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November 14, 2024

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ERCOT, IMM Share Details on Ancillary Services Study

ERCOT staff have made a pair of preliminary recommendations as part of their collaboration on an ancillary services study that is due to Texas regulators before the end of the year. 

Jeff Billo, ERCOT director of operations planning, told the Stakeholder Advisory Council on June 24 that staff have been “thinking through this stuff” and running the analyses. ERCOT is working with the Independent Market Monitor and Public Utility Commission staff on the study. 

Jeff Billo, ERCOT | © RTO Insider LLC 

“We really think that we have the right services and the right methodology for quantifying those services today,” Billo said. Unsurprisingly, he said ERCOT plans to use the current mechanisms and is not proposing any changes to those products. 

Billo said the first preliminary recommendation covers the frequency control portion of ancillary services: regulation, responsive reserve service and the frequency-response portion of ERCOT Contingency Reserve Service (ECRS). Staff’s other recommendation is to examine the benefits of determining some portion of AS quantities closer to the operating day based on daysahead forecast conditions rather than an annual calculation. 

Some ERCOT stakeholders and the IMM have objected to the heavy use of ECRS since its first use last year, saying it has added billions of dollars in costs to the energy-only market. The grid operator procures capacity resources that can be brought online within 10 minutes and sustained at a specified level for two consecutive hours. (See “Contentious NPRR Revising ECRS Passes over Monitor’s Objections,” ERCOT Board of Directors Briefs: June 17-18, 2024.) 

Billo reminded TAC of where ERCOT was in 2021, when he told the committee that staff were going to a conservative operations approach, setting aside larger amounts of operating reserves than before.

“[I said we] were going to not walk up right to the edge of the cliff, but we were going to take a few steps back, and we were going to operate with higher reserve margins in real time,” he said. “The idea there is that we’re operating with a lower risk compared to how we historically operated, and that has also driven a change in the amount of ancillary services that we’re getting.” 

ECRS and other products have become necessary with the increased addition of renewable resources and the resulting growth in load variability, Billo said. He said ECRS was needed to address increasing net load ramps causing greater intra-hour risk and fewer online reserves available to recover frequency after a large unit trips. 

“We see the greater exposure when we have forecast misses and so that’s why you’ll see, during especially those ramp times, that we’re getting higher amounts of ECRs to cover that kind of higher exposure,” Billo said. 

Also playing a role in the increased use of AS was the public’s anxiety over ERCOT’s ability to meet demand following the disastrous and deadly 2021 winter storm that nearly brought down the Texas grid. 

“I think that prior to Winter Storm Uri, there were lots of times where we had watches or we went into [energy emergency alerts] and the public didn’t really notice and didn’t really care,” Billo theorized. “Post-Uri, I think as we saw in 2021, there were times where we would go into a watch and that there’d be a lot of attention on that from the public, but also from state leadership. I think the message that we got … was, ‘ERCOT, we don’t want you to go into a watch and an EEA as much as you have in the past.’ 

“In my mind, that is a criteria change for how we operate the system and the amount of reserves we’re procuring,” he added. 

The IMM’s deputy director, Andrew Reimers, told TAC the IMM’s study is intended to estimate the reliability value of different levels of reserves to inform AS procurement targets. He said the Monitor is focusing on reserves that are responsive within minutes to hours.  

The IMM is using 10,000 random draws of a Monte Carlo simulation for each hour in the study period to determine how reserve levels influence loss-of-load projections, given probabilistic distributions of unplanned outages and net load forecast errors. Its staff are using historic hours from June 2023 to June 2024 to compare the capacity at risk to different reserve levels. 

“The timeline is definitely a challenge,” Reimers said. “We’re trying to triage this to do the best study that we can given the relatively limited amount of time we have to go on. Ultimately, that means prioritizing what we can getting the results that we can and then figuring out what things have to be left for future work.” 

“We’ve had a lot of really good conversations with the IMM. I don’t know if by this September that we’ll agree on all of the details, but conceptually, I think we agree on the framework,” Billo said. “Some of the things we still need to think through are around data. It’d be great if we used 10 years of data, but the forecasts have improved. I’m trying to quantify what my risk is of a forecast error; I really don’t want to use forecast data from 10 years ago.” 

Billo asked for stakeholder input before he presents a study update to the Board of Directors during its Aug. 19-20 meetings. An AS workshop will be held after the Aug. 28 TAC meeting and a final report posted to the commission before October. 

The PUC also plans an AS workshop in the latter half of October. It’s asking for TAC feedback on which ERCOT and IMM information presented Aug. 28 would be most helpful in filing comments at the commission (55845).  

The study is a requirement of legislation passed last year by Texas lawmakers. It directs the PUC to review the type, volume and cost of AS and determine whether those services are necessary in the ERCOT market. The law also requires the commission to evaluate whether additional services are needed for reliability. 

Separately, ERCOT staff will begin discussions with stakeholders in July on the grid operator’s 2025 AS methodology. (Billo said ERCOT won’t have time to incorporate learning from the PUC study’s results.) 

Staff plan to present its proposal during the October board meeting, allowing for PUC review before next year. ERCOT’s annual requirement to update its AS methodology now includes commission approval. 

Members Endorse 7 Changes

TAC approved a protocol change (NPRR1190) that would recover demonstrable financial loss arising from a manual high dispatch limit (HDL) override to reduce real power output, should the output be used to meet qualified scheduling entity load obligations. 

The change’s approval came after an attempt to table NPRR1190 until further IMM review came up short. The measure passed 22-6 with an abstention. 

The consumer segment provided all six opposing votes over concerns that the change incorrectly expands the opportunity for entities to receive compensation for scheduled-but-not-provided energy under out-of-market ERCOT actions. Supporters noted the infrequent occurrence of the conditions covered by the NPRR and the language that prevents recovery of lost opportunity costs stemming from an HDL override, according to the committee’s report. 

The motion to table failed 8-19 with a pair of abstentions. The consumer segment favored tabling. 

Members also endorsed three other NPRRs, an Other Binding Document revision (OBDRR) and single changes to the Planning Guide (PGRR106) and the Verifiable Cost Manual (VCMRR) that, if approved by the Board of Directors, would: 

    • NPRR1215: clarify that the day-ahead market’s energy-only offer credit exposure calculation zeros out negative values, with any zeroed-out values being included in the calculation of the percentile difference. 
    • NPRR1216, OBDR051 and VCMRR039: align the protocols with the PUC’s order establishing an emergency pricing program for the wholesale market. During an emergency offer cap (ECAP) effective period, the systemwide offer cap is set to the ECAP, with a value equal to the low systemwide offer cap. 
    • NPRR1225: update the protocols to align with the PUC’s declaratory order on ERCOT’s settlement systems. The grid operator added revisions to meet the commission’s order that exclusions be effective March 4, 2024, when the transfer of Lubbock Power and Light retail customers to retail electric providers began. 
    • PGRR106: clarify which transmission projects are included in the Transmission Project Information and Tracking report. 
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BNEF: ICE Phaseout by 2035 Critical to Reach Net Zero by 2050

Electric vehicle sales may have slowed in the U.S., but elsewhere, EV markets are robust and growing, according to BloombergNEF’s new Electric Vehicle Outlook 2024 report. 

