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December 15, 2025

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ERCOT ESRs, Solar Production Lessen AS Costs

Energy storage resources and solar capacity helped reduce ancillary services costs and tight system conditions in the ERCOT market in 2024, Potomac Economics said in its recent State of the Market report for the ISO. 

Potomac, which serves as the grid operator’s Independent Market Monitor, said an “influx” of new supply contributed to fewer tight system conditions. Solar and ESRs added 7.5 GW and 5 GW of new capacity, respectively, it said. 

The IMM specifically pointed to ESRs as helping produce the supply increase that reduced costs. The IMM said normalized ancillary services expense dropped to $0.98/MWh of load from $3.74/MWh in 2023.  

ERCOT contingency reserve service’s (ECRS) average price fell to $9.62/MWh from $76.77/MWh but still contributed almost $1 billion in excess real-time market costs. The monitor said the use of ECRS created artificial scarcity conditions by withholding reserves from the real-time market until manually deployed during the seven months after it was implemented in 2023. It said that resulted in an excess cost of more than $12 billion, a claim ERCOT pushed back against. (See ERCOT Board of Directors Briefs: Dec. 19, 2023.) 

“The continuation of these ECRS deployment practices is a cause for concern,” the IMM said. “Most consumers are not directly exposed to these excess costs in the real-time market, but these pricing outcomes factor into future contracts offered by [electric retailers].” 

Average real-time prices, excluding adders, fell to $32/MWh, down about 52% despite a 14% decline in natural gas prices. The IMM said more than 75% of the sharp decline was a result of less frequent ECRS artificial shortages. 

Day-ahead prices averaged $31/MWh in 2024. 

The monitor said real-time co-optimization (RTC), scheduled to go online in December 2025, will improve the issues it raised over market performance and operational risk. A “critical aspect,” the IMM said, is that RTC’s logic will allow the market to go short on real-time operating reserves, with the shortage’s cost defined by set ancillary service demand curves (ASDCs). 

The IMM continues to recommend that the grid operator reconsider its policies for procuring and deploying ECRS.  

It also recommended: 

    • That the ASDCs be reformulated based on the marginal reliability value of each product and that ERCOT incorporate a stochastic (using a random probability distribution) risk methodology for setting target levels for operating reserves. The IMM said embedding this tradeoff in the real-time market-clearing logic will address many of the issues it identified with ECRS deployment. 
    • That policymakers move away from the four-coincident peak (4CP) method — which calculates each consumer’s 4CP transmission tariff rate for the following year based on their load ratio share during the previous summer’s highest systemwide demand 15-minute intervals — and implement a transmission cost-allocation framework that more accurately reflects cost causation. 
    • An uncertainty reserve product provided by resources that can start in two hours or less when reliability is threatened. 
    • A multi-interval, real-time market process that can look ahead and optimize across several intervals. 
    • That ERCOT prioritizes development of market solutions that ensure resource adequacy, given projected load growth and the development lag between price signals and new generators’ commercial operations date. 
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FERC Clarifies SEEM Ruling, Denies Rehearing

In a response to opponents of the Southeast Energy Exchange Market, FERC on June 13 clarified the legal standard it relied on in its March 14 order directing SEEM members to update the market agreement (ER21-1111).  

In doing so, the commission also dismissed the opponents’ alternative request for rehearing of the order, arguing it was moot given FERC’s clarification, and improper under the D.C. Circuit Court of Appeals’ 2020 ruling in Allegheny Defense Project v. FERC that rehearing requests could not be granted “for the limited purpose of further consideration.” 

The SEEM opponents, a group of 13 organizations including the Sierra Club and the Southern Alliance for Clean Energy filing jointly as the ad hoc Public Interest Organizations (PIOs), filed their request April 14, the same day SEEM’s members responded to the March 14 order. (See SEEM Opponents Urge FERC for Clarification.) FERC’s order mandated updates to the market agreement to clarify its territorial requirements and outline whether pseudo-ties could be used to satisfy them. 

