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August 22, 2024

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CAISO Adjusts Timeline for Storage Bid Cost Recovery Initiative

Responding to significant stakeholder pushback, CAISO has extended the timeline of its Storage Bid Cost Recovery and Default Energy Bids Enhancements initiative to allow more discussion of alternative solutions to refine BCR provisions for storage resources. (See CAISO Proposal Seeks to Refine Storage Bid Cost Recovery.) 

CAISO staff discussed the changes in an Aug. 19 meeting originally intended to review the revised straw proposal slated to be released Aug. 14. But after stakeholders consistently asked for a more holistic initiative, the meeting was spent considering alternative proposals to the first one presented by the ISO.  

“This is a change that we think will support stakeholders to collaborate with us to develop those ideas so that we can continue comparing them to other proposals and determine what is the best path forward given the challenges that we’re trying to solve,” said Sergio Dueñas Melendez, storage sector manager at CAISO. “I want to note that this revised schedule does not change the importance and the sense of urgency that we have in addressing this issue.”  

In 2022, the ISO identified that bid cost recovery (BCR) provisions for energy storage didn’t align with the intent of BCR, resulting in unusually high payments to storage resources. (See CAISO Kicks Off Storage Bid Cost Recovery Stakeholder Initiative.)  

The problem materialized because CAISO’s BCR construct doesn’t adequately consider state of charge (SOC), Dueñas Melendez said, which is necessary for an energy storage resource to support its awards and schedules. It led to two main concerns: that storage assets are not exposed to real-time prices for deviating from day-ahead schedules and that they may have an incentive to bid strategically to maximize the combined BCR and market payments.  

In response, the ISO presented a proposed solution that would redefine dispatch that is unavailable due to SOC constraints in the binding interval as “non-optimal energy,” which would be ineligible for BCR. If a storage resource’s SOC at the start of the binding interval was equal to its minimum or maximum value, the market would rerate or derate the Pmax or PMin to zero in order to capture that the asset is completely full or empty, the proposal says.  

Alternative Proposals

Some stakeholders supported the proposal, including the California Public Utilities Commission’s Public Advocates Office, which described it as “a measured and sufficiently well-targeted approach to ensure that storage resources are not incentivized to deviate from day-ahead schedules to achieve excess BCR payments,” Dueñas Melendez’s presentation said.

Others, such as the California Energy Storage Alliance (CESA), suggested implementing an alternative solution in the interim that would address concerns related to strategic bidding. CESA proposed modifying the formula used to calculate BCR from real-time dispatch minus day-ahead schedule to day-ahead locational marginal price (LMP) minus real-time LMP. This calculation would eliminate the impact of a resource’s bid on BCR payments, according to CESA.  

“Stakeholders have argued for this solution for a couple of reasons: first, because it would eliminate the impact of that resource’s bid on BCR payments, so that way it’s no longer something that they can strategically use,” Dueñas Melendez said. He added that other stakeholders favored the solution because the software they use for automatic bidding uses -$150/MWh bids in the hours representing their day-ahead schedules to firm up those bids or schedules.  

While stakeholders supporting the proposal acknowledged the solution wouldn’t address the concern that storage assets are not exposed to real-time prices for deviating from day-ahead schedules, they argued it would allow for more time to develop a more “holistic” solution.  

Dueñas Melendez highlighted other potential drawbacks of the proposal, including that it would not eliminate buy- and sell-back BCR and that it would pay BCR to resources that are not available in real time. The ISO also questioned how the proposal would be implemented for storage assets in the Western Energy Imbalance Market (WEIM) outside CAISO’s footprint, considering that there is no day-ahead LMP for WEIM storage resources.  

CAISO further questioned CESA’s proposal, stating that the modified calculation could lead to revenue credit in intervals where the resource wasn’t dispatched due to a high offer, as well as unwarranted BCR when the day-ahead LMP is greater than the real-time LMP.  

Don Tretheway, director of markets and regulatory policy at GDS Associates and representing CESA, responded: “The intent of what CESA put out there was really to address instances where there was inflated BCR, so putting out an example that says the CESA proposal results in higher BCR payments … we would never have put that out as an approach, and we did recognize that there would be the need for some additional logic.” 

The intent of the approach, he said, was to show that not using real-time bid prices could help “unwind the inflated BCR payments,” giving the ISO more time to “come up with a holistic solution about what BCR should mean for storage” and what market design enhancements CAISO should pursue.  

