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November 16, 2024

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DOE Wind Power Reports Show Mixed Results in 2023

The 2024 editions of the U.S. Department of Energy’s wind energy market reports show growth amid challenges. 

Utility-scale onshore wind capacity increased by 6.5 GW in 2023. While that represented a $10.8 billion capital investment, it was the third consecutive annual decline, and the smallest capacity addition since 2014. 

The emerging U.S. offshore wind industry ran into serious problems in 2023, and by May 2024, there still was only 174 MW operational in U.S. waters. But three projects totaling 4,097 MW were under construction, and four other projects totaling 3,378 MW had been permitted. 

Distributed wind capacity nationwide reached 1,110 MW with the addition of 1,999 new turbines in 16 states in 2023. This was more turbines than were added in 2022 or 2021, but the cost and the capacity of those additions was greater than in 2023. 

The difference in 2022 and 2023 average wind speeds is shown across the 48 contiguous states. | Pacific Northwest National Laboratory

DOE’s Wind Energy Technologies Office funded the reports, which were compiled by three DOE national laboratories. 

The office said in a news release that the policies of the Biden administration and funding from the Inflation Reduction Act have accelerated the wind energy sector to the point that it accounted for more than 10% of electricity generated and 12% of capacity added in the United States in 2023. 

It said the U.S. project pipeline is 53% larger than a year ago and projected that annual capacity additions would exceed 15 GW by 2026 and be nearly 20 GW by 2030. 

Onshore Wind

The Land-Based Wind Market Report was prepared by Lawrence Berkeley National Laboratory. 

Highlights include:  

    • Installed capacity surpassed 150 GW in 42 states, with Texas leading in nameplate capacity (41,594 MW) and Iowa leading in percentage of in-state electricity generation (59.2%). 
    • General Electric built the majority of wind turbines installed in the U.S. in 2023 — 58%. Vestas was a distant second at 30%. Nordex and Siemens-Gamesa Renewable Energy accounted for 9 and 4%, respectively. 
    • The U.S. wind industry continues to rely on imports, although the IRA has created renewed optimism about domestic supply chain expansion; annual U.S. production capacity at the end of 2023 stood at 15 GW for nacelle assembly, 12 GW for tower manufacturing and 4 GW for blade manufacturing. 
    • Independent power producers own over 90% of the new wind capacity installed in 2023. 
    • Direct retail purchases of wind power, including corporate offtakers, led the market for new wind energy capacity for a second year in a row, buying electricity from at least 48% of the new facilities; electric utilities were a distant second at 29%. 

Offshore Wind

The Offshore Wind Market Report was prepared by the National Renewable Energy Laboratory (NREL). 

Highlights include: 

    • Using the broadest definition, including the maximum potential capacity of lease areas that are newly designated but not yet sold, the U.S. offshore wind pipeline grew 53% to 80,523 MW as of the end of May. 
    • Just over 25,000 MW of that pipeline calls for floating wind turbines, which still are in the development stage and are not expected to be installed in U.S. waters at commercial scale anytime soon. 
    • Estimated investment in the U.S. offshore wind supply chain has reached $10 billion since President Biden took office; NREL has estimated the need to be at least $22 billion. 
    • State-level policies continue to drive offshore wind development; as of May 31, mandates in eight states total 45,703 MW and non-binding planning targets in five states total 69,427 MW. 
    • Fifteen contracts to purchase 12,378 MW from offshore wind farms have been signed. 
    • The report tallied 68,258 MW installed capacity worldwide as of December 2023, less than 100 MW of it in the United States. 

Distributed Wind

The Distributed Wind Market Report was prepared by the Pacific Northwest National Laboratory. 