The PIOs claimed one part of the order — in which FERC said SEEM’s open access transmission tariff is “consistent with or superior to the pro forma OATT” based on the commission’s comparability standard — was inconsistent with precedent.  

According to the PIOs, the comparability standard as first described in 1994 meant that an OATT “should offer third parties access on the same or comparable basis, and under the same or comparable terms and conditions, as the transmission provider’s uses of its system.” However, in the March 14 order, FERC said the standard “requires that comparable service be provided to comparable customers.”  

Because the phrase “comparable customers” never has been used in reference to the comparability standard, the PIOs argued the commission effectively invented a new definition to apply to SEEM. 

FERC denied it had redefined the standard but agreed it would be “appropriate” to clarify its reasoning. The commission said it was guided by Order 888’s articulation of the comparability standard, which said that “under a non-discriminatory open access tariff, a transmission provider must not only treat similarly situated customers similarly but also provide third parties with comparable service to what they provide themselves.” 

“To the extent that … the March 2025 order can be read otherwise, we clarify that these are the standards the commission applied in reviewing SEEM,” FERC said.  

The commission went on to “confirm that … SEEM affirmatively meets the comparability requirements because it offers comparable service to SEEM members … and participants, both of which must take service under the same terms and conditions.” 

FERC said the question before it in the proceeding was whether all “similarly situated entities” that wanted to participate in SEEM were treated similarly, and that the territorial requirements do not amount to dissimilar treatment because entities outside the SEEM territory “are not similarly situated” to those inside. 

Commissioners concluded the clarification of its language “does not impact the outcome of the March 2025 order,” which SEEM members addressed in their April 14 filing. (See SEEM Members File Market Agreement Update.) 

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NYISO Stakeholders Propose Capacity Retention Market

Central Hudson, Con Edison, National Grid and the Natural Resources Defense Council have co-submitted a proposal to the NYISO project prioritization process asking that the ISO consider developing a capacity market based around retaining existing resources.  

The project proposal says the market is intended to operate within a framework where generator entry to the New York market is driven by state government procurements. Various stakeholders have contended in prior working group meetings that the capacity market as currently designed ignores this and as a result no longer functions to incentivize new entry. (See NYISO Stakeholders Debate Purpose of Capacity Market.) 

“Given the dominant role of the state, we think it would be prudent to consider the merits of, and efficiencies that we might gain, by focusing the capacity market on the cost of retention today,” said Ekene Umeike, speaking on behalf of Con Edison. 

During his presentation, Umeike said the project would replace the elements of the capacity market structure review that are considering a bifurcated market. Such a market could implement price discrimination between new and old capacity.  

“The proposal recognizes that the implementation of a retention-only capacity market would require the development of separate mechanisms for market entry,” Umeike said. “While other capacity market programs have been proposed, in our view, none of them appear likely to address the fundamental concern of customers facing higher costs without a commensurate improvement in reliability.” 

Several stakeholders asked for clarification on the project and how it fits into the current project prioritization process. One stakeholder asked that Con Edison and the other co-sponsors of the proposal come to the ICAP working group to discuss elements of the project and its description before asking stakeholders to vote on it.  

Project Prioritization Continues

NYISO has included 48 “market projects” in the project prioritization process. Of those, 25 focus on changes to the energy market, 10 to the capacity market and seven to new resources. The remainder focus on planning and transmission congestion contracts markets.  

NYISO staff added several new projects to the pool of potential candidates for focus in 2026, including designing a market mechanism for bifurcated capacity markets and the net congestion rent assignment study proposed by the MMU. (See MMU, FTI Argue for Maintaining Uniform Pricing in NYISO Capacity Market and NYISO Monitor Proposes Changing Congestion Rent Assignments.) 

A list of project descriptions can be found here. Project costs and descriptions still are in draft form and will be finalized by June 30. After that, NYISO will distribute surveys to stakeholders for project scoring. These surveys are due July 15 and survey results will be discussed July 30. 