About 20% of all vehicles sold worldwide this year will have a plug ― either battery electric or plug-in hybrid ― with sales predicted to rise to one-third by 2027, said Colin McKerracher, head of clean transportation at BNEF, speaking during a June 26 launch webinar for the report. But even more growth, government support and private investment will be needed to hit national and global targets for EV adoption and critical reductions in transportation emissions.  

“Internal combustion engine vehicle sales peaked in 2017 ― that’s seven years ago ― and they are now down 30% from their 2017 peak,” McKerracher said. BNEF does not expect sales of ICE vehicles to regain their 2017 peak, but also doesn’t see them disappearing. 

The report looks at two scenarios. In the “economic transition” scenario, EV adoption is driven by technological, economic and market forces, with no new polices or additional government support, and “most countries do not achieve a full phaseout of combustion engine sales,” he said. 

BNEF’s second, net-zero scenario looks at what will be needed to get to a “net zero-capable fleet” by 2050 and keep global climate change under 2 degrees Celsius. A phaseout of ICE sales by 2035 would be required, and in some markets even sooner, McKerracher said.  

The emission reductions needed for a global net-zero target would “rely on hundreds of millions of electric vehicles on the road by 2050, even approaching 1 billion,” he said. “If that market doesn’t deliver that, then most of those climate targets will be unreachable.” 

President Joe Biden wants 50% of all U.S. auto sales to be electric by 2030 and has pledged to cut the nation’s GHG emissions 50 to 52%, also by 2030. EVs made up about 7% and PHEVs 2% of U.S. auto sales in 2023, according to the U.S. Energy Information Administration.  

By comparison, BNEF’s figures show global EV markets moving in the right direction but still falling short of the growth needed for net zero, McKerracher said. By the end of 2023, light-duty passenger EVs made up about 18% of all vehicles in the fleet, while electric vans and trucks accounted for only 4%. Buses are a major wedge for transportation electrification, coming in at 26% of the existing fleet. 

China’s ongoing dominance and the lackluster status of the U.S. in both BNEF scenarios expose some of the challenges facing wider EV adoption in the U.S. ― including the increased power demand from EVs ― and potential blind spots for domestic automakers. 

For example, while Chinese automakers are racking up sales from a range of lower-priced EVs aimed at middle- and lower-middle-income customers ― and making inroads in emerging markets ― the U.S. market is saturated with higher-priced electric SUVs.  

Chinese automakers also are ahead in sales of plug-in electric vehicles (PHEVs), which have become one of the fastest-growing segments in global markets, due in part to newer models with longer electric battery ranges. The average electric range for Chinese PHEVs is 55 miles, BNEF says, while in the U.S., most PHEVs now available have electric ranges well under 40 miles, according to a recent analysis by J.D. Power. 

The difference, McKerracher said, is that U.S. and European PHEVs are designed to meet government-mandated standards for cutting vehicle emissions. Newer PHEVs, with longer electric ranges and larger batteries, “are also aimed at actually satisfying a customer’s needs,” he said.  

The Miles Matter

Another significant insight from the study is that worldwide EVs and PHEVs are driven more miles than ICE vehicles. 

“When you talk about energy impacts and emission impacts, what matters is the total kilometers, not the total number of cars on the road,” McKerracher said.  

One factor here is that taxi and ride-share drivers around the world are buying EVs and putting tens of thousands of miles on them per year, he said. Looking again at China, McKerracher said, “The vast majority of professional drivers in taxi and ride-hailing applications are driving EVs now. The working drivers who really care about total cost of ownership are switching to electric way, way faster than the private owners.”  

The U.S. is the exception to the global trend: EVs and PHEVs here are driven fewer miles than ICE vehicles, except in California. McKerracher speculated that EV drivers there may have better access to charging infrastructure and be past the early adopter stage in which households may have more than one car and drive a new EV less than their ICE. 

More miles driven also means more electricity used. Ryan Fisher, BNEF’s lead for charging infrastructure, said that by 2050, the additional electricity needed to power EVs worldwide could equal twice the total annual electricity demand of the U.S. ― or about 11 to 12% of global power demand. 

The exact cost of building out the grid to meet that demand will vary and may be hard to split out from grid capital expenses in general, Fisher said. In its economic transition scenario, BNEF sees global grid spending for EV charging rising from 5% in 2025 to a high of over 15% in 2040 and then falling back to 5% by 2050. Costs are less in the net-zero transition, staying between about 4 to 11%. 

In either case, making those investments may require “special finances to come in loans, for example, from different government bodies to support this big infrastructure growth, to basically give us those incentives and upgrades we need in those later years,” he said. 

He also pointed to EV chargers as potential grid assets, with the global fleet of chargers eventually providing as much as 10 TWh of storage. 

Battery Oversupply

The big story in the EV supply chain is the rapid drop in battery prices in China and a resulting oversupply, which is driving increased competition in the market, both in China and worldwide, said Yayoi Sekine, who leads BNEF’s energy storage team.  

A key driver is the move away from lithium batteries with its more expensive nickel and cobalt chemistry toward lithium, iron and phosphate (LFP) batteries. Sekine sees LFP “taking over the battery market” between now and 2030, with the technology gaining ground based not only on cost, but on “improvements in performance in low-temperature environments, as well as things like improvements in fast-charging capabilities.” 

China continues to dominate in the battery market, controlling “upwards of 85%” of all parts of the supply chain, Sekine said. The average price for LFP batteries in China is $53 per kWh, versus $95 per kWh worldwide. 

“There’s a lot of competition in [the Chinese] market, and a lot of battery cell manufacturers are willing to squeeze their margins to sell into this market at higher volumes,” she said.  

Worldwide, BNEF projects that by 2025, global battery production will reach 7.9 TWh of capacity, which could be four times more than demand. Sekine said lower prices and oversupply could stoke some additional EV demand, but not enough “to absorb all the overcapacity we see in the market.” 

Similarly, Sekine noted the EV battery supply chain is being overbuilt, with billions going into battery cell manufacturing but much less toward mining and refining of the critical minerals needed for batteries. At present, the investments for battery factories announced worldwide average $155 billion per year between now and 2030, which is about 2.4 times what would be needed for BNEF’s net-zero scenario, she said. 