CAISO’s Department of Market Monitoring disagreed with the suggestion to develop an interim solution, saying that addressing all issues in track 1 is a better approach than implementing an interim change and then tackling bidding incentive issues — which DMM believes to be the core issue — in a later process.  

The revised straw proposal is now scheduled for release Sept. 3, with the final proposal expected Sept. 30, a month later than the initial timeline. The joint ISO Board of Governors and Western Energy Markets Governing Body will vote on the proposal Nov. 7 instead of Sept. 26. 

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SDT Recommendations Spark Debate at Standards Committee

Members of NERC’s Standards Committee again debated qualifications for standard drafting team participation at their monthly conference call Aug. 21, with the discussion extending the meeting more than a half-hour over its planned end time.

The committee was considering two proposals submitted by NERC staff to approve members of new standard drafting teams (SDT), along with a proposal to add supplemental members to an already existing team. The new teams were for Project 2024-01 (Rules of Procedure definitions alignment — generator owner and generator operator) and Project 2024-03 (Revisions to EOP-012-2), while the existing team to be augmented was for Project 2022-02 (Uniform modeling framework for inverter-based resources).

Project 2022-02 came first on the agenda. NERC Manager of Standards Development Jamie Calderon explained that NERC recently assigned the project a new standard authorization request (SAR) in response to FERC Order 901, which requires the ERO to submit standards concerning data sharing and model validation for inverter-based resources (IBRs) by November 2025. (See NERC Standards Committee Moves Forward on IBR Projects.)

Because of the scope of the new SAR, Calderon said, the existing SDT members wished to bring in new participants with “additional skill sets [such as] inclusion, performance data and other aspects of modeling.” Industry stakeholders nominated six new members, of which NERC staff recommended five for addition to the team.

The exclusion of the sixth member, who like other nominees was only identified by number during the meeting, sparked questions from Robert Blohm of Keen Resources. Reading off background information provided to committee members, Blohm noted that the candidate was not recommended because their organization “did not support the candidacy [because] it didn’t have the resources … to allocate his time.” Blohm asked if the nominee could still participate in the SDT “if he’s willing to volunteer his own time and put in the effort,” perhaps as an observer.

Committee Chair Todd Bennett, of Associated Electric Cooperative Inc., said that while “each committee member [could] decide on their own” whether they agreed with Blohm, he would look at the employer’s feedback as “a non-supportive recommendation” if he were not an officer and had the ability to vote. Steve Rueckert, director of standards at WECC, said he understood Blohm’s reasoning, but he expected that NERC would already have asked the candidate for their willingness to participate and factored that into their recommendation.

Following his feedback, Rueckert moved for the committee to accept the original slate of five suggested by NERC. The motion passed unanimously.

Next on the agenda was Project 2024-01, which is intended to “address the definitions for generator owners and generator operators within the NERC Glossary of Terms to ensure the inclusion of [IBRs]” that meet recently approved registration criteria. (See FERC Accepts NERC ROP Changes, Drops Assessment Proposal.) Members were asked to approve a chair, vice chair and eight additional members to the SDT for the project.

Rueckert noted that NERC had received 11 nominees for the team and asked why only 10 were recommended. Calderon replied that two of the nominees were members of the same “representative body” and NERC felt that if both were included, it would reduce the diversity of the team.

Blohm argued for including the 11th candidate, observing that “only two candidates among the 10 recommended … have drafting team experience.” He suggested that the candidate, who has previously served as an SDT chair, would add valuable perspective to the team. He moved to amend the proposal to allow all the nominees to serve.

Members largely supported Blohm’s motion, which passed with no objections. Maggy Powell of Amazon Web Services was the sole abstention, saying she was “not particularly comfortable” with the idea of adding people to the team that were not recommended because it “discounts … the work that NERC has done to … vet these participants and [their] qualifications.”

The final project voted on at the meeting was Project 2024-03, which is working on the most recent changes ordered by FERC to NERC’s cold weather standards. NERC recommended a chair, vice chair and 11 members from the 18 candidates nominated by industry stakeholders.

Blohm again warned that the nominees seemed to lack experience serving on SDTs. He observed that of two candidates from the same company, NERC staff had recommended one with no drafting team experience over another who had previously served on SDTs. He suggested switching the two candidates and also adding another two industry nominees, which he said would “make a team of 14, eight members of which — in other words, a majority … would have drafting team experience.”

Members were receptive to Blohm’s suggestion, though there was considerable disagreement about the best parliamentary approach to handling the amendments. Rueckert reiterated Powell’s objection to “discounting NERC’s work based on a short [biography] that we’re seeing presented to us.” He also reminded members that inexperienced candidates could only gain experience by serving on SDTs.