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MISO 2025 Transmission Planning Cycle Rises to $13B

MINNEAPOLIS — MISO’s 2025 Transmission Expansion Plan (MTEP 25) has amassed another $2 billion in investment since early spring, bringing its total to $13 billion.

MISO said the $13.1-billion, 444-project portfolio still is driven mainly by growing load. In spring, the RTO pinned the collection at 434 projects and $11 billion. (See Load Growth Drives Early MTEP 25 to $11B.) MTEP 25 is considered preliminary until late fall; MISO revealed the latest MTEP 25 tallies at a June 10 System Planning Committee meeting of the MISO Board of Directors.

This year’s MTEP is loaded with a record-high 37 expedited project requests valued at $4.36 billion.

Executive Director of Transmission Planning Laura Rauch said six of MTEP 25’s top 10 most expensive projects originated from expedited project requests. MISO’s top 10 projects account for 43% of MTEP 25 spending.

The grid operator said 76% of MTEP 25 projects are due to be in service within three years. MISO said MTEP 25’s project totals contain more than 1,900 miles in transmission lines.

Rauch said the traditional and expedited projects are set to serve about 8.7 GW in new load across the footprint.

During a June 2 East Subregional Planning meeting, MISO’s Scott Goodwin said requests for MISO to expedite MTEP processing of some transmission projects have “exponentially exploded” since 2022, when the RTO fielded only 16.

MISO hopes to pivot to a bimonthly processing approach for the growing number of transmission projects submitted by members for expedited treatment.

Going forward, MISO plans to open an every-other-month acceptance window for expedited project requests. It has said the new cadence should be less cumbersome on staff than MISO’s existing ad-hoc approach.

Currently, MISO evaluates requests as they’re received for transmission projects that cannot wait until end-of-the-year approval through the annual MTEP. MISO originally hoped to roll out a quarterly expedited process but was met with stakeholder resistance. (See MISO Starting from Scratch on New Schedule for Reviewing Expedited Tx Projects.)

MISO plans to study smaller expedited projects in batches while larger, complicated projects will get individual assessments. It said it hoped to debut a 30-day study turnaround for the more straightforward projects.

The grid operator also said it will schedule a single, monthly Technical Study Task Force meeting to discuss expedited projects instead of holding piecemeal, short task force meetings every time a request pops up.

Some stakeholders have asked MISO to consider a load interconnection queue like its generator interconnection queue because of the snowballing expedited requests.

MISO has experienced a runaway volume of expedited requests in recent years as load growth surges. While it used to process an average of six expedited requests annually, since 2021, it has experienced upward of 30 requests. The projects themselves are becoming larger and more complex.

MTEP 25’s expedited investment eclipses MTEP 24’s $896 million worth of expedited requests and MTEP 23’s $684 million.

MISO is set to hold a round of subregional planning meetings to review a more finalized MTEP 25 in September. MTEP 25 goes before the MISO Board of Directors for approval in early December.

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Trump Directs Feds to Withdraw from Deal on Snake River Dams

President Donald Trump pulled the federal government out of a deal the previous administration had signed that eventually could have led to breaching several dams on the Snake River in the Pacific Northwest operated by the Bonneville Power Administration.

Trump issued a memo June 12 withdrawing from the deal that was entered into after lengthy litigation about four tribes’ rights to fish in the river. The deal was opposed by other interests in the region including senior Republicans in Congress. (See Parties Split on Biden Administration Deal on Snake River Dams.)

The Biden administration was considering breaching four dams that produce more than 3,000 MW, but it had not made a final decision.

“The negative impacts from these reckless acts, if completed, would be devastating for the region, and there would be no viable approach to replace the low-cost, baseload energy supplied; the critical shipping channels lost; the vital water supply for local farmers reduced; or the recreational opportunities that would no longer be possible as a result of these acts,” Trump’s memo said.

