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November 8, 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 multiday 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 owners’ 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 TOs’ 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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SEEM Members Respond to FERC Briefing Request

Members of the Southeast Energy Exchange Market (SEEM) told FERC in a filing that, contrary to what SEEM’s opponents claim, the market “is bringing savings to customers and should be allowed to continue” (ER21-1111, et al.).  

Participants in the Aug. 13 filing included Southern Co., Dominion Energy, Duke Energy and Louisville Gas & Electric, all of which were among the founding utilities that first proposed SEEM in 2021. They aimed to answer questions commissioners posed in a June 14 filing seeking information on whether SEEM qualifies as a loose power pool under FERC Order 888 and whether the market’s requirements that entities transacting in it have a source and sink inside its footprint violate Order 888. (See FERC Requests Briefings on SEEM After DC Circuit Order.) 

FERC ordered the briefing as a step toward satisfying last year’s order by the D.C. Circuit Court of Appeals that remanded the commission’s approval of the market — which occurred by default when the commission split 2-2 when the deadline for approval arrived. (See DC Circuit Sends SEEM Back to FERC.) 

The court also found FERC failed to explain why SEEM should not be considered a loose power pool. Opponents argued the market’s nonfirm energy exchange transmission service (NFEETS) made SEEM a loose power pool, which under FERC’s rules must be open to nonmembers.  

FERC provided a series of questions for SEEM members, including whether it is a loose power pool and, if so, whether and how it meets or exceeds Order 888’s open-access requirements for power pools and, if not, whether it is consistent with the pro forma open access transmission tariff (OATT). The commission also asked whether NFEETS should be considered a non-pancaked rate and whether entities with a source or sink outside of SEEM’s territory could conform with the technical requirements of the market’s matching platform. 

In their response, SEEM members argued that SEEM does not quality as a loose power pool because “the commission has already found that NFEETS is neither a discount not a special rate” and that the D.C. Circuit did not find fault with FERC’s reasoning on that point.  

Members claimed the court instead was concerned about a possible inconsistency because it read part of Order 888 to “equate a discount with a non-pancaked rate.” The filing countered this by claiming that NFEETS is pancaked because charges for losses and imbalances are cumulative across balancing authorities (BA). In addition, members asserted that NFEETS is “available to everyone, including SEEM members, on the same terms and conditions, and at the same price, under the [OATT] (or equivalent) of each member.” 

The respondents confirmed that owning a source or sink connected to a SEEM transmission provider is necessary for SEEM to be technically feasible, explaining that SEEM was never intended to be a “fundamental, ground-up reconstruction of the market design in the Southeast,” quoting the initial SEEM filing.  

However, they argued the requirement is not “unduly discriminatory to entities outside the SEEM territory” because there are other ways loads and resources outside the SEEM territory can participate in the market. Members held up pseudo-ties — which are used to represent interconnections between two BAs where no physical connection exists between the load or generation and the power system network — as one possible means of participation by outside entities. 

Finally, members urged FERC to maintain SEEM as the best choice currently available for Southeastern ratepayers, claiming that despite their technical arguments, the market’s opponents have an overarching motive for their objections.  

“At the outset of this litigation, petitioners made their real objective clear: They want a different kind of market for the Southeast,” members said. “But … every prior effort at increased coordination in the Southeast has failed. More importantly, SEEM benefits customers, and those customers should not become victims of petitioners’ ulterior objective. SEEM is the proposal on the table now and must be evaluated on its own merits. And it passes the test easily.” 

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Maine Approved for Floating Wind Research Lease

The nation’s first-ever floating offshore wind research lease has been issued to Maine.

The U.S. Bureau of Ocean Energy Management announced the decision Aug. 19, paving the way for placement of up to 12 floating turbines with a combined rating of up to 144 MW.

Construction is not expected to start for several years. The state first must draw up a research activities plan, then BOEM must perform an environmental analysis on it.

Offshore wind turbines have been built for more than 30 years on foundations affixed to the seabed in shallow water but only now are turbines on floating towers beginning to be deployed in deeper waters, and the design of the towers and anchoring systems is a work in progress.

Maine aspires to be a leader in the floating wind sector. Much of the Gulf of Maine is too deep for fixed-bottom turbine foundations.

The University of Maine has been working for years to refine floating foundation designs.

For commercial purposes, BOEM sold five floating wind leases off the California coast in a December 2022 auction and plans to offer eight in the Gulf of Maine in an auction in late 2024. But the lease announced Aug. 19 was the first for the purpose of researching floating wind.

Some commercial wind leases have drawn bids in the range of hundreds of millions of dollars, but BOEM awarded lease OCS-A 0553 to Maine at no cost.

