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December 19, 2024

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Lame Duck Permitting Push Fails; Manchin Blames House GOP Leaders

The bipartisan permitting bill that passed the Senate Energy & Natural Resources Committee is officially dead, with Sen. Joe Manchin (I-W.Va.) saying Dec. 16 it would not be included in a must-pass spending bill. 

Manchin blamed House Republicans, specifically Majority Leader Mike Johnson (R-La.), as negotiations around the issue failed and it will not be included in the last legislative vehicle to make it out of this Congress. 

“By taking permitting off the table for this Congress, Speaker Johnson and House Republican Leadership have done a disservice to the incoming Trump administration, which has been focused on strengthening our energy security and will now be forced to operate with their hands tied behind their backs when trying to issue permits for all of the types of energy and infrastructure projects our country needs,” Manchin said. 

While Republicans are poised to also take control of the Senate next year, their 53-47 majority will require votes from Democrats for meaningful permitting reform, he added. Reforming the National Environmental Policy Act, FERC’s governing statutes and other relevant laws is too far afield from the budget to be eligible for the reconciliation process that avoids the 60-vote threshold, which Democrats used to pass the Inflation Reduction Act. 

“I am very proud of the work that my friend and partner, Sen. John Barrasso, and I put in over the course of nearly two years with our colleagues on the Senate Energy & Natural Resources Committee to get the Energy Permitting Reform Act negotiated, drafted and through the committee process with a historic 15-4 favorable vote, sending a clear signal that the time is now to get this done,” Manchin said. 

As Congress was negotiating what would be included in the continuing resolution it needs to pass by the end of this week to keep the government funded, a broad group of trade associations asked for its passage.  

The American Council on Renewable Energy, American Chemistry Council, Advanced Energy United, Center for LNG, Clean Energy Buyers Association, Electric Power Supply Association, National Mining Association, Solar Energy Industries Association, the U.S. Chamber of Commerce, and dozens of others signed onto a letter urging Congress to pass a bill. 

“America’s energy industry is united in one common goal — providing affordable, reliable, cleaner domestic energy,” the letter said. “But our current permitting system frequently prevents us from accomplishing that goal, bogging down our projects in bureaucratic delays and endless litigation. For example, it can take, on average, up to 10 years to permit a single transmission line and 29 years to move mining projects through the federal permitting process, 3-8 years just for litigation.” 

Another letter from 25 conservative and “free market” groups, led by the Competitive Enterprise Institute, urged Congress to wait until its next session to pass permitting legislation. They specifically argued against increasing the federal role in electric transmission siting. 

“It makes no sense for Republicans to move forward with legislation now when next year they will control the House, the Senate and the White House,” the CEI-led letter said. 

“Anything that Republicans and those who want genuine permitting reform can get now they can get next year, and much more. There would be less need for compromise, such as by enacting harmful transmission policy that would untap the Inflation Reduction Act subsidies and primarily serve to put unreliable electricity generation on the grid (i.e. wind and solar).” 

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Rising Transmission Costs in PJM Concern Consumer Advocates, Enviros

Speakers at the PJM Public Interest and Environmental Organizations User Group’s meeting Dec. 10 said the growth of local transmission projects is a major contributor to grid upgrades making up an increasing share of rates.

RMI’s Claire Wayner said transmission and distribution are making up an increasingly larger amount of consumers’ energy spending even as the number of line miles built is decreasing. Compared to regional projects that are reviewed at multiple levels to ensure reliability is delivered at least cost, local projects lack transparency and oversight, she argued.

Wayner co-authored a report for RMI, released in November, that recommended several changes to the regulation of local projects. It showed that while transmission spending nationwide hit a new high in 2023 — accounting for 24% of consumers’ bills in 2020 compared to 10% in 2005 — the share of transmission spending that went to high-voltage projects has declined, falling from 72% in 2014 to 34% in 2021. In PJM, spending on local projects increased 26-fold between 2009 and 2023.

Many states don’t require certificates of public convenience and necessity (CPCNs) for local projects, which Wayner said effectively exempts them from review at public utility commissions. In addition to expanding CPCN requirements, she said states can also create electric transmission authorities and establish expedited cost recovery for projects that have undergone regional review.

Wayner recommended that FERC require independent transmission monitors, consider performance-based regulation, and rework its formula rate process to eliminate the presumption of prudence and RTO adder for local projects that do not undergo regional review.

She also argued that PJM could improve its processes by creating windows for utilities to submit local needs to be reviewed by the RTO as it plans regional solutions; standardizing definitions and tracking of local projects; and providing states with more opportunities for input on regional planning.

Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), said he has submitted cost-related questions on dozens of local, supplemental projects in PJM’s Planning Community portal and often received what he deemed inadequate or incomplete responses. In some cases, answers simply referred him back to the PJM website, which does not provide the detailed cost breakdowns he was seeking, he said.