The memo directs cabinet secretaries to work to withdraw from the deal and to rescind a supplemental environmental impact statement on the four dams that was published in December 2024.

The Department of Energy said the Biden-era memo of understanding (MOU) required the government to spend $1 billion to comply with commitments aimed at replacing the dams in the Lower Snake River, including possibly breaching them.

“The Snake River Dams have been tremendous assets to the Pacific Northwest for decades, providing high-value electricity to millions of American families and businesses,” DOE Secretary Chris Wright said. “American taxpayer dollars will not be spent dismantling critical infrastructure [or] reducing our energy-generating capacity.”

The Biden administration signed the deal with the Yakama, Umatilla, Warm Springs and Nez Perce tribes along with the states of Oregon and Washington. The deal supported federal investments in a comprehensive plan for salmon restoration, energy development and transportation infrastructure in the Columbia Basin, said a press release from the Confederated Tribes and Bands of the Yakama Nation.

The MOU from Biden also led to the stay of ongoing litigation under the Endangered Species Act over federal hydropower operations the federal government had consistently lost in, said the Yakama.

“The administration’s abrupt termination of the Resilient Columbia Basin Agreement jeopardizes not only tribal treaty-reserved resources but also the stability of energy, transportation and water resources essential to the region’s businesses, farms, and families,” Yakama Tribal Council Chairman Gerald Lewis said in a statement. “This agreement was designed to foster collaborative and informed resource management and energy development in the Pacific Northwest, including significant tribal energy initiatives. The administration’s decision to terminate these commitments echoes the federal government’s historic pattern of broken promises to tribes and is contrary to President Trump’s stated commitment to domestic energy development.”

The Yakama Nation is disappointed Trump withdrew from the deal, especially without prior consultation. The way the government has managed the river historically will lead to salmon extinction, Lewis said.

Sen. Ron Wyden (D-Ore.) also blasted the decision to withdraw from a deal two states and four tribes worked hard on only “to have it upended so casually from 3,000 miles away.”

“Donald Trump proves yet again his irrational preference for litigation and mindless destruction of actual achievements like this settlement agreement,” said Wyden, a senior member of the Senate Energy and Natural Resources Committee. “His approach will make life more difficult for businesses and families by upending meaningful progress to meet regional energy production, water resources and transportation needs while recovering a river and its salmon key to our part of the country.”

The National Rural Electric Cooperative Association welcomed the move by Trump, which seeks to ensure the dams are not breached.

“Hydroelectric power is the reason the lights stay on in the region,” NRECA CEO Jim Matheson said in a statement. “And as demand for electricity surges across the nation, preserving access to always-available energy resources like hydropower is absolutely crucial.”

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CAISO Proposes Alternative Approach for Calculating RA Resources During Peak Times

CAISO is proposing a new method for verifying how much energy thermal resources can provide during peak conditions on California’s grid for resource adequacy purposes. 

CAISO presented the proposal at a June 11 meeting as part of its resource adequacy (RA) working group, which reviews RA rules, requirements and processes for grid reliability and operations. 

Under current rules, a resource’s seasonal ambient derate data is not consistently reflected in that resource’s net qualifying capacity (NQC) value. This inconsistency creates challenges in reliably operating the grid, CAISO said in its proposal. For example, a 50,000-MW peak load contains about a 4% ambient derate, compared to a 20,000-MW peak load on the system, which has about a 2% ambient derate, CAISO said. 

In California, RA programs began in 2004 under the California Public Utilities Commission to ensure the state’s grid always had enough power to meet demand. CAISO’s RA initiatives are intended to complement the CPUC’s RA programs.  

In the proposal, CAISO would verify an RA resource’s qualifying capacity (QC) value based on that resource’s historic outage data. The proposed method “ensures RA resources’ operational capabilities during peak load conditions are reflected in NQC values,” CAISO said in the proposal. 