The North Atlantic region off the New York-New England coast has the most advanced portfolio in the U.S. offshore wind industry. | Lawrence Berkeley National Laboratory

Highlights include: 

    • Ohio, Illinois and Alaska accounted for 78% of the distributed wind capacity added in 2023. 
    • Large turbines (larger than 1 MW) accounted for 69.5% of capacity added; midsize turbines (101 kW to 1 MW) accounted for 8.6%; small turbines accounted for 21.9%. 
    • The major distributed projects in 2023 were a 4.5-MW facility for a lime manufacturing plant in Ohio, a 2.8-MW facility to support an EV maker’s plant in Illinois and a 0.9-MW facility to serve communities in Alaska. 
    • Only 11% of distributed wind installed in 2023 feeds into the grid for local use, while 89% was installed to supply an on-site use; this was an aberration caused by two particularly large projects at industrial sites. 
    • Significant activity and investment in the small wind market in 2023 suggests development might increase in coming years. 
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Exec Details MISO’s Tight Spot Between Load Growth, Retirements, Unwieldy Queue

INDIANAPOLIS — Senior Vice President Todd Hillman encapsulated MISO’s current pressure cooker environment of escalating data center demand, a precarious reliability situation and an overwhelmingly large interconnection queue at Infocast’s inaugural Midcontinent Clean Energy Summit Aug. 20.

Hillman said the days of 0.6 to 1% “anemic” load growth MISO-wide are in the rearview. He said MISO is bracing for 10% load growth in the next few years, driven by 14 to 16 GW of new facility demand.

But he added a caveat that MISO has poor visibility into the magnitude and entrances of large loads. Complicating matters, MISO is scraping its reserves as generation retirements continue.

“In the Midwest, we are at our reserve margins,” Hillman said. “We’ve already been driving to this reserve margin without any load growth.”

MISO expects 80-plus GW of retirements in its dispatchable fleet by 2042, Hillman said.

“We’re all waiting for that next thing: ‘Is it small nuclear reactors, is it long-duration storage, is it, is it, is it?’ My question is when will these technologies become commercially viable? Because we need them now,” he said.

For its part, MISO is trying to craft markets that place reliability front and center, Hillman said, invoking MISO’s proposed availability-based capacity accreditation for all resources, efforts to beef up scarcity pricing and exploring a possible new resource adequacy standard to replace the loss of load expectation.

Hillman said the MISO community should take notice of PJM’s capacity auction, where Dominion Energy’s entrance caused its zonal price to skyrocket to more than $440/MW-day. He said the unofficial data center capital of Arlington, Va., contained in the zone provides a cautionary tale for MISO. He said PJM and MISO, which can rely on one another in times of need, cannot count on the other’s imports when both regions are maxed out before emergency conditions descend.

“You can’t have two drunks leaning on each other. One of them is going to fall down. Now I’m not saying MISO is the drunk. I’m not saying that,” Hillman joked to audience laughter.

Hillman said the typical data center can be built in a matter of months. Generation, on the other hand, takes about six years to build, factoring in queue wait times and construction obstacles.

He said the situation is becoming desperate enough that Holtec International will attempt a restart of Palisades’ 800 MW reactor in Michigan after three years of retirement “to the low, low, low introductory price of $2.5 billion.”

Hillman also touched on the double-edged sword nature of MISO’s very active interconnection queue, which potentially could grow to 350 GW if MISO certifies all 123 GW of its 2022 queue submittals.

“The good news is that we have a very robust queue. The bad news is that we have a very robust queue,” Hillman said.

He said MISO’s active queue is so large engineers deem it “technically infeasible” to study potential interconnections.

Hillman reflected on how far MISO has come in two decades. He pointed out that the conference’s location, the Mariott Indianapolis North, was the site of MISO’s first annual meeting in 2005.

Back then, MISO was in the thick of what would become known as “Peakerfest,” Hillman said, where control room operators would over-commit peaking resources out of an abundance of caution. He also said MISO’s then approximately 5 GW wind fleet now stands at 35 GW.

“We’ve basically had three generation renaissances in the last 50 years,” Hillman said of the energy industry. He noted that from about 1969 to 1986 the nation built about 200 GW of coal power, which was followed by approximately 200 GW of new natural gas generation in the 1990s and the early 2000s surge in wind farms.

“Now we’re in the fourth renaissance, and that’s a load renaissance,” Hilman said. He called for a “higher level of debate” on the clean energy transition.

“We have always seen our industry come through,” he said. “It’s going to be quite the ride. It’s going to be quite the adventure.”

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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.”