Investments in mining and refining totaled about $7.2 billion in 2023, about half of the $15 billion per year that will be needed by 2025, she said. 

Tariffs and Trump

The webinar closed with a few minutes for audience questions, with the impact of EV tariffs in the U.S. and Europe and the potential impact of Donald Trump returning to the White House in 2025 being hot topics. 

Biden announced a 100% tariff rate on Chinese EVs in May and raised tariffs on Chinese EV battery cells from 7.5 to 25%. The European Commission has set tariffs ranging from 17 to 38% on imported EVs, on top of its existing 10% tariff on cars, according to Reuters. The European tariffs are scheduled to go into effect in July.  

With the steep drop in battery prices in China ― allowing for lower-priced EVs ― some Chinese automakers could absorb the lower European tariffs without raising their prices, McKerracher said. Higher tariffs will be more difficult to absorb and could have a “negative near-term impact for EV adoption,” he said. 

“I think the big picture is that this does push more localization,” McKerracher said. “The fragmentation of the global auto market means more automakers will have to localize production, and you’re already starting to see that effect.” 

The impact of the tariffs could also dissipate as Chinese automakers move manufacturing hubs to other countries, he said, as has occurred with solar cells and panels. Leading Chinese automaker BYD plans to build a factory in Mexico and began building a plant in Brazil this year, according to a June 21 report in Electrek.  

On the election, McKerracher said a Trump administration likely would be “significantly less favorable” to EVs. “They will probably go after some of the things that are helping drive EV adoption … like [Corporate Average Fuel Economy] standards, as well as California’s waiver [from EPA] to set its own standards.” 

On the Inflation Reduction Act, McKerracher questioned the conventional wisdom that the law has driven so much investment ― and new jobs ― into red states, that its tax credits and other incentives would not be repealed. 

“I don’t know if that rationality will hold,” he said. Trump has been railing against EVs in his recent campaign speeches, McKerracher said, “so, whether that jobs argument and the investment argument are stronger than a more ideological or partisan one, it’s hard for us to say right now.” 

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NEPOOL Holds Summer PC Meeting amid New England Heat Wave, Climate Protests

BRETTON WOODS, N.H. — Government officials, RTO leaders, industry representatives and climate protesters from New England and beyond descended upon the Mount Washington Hotel in New Hampshire’s White Mountains for the 21st annual NEPOOL Participants Committee summer meeting June 25-28.

During a multiday stretch of extreme heat just days prior to the meeting, the ISO-NE grid hit its highest demand of the year at 23,324 MW, which caused the RTO to issue an abnormal conditions alert that extended across three days. The outage of a large generator as the system approached the daily peak on June 19 forced the RTO to dip into its operating reserves to stabilize the grid.

The peak loads throughout the heat wave were significantly reduced by the recent progress of behind-the-meter solar in the region. Preliminary data from ISO-NE indicate BTM solar reduced the peak on June 20 by about 2,500 MW, while also shifting the peak later in the day.

But the proliferation of distributed renewables is not without its challenges for grid operators. Previewing the RTO’s preliminary 2025 budget, ISO-NE CFO Robert Ludlow projected a 13.5% increase — a $37 million bump — in ISO-NE’s annual revenue requirement, largely because of increasing demands of the clean energy transition.

This increase would result in a 17.1% increase in the per-kilowatt-hour rate charged to consumers, or an approximately 25-cent increase in the monthly charge to the average ratepayer.

“The main driver of the 2025 budget is the need to add personnel to the organization to address the modeling, analysis, processing, operational and communication needs directly resulting from the clean energy transition,” Ludlow said.

The preliminary budget proposal comes on the heels of a 21% revenue increase for 2024, which also was based on needs associated with the changing resource mix. (See ISO-NE Proposes 21.5% Budget Increase for 2024.)

Ludlow said the energy transition creates new technology and cybersecurity needs and requires better modeling and forecasting “to account for net load characteristics and trends that have rapidly evolved in recent years and are anticipated to change even more significantly in the coming decades.”

ISO-NE’s ongoing work to significantly reform its capacity market, along with a greater focus on long-term transmission planning, also contributed to the proposed budget increase, Ludlow said. (See Stakeholders Support ISO-NE Long-term Tx Planning Filing, with Caveats.)

Recommendations from the External Market Monitor

David Patton of Potomac Economics, ISO-NE’s External Market Monitor, presented his annual report on the markets along with several recommendations for improvements.

“We find that the markets performed competitively but identify key improvements that will be increasingly important in the coming years,” Patton said, adding that there was “no market power abuse or manipulation affecting clearing prices.”

He noted that New England has high energy costs relative to other RTOs because of higher gas prices, along with higher capacity costs “because of over-forecasted demand ahead of the [Forward Capacity Auctions], which are slow to correct in the” capacity market.

Congestion costs remain extremely low in the region because of transmission investments made in the past 10 years, although this has led to significantly higher transmission costs, Patton said.

Patton added that ISO-NE’s wholesale markets are “fundamentally robust and structured to handle” the increasing influx of intermittent renewable generations because of “efficient shortage pricing” and the ongoing work to improve the accreditation of resources in the capacity market.

He said ISO-NE could drive more efficient prices by adopting a “look-ahead dispatch model to optimize multiple hours into the future.” Such a model could provide important signals for slower-ramping resources to prepare to come online and for storage resources to optimally dispatch, Patton said.

Patton also provided a pair of recommendations based on the assessment of a capacity deficiency event in July 2023, which was triggered by the shutdown of a Hydro-Québec transmission line because of nearby wildfires. (See Canadian Wildfires Trigger ISO-NE Capacity Deficiency.)

While ISO-NE curtailed some exports during this event, the structure of the Pay-for-Performance (PFP) pricing enabled some generators to profit while simultaneously exporting their power to neighboring regions. To close this loophole, the Monitor proposes charging all exports the PFP rates, effectively canceling out any PFP profits they could make from New England for exported power.

He also said ISO-NE should adjust how it scales PFP prices, arguing that “fixed, escalating PFP rates and shortage pricing together set prices much higher than efficient levels during most shortages, incenting suppliers to self-commit high-cost units inefficiently and retire longer-lead-time units inefficiently.”

With winter risks projected to surpass summer risks in the 2030s, Patton said ISO-NE’s proposed transition to a prompt and seasonal capacity market will help the region cope with winter challenges. However, he stressed the importance of ISO-NE’s ongoing resource capacity accreditation (RCA) changes to mitigate winter reliability risks.

Patton said the RCA project should rely on “conservative assumptions” related to LNG inventories to account for historical inventory variability associated with LNG prices. He said this would increase incentives for generators to enter firm fuel contracts.