More specifically, CAISO would produce monthly “capability values” as part of its NQC process. These capability values represent a resource’s availability during peak load conditions, which often happen during times of high ambient temperatures.  

To calculate a capability value, CAISO would review a resource’s ambient derates due to temperature during peak demand in recent years with existing outage management system data, CAISO said in the proposal. Each year, CAISO publishes RA NQC data to its reliability requirements webpage.  

However, the proposed method has a “notable drawback,” CAISO said. Forced outages are “not consistently reported by resource SCs when a resource is experiencing multiple overlapping outages,” CAISO said. 

To address this potential issue, scheduling coordinators (SC) could adjust proposed QC values based on site-specific generator performance information under typical peak system conditions, thereby establishing monthly capability values for thermal resources. If weather data is not available at a generator’s site, SCs could pull data from nearby weather stations. SCs then could verify that a generator’s maximum output is feasible. This maximum value could reveal the generator’s likely performance under typical peak system conditions, CAISO said. 

The proposed method would apply only to thermal resources — i.e., gas, oil, coal, nuclear, biomass, geothermal and biogas fuel types — and represents resource availability during median peak load conditions, not extreme conditions. 

American Clean Power-California, in comments to CAISO, said it is concerned about double counting under the proposed method. The group encouraged CAISO to avoid including historic ambient derates into NQC processes if those historical derates already are accounted for in other processes. 

CAISO also considered using performance test data from each thermal generator, rather than historical data, to verify an RA resource’s QC value. However, stakeholders viewed the potential benefits of such a testing program as “providing limited value compared to the administrative costs of such a program,” CAISO said. 

“Given the challenges and administrative burden of developing an NQC testing program in accordance with CAISO [tariffs], CAISO is not moving forward with a testing-based proposal,” CAISO said in the proposal. 

Stakeholder comments on the proposal are due by June 25.  

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NERC Standards Committee Reviews Project Prioritization

NERC continues to work on streamlining its slate of standards development projects to ease the burden on industry, members of the ERO’s Standards Committee heard at their quarterly in-person meeting, held at CAISO’s headquarters in Folsom, Calif. 

Reviewing the standards prioritization initiative that NERC staff have been pursuing since 2023, Manager of Standards Development Alison Oswald noted that the ERO has six projects under development that are classified as “high priority.” This category comprises projects that address “significant” risks, identified by the following criteria: 

    • subject of a NERC or FERC directive with a set due date; 
    • identified as a priority in NERC’s work plan; or 
    • recommended to address a specific risk by compliance feedback, stakeholder feedback or a study. 

NERC’s medium-priority projects, which account for five of the remaining current standards projects, must “steadily progress but … do not include a firm timeline,” Oswald said. These efforts may be in tandem with high-priority projects, address emerging risks, seek to clarify an existing standard, satisfy regulatory directives without a set deadline or originate from compliance or stakeholder feedback or a study. 

Low-priority projects “will be advanced as time and resources permit,” though Oswald emphasized that these still address real issues and their ranking is more a function of “resource management and NERC’s agile framework than an evaluation of the risk that’s being addressed.” These address standard requirements that are known candidates for retirement, corrections to existing standards or stakeholder feedback regarding a specific risk, and comprise the remaining eight active projects. 

Asked by Maggy Powell of Amazon Web Services about the expectations for progress by medium-priority standards development teams, Oswald confirmed that these projects have the same level of legal, engineering and compliance support from NERC as high-priority projects. The main differences are that these efforts do not have a set timeline and may have to wait to post their standards for ballot and comment periods if high-priority projects also are up for posting. 

Vicki O’Leary of Eversource Energy asked how NERC manages to keep the members of the low- and medium-priority project drafting teams engaged. In response, Director of Standards Development Jamie Calderon acknowledged that this topic is “a real concern” for the ERO, noting that “over a period of time, people need to come and go, and the longer that period of time is extended, the more people that might apply to.” 