“There is no ability to get more specific cost information than the sticker price of these projects,” he said.

Poulos also identified 31 instances in 2023 in which supplemental projects presented to PJM’s Transmission Expansion Advisory Committee were either already under construction or had been completed. He questioned what value there can be from stakeholder input on local projects that have already been completed.

CAPS has hired a consultant to further investigate how PJM’s tracking of supplemental projects can be improved, he said.

Advocates Lay out 2025 Priorities

Poulos also presented several issues that consumer advocates intend to focus on next year, including changes to PJM bylaws and governance, removing barriers to storage development, improving participation in demand response programs and a sub-annual capacity market design.

With rising capacity prices and the elimination of energy efficiency from PJM’s markets, Poulos said it is increasingly important for stakeholders to find opportunities for load to participate in the markets.

“It’s a part of the equation that has just been ignored for way too long,” he said.

Because consumer advocates make up one of five member sectors at PJM but only hold about 4% of non-sector-weighted votes at lower committees, he expressed skepticism that the stakeholder process could yield such changes directly.

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Texas Public Utility Commission Briefs: Dec. 12, 2024

The Texas Public Utility Commission’s staff has recommended not moving forward with the proposed performance credit mechanism (PCM) market design for ERCOT as it currently is designed, setting up an interesting decision for the PUC in its final open meeting of the year. 

A day after the commissioners agreed to delay any decision until that Dec. 19 meeting, staff said in a Dec. 13 filing that the PCM market tool results in “minimal” additional resource adequacy value under its current design parameters. They also said alternative design choices would result in the PCM not complying with state law, and market modifications likely will be needed to achieve the PUC’s chosen reliability standard in the long term (55000). 

“We intend to bring this back on the 19th and make a decision on where to go forward from there with the PCM,” PUC Chair Thomas Gleeson said during the commission’s Dec. 12 meeting. 

“There’s still a lot up in the air, right?” Commissioner Lori Cobos said. She referenced ERCOT’s stand-alone dispatchable reliability reserve service still under development, the Real-time Co-optimization plus Batteries project, and important questions surrounding the ancillary service demand curves, all of which are to be brought online before the PCM. 

“You have to put those into a structure then and put them into operation and be able to get this analysis to be able to understand whether [they’re] working or not,” Cobos said. 

Gleeson said during a conference in September the PCM should be placed on the back end of other market changes. 

“We have a number of tools at our disposal. We should try to see if we can meet our reliability goals with those tools before we look to implement something that’s new and novel and that we don’t really know how it interacts with the rest of our market,” he said at the time. (See “Market Participants Pan PCM,” PUC’s Gleeson at Texas Clean Energy Summit: Smooth Tenure Turns ‘Interesting’.) 

The commission in August directed ERCOT and the Independent Market Monitor to complete updated assessments on the PCM’s cost to and effects on the market and file a report on the costs and benefits of continuing the program. Staff then reviewed the assessments before making their recommendation.  

Staff said the ERCOT assessment, conducted with the Energy and Environmental Economics (E3) consulting firm, recommended refinements to the PCM’s design be considered so the tool could have a more substantive impact on reliability before eliminating it as a potential option. 

The IMM found the PCM to be a “novel form of a capacity market” in that it settles based on after-the-fact availability rather than ex-ante based on expected availability. Staff noted the monitor also concluded the PCM would provide a new source of revenue for generators that would increase ERCOT’s capacity margin and the costs to customers but reduce shortage revenues. 

The monitor said the PCM’s net costs are likely to exceed $1 billion annually in the short term because its cost cap provision is likely to bind. Eventually, the higher capacity margins would reduce the frequency of shortage pricing, with the net costs falling to $350 million to $725 million per year. Without the cost cap, those costs would range from $930 million to $2 billion, the IMM said.

The PCM was selected as ERCOT’s new market design in 2023 by the PUC, then under the chairmanship of Peter Lake. In February 2024, ERCOT and E3 filed a strawman design with 37 parameter decisions, leading to months of workshops and stakeholder discussion. 

The mechanism would reward thermal generators with credits based on their performance during a determined number of scarcity hours. Those credits must be bought by load-serving entities, based on their load during those same hours, or exchanged by LSEs and generators in a voluntary forward market. (See Texas PUC Submits Reliability Plan to Legislature.)

Two New TEF Applications

The commission approved two more applications for Texas Energy Fund (TEF) loans identified by staff and advanced them for due diligence (56896). 

The NRG Energy and WattBridge Energy IPP Holdings projects represent 1,231 MW of potential new generation and replace an apparently fraudulent project submitted by a company with suspect backing that left a nearly 1,300-MW hole in the fund’s portfolio. (See Texas PUC Rejects Possible ‘Fraudulent’ Loan Application.) 

