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December 17, 2024

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.

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.”

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.” 

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. 

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 non-linearity 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 non-linearity, 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.  

ERCOT’s Vegas Touts New Reliability Standard

Keynoting the Texas Reliability Entity’s December board meeting, ERCOT CEO Pablo Vegas touted the ISO’s development of a new reliable 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 (1 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 GW 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 okay 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. 

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. 

CAISO Monitor: ISO Easily Handled Annual Peak Demand in 2024

CAISO’s Department of Market Monitoring on Dec. 12 reported that the ISO saw “one of the highest demand peaks” in recent years, at 48,353 MW on Sept. 5 — but still well short of the record of 52,061 MW in 2022.

Speaking at the ISO’s Market Performance and Planning Forum, Guillermo Bautista Alderete, the department’s director of market analysis and forecasting, highlighted that the peak was also higher than the California Energy Commission’s forecast of 47,160 MW.

Annual CAISO demand typically peaks in July to mid-September. Besides the 2022 record, this year’s figure marked the highest peak load since Sept. 1, 2017, when demand rose to 50,116 MW. It was also an increase of about 8.6% over last year’s 44,534 MW on Aug. 16.

Monthly resource adequacy showings, which came out to be a little over 53,000 MW, slightly increased from 2023 and were sufficient to cover CAISO’s load plus operating reserves in September. That was “the reason why we didn’t have any tight supply conditions to the extent that we have observed in previous years,” Alderete said.

He also noted that there was a significant decrease in gas-fired generation coupled with a significant increase in storage resources: 3.6 GW compared to 5.5 GW.

“That aligns with the present trend that we have seen of quick penetration of storage resources exceeding the 10,000-[MW] mark sometime in 2024,” Alderete said.

Despite what Alderete described as a relatively moderate September, the ISO did support a “reasonable level” of wheel-through transactions, peaking at just over 500 MW.

September also saw the highest participation in the Assistance Energy Transfer (AET) program since its inception in 2023. Nine balancing authority areas opted into the program, accumulating approximately $720,000 in AET surcharges in August and September.

Calif. Energy Commission Approves EV Charging Plan

California regulators have approved a $95.2 million funding plan for zero-emission vehicle charging infrastructure, with nearly equal amounts going to charging for passenger vehicles and medium- and heavy-duty trucks. 

The California Energy Commission on Dec. 11 approved the funding for the Clean Transportation Program for fiscal 2024/25. The package includes $40 million for light-duty EV charging infrastructure; $38.2 million for medium- and heavy-duty ZEV infrastructure; $15 million in hydrogen-specific funding; and $2 million for workforce development. 

The slightly higher funding amount for light-duty charging infrastructure comes after the program has given more money to medium- and heavy-duty ZEV infrastructure over the years, Commissioner Patty Monahan noted. 

“But this year, given the fact that we really want to make progress on reaching our state goals for charger deployment, we’re leaning in a little bit more on light duty, but with a very strong focus on equity,” Monahan said. 

California will require all new cars sold in the state to be zero emission by 2035. A CEC report finalized this year projects the state will need 1 million public or shared-private light-duty EV chargers by 2030, growing to 2.1 million chargers by 2035. 

The state now has about 152,000 public or shared-private EV chargers, a number expected to grow to about 359,000 when chargers are built with previously allocated funding. 

Charger Types Debated

CEC staff described the funding plan as a high-level view. Specific projects will be selected later through competitive grant solicitations, block grants and in some cases, direct awards or loans. Among the yet-to-be-determined details is how much funding should go to particular types of light-duty EV chargers.  

Bill Magavern with the Coalition for Clean Air made a case for funding Level 1 chargers, which he said could benefit low- and moderate-income drivers living in apartments. “We continue to think that there’s a role for Level 1 charging in providing a really low-cost alternative for some of those multi-family dwellings,” Magavern said. 

On the other hand, Commission Chair David Hochschild noted the importance of DC fast chargers to those who drive for a living. He said one in five Uber rides in California now is in an electric vehicle, compared to one in 10 rides nationally. “Time is money. If they’re stuck at a slow charger, it really impedes their ability to drive electric,” Hochschild said. “Access to fast charging is essential to that sector.” 

Future Funding

Funding for the CEC’s Clean Transportation Program comes from a surcharge on California vehicle registrations. The program also can receive money from the state’s general fund or the Greenhouse Gas Reduction Fund. 

But due to a budget shortfall, those sources did not provide funding to the Clean Transportation Program for fiscal 2024/25. The CEC expects that funding to resume over the next three fiscal years to the tune of $1.3 billion. 