The committee eventually compromised on switching out the two candidates from the same organization, while adding just one of the non-recommended nominees, resulting in a team of 13 total.

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ISO-NE: New Mechanisms May be Needed to Ensure Future Grid Reliability

As the variability of generation and demand increases on the New England grid, market enhancements may be needed to promote dispatchable resources, ISO-NE told stakeholders at its Planning Advisory Committee meeting Aug. 21. 

“Current revenue structures may not adequately compensate resources for their value to the future grid,” said Patrick Boughan of ISO-NE, adding that the RTO plans to consider “the need for future market rule enhancements to support the ongoing reliability and economy of the region’s grid.” 

“While the precise nature of these enhancements requires further exploration, they could include new ancillary services intended to incentivize the resource attributes that will become more important as the clean energy transition continues,” he added. 

Curtailment likely will increase in the 2040s, reducing the value of new intermittent clean energy resources, ISO-NE found. An increasing amount of weather-based generation — coupled with increasing weather-based demand due to heating electrification — likely will make peak demand more variable.  

“Since the grid must be ready to serve load under the most extreme conditions, significant quantities of dispatchable resources will sit idle during milder winters,” Boughan said.  

As the renewables proliferate, the spring and fall seasons likely will be the first to decarbonize. By 2050, “almost all carbon emissions are concentrated in a handful of days in the winter,” Boughan added.  

At the PAC meeting, ISO-NE presented results from the Economic Planning for the Clean Energy Transition draft report. 

The study found that multi-day storage will become particularly valuable with more renewables on the system, with 100-hour batteries becoming the most cost-effective way to reduce emissions by 2050. New solar resources are projected to be the least cost-effective. 

Dispatchable resources like synthetic natural gas and small modular reactors also would provide significant winter reliability benefits and would reduce the need to overbuild wind, solar and storage, Boughan said. 

“Eliminating carbon emissions through complete electrification of the heating and transportation sectors and a near-exclusive reliance on wind, solar and storage to generate electric power is possible but involves significant cost and unresolved reliability concerns,” Boughan said.  

2050 Transmission Study

Building on the results of the 2050 Transmission Study, Reid Collins of ISO-NE presented more information about the RTO’s modeling of different offshore wind points of interconnection (POIs).  

The original study and an additional consideration of different POIs modeled offshore wind during peak loads and at reduced outputs than nameplate capacity. (See ISO-NE Analysis Shows Benefits of Shifting OSW Interconnection Points.) Collins noted that several stakeholders requested that the RTO model offshore wind projects at full capacity.  

Collins said the analysis is “intended to give a rough estimate of total offshore wind that may be plausibly installed on system without significant curtailment.” 

When looking at individual POIs, ISO-NE found that 22 of the modeled interconnection points could handle an addition of 1,200 MW without upgrades. Just three POIs could go up to 2,000 MW without upgrades, while just one could go up to 2,400 MW. Some POIs would require minimal upgrades to reach these levels.  

“Based on the expected 2033 transmission system, a significant amount of offshore wind may be able to be connected without major upgrades or significant curtailment across a variety of potential POIs in New England,” Collins said. He stressed the need for coordination between the states, transmission owners, project developers and ISO-NE to interconnect offshore wind projects efficiently. 

More upgrades could be avoided if developers accept some degree of curtailment, or if projects are paired with storage or advanced transmission technologies to reduce curtailment, Collins said. 

He said ISO-NE plans to publish more detailed results on this analysis in the fourth quarter of this year. 

Asset Condition Projects

National Grid presented a pair of asset condition projects, with combined costs of about $120 million. The projects include: 

      • replacing components of the company’s Brayton Point Substation and relocating the transformers outside of the 100-year flood plain, with a projected cost of more than $40 million. 
      • a proposed refurbishment of a 345-kV line in central Massachusetts, with a projected cost of about $80 million. 

Avangrid detailed a $218 million increase in the cost of an asset condition project in Connecticut that initially was proposed in 2018. The project initially was estimated to cost $180 million but now is projected to cost nearly $400 million. The company said the cost increase is due to price escalation and inflation, along with an order by the Connecticut Siting Council to change the route of the rebuild to minimize visual impacts.  

Asset Condition Process Updates

Robin Lafayette of Rhode Island Energy gave an overview of the New England transmission owner’s (TO’s) work to improve the process for presenting asset condition projects to the PAC. The New England states have been pushing for more transparency and oversight into asset condition projects. 