Project Votes

Calderon observed that O’Leary’s question provided a “great segue” to the first standards action on the committee’s agenda. This item asked members to approve the solicitation of nominations to supplement the SDT for Project 2017-01 (Modifications to BAL-003 — Phase II), a low-priority project to revise BAL-003-2 (Frequency response and frequency bias setting). 

Calderon explained that the project had to pause along with other low- and medium-priority projects in 2023 because of the high volume of high-priority projects. During the hiatus, three team members departed the project. NERC proposed the solicitation of new members to fill these vacancies, with a focus on expertise in synchronous and asynchronous generation operations, along with representation from the Texas Interconnection and areas with high levels of inverter-based resources. The proposal passed with no objections. 

Members next tackled a similar proposal to supplement the SDT for Project 2023-07 (Transmission system planning performance requirements for extreme weather). The project is in its second phase, developing a standard to provide long-term planning requirements for normal and extreme natural events, gas-electric interdependencies and events involving distributed energy resources. 

Manager of Standards Development Sandhya Madan explained that of the SDT’s 12 original members, only seven could return for the second phase because of “competing work requirements.” NERC wishes to solicit replacements for the five who could not participate. This proposal also passed unanimously. 

The final standards item called on the SC to reject a standard authorization request that was assigned to Project 2021-03 (CIP-002 Phase Two). This SAR was intended to address a threat to grid cybersecurity posed by communications protocol converters, but the project’s SDT determined, based on industry comments, that the SAR did not clearly define the reliability risks involved and that the request did not match the scope of the project in any case. The team recommended that the SC reject the SAR with written feedback to its creator. 

This proposal also passed unanimously, though Marty Hostler of the Northern California Power Agency noted that the SAR was assigned to the team in 2023 and asked why it took so long for the team to recommend its rejection. Calderon replied that at the time, the team was also working on a high-priority SAR and did not have time to review comments on the new SAR until that work was completed. 

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NERC State of Reliability Report Highlights Progress and New Challenges

NERC on June 12 released its State of Reliability report, which found the bulk power system remains highly reliable and underlying performance metrics such as frequency response and misoperation rates are improving or remain stable.

“Severe weather remained responsible for the most severe outages in 2024, with two significant winter storms and five major hurricanes that made landfall,” the report says. “NERC saw an improvement in performance during the winter events, with no operator-initiated load shed, in part due to industry’s efforts to improve generator performance during extreme cold weather following NERC and Federal Energy Regulatory Commission recommendations and regulatory updates.”

Hurricane Helene caused a record 431 transmission outages, but more than 95% of the outages caused by the storm were resolved within eight days, which is well below the average of 15 days seen for Category 4 hurricanes, NERC’s Jack Norris said on a press call.

An issue that continues to dominate the industry’s attention this year is the growth in data centers.

“Data centers can be developed faster than the generation and transmission infrastructure needed in the area to support them, resulting in lower system stability,” the report says. “Additionally, the voltage sensitivity and rapidly changing, often unpredictable, power usage of these facilities creates new operating challenges. As such, more accurate models of the operational characteristics of these impactful loads are essential to reliability to prevent instability caused by these large changes in electricity demand.”

Developers are not going to plan a major data center for a site that lacks enough capacity on the system to meet its needs, NERC Director of Reliability Assessments John Moura said.

“The issue is that this confidence often rests on assumptions of capacity that may not fully materialize, especially during system stress events,” Moura said. “So, the scenario we’re really warning about involves rapid demand growth outpacing the timing of new generation and transmission infrastructure. Even with a good plan, there are things that can challenge getting the infrastructure in place.”

Needed generation could get caught up in an interconnection queue or run into supply chain issues, while transmission projects could be delayed.

The report addresses several recent reliability incidents caused by data centers tripping offline, notably 1,500 MW in Virginia. (See Data Centers’ Reliability Impacts Examined at FERC Meeting.)