Adding the anticipated state funding to this year’s base funding, the CEC investment plan envisions allocating $1.39 billion through fiscal 2027/28. That would include $659 million for light-duty EV charging infrastructure, $668 million for medium- and heavy-duty ZEV infrastructure, $15 million in hydrogen-specific funding, $46 million for emerging opportunities and $2 million for workforce development. 

The funding plan notes those amounts could change as future budgets are finalized. 

The Clean Transportation Program was created in 2007 through Assembly Bill 118. AB 126 of 2023 extended the program until July 2035 and required that at least half of the program’s funding go toward projects that benefit low-income and disadvantaged communities starting in 2025. 

Since its launch, the program has invested $2.3 billion into projects supporting ZEV infrastructure. As of July 2024, 63% of funds have gone to projects in communities that are disadvantaged, low-income or both. 

“Approval of the investment plan reaffirms California’s commitment to funding zero-emission refueling infrastructure,” Monahan said in a statement after the vote. “There is no doubt — ZEVs are here to stay in the Golden State.” 

MISO, SPP to Revise Joint Agreement, Focus on TMEP Process in 2025

MISO and SPP staff told stakeholders Dec. 13 that they will not perform a Coordinated System Plan in 2025 but will accept transmission issues for their annual review early in the year.

“This next annual issues review will be more of a check-the-box type of exercise than the normal, which would inform our decision to embark on a study in that particular year,” Clint Savoy, SPP manager of interregional strategy and engagement, told members during a meeting of the RTOs’ Interregional Planning Stakeholder Advisory Committee (IPSAC).

“What we’re hoping to do with this process that we’re trying right now would result in updates to the process going forward. I think that’s something we’re going to be considering as we’re looking for ways to enhance the current CSP processes,” he added. “First off, how do we improve on the needs that we’re looking to provide solutions for and make sure we’re looking at the right things? We always consider the transmission issues that our stakeholders submit, and oftentimes those lead to more targeted studies.”

The IPSAC is scheduled to hold its annual meeting March 28, with stakeholders facing a Feb. 26 deadline to submit their issues for review. The meeting is required by the grid operators’ Joint Operating Agreement, as is a CSP every other year.

Five previous CSP studies have failed to produce any joint projects over differences in allocating costs. That led the RTOs to try a different approach with the Joint Targeted Interconnection Queue (JTIQ), which identified a five-project portfolio estimated to cost as much as $1.6 billion that could support up to 29 GW of interconnecting generation along their seam.

FERC approved the JTIQ framework and cost allocation in November, and the Department of Energy in 2023 awarded the portfolio $464 million under its Grid Resilience and Innovation Partnerships program. (See DOE Announces $3.46B for Grid Resilience, Improvement Projects.)

The commission’s approval of the JTIQ process has cleared the way for RTO staffs to revise the JOA language and refocus on their Targeted Market Efficiency Project (TMEP) process. They told stakeholders the new study approach will be much broader and forward looking and will be without predefined, specific historic issues to be resolved.

The RTOs plan to begin the study work in 2025. They are collaborating on a filing timeline and promised a stakeholder review will be shared at the IPSAC’s annual meeting.

The TMEP process was used in the 2022 CSP. It studies smaller, congestion-relieving, cross-border transmission projects already in use between MISO and PJM. (See MISO, SPP Take on 2nd Interregional Planning Effort.)

M2M Settlements Pass $600M

During a meeting of the SPP Seams Advisory Group, also on Dec. 13, staff reported that market-to-market (M2M) settlements with MISO have totaled $604.02 million through October in SPP’s favor.

Under the M2M process that began in March 2015, the grid operators exchange settlements for redispatch based on the non-monitoring RTO’s market flow in relation to firm-flow entitlements. Those settlements have steadily accrued to SPP, topping $100,000 in 2020, doubling in 2021 and doubling again in 2022.

However, the pace has slowed recently as the RTOs have added transmission to relieve congestion along the seam. Cumulative M2M payments exceeded $500 million in December 2023, but they only reached $600 million in October.

The notorious Neosho (Missouri)-Riverton (Kansas) flowgate accounted for $73 million in M2M settlements to SPP, according to a staff report to the SAG in December 2023. That number hasn’t budged since then, an indication that SPP did not have any M2M settlements on the flowgate this year.

“This issue is likely resolved by the transmission construction that occurred in the Neosho area over the last two or three years,” SPP spokesperson Meghan Sever said in an email.