Finally, Patton said ISO-NE’s proposed accreditation model does not explicitly include fuel inventories, and that this could lead to reliability issues during extended winter cold snaps. Failing to model fuel inventories would cause the capacity market to significantly overestimate the winter value of storage resources and undervalue the contributions of offshore wind, Patton said.

The inventory recommendation spurred some concern from NEPOOL members representing storage companies, who have stressed that the accreditation framework already outlined would result in a major reduction in capacity revenue for storage resources, potentially undermining state policy objectives regarding storage. (See ISO-NE: RCA Changes to Increase Capacity Market Revenues by 11% and Panel Provides Update on Energy Storage in Mass.)

Operations Report

ISO-NE COO Vamsi Chadalavada reported that the May energy market value was up by about 12% compared to May 2023, and by about 9% relative to this April.

His report also noted that 832 MW of solar and battery storage projects were added to the ISO-NE interconnection queue, which now totals over 47,000 MW.

New England power sector emissions for this year are tracking at a similar level as 2023 emissions, at just over 10 million metric tons of CO2 equivalent through mid-May. Coal and oil emissions are down significantly, while natural gas emissions have increased, Chadalavada’s report said.

NEPOOL

Estimated ISO-NE emissions through May 19 | ISO-NE

Climate Activists Join the Party

NEPOOL members were joined at the Mount Washington Hotel by several climate activists from the organization No Coal No Gas. They attended because “FERC sent us,” they said.

The commission recently denied No Coal No Gas’ petition of the results of FCA 18, ruling that the activists’ concerns about a structural bias of the auction in favor of fossil fuels were outside the scope of the proceeding (ER24-1290). (See FERC Accepts Results of New England Capacity Auction.)

Instead, these concerns should be raised in the stakeholder process, FERC wrote. Because NEPOOL is the official stakeholder advisory group for ISO-NE, the activists pitched in for a hotel room to bring their concerns to the summer meeting, they said.

The activists largely refrained from interfering with the NEPOOL goings on, instead distributing informational fliers in front of the meeting room about their capacity market concerns and sat at the periphery of the catered dinner and open bar eating trail mix.

They did, however, take aim at NEPOOL’s annual golf tournament. Eluding security guards by taking cover in the marshes surrounding the golf course, the activists left notes and planted coins and saplings in golf holes to express their disapproval of the grid’s continued reliance on fossil fuels and the lack of public transparency into NEPOOL meetings.

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FERC Rules for CAISO on Capacity Deliverability Rights Complaint

FERC on June 27 denied a complaint alleging CAISO unlawfully terminated the full capacity deliverability rights associated with a Mexico-based gas-fired generating unit that previously was interconnected with the ISO’s grid (EL24-92).

At issue in the order was the CAISO deliverability status of Unit C, a 181.5-MW combustion turbine plant operated by energy conglomerate Saavi. Under California rules, a resource with full capacity deliverability rights is entitled to count 100% of its output as qualifying capacity in the state’s resource adequacy program.

According to the complaint, since 2003, Saavi has operated Unit C under a FERC-approved nonconforming participating generator agreement (PGA) that gave the company the right to dispatch the plant into either CAISO or the territory of the Federal Electricity Commission (CFE), Mexico’s state-owned utility and national grid operator. The PGA outlined a process by which the unit could switch its dispatch location, with the option to reconnect to the CAISO grid after a disconnection.

“Saavi explains that these nonconforming terms were negotiated to accommodate legal and jurisdictional issues, as well as electrical configuration issues, which are unique to Unit C’s situation as a generator normally connected to and serving the CAISO grid, but that is physically located in Mexico,” the commission wrote.

Saavi said that in 2017, after providing the required contractual notice, it disconnected Unit C from CAISO in order to connect the plant to CFE’s grid to address reliability issues. In subsequent years, the company provided the ISO with semiannual updates on the unit’s interconnection status and continued to extend its disconnection from the California grid.

The company said CAISO expressly approved each extension and that the approval letters stated the ISO would “permit the continued disconnection and future reconnection of [Unit C],” but it also noted that “during the time period it is connected to CFE, [Unit C] will no longer be available or eligible to meet resource adequacy requirements in the ISO balancing authority area.” At no time during Unit C’s connection to CFE did CAISO indicate the plant was at risk of losing its deliverability status, Saavi contended.

Replacement Generation

The complaint goes on to describe that, in 2022, Saavi began developing a battery electric storage system (BESS) that would be connected to the CAISO grid using the same 230-kV Saavi-owned transmission line that connects Unit C to the ISO, saying that the BESS would act as replacement generation for the plant. The first phase of that project, designed to provide 185 MW of power, would reach commercial operation in third quarter of 2027.

Saavi said it was during the initial discussions with CAISO about the BESS project that it learned that Unit C had lost its deliverability status in the ISO because it “has been disconnected from and has not been scheduled into the CAISO system nor operated at the capacity level associated with its rated deliverability for over three years, which is required to retain such rights,” a stipulation CAISO said is laid out in the reliability requirements section of it Business Practice Manuals (BPMs). But the plant still retained its interconnection service capacity rights, the ISO noted.

Saavi argued that CAISO’s termination of Unit C’s deliverability status was unlawful under the Federal Power Act because it contradicted the procedures laid out in the PGA to accommodate Unit C’s status as a grid-switching resource. The company contended that it well exceeded the notice requirements of the PGA because it regularly consulted with CAISO regarding Unit C’s status and that the ISO repeatedly approved the continued connection with CFE.

Saavi also contended CAISO misapplied the BPM language by finding that Unit C’s temporary connection to CFE amounted to a valid reason to terminate full deliverability status, in part because the manual stipulates that a plant will lose that status after being unable to operate at its rated level for three consecutive years.

“However, Saavi states that this BPM section also makes an exception for a holder of the deliverability priority to retain its rights after the expiration of the three-year period if it can demonstrate that it is actively engaged in the construction of replacement generation to be connected at the bus associated with the deliverability,” FERC noted.

CAISO Response

In an April 9 answer urging the commission to deny the complaint, CAISO argued that Saavi’s arguments are not supported by the language of the PGA, the ISO’s tariff and the BPM for reliability requirements. And while CAISO noted that the PGA stipulates that Saavi can disconnect and reconnect with the ISO grid after providing written notice, the agreement also states that it “will be subject to the requirements of the CAISO tariff at all times.” Included in those requirements is the obligation for a generating unit to maintain an association with a CAISO-certified scheduling coordinator, something Unit C failed to do after disconnecting from the ISO in 2017 through July 2020, meaning the unit could not have had deliverable output for the consecutive three-year period.