The additions bump the TEF’s In-ERCOT Generation Loan Program portfolio to 18 applications offering 9.72 GW of potential new generation. They are seeking $5.34 billion in loaned funds. The Texas legislature has allocated $5 billion to the fund. 

The NRG application is for a new 721-MW natural gas combined cycle unit at its Cedar Bayou plant near Houston. WattBridge submitted applications for four projects totaling 1,600 MW. The company uses 48-MW aeroderivative gas turbines.  

The TEF was established by state law and voters in 2023 and offers a low-interest (3%) loan and grant program of up to $7.2 billion for dispatchable, primarily thermal, generation. The fund has four separate programs.

Entergy Resiliency Plan Approved

The commission approved Entergy Texas’s “Future Ready” resiliency plan, a $335 million, three-year proposal consisting of six resiliency measures that begins next year. Each of the measures is intended to prevent, withstand, mitigate or more promptly recover from the risks posed by one or more specified and defined resiliency events to the utility’s transmission or distribution system, Entergy said (56735). 

Entergy hopes to gain PUC approval of $137 million in projects and to seek conditional approval and include $198 million of additional resiliency projects under the TEF’s Outside ERCOT Grant Program. Once it’s up and running, the program will award grants for infrastructure modernization, weatherization, reliability and resiliency improvements, and vegetation management. 

Entergy also is making a second attempt to secure funds from the U.S. Department of Energy’s Grid Resilience and Innovation Partnerships program to help with its $107.5 million infrastructure and grid hardening project in Port Arthur, Texas. The utility’s staff told commissioners they are negotiating with the DOE over a $54 million cost-sharing portion of the plan. 

An administrative law judge found a settlement reached between Entergy and PUC staff, the Office of Public Utility Counsel and several consumer groups to be in the public interest.

Glotfelty Closes His Last Meeting

Commissioner Jimmy Glotfelty was given the honor of adjourning the open meeting with a ceremonial gavel honoring his 3½-year tenure on the PUC. It was the commissioner’s last meeting after announcing Dec. 4 he would step down. (See Texas PUC’s Glotfelty to Resign from Commission.) 

“This has been a wonderful opportunity, serving with you all and serving with the prior commissioners that have come before us,” Glotfelty said. “It has been a proud time in my career. It’s my hope that we’ve done it with honor and that we have done it knowing the gravity of our decisions can mean life and death.” 

“Thank you for all the work you did on my nuclear project. I appreciate you getting it started for me so I can take it over,” joked Gleeson, who will pick up Glotfelty’s role leading the PUC’s advanced nuclear reactor effort. “We’re definitely going to miss you. You’re leaving a big hole up at this dais with you walking out.” 

Glotfelty then gaveled the meeting to a close. “I announce us adjourned,” he said.

PUC Hires External Affairs Chief

Gleeson opened the meeting by announcing Lucy Nashed’s hiring as the agency’s new chief of external affairs. She will oversee the PUC’s external-facing divisions (communications, government relations, public engagement, utility outreach and consumer protection) and their strategy and day-to-day operations. 

Nashed previously directed communications for Texans for Lawsuit Reform over eight years. The organization advocates for a “fair and efficient” legal system and against “abusive and unnecessary litigation.” 

The commissioners also passed a motion requesting the Office of the Attorney General to intervene in Rio Grande Electric Cooperative’s petition from a declaratory order from FERC. The cooperative requests FERC not to assert jurisdiction over public utilities not presently under the Federal Power Act after RGEC disconnected from WECC and interconnected with ERCOT (EL25-23). 

The cooperative said that while some of its distribution lines served by its WECC transmission facilities cross state lines to serve end-users in New Mexico, the energy is carried by RGEC’s non-jurisdictional distribution facilities and would not constitute wholesale transmission in interstate commerce. 

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CISA Seeks Comments on Cyber Response Plan Update

The Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA) is taking comments on its draft National Cyber Incident Response Plan (NCIRP), developed alongside the Office of the National Cyber Director (ONCD) and with input from industry, which was published Dec. 16 in the Federal Register.

CISA has been revising the NCIRP since October 2023, as directed in the National Cybersecurity Strategy published by the Biden administration earlier that year. The NCIRP, originally published in 2016, is meant to serve as “the nation’s framework for coordinated response to significant cyber incidents.” However, the changing cyber threat landscape and national response capabilities have undergone significant changes since the original publication — not the least of which is the establishment of CISA and ONCD themselves.

“Today’s increasingly complex threat environment demands that we have a seamless, agile and effective incident response framework,” CISA Director Jen Easterly said in a statement. “This draft NCIRP update leverages the lessons learned over the past several years to achieve a deeper unity of effort between the government and the private sector. We encourage public comment and feedback to help us ensure its maximum effectiveness.”