The PAC does not have the power to approve or reject projects, but instead is intended to provide stakeholders with information on projects and to solicit feedback on proposals. 

Lafayette’s presentation focused on responding to feedback the TOs have received on the process updates, adding that the TOs will provide more detailed information on process updates in the fall.  

He said the feedback has clarified the need for standardization in asset condition project presentations. 

When assessing the health of transmission structures and equipment, “everyone is reporting on what appears to be a different grade scale,” Lafayette said. “What we’re proposing to do going forward is to all use the same rubric for structures, within the context of a PAC presentation.” 

He said TOs also plan to standardize how they present their evaluations of alternative solutions, including advanced transmission technologies. He added that the TOs plan to review and discuss ISO-NE longer-term planning studies when developing asset condition projects, to provide stakeholders with information on potential overlaps. 

A representative of the Connecticut Department of Energy and Environmental Protection said he’s “particularly interested in hearing more about how the TOs operationalize the feedback they have received.” 

Sheila Keane of the New England States Committee on Electricity, which has been vocal in pushing for more transparency and guardrails around the process, praised the TO’s responsiveness to stakeholder feedback. (See New England States Raise Alarm on Eversource Asset Condition Project.) 

“What you’ve previewed sounds like it’s going in the right direction,” Keane said. 

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FERC Rejects Basin Electric Proposal for Crypto Rates

FERC on Aug. 20 rejected Basin Electric Power Cooperative’s proposal to establish cryptocurrency blockchain and large load rate schedules, though it did so without prejudice (ER24-1610).

The commission found that Basin had not met its burden to demonstrate that its proposal was just and reasonable and not unduly discriminatory or preferential. But it acknowledged that there are increasing utility and stakeholder concerns related to the growing number of large loads seeking electric services.

“While we reject Basin’s proposed revisions because Basin has failed to support them adequately, we are sympathetic to Basin’s concerns regarding its ability to serve expected load growth reliably and economically,” it said. “Therefore, our rejection herein is without prejudice.”

Basin’s board of directors on Feb. 16, 2024, approved the rate schedules and associated clarifying revisions needed to incorporate them into its Rate Schedule A. The changes had been in development for years and entailed three crypto rate schedules: one each for the SPP and MISO regions, and one for the Western Interconnection.

The co-op said it would procure energy for crypto loads in SPP and MISO at market prices and pass the costs onto its members, which would pass the costs onto the crypto loads. Basin said it would negotiate a rate with members for crypto loads that were within the Western Interconnection and outside of an RTO market.

To recover general and administrative costs, Basin wanted to assess an additional cost on members serving crypto loads.

Basin said the new schedules were necessary because of “the highly speculative nature of crypto loads,” their high degree of operational flexibility and their uneven, unpredictable load, all of which could result in stranded costs. It said its crypto load was 200 MW in 2023 and that more than 1 GW is expected to locate within its territory.

The proposed large load rate schedule would have applied to new or single-load expansions of 75 MW or greater that were not crypto-related. Basin said these large loads are similar to crypto loads, in that they are highly speculative, but that the nature of that speculation is different.

Projects such as direct-air carbon capture plants, hydrogen hubs and green ammonia factories might be spurred by federal or state legislation and be contingent on government funding, Basin explained. If that funding did not materialize, a project could be canceled, and Basin would be left to bear the cost of the generation and transmission assets acquired to serve it.

Basin said its members are in discussion with 22 large-load projects totaling nearly 5 GW, which is roughly equivalent to the co-op’s entire 2022 peak load.

FERC said that Basin did not provide adequate evidence that all crypto loads pose a greater stranded asset risk than non-crypto loads of similar size. It noted that Basin itself acknowledged that there is a stranded asset risk for non-crypto large loads as well and that the co-op does not have specific experience with stranded costs from existing crypto load within its territory.

Commissioners Lindsay See and Judy Chang did not participate in the order.

Basin did not respond to a request for comment.

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San Francisco Ferry Operator Wins $5M Grant for ‘Charging Float’

Plans to transition California’s largest public ferry fleet to zero-emission vessels got a boost from a $5 million grant for charging infrastructure from the California Energy Commission.

The CEC awarded the funds Aug. 14 to the Water Emergency Transportation Authority (WETA), the agency that runs San Francisco Bay Ferry service. The funds will be used to install a “charging float” consisting of a dock, charger and battery storage.

The money was part of $87 million in grant funding the CEC voted to approve during the meeting. Much of the funding went to infrastructure projects for medium- and heavy-duty zero emission vehicles.