CAISO also argued it was Saavi’s responsibility to stay compliant with its obligations under the tariff and BPM, and therefore it should have known about the requirement to remain associated with a scheduling coordinator and that it would lose deliverability status after three years of not providing RA to California.

The ISO additionally contended that Saavi was mistaken in assuming the disconnection approval letters constituted an exemption from applicable tariff or BPM rules, or indicated continued deliverability status.

FERC Denial

In ruling in favor of CAISO, FERC found that in revoking Unit C’s full deliverability status, the ISO had not violated its tariff or unlawfully discriminated against Saavi.

“The tariff and the function of deliverability within the overall California resource adequacy framework support a finding that CAISO appropriately revoked Unit C’s deliverability rights after a three-year consecutive period of disconnection from the CAISO grid, during which time Saavi remained disassociated from any scheduling coordinator and was, therefore, incapable of operating in the CAISO markets,” the commission wrote.

The commission said it found “unpersuasive” Saavi’s contention that, in the CAISO BPM, the “capable of operating” provision for retaining deliverability “means merely that the generating unit can produce electric power up to its rated capacity, because this position ignores that, under the tariff, operating as a generating unit includes the ability to deliver the electric power that the generating unit produces to the CAISO grid.”

Rather, the commission found, the tariff “expressly links a resource’s deliverability to its eligibility to provide resource adequacy capacity.”

FERC additionally agreed with CAISO that revocation of Unit C’s deliverability rights did not violate the PGA because the agreement specified that the plant would be subject to ISO tariff requirements “at all times.”

The commission also said Saavi’s reliance on CAISO disconnection approval letters was “misplaced.”

“Nothing in these letters implies that Saavi was exempt from otherwise applicable requirements under the tariff and, therefore, cannot be interpreted as an affirmation of Unit C’s continued deliverability status,” it wrote.

The commission also agreed with CAISO that Unit C’s former deliverability allocation cannot be transferred to Saavi’s BESS project.

“First, as a practical matter, Unit C lost its deliverability in July 2020, three years after it disconnected from the CAISO grid and disassociated itself from its scheduling coordinator,” FERC said. “Consistent with its tariff, CAISO accounted for that development and reallocated the deliverability formerly associated with Unit C to other generators in the same electrical area. In essence, therefore, there is no deliverability available to transfer to the BESS.”

Second, FERC found, Saavi missed the window for starting such a discussion about replacement generation, which CAISO’s BPM stipulates must be initiated before expiration of the three-year period.

“Here, however, Saavi did not initiate discussions about the planned BESS until summer 2022, almost two full years after the three-year deliverability retention window closed,” the commission concluded.

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FERC Grants SoCal Edison Incentives for 2 Transmission Projects

FERC on June 27 approved two transmission incentives requested by Southern California Edison (SCE) that would offset potential costs associated with building the Del Amo-Mesa-Serrano and Lugo-Victor-Kramer projects (EL24-71). 

In an order issued at its monthly open meeting by a 2-1 vote, FERC found the projects satisfy the Order 679 requirement for incentive rate treatment because they improve reliability or reduce congestion, as both projects are included in CAISO’s 2022-2023 Transmission Plan. 

FERC approved use of the construction work in progress (CWIP) and the abandoned plant incentives mainly because of the long lead times and potential local opposition for both projects. As has become common in transmission rate incentive requests, Commissioner Mark Christie dissented. 

The Del Amo project will extend through Los Angeles, San Bernardino and Orange counties. It includes constructing a new 500/230-kV substation with three new transformer banks and new 500-kV transmission line segments, including two approximately 13-mile segments from SCE’s Del Amo and Serrano substations. It will also include another 13-mile 500-kV line from the Del Amo substation and a 2-mile 500-kV line from the Mesa substation to create the Del Amo-Mesa line. Finally, the project will require a loop of SCE’s 230-kV Alamitos-Barre No. 1 and No. 2 transmission lines into the Del Amo substation. 

The Lugo project was selected by CAISO to increase access to solar resources and will help California meet its clean energy mandates, as well as increase reliability by addressing certain constraints and voltage instability identified in the region. The project will include the construction of a new 500/230-kV transformer, reconductoring of four 230-kV transmission lines, reconstruction of SCE’s 115-kV Kramer-Victor line to increase it to 230 kV, and looping a remaining old segment of the Kramer-Victor line into SCE’s Roadway substation. 

SCE requested to “include 100% of prudently incurred construction work in progress for the projects in rate base” and “recover 100% of prudently incurred costs of the projects if they are abandoned for reasons beyond SoCal Edison’s control.” 

The latter incentive is to account for the long lead times from the extensive licensing processes required by the California Public Utilities Commission for the projects, in addition to potential local opposition. The utility also argued that the projects qualify for the CWIP incentive because of the time between the commencement of construction and the anticipated final in-service dates in 2033. 

“SoCal Edison contends that requiring the investors to wait years before seeing a return on their investments would diminish the attractiveness of these investments, which CAISO has deemed necessary in its transmission plan,” FERC said. “SoCal Edison maintains that this rate treatment will provide upfront regulatory certainty, rate stability, improved cash flow at a time when SoCal Edison is financing significant wildfire mitigation-related capital expenditures, and substantial infrastructure replacement activities needed to support system reliability.”  

SCE also highlighted that the CWIP incentive would decrease the likelihood of “rate shock” to its customers. Without CWIP recovery, FERC said, all of SCE’s rate increases will apply to its customers at one time.  

The CPUC filed a protest against SCE’s request for the CWIP incentive in March. “While the CPUC does not oppose FERC granting SCE the abandoned plant incentive for these projects, the CPUC protests this filing because SCE has not demonstrated that the CWIP incentive should be granted here,” it told FERC. “The CWIP incentive has shown to be harmful to California ratepayers, providing premature and excessive rate recovery. Granting the incentive goes beyond the intended scope of Order 679 and would not result in just and reasonable rates.” 

The CPUC further explained that, with projects having longer lead times and higher costs than forecast when the incentives were granted, the incentives end up being costlier to customers, “resulting in customers effectively serving as lenders to the utility, with the benefit being one-sided toward the company.” 

The state commission also argued that SCE has a history of long delays and cost overruns associated with its projects and that CWIP removes the utility’s incentive to complete them on time. The CPUC requested that, should FERC grant the incentive, CWIP eligibility be capped at the cost of the project and be rescinded once CAISO’s in-service date has passed. 

In its answer to the protest, the utility asserted that the CPUC “ignores that CWIP is intended to address the very risks that the CPUC derides as SoCal Edison’s failures, disregards the benefits of CWIP to ratepayers and improperly requests that [FERC] implement widespread policy changes.” 

FERC granted the incentive without conditions. 