The goal of the NCIRP was to set out, in broad terms, the structures of the federal government’s response to cyber incidents and its relationship to federal agencies; state, local, tribal and territorial governments; the private sector; and civil society. Entities should not approach it as “a step-by-step instruction manual on how to conduct a response effort,” CISA said, noting that “every incident and every response is different.”

The plan’s authors laid out four lines of effort: asset response, threat response, intelligence support and affected entity response.

Asset response involves helping affected entities protect their assets, mitigate vulnerabilities and reduce the impact of cyber incidents. Threat response means coordinating law enforcement and national security investigations, collecting evidence and facilitating information sharing.

Intelligence support refers to building situational threat awareness, while affected entity response refers to supporting affected entities’ efforts to manage the impact of a cyber incident.

Cyber incident response comes in two main phases, according to CISA: detection and response. Detection involves the discovery, reporting and validation of an incident, as well as assessing whether it qualifies as a significant cyber incident, which 2016’s Presidential Policy Directive 41 defines as a cyber incident or group of incidents that likely will cause harm to U.S. national security or economic interests, foreign relations, or the liberties or public health and safety of the American people.

Detecting events and validating their severity requires “active engagement with service providers, the cybersecurity community, and critical infrastructure owners and operators,” the plan said. The detection phase begins when a cyber incident is identified and involves a series of key decisions including determining the incident’s severity, engaging private sector stakeholders for additional information, and understanding the scope and impact of the incident.

In the response phase, entities act to contain, eradicate and recover from incidents, while assisting law enforcement agencies with their investigations. Key decisions in this phase include determining which non-governmental stakeholders can best contribute to solution development and implementation, identifying shared priorities for response and deciding what additional resources might be needed for effective mitigation.

After a significant cyber incident, the Cyber Response Group in the office of the president must order a review of the response and prepare a report within 30 days. A declaration of a significant incident will terminate 120 days after the declaration or its last renewal. The government’s Cyber Safety Review Board also will review the incident to find areas for improving cyber response practices in the public and private sectors.

Cybersecurity has become a constant concern in recent years as nation-state rivals have sought to gain advantages over the U.S. by threatening the integrity of critical infrastructure including the electric grid. CISA has issued multiple warnings this year about electronic infiltration from actors sponsored by Iran and China, which have used sophisticated techniques called “living off the land” to disguise their intrusions as normal network traffic. (See Agencies Describe a Year of Iran Cyber Attacks.)

Members of the public have until Jan. 15, 2025, to register comments on the NCIRP.

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Stakeholders Turn down NYISO Reserve Performance Penalties

The NYISO Business Issues Committee on Dec. 11 tabled an ISO proposal to levy financial penalties against consistently underperforming generators in the reserve market, though it supported a related measure intended to better identify such resources so they can be removed.

The Operating Reserves Performance Penalty proposal, presented to the Installed Capacity Working Group in November, consisted of two components. The BIC declined to recommend that the Management Committee approve assessing the financial penalties, which would require tariff changes and was not well received by members of the ICAPWG. (See Stakeholders Skeptical of NYISO Performance Penalty Proposal.)

“We’ve received robust feedback across multiple meetings, and in the holiday spirit, it makes me feel a bit like a chestnut roasting on an open fire at times,” said Nathaniel Gilbraith, NYISO manager of energy market design.

While NYISO believed that the performance penalty proposal was “reasonable and commensurate” with the issue of underperformance, the ISO recognized that stakeholders preferred focusing on disqualification and removal of poor performers, Gilbraith said.

The dollar value of these poor performers ranges between $100 million and $260 million per year, according to the ISO.

The committee did, however, support the second component, which is to establish a rebuttable presumption for resources found to be underperforming. Those resources would be removed from the market unless they can demonstrate that the cause of the poor performance has been fixed. As part of that, NYISO would establish three different metrics for assessing underperformance. The BIC recommended directing the ISO to describe the “consequences for persistent operating reserve market underperformers” as described in the original proposal.

If approved by the MC at its meeting Dec. 18, NYISO would develop a new proposal in the first quarter of 2025 to be presented for feedback and aiming for stakeholder approval by the end of next year.

The BIC’s motion specified that “the proposed process enhancements will not alter the NYISO’s existing tariff authority to remove operating reserves qualification from suppliers that consistently underperform.”

It passed with four abstentions and New York City in opposition.

“As I understand it, the removal will occur after some period of time, but during that period of time, these market participants are still going to be compensated for a service they have not provided,” said Kevin Lang of Couch White, speaking on behalf of the city. “From the perspective of a consumer, that is unjust and unreasonable.”

Lang said that while the city supported removing bad actors, without the financial penalties, the proposal did not fully address the issue.

“We are extremely concerned that the NYISO is not going to pursue what, quite frankly, we thought was the totality of this,” he said.