State’s Largest Public Fleet

With 15 vessels carrying about 3 million passengers a year across several routes, San Francisco Bay Ferry is California’s largest public ferry fleet.

The fleet runs on diesel, but WETA is planning a transition to zero-emission vessels through its Rapid Electric Emission-Free (REEF) program. The agency has set a goal of shifting half its fleet to zero emission by 2035.

Last month, the ferry service launched the MV Sea Change, a 75-passenger vessel described as the world’s first commercial passenger ferry powered completely by zero-emission hydrogen fuel cells. The California Air Resources Board funded the vessel’s development.

Owned by SWITCH Maritime, the hydrogen-powered ferry will run for a six-month demonstration period. Sponsors of the demonstration service include Chevron New Energies, United Airlines and the Golden Gate Bridge, Highway and Transportation District.

In November, the Federal Transit Administration awarded a $16 million grant to WETA for the electrification of four ferry floats. The project involves structural alterations to the passenger floats, installation of battery banks and vessel charging equipment, and grid connections.

WETA now plans to buy an electric ferry with funding from the Bay Area Toll Authority and the regional Metropolitan Transportation Commission.

Elsewhere on the West Coast, Washington State Ferries announced last month that it is partnering with ABB, a marine technology company, on the design and construction of five new hybrid-electric, 160-auto-capacity ferries. WSF, the largest ferry system in the U.S., has set a goal of running a zero-emission fleet by 2050.

Under mandates from the state legislature and governor, WSF will transition to hybrid-electric power by 2040.

Implementing Blueprints

WETA previously received CEC funding to develop a plan called a blueprint for transitioning to a zero-emission ferry fleet. The agency was one of 34 entities that completed blueprints for infrastructure to support medium- and heavy-duty zero-emission vehicles.

“To be able to move swiftly to deploy infrastructure for zero-emission vehicles, you actually have to have a plan,” Commissioner Patty Monahan said before voting for the WETA funding. “And you have to think about where you want to site it, how it fits with the grid.”

In addition to WETA’s ferry-charging project, the CEC voted Aug. 14 to approve funding for two other projects that came from the blueprints.

The city of Long Beach received $5 million for DC fast chargers and a battery backup system for the city’s medium- and heavy-duty truck fleet. Another $5 million went to Pilot Travel Centers for two rapid hydrogen dispensers and a hydrogen storage tank at a truck stop off Interstate 5 in Southern California.

The CEC awarded grant funding to an array of other projects on Aug. 14. Those include:

    • International Transportation Service received $3 million for hands-free EV charging stations at the Port of Long Beach, including a dynamic charging rail that can charge up to five yard tractors while they’re in operation.
    • Penske Truck Leasing received $7.9 million for chargers at two locations for its growing medium- and heavy-duty EV rental fleet.
    • Skycharger LLC received $10 million for EV chargers at the Port of San Diego for overnight and opportunity truck charging, as well as a 1.7 MW solar-powered microgrid and 1 MW battery storage system.
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Form Energy to Develop First Multiday Storage Project in New England

A major multiday energy storage project in central Maine intended to ease congestion is moving forward thanks to $147 million in federal funding.

The 85-MW battery project will be located in the town of Lincoln, Maine, and has a projected in-service date of 2028, contingent on the timeline on interconnection, permitting and community engagement.

Form Energy, the project developer, has attracted significant attention for its iron-air battery technology that it says can discharge for up to 100 hours. The early-stage company has yet to bring any large-scale projects online but expects several to be operational in 2025. The Maine battery project is its largest proposal announced to date. (See Form Energy Wants to Bring Long-duration Storage to New England.)

The federal funding stems from a $389.3 million Department of Energy grant to the New England states for the Power Up New England project, which also includes a major investment in substations in southern New England to interconnect offshore wind projects. (See DOE Announces $2.2B in Grid Resilience, Innovation Awards.)

The storage project is “intended to address grid resilience and reliability throughout ISO New England,” Form CEO Mateo Jaramillo told RTO Insider. He noted that the states were particularly drawn to the battery’s ability to reduce congestion and balance the output of wind power in northern Maine.

Jaramillo noted that wind patterns often vary over multiple days, creating a need for resources that can store excess energy and balance out intermittencies over extended periods.

“Having the type of storage resource that is well matched to that period of intermittency that comes from wind is why this battery in particular [is] well suited to address the congestion challenges that come from wind,” he said.

Congestion costs in New England are relatively low because of transmission investments made over the past two decades; ISO-NE’s External Market Monitor noted in its 2023 report that “congestion levels per MWh of load in the other RTOs were six to 11 times higher than in New England based.”