Maine has designated Pine Tree Offshore Wind LLC, an affiliate of New England Aqua Ventus LLC, as the operator for the research lease. Aqua Ventus began utility power purchase agreement negotiations before the Maine Public Utilities Commission (Case 2022-00100) in April 2022.

Maine Gov. Janet Mills (D) said in a prepared statement Aug. 19 that the research array, as proposed, will use floating platform technology development by the University of Maine and deployed by its development partner, Diamond Offshore Wind.

“This lease between the state and BOEM to support the nation’s first research array devoted to floating offshore wind technology is the result of extensive engagement with stakeholders and communities across our state to establish Maine as a leader in responsible offshore wind, in balance with our state’s marine economy and environment,” she said.

BOEM in its news release said the research project goes beyond Maine’s ambitions, allowing the wind energy industry, fishing community, wildlife experts, governments and others to evaluate floating wind as a renewable energy source in the Northeast, and to evaluate its impacts.

Maine first requested a research lease in October 2021, and the request went through revisions during the review process. The awarded lease area totals nearly 15,000 acres, about 28 nautical miles southeast of Portland.

The upper limits specified in the floating research lease — 12 turbines and 144 MW — potentially put the project on the scale of the first completed wind farm in U.S. waters: South Fork Wind, a fixed-bottom project whose 12 turbines are rated at 132 MW.

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CenterPoint Energy Still in Eye of the Storm

It’s been six weeks since Hurricane Beryl, a Category 1 storm, blasted through the heavily wooded Houston area, toppling trees into distribution lines and knocking out power to nearly 3 million residents.

Electricity has been restored after weeks of recovery efforts, but lawmakers and regulators still are trying to figure out how a puny Cat 1 storm could have caused the devastation that led to long-term outages.

Houston utility CenterPoint Energy has borne the brunt of the scrutiny. Entergy lost several hundred thousand of its own customers in its Texas footprint; however, it had better communications with its customers and an outage tracker that worked.

Texas Attorney General Ken Paxton (R) became just the latest to probe the beleaguered company when he launched an investigation on Aug. 12 over allegations of CenterPoint fraud, waste and “improper use of taxpayer-provided funds” following Beryl. He said any unlawful activity his office uncovers will be met “with the full force of the law.”

Texas Gov. Greg Abbott (R), who said in 2021 just four months after the disastrous winter storm that ERCOT’s grid “is better today than it’s ever been,” has taken a hands-on approach with CenterPoint. He ordered the utility to file a plan outlining its preparation and response practices for the next storm, threatening to cut rates if the response was insufficient. After meeting with CenterPoint executives at the July 31 deadline, he called the plan “inadequate” and said “more must be done [and] faster.”

Abbott also has directed the Public Utility Commission, whose members he appoints, to conduct a “rigorous” study to determine why severe weather events lead to “repeated … power failures” in the Houston area. The PUC brought first-year CEO Jason Wells and other CenterPoint executives in for one hearing and is receiving regular updates from the utility. It plans to report its findings to the legislature by Dec. 1 (56822).

Both of Texas’ legislative houses have joined in the fun and conducted public floggings of the utility’s executives, with most of the ire coming from Houston senators. Wells was asked by Sen. Paul Bettencourt (R) whether he would heed calls for his resignation during a special Senate committee’s July 29 hearing. Noting CenterPoint has laid out 40 actions to immediately begin regaining community trust, Wells said, “I think if I resign today, we lose momentum on the things that are going to have the best possible impact for the greater Houston region.”

Some lawmakers were shocked — shocked — to learn during the hearing that CenterPoint’s regulated business model allows it to recover storm-restoration, vegetation management, line maintenance and other costs in its rate cases, while earning a 9.4% return on capital investments. They called for more accountability from the utility, threatening it with clawing back profits, trimming rates, shrinking its service territory and implementing performance-based ratemaking.

“It’s a pretty amazing business model,” Sen. Lois Kolkhorst (R) told CenterPoint execs. “Most of us that run a business, we don’t get reimbursements for our expenses.”

However, it’s CenterPoint’s $800 million lease agreement for 15 large (32 MW) mobile generators and several smaller ones in 2021 that has attracted much of the politicians’ focus. The utility said the larger generators could support restoration efforts after power outages. However, they sat unused after Beryl, as they have since being leased. The large units are so heavy they need permits to be transported and take days to set up.

Senators derided the generators as “quasi-mobile.” Wells defended the lease agreement, which may have relied on personal relationships, saying the generators are necessary when there is another load shed event as occurred during the 2021 winter storm.

“I find it troubling that you’ve been using the rate of return on something that you’re not using,” said Sen. Charles Schwertner (R), the committee’s chair. “It doesn’t smell good at all.”