NYISO staff clarified that penalties could be reexamined in 2025. Lang was not satisfied, later saying that this was not a “market design complete” proposal, something he blamed on the rushed process toward the end of the year.

Mark Younger of Hudson Energy Economics agreed.

“I hope we can do this at a high level and get through this alternative motion quickly, and get on with the holiday period,” Younger said. “It should be no surprise to anybody that I thought the process we took to get here was a total disaster. … You heard vociferous and, as you tended to note, very consistent and clear concerns that were ignored until about a week ago.”

Younger added that he hoped NYISO would have this “all wrapped up by the end of April.”

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Strong 2025 Predicted for US Blue Hydrogen

Wood Mackenzie predicts that the U.S. low-carbon hydrogen sector will focus on blue rather than green in 2025 as federal leadership turns from blue to red. 

Regulatory uncertainty, policy changes and competition for the renewable power used to generate green hydrogen will have a significant impact, the data and analytics firm said in its newly published forecast. 

But Wood Mackenzie does expect 2025 to be a pivotal year for the hydrogen and ammonia sectors despite the challenges that persist.  

“We anticipate increased levels of activity across both sectors and a shift towards greater commercialisation, with some surprises along the way,” principal analyst Bridget van Dorsten wrote Dec. 12 in announcing “Hydrogen: 5 things to look for in 2025.” 

Wood Mackenzie’s analysts expect the U.S. to solidify its position as the world’s leading producer of blue hydrogen as the second Trump administration begins. Over 1.5 Mtpa of U.S. blue production capacity will reach final investment decision in 2025, the report predicts, over 10 times more than for green hydrogen. 

The Biden administration’s push to develop the clean hydrogen sector has been slow to develop momentum, and the report envisions some significant headwinds for U.S. green hydrogen as President Trump returns to office. 

“While there will still be some demand driven by corporate decarbonisation efforts, near-term opportunities for green hydrogen will shrink, and we anticipate a substantial uptick in cancellations, particularly for projects targeting mobility, steel and e-fuels,” the authors write. 

A dozen or more colors and shades exist to designate the means by which hydrogen is produced. Truly green hydrogen is produced from water with renewable power and creates no carbon dioxide emissions, while blue hydrogen is generated from natural gas, with resulting CO2 captured and sequestered or repurposed. 

The distinctions and details are of intense interest to industrial and environmental lobbyists, and neither side seems happy with the state of affairs. Over two years after Biden’s signature Inflation Reduction Act passed, there still is no final guidance for the 45V tax credit for clean hydrogen production. 

Trump has railed against the Inflation Reduction Act and various aspects of the clean energy transition, placing the future of 45V and Biden’s Hydrogen Hub initiative in question. 

But Wood Mackenzie expects that the 45Q tax credit — for investment in carbon capture and storage — will receive continued support, as it is strongly backed by the oil and gas industry. 

The report predicts some 2025 growth in green hydrogen outside the U.S., with at least one giga-scale project reaching final investment decision. 

It sees strongest growth in China, India and the emerging economies of Latin America and the Middle East where there are low-cost renewable options, supportive government initiatives and availability of low-cost Chinese-made electrolyzers. 

However, Wood Mackenzie also expects a continued mismatch between investments in production and contracts for output. 

Of the 5.5 Mtpa of low-carbon hydrogen projects that have taken final investment decisions, the report notes, 2.5 million tons is uncontracted, most notably within U.S. blue hydrogen. 

Even as some of these blue hydrogen projects start to unwind their uncontracted positions, overall uncontracted volumes are expected to rise. 

The report also predicts growing momentum for the low-carbon ammonia space. It estimates an $8 billion investment across the value chain in 2025, double the amount seen in 2024. 

“A key driver will be the strategic investments aimed at enabling offtake agreements, as projects push forward with greater certainty,” the authors write. “Many of these investors are targeting new energy markets for hydrogen (e.g. maritime, aviation, etc.), where demand for low-carbon ammonia is rising, positioning themselves to secure long-term offtake agreements as the market scales.” 

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FERC OKs CAISO Plan to Streamline Interconnection Process

FERC on Dec. 16 approved CAISO’s request to further streamline its generator interconnection process in response to the high volume of requests in its interconnection queue.  

The commission’s order permits the ISO to apply six sets of tariff revisions related to its Generator Interconnection and Deliverability Allocation Procedures (GIDAP) and associated Generator Interconnection Agreements (GIAs) to resources that joined the queue in Cluster 14 — which opened in April 2021 — or earlier. 

The tariff revisions won’t apply to interconnection customers that already have executed GIAs or have requested that GIAs be filed unexecuted.  

In September, FERC approved a larger proposal to streamline the ISO’s interconnection process starting with 2023’s Cluster 15 and beyond. (See FERC Approves CAISO Plan to Streamline Interconnection Process.)  