However, the RTO’s Internal Market Monitor has indicated that northern Maine is the part of the region where generation is most limited by transmission constraints, affecting the development of new renewable resources in the area. As electricity demand increases and renewables proliferate, transmission constraints likely will become a greater issue. ISO-NE estimates that transmission upgrades needed by 2050 could cost up to $26 billion. (See ISO-NE Prices Transmission Upgrades Needed by 2050: up to $26B.)

While this project is centered around onshore wind, offshore wind is likely to face significant transmission constraints as it scales up. ISO-NE’s 2050 Transmission Study found a high likelihood of overloads on north-south transmission lines during periods of high offshore wind generation, although the extent of overloads is dependent on where offshore wind projects interconnect. (See ISO-NE Analysis Shows Benefits of Shifting OSW Interconnection Points.)

Form has not announced other projects in New England, but Jaramillo said the company is working to bring other projects online in the region.

“I don’t at all expect this to be the only project in New England in the next few years,” Jaramillo said. “This is certainly on the larger side of what we expect, but there’s other clear opportunities that we’re pursuing on the same time horizon.”

While the project is supported by a mix of federal and private funding, Jaramillo said it is “still to-be-determined how much of the funds to cover the investment will come from the market.”

ISO-NE is in the middle of an extended effort to update how it values different resource types in its capacity market, aiming to better align capacity awards with reliability benefits. The RTO plans to implement the reforms for the 2028/29 capacity commitment period. (See ISO-NE Outlines ‘Straw Scope’ of Capacity Market Reforms.)

The new accreditation process likely will increase the financial incentives for longer-duration energy storage resources. Existing capacity market rules provide little incentive for storage resources to increase their duration beyond two hours. (See ISO-NE Capacity Accreditation Reforms Spur Energy Storage Concerns.)

“Form will be the owner of the asset, and so we’re very interested in making sure that the right market products are there in the ISO to compensate for the value that we bring,” Jaramillo said.

As the region’s winter risk increases, long-duration batteries would help boost winter grid reliability by balancing wind resources, which often perform better with lower temperatures, Jaramillo said.

“What we’re bringing is a new type of asset,” Jaramillo said. “An integrated system that has this type of asset in the end is a more reliable system.”

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RPS, CES Driving Smaller Share of Renewable Additions

A new report finds that the percentage of renewable energy generation additions associated with renewables portfolio standards (RPS) has declined since this century began as development increased. 

The 2024 edition of the report by the Lawrence Berkeley National Laboratory indicates most of the 29 states with an RPS have met their targets in recent years but most clean electricity standards (CES) targets are not yet in force. 

“U.S. State Renewables Portfolio & Clean Electricity Standards: 2024 Status Update” also summarizes recent legislative revisions, key policy design features, compliance with interim targets, impacts on clean electricity development and compliance costs. 

This chart shows regional progress toward goals set in renewables portfolio standards. | Lawrence Berkeley National Laboratory

The report’s accompanying spreadsheets drill down to more granular detail in individual states, including demand projections, nominal percentage targets and retail electricity sales projections. 

Berkeley Lab will host a webinar on the report Aug. 28. 

Report Details

The report offers a broad perspective on aspects of the clean energy transition and the role RPS and CES policies play in it.  

Among the details: 

    • Twenty-nine states and the District of Columbia have RPS policies; 16 of those have final targets of at least 50% retail sales, and four have a 100% RPS. 
    • Sixteen states have a 100% CES; all but one of those also have an RPS. 
    • While RPS-related capacity additions have increased over time, they have shrunk as a percentage of new renewable energy construction — 35% in 2023, compared with 60 to 70% per year 10 to 15 years earlier. 
    • The authors acknowledge the difficulty of attributing growth of renewable energy to one factor, but they say RPS policies have been a key driver; nonhydro renewable generation increased by 648 TWh from 2000 through 2023, but RPS and CES policies required only 280 TWh of growth. 
    • Aggregate RPS requirements rise from 450 TWh in 2024 to 930 TWh in 2050; CES requirements begin to ratchet up in 2030 and reach 770 TWh by 2050. 
    • New interregional transmission could reduce resource needs for both RPS and CES; retirements of nuclear, large hydro and other existing assets would increase those resource needs. 
    • A total of 35 GW of renewable capacity was added in 2023; the largest off-taker was load-serving entities, at 39%, but retail off-takers continue to grow, accounting for 29% of new capacity in 2023. 
    • The voluntary market — targets adopted or imposed beyond RPS and CES — might absorb a larger portion of new generation than assumed in the report. 
    • In 2023 and the first quarter of this year, 112 pieces of RPS- and CPS-related legislation were introduced, but only 13 were enacted into state law; 24 of the proposals would have weakened the standards, but none were signed into law. 