“We find that SoCal Edison has shown a nexus between the proposed CWIP incentive and its investment in the project. We agree that recovering CWIP expenditures in transmission rate base will help cash flow and smooth the projects’ rate impact,” FERC said. “The commission has also found that allowing companies to include 100% of CWIP in rate base would result in greater rate stability for customers by reducing the ‘rate shock’ when certain large-scale transmission projects come online.” 

SCE expects to start construction for the Lugo project in 2027 and the Del Amo project in 2030. 

While Commissioner Christie noted in his dissent that he continues to urge revisiting FERC’s policies under Order 679, he was particularly incensed by the majority’s approval of incentives because the CPUC has not yet approved the projects themselves. Under 679, the commission presumes that projects included in an RTO/ISO transmission plan will enhance reliability or reduce congestion. 

“Although regional transmission planning process is only one rebuttable presumption established in Order No. 679 allowing qualification for incentive rate treatment, reliance on regional transmission planning in lieu of state approval to construct is one of the major problems with FERC’s policy. This practice is indefensible and always has been,” Christie wrote. 

“With all due respect to CAISO’s transmission planning process — and I do respect it along with planning processes in other RTOs/ISOs — the regional planning process in a transmission planning organization is not remotely the equivalent of a serious litigated state [approval] process, which includes witness cross-examination and is open to intervenors such as consumer advocates.” 

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BOEM Sets Central Atlantic OSW Auction for August

The federal government will auction two lease areas along the Central Atlantic coast for wind energy projects with a potential of up to 6.3 GW of emissions-free power generation. 

The June 28 announcement by the Bureau of Ocean Energy Management had been expected, and the prospect has drawn interest — 17 companies have been qualified to participate in the Aug. 14 auction. 

This auction is the first in a series of a dozen offshore wind lease sales tentatively scheduled by BOEM through the end of 2028. Next up are a Gulf of Mexico wind energy auction targeted for September and auctions in the Gulf of Maine and off the coast of Oregon targeted for October. 

BOEM’s Central Atlantic region — from Delaware to North Carolina — includes the largest U.S. wind farm announced to date: Dominion’s 2.6-GW Coastal Virginia Offshore Wind, now under construction.  

But planning for additional development has run into conflict due to concerns that massive wind turbines would be incompatible with military and NASA operations in the area. 

BOEM announced eight possible wind areas totaling 1.7 million acres in November 2022. That was winnowed down to three, two of which will be offered in this auction: A-2 (101,433 acres off the mouth of Delaware Bay) and C-1 (176,505 areas off the mouth of Chesapeake Bay).  

The third, Area B-1 (78,285 acres off Ocean City, the only one of the three off the Maryland coast), may be offered in a future auction. 

This has limited the options for Maryland as it tries to reach its goal of 8.5 GW of offshore wind installed by 2031.  

The state lost Skipjack Wind from its portfolio in January, after Ørsted decided it would not proceed to construction under the existing offtake agreement. In May, the state allowed the one offshore wind developer still under contract, US Wind, to seek increased compensation for its projects. 

In December, after it concluded it could not offer B-1 at auction, BOEM committed to helping Maryland reach its goals. The two formalized that agreement with a memorandum of understanding June 7. 

Trade group Oceantic Network welcomed the June 28 auction announcement but said additional seabed acreage for offshore wind development is critical for the region and for Maryland in particular: “We encourage BOEM and Maryland to continue their work in identifying new areas to help meet regional targets,” CEO Liz Burdock said in a prepared statement. 

The Central Atlantic auction announcement comes amid a regulatory transition for BOEM: Its new Renewable Energy Modernization Rule will take effect July 15, by which time the terms of the auction already will have been set. 

Before the Central Atlantic auction takes place, details such as timing of lease terms and formulas for calculating operating fees will be revised according to the new rule. 

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Bp Says It is Still Evaluating Beacon Wind

Oil supermajor bp said it is still evaluating its options for Beacon Wind, the offshore wind plan it withdrew from New York’s renewable development queue early this year. 

Reuters reported June 27 that CEO Murray Auchincloss had taken steps to refocus bp on oil and gas, pausing new offshore wind development and instituting a hiring freeze. 

It was a sharp reversal from the transition away from fossil fuels begun by his predecessor, Reuters said. And it followed a decision by the subsidiary of another oil supermajor, Shell, to divest its 50% share of the SouthCoast Wind proposal off the New England coast. 

NetZero Insider asked bp about the impact of Auchincloss’ decision on its proposals in New York: Beacon Wind, a two-phase wind farm on a 128,811-acre tract off the southeast end of Long Island, and the Astoria Gateway for Renewable Energy, a converter station for the power generated by Beacon.  

The Gateway would be built on the northwest end of Long Island, in a New York City neighborhood where a gas turbine peaker plant once stood. 

A U.S.-based bp spokesperson indicated no decision has been made on the New York plans: “We are pursuing a disciplined, value-driven development approach to the Beacon Wind and Astoria Gateway for Renewable Energy projects, which includes taking the necessary time to fully evaluate the initial design plans. This will enable us to continue advancing the developments and deliver the highest value to local communities and bp.” 

The company website lists offshore wind plans in Germany, Japan, South Korea, the United Kingdom and the U.S., Beacon.

Beacon Wind was a product of the 50-50 partnership between bp and Equinor, the Norwegian oil and gas producer making a hard push into renewables. 

The two had secured a contract from New York for the 1,230-MW Beacon Wind 1 in New York’s 2020 solicitation and unsuccessfully bid the 1,360-MW Beacon Wind 2 into New York’s 2022 solicitation. 

Beacon Wind 1 became one of the many offshore wind casualties in 2023 and early 2024, when the majority of projects along the Northeast coast were canceled outright or canceled offtake agreements. Amid soaring costs, it had become financially untenable to proceed to construction with revenue agreements locked in years earlier. 

Equinor and bp also held New York contracts for Empire Wind 1 and 2, and decided to cancel them, as well. 

Amid the fallout, the two companies dissolved their partnership. 

As part of the split, Beacon and Astoria went to bp. Empire went to Equinor, which continued to actively develop the proposal. 

New York recently awarded Empire Wind 1 a new contract at a much higher strike price. Equinor expects to “mature” Empire Wind 2 and rebid it into a future solicitation. 

After the split, Equinor also took sole ownership of the partners’ lease of the South Brooklyn Marine Terminal. It is now converting the site to an offshore wind hub for Empire and for future projects other companies envision off the Northeast coast. The contractor, Skanska, has said the contract is valued at $861 million. 

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Supreme Court Ends Chevron Deference to Administrative Agencies

The U.S. Supreme Court on June 28 overturned the doctrine of deference to federal agencies in interpreting statutes when issuing rules, ending 40 years of legal precedent and putting into question numerous existing agency rules, including those from FERC.