The newest tariff amendments are intended to manage the “large volume of interconnection requests already studied but for which GIAs have not yet been executed,” the commission noted in its order (ER25-131). The revisions are a result of the ISO’s Interconnection Process Enhancements (IPE) initiative, which involved over a year of stakeholder engagement that led to the approval of refinements to the process.  

The IPE proposal is intended to complement — not replace — CAISO’s FERC Order 2023 compliance filing, which is still pending approval. The order states that, while the tariff revisions in the most recent filing touch on some reforms in the Order 2023 filing, “CAISO does not propose revisions to any section of its tariff pending commission acceptance.”  

The six sets of tariff revisions the commission approved Dec. 16 will:  

Subject new small asynchronous generating facilities in Clusters 14 or earlier to fault recording requirements that CAISO currently applies only to asynchronous generating facilities larger than 20 MW. 

    • Update the granularity of phase angle measuring unit data for asynchronous facilities by increasing the sampling rate of that data. 
    • Unify the payment and authorization schedules among interconnection customers sharing network upgrades to develop a construction timeline necessary to meet the earliest interconnection customer’s commercial operation date. 
    • Increase the material modification assessment (MMA) deposit cost from $10,000 to $30,000 and extend the estimated time to complete an MMA from 45 days to 60 days.  
    • Create a new “implementation deposit” of $35,000 to cover specific customer costs after completion of interconnection studies in order to avoid passing off those costs to other market participants.  
    • Limit the ability of a customer to linger in the queue after it gives up its deliverability rights. 

The commission said CAISO’s proposals “will improve the accuracy of data about the system, help mitigate reliability issues, enhance the certainty and efficiency of the network upgrade process, ensure that the costs of managing interconnection requests between GIA execution and commercial operation are not allocated to all market participants, and reduce administrative overhead.”  

The new rules become effective Dec. 17.  

Robert Mullin contributed to this article. 

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CAISO Launches New Initiative for Storage Resource Design

CAISO on Dec. 11 kicked off a new Storage Design and Modeling Initiative intended to tackle an array of challenges related to the market participation of storage resources, including further addressing bid cost recovery (BCR) issues and developing a default energy bid (DEB) formula specifically for batteries.  

The initiative piggybacks off the ISO’s prior storage BCR working group, which identified that BCR provisions don’t align with storage resources and led to passage of a proposal to modify the calculation used to determine BCR payments. (See Proposal to Refine Bid Cost Recovery for Storage Passes Unanimously.) 

But several stakeholders, along with CAISO’s Market Surveillance Committee and Department of Market Monitoring, emphasized that the proposal was only a first step in addressing the number of problems identified with storage BCR and their default energy bids.  

The new initiative will delve into previously identified problems, including the need for a holistic redesign of the uplift mechanism for storage and changes to the DEB that reflect the specific characteristics of the resources. It will also introduce new ideas designed to further integrate batteries efficiently into the ISO market, including a proposal to develop a state-of-charge (SOC) mechanism and a way for storage batteries to bid into the market based on their SOC.  

The working group’s effort will be separated into three topic groups: The first deals with BCR, the DEB and outage management systems (OMS); the second covers all topics related to state-of-charge management; and the third deals with distribution-level and paired resource topics.   

Bid Cost Recovery, Default Energy Bid Modification

While CAISO’s completed storage BCR and DEB initiative closed a major market design gap related to existing BCR for storage resources, the ISO identified a further need to address storage assets’ lack of exposure to real-time prices if they deviate from their day-ahead schedules. As a result, the new initiative will seek to redesign the storage uplift mechanism, Sergio Dueñas Melendez, storage sector manager at CAISO, said during the meeting to launch the effort.  

In prior working groups, stakeholders also recommended modifications to the storage DEB and the desire to consider standard approval for storage reference level change requests, which are currently manually processed by ISO staff. Automation and standard approval would provide clarity for market participants, Dueñas Melendez said.  

Lastly, the ISO is seeking to enhance the outage management system (OMS) to align with storage resources, which includes reviewing lower and upper SOC real-time biddable parameter use, clarification of how SOC physical outages impact Pmax and Pmin outages, and improvement of OMS functionality to better support outage submissions from storage assets.  

State-of-charge Management

The ISO is considering developing a “system SOC” mechanism that would track total energy available across the entire storage fleet.  

“Thinking about the fleet holistically may allow better optimization of that storage fleet in critical conditions,” said Dinesh Das Gupta, policy developer at CAISO.  

The system SOC mechanism will work in tandem with how the market operates, so it would be an addition to the system, not a replacement.  

CAISO is also considering developing a “biddable SOC market participation pathway” that would allow energy storage resources to offer charge and discharge bids in relation to their SOC.  