This chart shows where new U.S. renewable energy generation capacity is going as it comes online. | Lawrence Berkeley National Laboratory

The report concludes that the future impacts of state RPS and CES programs will depend on multiple factors, including: 

    • whether states decide to expand and broaden their programs;  
    • the types of implementation and enforcement mechanisms established;  
    • efficacy of federal policy in stimulating new clean electricity supplies and transmission;  
    • efforts to address issues surrounding renewable energy integration, permitting and interconnection; and  
    • the price trajectories of renewable energy construction and renewable energy certificates. 
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State Briefs

ARIZONA 

TEP to Build Second Battery System

Tucson Electric Power last week said it plans to build a second, large battery system in southeast Tucson to meet peak power demand. 

TEP’s planned 200-MW Roadrunner Reserve II system will be a twin to the Roadrunner Reserve system currently under construction and store 800 MW hours of energy. It is scheduled to begin operation in early 2026, a year after the first system begins operating on the same site. 

Construction on Roadrunner Reserve II is scheduled to begin later this year. 

More: Tucson.com 

CONNECTICUT 

AG Takes Legal Action Against Solar Companies, Individuals

Attorney General William Tong last week initiated legal action against two individuals and three companies for allegedly committing multiple crimes, including impersonation of homeowners and the unauthorized installation of solar panels. 

The lawsuit targets Sierra Howes and Dakota Grumet, principals at Elevate Solar Solutions, Bright Planet and Sunrun, the company responsible for the installations and system ownership. In one instance, known as the Windsor Transaction, Howes and Grumet proposed a project to a homeowner who rejected the offer. Subsequently, an employee from Bright Planet is alleged to have forged the homeowner’s digital signatures. The lawsuit also includes a recorded call of a Bright Planet employee impersonating the homeowner to Sunrun. About a week after the call, Sunrun installed a system without permits. 

Tong’s complaint enumerates 15 counts of legal violations, with four charges each against Sunrun, Bright Planet and Elevate Solar Solutions. These charges include unfairness, deception, per se violations (violations that are inherently illegal) and willfulness. 

More: pv magazine 

PURA Approves Rate Increases for Eversource, United Illuminating

The Public Utilities Regulatory Authority last week approved a rate adjustment for Eversource and The United Illuminating Co. 

The increase will go into effect on Sept. 1 and will add 0.385 cents and 0.4592 cents per kWh to Eversource and United customers’ bills, respectively. Eversource officials estimate the increase will add $3 per month for typical residential customers. 

More: News Times 

MASSACHUSETTS 

Family Suing Eversource for $450M in Fatal Blast

The family of a man killed in a 2021 gas explosion in Maynard has filed a $450 million wrongful death lawsuit against Eversource, alleging negligence. 

Greg Sharrigan was killed in 2021 when his home exploded. The blast was caused by a leak in a corroded gas line. 

The suit accuses Eversource of knowing about the corroded gas line and not fixing it. 

More: WCVB 

State to Expand New Bedford OSW Terminal

The state last week said it is expanding its first marshaling terminal to handle bigger and heavier turbine components as several staging sites come online along the East Coast. 

MassCEC said the expansion plan was formed via input from developers, turbine manufacturers and installation companies to meet the “evolving needs” of the industry. When completed, the project will expand the available heavy-lift storage area by 5 acres to a total of 26 acres and increase the total heavy-lift quayside available to 1,200 feet. 

The agency has committed $45 million to the project, with an anticipated completion date of December 2026. 

More: The New Bedford Light 

NEW YORK

PSC Approves National Grid Rate Hike

The Public Service Commission last week approved a National Grid rate hike that will be phased in over three years. 

The average bill will go up by about $33 per month in the first year, $8 per month in the second and $19 in the third. In total, the average bill will increase by about $60 per month by September 2026. 

More: News12 Long Island 

NORTH CAROLINA

Utilities Commission Approves Duke Tariff Proposal

The Utilities Commission last week approved a Duke Energy green tariff proposal that will allow large electric customers to chip in extra for renewable projects Duke is already mandated to build, as well as speed up construction of new solar farms by about two years. 

The commission said the amendment to speed up construction was an “improvement” because the change “adds additional accelerated capacity” of renewable energy. 