“Fortunately, due to the location of this 2024 event, there was no major negative impact to reliability, but as more of these types of load interconnect, the need to address this risk will continue to grow,” Norris said. Northern Virginia is home to the largest concentration of data centers in the world, so 1,500 MW of load dropping off did not impact frequency on the grid as much as it could have if the facilities were in a more isolated location on the grid, he said.

The growth in data centers caught the industry by surprise, with a sudden focus on meeting rising demand after decades of stagnant growth in most markets. FERC recently held a two-day conference on resource adequacy where that was a key issue, and the Department of Energy has been ordering power plants to keep running based on NERC’s reports of narrow reserve margins. (See Wright Addresses Recent Orders Keeping Power Plants Open at Hearing.)

Another part of the issue is that markets have incentivized narrower reserve margins as part of their design to ensure reliability at the cheapest possible price, which means avoiding the overbuilding that preceded them, Moura said. But with the new demand growth and rising prices, power plants have seen retirements pushed back.

Some retirements that were planned have been deferred, but the changing market dynamics have also improved the economics for generators that were on the edge. Now higher prices are keeping them open to help meet the rising demand, Moura said.

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CEC Approves Massive Solar-plus-storage Project

California regulators approved Intersect Power’s Darden Clean Energy Project, which is expected to be the largest battery energy storage system in the world when completed.

The California Energy Commission voted June 11 to approve the project, which includes a 1.15-GW solar facility and 1.15 GW of four-hour battery storage. The solar facility will consist of about 3.1 million panels.

The decision marks the commission’s first project approval under its streamlined “opt-in” permitting process.

“The transition to 100% clean electricity by 2045 requires bold, utility-scale projects like Darden,” CEC Chair David Hochschild said in a statement. “This project is significant not only for its size but its cutting-edge design and safety measures.”

The CEC reported in April that California had 15,763 MW of battery storage: 13,248 MW of utility-scale storage, 1,829 MW of residential storage and 686 MW of commercial storage. The total puts the state at about 30% of its storage target of 52,000 MW by 2045.

“The key to a cleaner, more reliable power grid is batteries – and no other jurisdiction on the planet, save China, comes even close to our rapid deployment,” Gov. Gavin Newsom said in a statement in May.

Community Benefits

Intersect Power subsidiary IP Darden I will build the Darden project on 9,500 acres of retired agricultural land in Fresno County. It will interconnect to one of Pacific Gas and Electric’s existing 500-kV transmission lines, Los Banos-Midway No. 2.

At one point, the Darden project included an 800-MW green hydrogen facility, but that component was scrapped last year. (See 2 Huge Solar-plus-storage Projects Planned in California.)

Under the CEC’s opt-in requirements, projects must deliver community and economic benefits. The Darden project will invest $2 million into the community over the next decade, starting with $320,000 to Centro La Familia Advocacy Services, a nonprofit that supports crime victims, family wellness and civic engagement in rural communities.

In addition, the project will produce more than 2,000 prevailing-wage construction jobs and an estimated $169 million in economic benefits over its 35-year lifetime.

The CEC’s opt-in certification is a voluntary process intended to streamline permitting of renewable energy projects.

Under the opt-in procedure, the CEC becomes the lead agency for permitting and state environmental review, consolidating the permitting process. The environmental review for a project must be completed within 270 days of the project application being deemed complete, unless the proposal changes significantly.

Intersect Power has another solar-plus-storage proposal moving through the opt-in certification process. The Perkins Renewable Energy Project, proposed by subsidiary IP Perkins, would be a 1.15-GW solar facility in Imperial County. It also would include up to 1.15 GW of four-hour battery storage, or up to 4,600 MWh of storage.

Another opt-in project, the Compass Energy Storage Project, was the subject of a public meeting earlier in June. The proposed 250-MW project in Southern California has drawn a slew of comments, many voicing concerns about the safety of the facility. (See CEC Considers Opposition to Compass Battery Project in Southern California.)

In a release about the approval of the Darden project, the CEC said the safety of battery storage facilities “remains a top priority.”