“That’s fraud!” Bettencourt charged, threatening to claw back rates related to the lease agreement.

As the senators piled on Wells, Jason Ryan, CenterPoint’s executive vice president of regulatory services and government affairs, took to social media to say the large generators are a necessary tool in the toolbox to avoid a repeat of Winter Storm Uri.

CenterPoint CEO Jason Wells gathers his thoughts during a pause in the Senate hearing after a technical glitch. | Texas Senate

“Like our own toolboxes at home, not every tool is used in every situation, and not every emergency generation asset in our fleet is likely to be used in any one event,” he wrote on X, formerly known as Twitter. Ryan’s account no longer exists.

Sen. Phil King (R), who wrote the legislation that cleared the way for regulated wires provider CenterPoint to acquire generation, apologized to the committee after Wells’ testimony.

“The intent was to simply allow there to be very mobile storm response generation,” he said. “It was never intended, at least by me, to allow it to be used for large generation of the nature we’ve talked about today. I feel like I’ve been taken advantage of, to be honest. We will fix that going forward.”

Following the hearing, Lt. Gov. Dan Patrick (R), who essentially runs the Senate, sent a letter to the PUC urging it to claw back the $800 million to ensure ratepayers do not pay for CenterPoint’s “mismanagement.” Schwertner promised lawmakers “will hold CenterPoint accountable for lining its pockets at the expense of its customers” in the coming months.

Apparently, renegotiating the generators’ contract is not an option. Ryan told the PUC during its Aug. 15 open meeting that CenterPoint can’t break the contract unless the vendor, Life Cycle Power, fails to meet its obligations. That left the commissioners incredulous.

“You entered into a contract you can’t terminate unless there’s vendor non-performance,” Commissioner Lori Cobos told Ryan. “It just seems like we’re in this circular place where you all are coming across like your hands are tied to this contract.”

Energy consultant Alison Silverstein, a former PUC and FERC adviser, said the easiest way for Texas regulators to punish CenterPoint would be to reopen the mobile generation case and assess whether CenterPoint provided “accurate or misleading” information about the generation assets and their intended purpose.

“This could be a pretty fast proceeding and could look like enough of a spanking to make customers and politicians happy,” Silverstein told RTO Insider.

She dispelled the notion that a new wires provider could be handed the franchise for the nation’s fourth-largest city.

“Outside of Florida, no utilities are doing a competent job dealing with hurricane-heavy service geographies,” Silverstein said.

Performance-based ratemaking could be one option, she said, by aligning all utility incentives (profits, cost recovery, executive compensation) with reliability, resilience and affordability. At the same time, Silverstein doubted the PUC would revise the state’s ratemaking rules on its own.

“This would be a long and boring process that won’t have the speed, bloodletting and circus elements or assured outcome that would make local and state politicians happy,” she said.

“I think we need a comprehensive look at how we fund utilities, how they prepare for storms,” PUC Chair Thomas Gleeson said during the Senate hearing.

The day after that hearing, CenterPoint held its quarterly earnings call with financial analysts and reported a 93.2% increase in earnings. It said it planned to ask the PUC to recover between $1.5 billion and $1.7 billion in Beryl storm costs.

“That dog won’t hunt,” Sen. Carol Alvarado (D) said on X.

Two days later, CenterPoint withdrew both its $2.3 billion resiliency plan filed in April (56548) and its rate-increase request to recover $6 billion of investments made since its last rate proceeding in 2019 and expand its return-on-equity (56211). The utility had been negotiating settlements in both dockets.

However, on Aug. 16, the state Office of Administrative Hearings rejected the rate case’s withdrawal. The court said the withdrawal would conflict with state law requiring investor-owned utilities in the ERCOT region to file a comprehensive rate review within 48 months of their most recent rate proceeding.

Consumer groups opposed CenterPoint’s request, saying it would prevent them from clawing back certain expenditures.

Since then, CenterPoint has continued to try to make amends. The utility rolled out its Greater Houston Resilience Initiative that tracks its progress in substituting composite poles for wood structures and its vegetation management program; unveiling a new cloud-based outage map to replace its locally hosted version that crashed during a derecho in May; fired its senior vice president of electric business; beefed up its social media presence, with more than a dozen posts on X on Aug. 17-18 alone; and held the first of 16 community open houses through September.

PUC staff is attending each of the open houses and will lead a public work session in Houston Oct. 5. The commission also created a web tool to gather feedback from Houston residents.

“What was good enough 15 years ago is not good enough anymore,” Gleeson told the Senate committee. “We have not held them to a standard that is sufficient. I think we need a comprehensive look at how we fund utilities and how they prepare for storms.”