In a 6-3 decision, with Chief Justice John Roberts writing the majority opinion, the court said that the doctrine, known as Chevron deference after the 1984 case Chevron v. Natural Resources Defense Council, cannot be squared with the Administrative Procedure Act (APA), in which Congress said that the reviewing court — not the administrative agency in a case — is to “decide all relevant questions of law.”

“Chevron cannot be reconciled with the APA by presuming that statutory ambiguities are implicit delegations to agencies,” the court said. “That presumption does not approximate reality. A statutory ambiguity does not necessarily reflect a congressional intent that an agency, as opposed to a court, resolve the resulting interpretive question. Many or perhaps most statutory ambiguities may be unintentional.”

The ruling came in the case of Loper Bright Enterprises v. Raimondo, which dealt with requirements from the Department of Commerce that commercial herring fishers pay for federal employees on their ships to monitor their catch to prevent overfishing. (See Supreme Court Hears Oral Arguments on Overturning Chevron.)

The department’s National Marine Fisheries Service (NMFS) based its rule on the Magnuson-Stevens Fishery Conservation and Management Act of 1976. Loper Bright Enterprises, a New Jersey-based herring fishing company operating off New England, challenged the agency’s authority under the law to issue such a rule, arguing that the statute’s wording was ambiguous.

Under Chevron, if congressional intent in the wording of a law was ambiguous, courts would defer to agencies’ rules as long as they found they had reasonably interpreted Congress’ intent.

While Magnuson-Stevens explicitly authorized fees on industry for federal monitoring of foreign and Pacific Ocean fisheries, it did not do so for those in the Atlantic Ocean. The D.C. Circuit Court of Appeals found in favor of NMFS in 2022 under Chevron.

But the Supreme Court said Chevron’s presumption is misguided because agencies do not have special competence in resolving statutory ambiguities; courts do.

“Even when an ambiguity happens to implicate a technical matter, it does not follow that Congress has taken the power to authoritatively interpret the statute from the courts and given it to the agency,” the court said. “Congress expects courts to handle technical statutory questions, and courts did so without issue in agency cases before Chevron.”

Until Chevron, courts would only defer to agencies’ expertise for “fact-bound determinations” that did not involve statutory interpretation. When the APA was enacted in 1946, Congress specifically said that when agency actions are appealed, “the reviewing court shall decide all relevant questions law,” without any deferential standard for courts to use.

Thus, Chevron requires a court to ignore, not follow, “the reading the court would have reached” had it exercised its independent judgment as required by the APA, the Supreme Court said.

When it comes to deferring to an agency’s technical expertise, Roberts wrote that it does not follow that Congress has taken the power to authoritatively interpret the relevant statute from the courts and given it to the agency. Congress expects courts to handle technical statutory questions.

“Courts, after all, do not decide such questions blindly,” Roberts said. “The parties and amici in such cases are steeped in the subject matter, and reviewing courts have the benefit of their perspectives. In an agency case in particular, the court will go about its task with the agency’s ‘body of experience and informed judgment,’ among other information, at its disposal.”

The court also said that stare decisis is overcome because Chevron has proved fundamentally misguided by reshaping judicial review of agency action without grappling with the APA. “Chevron was a judicial invention that required judges to disregard their statutory duties.”

Justices Clarence Thomas and Neil Gorsuch wrote individual concurring opinions.

Thomas joined the majority’s opinion in full, but he wrote “separately to underscore a more fundamental problem: Chevron deference also violates our Constitution’s separation of powers. … It curbs the judicial power afforded to courts, and simultaneously expands agencies’ executive power beyond constitutional limits.”

“Today, the court places a tombstone on Chevron no one can miss,” Gorsuch wrote. “In doing so, the court returns judges to interpretive rules that have guided federal courts since the nation’s founding.”

Liberal Justices Dissent

Justice Elena Kagan wrote the dissenting opinion, on which she was joined by Justices Sonia Sotomayor and Ketanji Brown Jackson.

Chevron was a “cornerstone of administrative law” for 40 years, Kagan wrote. If Congress’ intent was clear in the law, that was how the court based its decision, and the agency’s view made no difference. The doctrine covered the situations when Congress left an ambiguity or gap in the law.

“The answer Chevron gives is that it should usually be the agency, within the bounds of reasonableness,” Kagan said. “That rule has formed the backdrop against which Congress, courts and agencies — as well as regulated parties and the public — all have operated for decades. It has been applied in thousands of judicial decisions. It has become part of the warp and woof of modern government, supporting regulatory efforts of all kinds — to name a few, keeping air and water clean, food and drugs safe, and financial markets honest.”

Congress cannot write perfectly complete regulatory statutes, Kagan said. “It knows that those statutes will inevitably contain ambiguities that some other actor will have to resolve, and gaps that some other actor will have to fill. And it would usually prefer that actor to be the responsible agency, not a court.”

Agencies have scientific and technical subject matter expertise that courts lack, and some decisions demand a detailed understanding of interdependent regulatory programs that agencies know “inside-out,” Kagan said.

“In one fell swoop, the majority today gives itself exclusive power over every open issue — no matter how expertise-driven or policy-laden — involving the meaning of regulatory law,” Kagan said. “As if it did not have enough on its plate, the majority turns itself into the country’s administrative czar.”

Reactions to the Decision

It is unclear how much the end of Chevron will impact FERC, but at the Energy Bar Association’s meeting in April, the general counsels for the commission and the Department of Energy both argued they would be able to defend their regulations without it. (See Energy Lawyers Debate the Impact of Losing Chevron Deference.)

Republicans and some industry groups welcomed the court’s decision, while Democrats and clean energy groups decried the decision.

“In overruling Chevron, the Trump MAGA Supreme Court has once again sided with powerful special interests and giant corporations against the middle class and American families,” Senate Majority Leader Chuck Schumer (D-N.Y.) said. “Their headlong rush to overturn 40 years of precedent and impose their own radical views is appalling.”

Minority Leader Mitch McConnell (R-Ky.) said the decision makes clear that no federal agency can co-opt Congress’ authority to make the law.

“Congress’ willingness to outsource legislative responsibilities to the most unaccountable corners of the executive branch weakened both its own Article I powers and the link between the American people and a responsive federal government,” McConnell said. “The days of federal agencies filling in the legislative blanks are rightly over.”

U.S. Chamber of Commerce CEO Suzanne Clark said that the decision will help create a more predictable and stable regulatory environment.

“The Supreme Court’s previous deference rule allowed each new presidential administration to advance their political agendas through flip-flopping regulations and not provide consistent rules of the road for businesses to navigate, plan and invest in the future,” Clark said. “The Chamber will continue to urge courts to faithfully interpret statutes that govern federal agencies and to ensure federal agencies act in a reasonable and lawful manner.”