More: Energy News Network 

TENNESSEE 

PUC Approves Chattanooga Gas Rate Increase

The Public Utility Commission last week approved a rate increase for Chattanooga Gas Co. 

The increase, which the company said was needed to recover costs it incurred in 2023 to meet the region’s growing demand for natural gas, will raise the average monthly bill by $4.21. 

In its April request to the state, Chattanooga Gas said it is experiencing unprecedented growth, which it expects to continue for the foreseeable future. 

More: Chattanooga Times Free Press 

VIRGINIA 

Dominion Energy Installs 50th Monopile for Coastal Virginia OSW Project

Dominion Energy last week reported installing the Coastal Virginia Offshore Wind project’s 50th monopile foundation, 33 miles off the coast of Virginia Beach. 

Dominion is trying to install 70 to 100 monopile foundations by the end of October, before critically endangered North Atlantic right whales begin migrating for the season. Monopile installation will pick back up again in May 2025. 

More: WVEC 

Mecklenburg County Nixes Solar Facility

The Mecklenburg County Board of Supervisors last week voted down a proposed deal with solar developer Longroad Energy to build its 80-MW Seven Bridges facility near Chase City. 

The board voted 7-2 to extend its embargo on solar power despite requests by Chase City officials for the board to approve the project and the revenue it would bring. Board members who voted down the siting agreement gave no explanation for their opposition. 

More: Mecklenburg Sun 

WEST VIRGINIA

Natural Gas Companies File to Decrease Rates

Natural gas companies serving southern West Virginia and other parts of the state last week filed for rate decreases with the Public Service Commission that would change residential customers’ bills starting this November. 

Mountaineer Gas Co. (12.24%), Hope Gas (13.6%) and Cardinal Natural Gas Co. ($10.45) all filed for decreases. Hearings will be scheduled for all requests. 

More: Bluefield Daily Telegraph 

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Federal Briefs

Wind Beats Coal 2 Months in a Row for US Generation

Wind turbines generated more electricity than coal-burning power plants across the U.S. in March and April, outstripping the fossil fuel for two consecutive months for the first time, according to the EIA. 

Wind generated 45,879 GW and 47,689 GW in March and April, respectively. Those numbers outpaced coal, which totaled 38,360 GW and 37,223 GW in the same months. However, through the first four months, coal still leads wind by about 25,000 GW. 

More: The New York Times, EIA 

US Battery Storage Climbs 87% Year-over-year in Q2

Total U.S. battery storage capacity climbed 87.3% year-over-year to reach a total of 23.775 GW by the end of second quarter this year, with 5 GW expected to be added in the third quarter. 

There was expected to be 6.9 GW added in Q2. However, only 3.976 GW came online, an increase of 20% from Q1, according to an S&P Global Commodity Insights compilation of various government filings. 

WECC is projected to climb to 15.838 GW of storage capacity by the end of 2024 and surpass 20 GW in 2025, according to the North American Electricity Long-Term Forecast Supplement. ERCOT is expected to reach nearly 7.2 GW in 2024 and surpass 10 GW in 2025. ISO-NE is slated to surpass 1 GW in 2025, while NYISO and MISO are expected to reach that milestone in 2026, followed by PJM and SERC in 2027. SPP and Florida Reliability Coordinating Council are not expected to reach 1 GW of capacity until 2029. 

More: S&P Global

Posted on

Company Briefs

GM Signs PPA for 3 Assembly Plants

General Motors last week announced a 15-year renewable energy purchase from NorthStar Clean Energy to supply three U.S. assembly plants. 

The power from NorthStar’s Newport solar panel project in Newport, Ark., will provide electricity to the automaker’s Lansing Delta Township Assembly and Lansing Grand River Assembly plants in Michigan and the Wentzville Assembly plant in Missouri. 

GM said the move is an “important milestone” in its goal to be carbon neutral by 2040. 

More: The Detroit News 

Judge Says Tesla Lawsuit Can Move Forward

Judge Nöel Wise last week said a class-action lawsuit against Tesla over treatment of Black workers at its Fremont electric car factory will go before a jury on Sept. 8, 2025. 

The lawsuit is the largest of several lawsuits — including by the state and federal governments — claiming the automaker has allowed rampant, anti-Black racism at the plant. Nearly 6,000 current and former Black employees and contractors at the plant have signed onto the lawsuit, and the number could climb past 10,000 in coming months, a lawyer for the workers said. 

Black workers claim they experienced racist epithets, graffiti, discrimination and harassment at the plant. 

More: The Mercury News