lines to bring wind power to population centers, cutting wind curtailment from 17 to 0.5% and leading to unexpected benefits like solar development in West Texas and electrification of oil and gas drilling in the regions. 

MISO’s Long Range Transmission Planning (LRTP) Tranche 1 Portfolio is another example, investing $10.3 billion to build out 2,000 miles of lines that offer at least 2.6:1 benefits to load. 

Recent federal action like FERC Order 1920 and DOE’s Transmission Facilitation Program to help finance new transmission lines should help, but the report said private capital needs to be invested to expand the grid. 

“Utilities are still currently incentivized to prioritize low- voltage upgrades focused on reliability and asset replacement,” the report said. “Both policymakers and regulators must capitalize on FERC’s issuance of Order No. 1920 to ensure the momentum brought about by federal action truly changes the incentives for transmission investment and helps spur a massive investment in the construction of new high-voltage transmission lines to ensure a reliable and affordable transition to a cleaner grid.”