In 2024, the governor launched a state-level collaborative to continue to strengthen safety standards for battery storage systems. The efforts include updating the California fire code to include specific fire safety requirements for stationary lithium-ion battery storage systems.

The California Public Utilities Commission also approved new safety standards and enhanced oversight of emergency plans for grid-scale battery energy storage systems.

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N.Y. OKs 642 MW of Urgent Infrastructure Upgrades

New York has authorized its first tranche of projects under a 2024 order that sought to address urgent existing and anticipated electric infrastructure needs as the state pushes to decarbonize transportation and buildings. 

The 29 projects chosen are intended to expand capacity by 642 MW at an anticipated cost of $636 million, or about $1 million per megawatt. They were winnowed down from 65 proposals rated at 1,290 MW that would have cost $1.88 billion, or $1.5 million per megawatt of new capacity. 

The Public Service Commission voted unanimously to approve the work at its June 12 meeting (Case 24-E-0364). 

Most of the projects are in upstate New York, but much of the spending and much of the new capacity will come through five Con Edison upgrades in a few square miles of New York City facing immediate constraints. 

Con Edison said extensive transportation electrification in an area of the South Bronx requires urgent near-term distribution system, sub-transmission and area station investments. 

The area is dotted with fleet depots and service centers that serve an estimated 15,000 commercial vehicles, some of which are expected to electrify and some that already have. 

There also is the largest-of-its kind Hunts Point Food Distribution Center, target of multiple electrification initiatives including a freight-focused charging facility and development of dozens of DCFC and L2 plugs. 

Con Edison’s five projects would increase capacity by 380 MW at an estimated cost of $440 million. 

The PSC in its August 2024 order directed the state’s large investor-owned electric utilities to begin the process and identify urgent needs. (See New York Orders Utilities to Join in Proactive Grid Planning.) 

Con Edison, National Grid, NYSEG and RG&E submitted the 65 proposals; Central Hudson and O&R indicated they had nothing “urgent.” 

Department of Public Service staff rejected more than half the proposals for not meeting one or more of the evaluation criteria: 

    • The work is needed to meet anticipated load growth from building electrification and/or transportation electrification.
    • Construction-related activity could start by July 1, 2026.
    • There is a high degree of certainty about location, magnitude and timing of load
    • There is demonstrated consideration of risks and benefits of the size and timing of the proposed action, and of delaying that action or not taking it at all. 

The 36 proposals that did not meet all four conditions may be able to advance later on a path other than this urgent/proactive process. 

“We are approving these projects today because significant grid capacity is needed to support electrification across vehicle duty classes and buildings,” PSC Chair Rory M. Christian said in a news release. “Grid constraints have already begun to limit electrification in some parts of the state. The urgent grid upgrade projects would expand grid capacity in many areas of the state, relieving urgent constraints on an accelerated basis while a broader, unified planning framework is developed.” 

One project each was authorized for NYSEG and RG&E. 

NYSEG’s Kent Falls project would add 30 MW of capacity at a cost of $37.1 million to support a large and expanding manufacturing facility. 

RG&E’s Station 124 project in Penfield would add 47 MW of capacity at a cost of $33.2 million to address electric vehicle charging needs and growth of existing loads in the Rochester area. 

PSC approved 22 National Grid proposals with a combined capacity of 185 MW and estimated cost of $126 million — most of them small, but with a few station rebuilds and other larger projects included. 

Among them is an “innovative” bridge-to-wires project that involves 4.4 MW of mobile battery energy storage systems. It would address immediate constraints, support transmission electrification and provide flexibility while a substation solution is developed for the longer term. At $21.6 million, its estimated cost per megawatt is nearly five times the average of the projects authorized June 12. 

The most expensive project by capacity on the list would support a load request by a depot serving a school bus fleet that is being electrified to meet a state mandate. At 2.2 MW and $15 million, it would cost $6.8 million per megawatt.