Advanced Energy United CEO Heather O’Neill argued just the opposite, saying it was incumbent on Congress to ensure the decision does not undo decades of progress in the energy transition.

“While the march to clean energy will continue, today’s Supreme Court decision to radically overturn 40 years of judicial precedent is a blow for effective and efficient government,” she said. “Technology and regulation go hand-in-hand in making America a prosperous, safe and clean place in which to live. Overturning the so-called Chevron doctrine will invite chaos, inefficiency and added cost to everyday people.”

White House Press Secretary Karine Jean-Pierre said the ruling is “another deeply troubling decision that takes our country backwards.”

President Joe Biden “has directed his legal team to work with the Department of Justice and other agency counsel to review today’s decision carefully and ensure that our administration is doing everything we can to continue to deploy the extraordinary expertise of the federal workforce to keep Americans safe and ensure communities thrive and prosper,” she said.

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FERC Orders Further Cold Weather Standard Modifications

NERC will go back to work on another revision to its most recent cold weather standard after FERC on June 27 accepted EOP-012-2 (Extreme cold weather preparedness and operations) while ordering additional “targeted modifications” to be completed by next March (RD24-5). 

The approval of EOP-012-2 brings to an end what FERC Chair Willie Phillips called the “second round on this particular standard” at the commission’s monthly open meeting. Phillips commended NERC for its efforts to improve the grid’s resilience to cold weather impacts while observing that there is still a lot of work left to achieve the goals in the commission’s cold weather preparedness dashboard. 

“The standard … has helped close some ongoing reliability gaps and address many of the outstanding commission recommendations on winterization,” Phillips said. “Nevertheless, I would be remiss not to note that there are still changes that need to be made to help the standard reach its full potential.” 

NERC’s Board of Trustees approved EOP-012-2 in February. The standard’s 12-month development period began after FERC accepted its predecessor EOP-012-1 last year. 

The first version, which has yet to take effect, outlined several measures for generator owners to implement to prevent their units from freezing during extreme cold weather events, along with situations in which GOs would need to submit corrective action plans. However, FERC said the standard should be further revised to clarify language and enhance some of its requirements. 

EOP-012-2 underwent three formal comment and ballot periods before finally receiving the blessing of industry in January. (See Industry Approves New Cold Weather Standard in Final Vote.) NERC’s Board of Trustees had warned that it might have to step in to approve the standard if it looked like the ERO might miss FERC’s deadline — an authority it possesses under section 321 of NERC’s Rules of Procedure — but the successful ballot averted this possibility. 

FERC called the new standard an “improvement” to EOP-012-1 but said “some elements … are not fully responsive to the commission’s February 2023 order.” While it did not agree with the ISO/RTO Council’s request to remand EOP-012-2 to NERC for further revisions — which FERC observed would leave EOP-012-1 to go into effect Oct. 1 “despite its ambiguities and other identified issues” — the commission did identify some remaining shortcomings that still need to be overcome. 

FERC’s order directs NERC to submit another revised standard within nine months that: 

    • ensures that the standard’s generator cold weather constraint declaration criteria “are objective and sufficiently detailed” so that entities understand the requirements. NERC is to remove phrases such as “reasonable [or] unreasonable costs” and “good business practices” in favor of “objective, unambiguous and auditable terms.” 
    • allows NERC to evaluate and confirm the validity of cold weather constraints invoked by generator owners “to ensure that such declaration cannot be used to avoid” compliance with the standard or corrective action plans. 
    • shortens and clarify implementation timelines and deadlines for corrective action plans. 
    • ensures that any extension of a corrective action plan deadline beyond the maximum time frame provided by the standard is preapproved by NERC, and that GOs inform relevant entities of resulting extreme cold weather operating limits. 
    • implements more frequent reviews of generator cold weather constraint declarations to ensure the declaration is still valid. 

Noting the urgency FERC has “repeatedly expressed” for implementing cold weather standards, and the fact that the above directives are meant to “fully address issues identified in the commission’s prior February 2023 order,” FERC mandated that the ERO complete revisions to the standard within nine months. 

In a statement, NERC said it “appreciates FERC’s focus on reliability matters and will continue to work toward assuring the reliability and security” of the electric grid. 

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RI Sets 600-MW Energy Storage Target

Rhode Island is the latest state to set targets for energy storage system construction.

Gov. Dan McKee (D) signed the Energy Storage Systems Act into law June 26. It directs the state Public Utilities Commission to adopt a framework for adoption of tariffs to apply to grid-connected energy storage systems, and the Rhode Island Infrastructure Bank to develop programs and distribute money to help achieve the goals of the act.

It sets a series of targets for installation of storage over the next decade: 90 MW installed by Dec. 31, 2026; 195 MW by the end of 2028; and 600 MW by the end of 2033.

On a per-capita basis, the numbers are much larger than they might appear.

New York’s target is 6 GW — the most of any state, and 10 times higher than Rhode Island’s new target. But New York has nearly 18 times more residents than Rhode Island.

Rhode Island also has the lowest electricity consumption per capita of any state, according to the U.S. Energy Information Administration.

The legislation (2024-S 2499A, 2024-H 7811aa) cleared both houses of the General Assembly by wide margins.

“This bill sets concrete goals and action plans to build a resilient grid that can accommodate the green energy transition that is happening now,” Senate Judiciary Committee Chair Dawn Euer (D) said in a June 13 press release. “This is just one of many actions we will need to meet our diverse energy goals and ensure that Rhode Island keeps its commitment to a carbon-neutral future.”

Advanced Energy United cheered McKee’s signature.

“Energy storage is flexible, reliable, affordable and will be a game changer for Rhode Island’s power grid,” said Kat Burnham, the group’s Rhode Island lead. “Investing in energy storage technologies will drive economic development and job creation in the clean energy sector.”

In its March 2024 energy storage policy update, law firm Morgan Lewis listed 11 states with codified energy storage targets: California, Oregon, Nevada, Illinois, Virginia, New Jersey, New York, Connecticut, Massachusetts, Maine and Maryland.

Some states have a long way to go to reach their goals. The U.S. Energy Information Administration reported that as of November 2023, there were three categories: California (7,302 MW), Texas (3,167 MW) and the other 48 states (3,500 MW combined).

But EIA predicted 2024 would be a busy year for storage installation, if all plans in place come together on schedule.

Wood Mackenzie earlier this month reported 1,265 MW of storage was deployed nationwide in the first quarter of 2024, much more than the first quarter of 2023 but much less than the fourth quarter of 2023.

Rhode Island’s first utility-scale battery energy storage — a 3 MW system serving the Pascoag Utility District — went online July 7, 2022.