“The vast majority of storage resources participate in the market through the non-generator resource model, which approximates values through megawatt price bid pairings,” Das Gupta said. “A new pathway option centered on bidding at a given SOC may address multiple needs that are currently not found with the non-generator model.”  

Developing this new pathway would take additional time from a policy and technical perspective, Das Gupta highlighted.  

The ISO also highlighted the need to modify the SOC definition and calculation, after determining that resources may face physical constraints not reported to the market that prevent dispatch. Refining how SOC is defined and calculated would improve the ISO’s confidence in a storage resource’s ability to follow dispatch signals during tight system conditions, Das Gupta said.  

The working group will also consider the nonlinearity of a storage resource’s SOC. Non-generator resources are modeled linearly, but energy storage resources have non-linear maximum charging and discharging abilities. Better accounting for this nonlinearity, especially under extreme conditions, may improve storage resource performance, Das Gupta said.  

Finally, the ISO highlighted the need to explore SOC management for capacity awards. The current SOC calculation doesn’t fully model the impacts of capacity awards, particularly for the ISO’s flexible ramping product, which could result in storage resources being unavailable for other commitments, potentially jeopardizing reliability.  

“With the flexible ramping product, we’re seeing potentially serious implications given the price of the product and the high percentage of the product being provided by storage resources,” Das Gupta said.    

Distribution-level Resources

Distribution-level storage assets provide wholesale energy storage to the system via the distribution network rather than through a direct interconnection at the bulk transmission level. These assets fall under both the ISO tariff and the distribution level tariff, and aligning the two would “enhance operational confidence for both resources,” Das Gupta said.   

Additionally, due to significant growth in co-located resources, each with unique parameters and challenges, the ISO is also seeking to explore settlement provisions, including BCR, following increased operational experience with co-located resources.  

The last effort in this topic group seeks to address the lack of a DEB for hybrid resources. Developing a bid for such resources would allow bidding up to the soft-offer cap.  

Next Steps

CAISO expects to release a straw proposal for the initiative in March 2025, with a final proposal slated for July.  

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ERCOT’s Vegas Touts New Reliability Standard

Keynoting the Texas Reliability Entity’s December board meeting, ERCOT CEO Pablo Vegas touted the grid operator’s development of a new reliability standard for the market as “one of [our] more significant” accomplishments. 

He said rather than focus on an outage event’s frequency risk — the loss-of-load expectation, generally set at once every 10 years — as do other grid operators, ERCOT’s reliability standard will measure frequency (one in 10), duration (no more than 12 hours in any event) and magnitude. 

“When you couple or put together all three of those pieces and parts, you have a comprehensive reliability standard that better characterizes what the real risk probabilities are of a grid event and what the impact characteristics would be to consumers in the region,” Vegas told the Texas RE Board of Directors on Dec. 11. 

ERCOT staff are finalizing the magnitude element and working on the various parameters and scenario modeling for the new standard, Vegas said. 

“We want to set it at a level where it’s reasonable to rotate outages should you get into that scenario, so that people who experience a grid-related outage would not have an elongated, continuous outage, but rather would have the opportunity to have power restored as those rotating outages move through different customer groups,” he said. 

The Public Utility Commission approved the reliability standard’s framework in August. Criteria deficiencies are to be assessed at least once every three years, beginning in 2026. The PUC will approve the modeling assumptions and include a public review before the assessment begins. ERCOT is required to develop market design options that address the expected deficiencies.  

“The way this is going to be used effectively, we’re going to now have a yardstick that is going to effectively help us measure how we think the ERCOT market will perform in some period of time,” Vegas said. “I’m really excited to have the first really formal reliability standard in the ERCOT market with the completion of this work.” 

Vegas also briefed the Texas RE on the “remarkable load growth trajectory” ERCOT expects over the next five to 10 years — an additional 65 to 150 GW by 2030 — that could grow the oil-rich West Texas load zone to nearly the size of Houston, the nation’s fourth-most populous city. AI data centers, crypto miners and other large loads have accounted for about 63 GW seeking interconnection to the grid, he said. 

In response, ERCOT is considering 765-kV transmission backbones and trying to add smaller infrastructure as quickly as possible. The continued wave of energy storage and solar facilities is useful in meeting demand during tight periods and providing ancillary services. 

Alluding to the energy transition and thanking Vegas for his presentation, board Chair Jeff Corbett said, “All those of us in this world, we’re reading this every day, but when you come and talk about it, you put it in a nice package that allows us to actually take a step back and go, ‘Crap!’ 

“But I will say that I do sleep OK at night because Pablo is at ERCOT.” 

In other business: 

    • The board endorsed the Nominating Committee’s recommendation that Corbett continue to serve as chair and Suzanne Spaulding as vice chair in 2025.  
    • The Texas RE’s membership has dropped from 125 members to 107. Generation resources account for the bulk of the entity’s members, with 74. 
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LPO Announces $1.25B Loan to Help EVgo Install 7,500 Fast Chargers

The latest billion-dollar loan announcements from the U.S. Department of Energy’s Loan Programs Office are aimed at putting 7,500 new public electric vehicle fast chargers online in the next five years and replacing retiring coal plants in Wisconsin with upgraded hydropower, along with solar, wind and storage projects. 

On Dec. 12, LPO announced the closing of a $1.25 billion loan to EVgo, which is developing a national network of public direct current fast chargers. On Dec. 13, the office announced a conditional $2.5 billion loan to the Wisconsin Electric Power Co. (WEPCO), a subsidiary of the Milwaukee-based WEC Energy Group. 

For its loan, EVgo has committed to deploying 350-kW direct current fast chargers that will be compatible with both SAE J3400 and CCS EV connectors. Previously, only Tesla EVs used the J3400, or North American Charging Standard (NACS), connectors, while other automakers used CCS. However, almost all major automakers have said their new EVs will come with J3400 connectors, beginning in 2025.  

During a Dec. 12 investor call about the loan, CEO Badar Khan said the company would receive the first $75 million of the federal money in January, which should cover an initial deployment of 200 to 300 new chargers. The company expects to be able to cut its installation costs over the course of the five-year loan, which could add 1,600 more fast chargers to the 7,500 that LPO is funding.  

Khan also noted that while Tesla tends to locate its fast chargers near major highways, EVgo’s strategy is to place them in urban and suburban areas “closer to amenities,” which could draw EV owners living in apartments without chargers on site. As automakers produce EVs that can charge at faster speeds, “that will make the use case for DC fast charging more compelling to drivers,” he said. 

The company tries to avoid delays in interconnecting new chargers with a siting plan that includes having two or more potential locations for each new charging station, Khan said. For the DOE loan, 57% of the planned installations already have three or more possible locations, and an additional 15% have two possible locations.  

Khan said expanding the availability of fast chargers is “a key ingredient to the long-term competitiveness and sustainability of the U.S. automotive industry. There is an unmistakable trend towards electrifying transportation across the globe that China is currently winning.” 

The U.S. has about 100 EVs for every DC fast charger, while in China, the number is 50, he said.  

WEPCO

If finalized, the WEPCO loan could replace retiring coal plants with up to 1,650 MW of utility-scale renewable energy and storage projects, which could lower rates for the utility’s customers.  

It also would be the first LPO investment made under the office’s Energy Infrastructure Reinvestment program, funded by the Inflation Reduction Act. The program is designed specifically to help regulated, investor-owned utilities “retool, repower, repurpose or replace energy infrastructure that has ceased operations or enable operating energy infrastructure to avoid, reduce, utilize or sequester air pollutants or greenhouse gas emissions,” according to the LPO website. 

EIR loans also can be used to fund “multiple individual project sites, including individual project components that may be technologically diverse, geographically varied and at different stages of the utility planning and execution process,” LPO says. 

In addition, “EIR projects must demonstrate that the financial benefits received from the [LPO] loan guarantee will be passed on to the customers of, or communities served by, that utility.”  

The first project to be funded under the WEPCO loan could be an upgrade of the 16-MW Big Quinnesec Falls hydropower project, located in the northeast corner of Wisconsin. To finalize the loan, WEPCO will be required to meet specific technical, legal, environmental and financial conditions, according to LPO.  

The EVgo and WEPCO announcements continue the office’s accelerated pace for getting IRA dollars out the door in the final weeks of the Biden administration. On Dec. 3, the office finalized a $303.5 loan to EOS Energy to expand production of its zinc-based, long-duration energy storage technology. A conditional commitment for a second $303.5 million loan followed on Dec. 9 for Project IceBrick, a virtual power plant aggregating power from 193 cold thermal energy storage units installed in commercial buildings across California.  

Developed by Nostromo Energy, the IceBrick cold thermal storage system freezes a water-based solution during off-peak hours when energy is abundant and clean and then uses it to cool buildings during periods of peak demand when electricity is more expensive and may be dirtier. 

Speaking at the U.S. Energy Association’s Advanced Energy Technology Showcase on Dec. 12, LPO Director Jigar Shah said conditional and final loans should be safe from any claw-back attempts by the incoming Trump administration. Existing LPO loan contracts were honored during President-elect Donald Trump’s previous four years in the White House, and conditional commitments are signed contracts. (See Jigar Shah: ‘Loan Programs Office Is Government Doing its Job Well.’) 

As of Dec. 12, in the past four years, LPO had finalized 15 loans and loan guarantees totaling $14.51 billion and 18 conditional loans, totaling $40.24 billion pending finalization.  

According to Shah, the office continues to receive about one new loan application per week and is processing 212 applications requesting a total of $324.3 billion.