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November 23, 2024

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ISO-NE Sees Manageable Shortfall Risk for Upcoming Winter

ISO-NE projects shortfall risks from extreme weather events to be manageable this winter and expects market mechanisms to provide relief by encouraging fuel conservation and replenishment, the RTO told the NEPOOL Participants Committee on Nov. 7. 

The shortfall assessment modeled “four representative extreme 21-day events” using the RTO’s recently developed probabilistic energy adequacy tool (PEAT). This winter marks the first season ISO-NE has incorporated the PEAT into its seasonal outlook. The modeled events are meant to assess the worst-case conditions for the system, “characterized by periods of extreme cold temperatures, low winds and low solar irradiance.”  

For each event, ISO-NE looked at how varying levels of fuel inventories, fuel prices, generator outages and imports would affect shortfall risks. The modeling showed a limited amount of shortfall associated with the extreme events on average, with a 244,353-MWh 21-day energy shortfall shown for the worst-case scenario, with a 0.000031% probability. 

“ISO expects these shortfalls are manageable and that market-based incentives will provide relief in the form of market response, including the use of opportunity costs in energy offers and fuel replenishment,” said Vamsi Chadalavada, ISO-NE chief operating officer.  

“If necessary, the ISO would implement additional preventive operational measures such as reducing exports [and] scheduling additional imports, seeking waivers of emissions or air permit limitations, [and] conservation appeals,” Chadalavada added.  

According to data from the National Oceanic and Atmospheric Administration, New England faces a 33 to 50% chance of above-average temperatures this winter, with above-average temperatures more likely in the southern part of the region.  

As carbon emissions drive higher temperatures, New England has warmed faster than the global average since 1900, and winter is the region’s fastest-warming season. Last winter featured the warmest December-February stretch on record in the Northeast, while the prior winter featured the third-warmest December-February period.  

ISO-NE projects the winter peak load to be 20,308 MW under average conditions, about 39 MW higher than the RTO projected prior to the 2023/24 winter. ISO-NE’s more extreme 10th percentile forecast projects a 21,089-MW peak. 

Chadalavada said there are “no significant generation or transmission outages” scheduled, adding that current fuel-oil inventories are about 48% of their maximum and the LNG tanks in St. John “are expected to be full heading into the winter.” 

He said the Everett Marine Terminal may be available to meet generation demand but noted ISO-NE has less insight into the availability of the facility after the Mystic Agreement expired at the end of last winter. The facility now is under contract with gas distribution companies. (See Massachusetts DPU Approves Everett LNG Contracts.) 

“Consistent with past winter seasons, the ISO assumes that approximately 3,900 [MW] to 4,800 MW may be at risk due to constrained natural gas pipelines,” Chadalavada added, noting that the RTO will “continue to monitor natural gas deliverability throughout the winter.” 

ISO-NE will have its inventoried energy program in place for the upcoming winter, which compensates generators for keeping up to 72 hours of stored fuel throughout the winter. The RTO has not indicated whether it plans to extend the program beyond the 2024/25 winter. 

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$21.8B Long-range Tx Plan Goes to Membership Vote; MISO Resolute, IMM Protesting

CARMEL, Ind. — MISO members are mulling an advisory vote on whether to support the RTO’s $21.8 billion long-range transmission plan (LRTP) portfolio while tensions simmer between MISO and its Independent Market Monitor over the necessity of the major transmission expansion.  

On Nov. 8, MISO’s Planning Advisory Committee (PAC) took up whether to recommend that the 2024 Transmission Expansion Plan (MTEP 24) — which includes the second LRTP portfolio — proceed to the System Planning Committee of the Board of Directors for consideration. The PAC settled on an email ballot that will be conducted over the next two weeks. A final decision on the LRTP portfolio alongside MTEP 24 is expected from the full MISO Board of Directors in early December.  

Director of Cost Allocation and Competitive Transmission Jeremiah Doner said from a reliability perspective, it’s cost-effective to build the 24-project, mostly 765-kV “regional highway” and confidently avoid future risks rather than building one-off projects to handle vulnerabilities.  

MISO anticipates a benefit-to-cost ratio of between 1.8:1 and 3.5:1 over the first 20 years of the LTRP projects’ lives through reliability improvements, production costs, capacity that won’t be built and environmental benefits. 

“What is happening on the system is unprecedented with the resource transition, and we have a shared responsibility … to be proactive,” Doner told stakeholders. 

MISO’s End-Use Customer Sector asked that this year’s PAC vote on MTEP be a proportional vote, where sectors can divide their votes into a percentage to separately consider the $6.7 billion of traditional MTEP 24 local spending, the $21.8 billion LRTP and the $1.65 billion Joint Targeted Interconnection Queue transmission portfolio in partnership with SPP. MTEP 24 comprises all three. The End-Use Sector said this year’s PAC vote deserves some nuance because of the sheer amount of investment involved.   

MISO’s Independent Market Monitor David Patton capped a campaign against the second LRTP portfolio during a late October meeting of some of MISO’s board members. Patton once again argued that benefits are exaggerated and MISO is not working from a realistic set of future resource assumptions. (See MISO IMM Makes Closing Arguments Against $21.8B Long-range Tx Plan.)  

MISO said it “disagrees that the benefit calculations are flawed, in error or arbitrary.” The grid operator also is resolute that it will not test the value of the LRTP portfolio against a future scenario where it never develops the LRTP projects. 

“The future scenarios used for LRTP are appropriate, and the development of a new resource plan without transmission would be inappropriate,” MISO said. “The objective of LRTP is to understand the value of transmission based on the collective member resource plans as represented in the future. This approach is how MISO and others have performed benefit analysis for regional transmission for more than a decade.” 

Further, MISO formally disagreed with the IMM’s State of the Market recommendation from 2022 to improve the LRTP process and benefit projections. The RTO said it was contradicting its Monitor after extensive evaluation and affirmed its support for the LRTP process. 

MISO said the LRTP and “other transmission planning processes are not in scope for the IMM’s role to evaluate and monitor the performance of the markets.” 

At the October Market Subcommittee meeting, Patton argued that the capacity expansion MISO envisions through the early 2040s and based the portfolio on is “extremely unrealistic” and “not reflective of what the states and utilities say they’re going to do.” He also said MISO continues to overinflate the benefits of the portfolio and pinned the value of LRTP II closer to a 0.3:1 benefit-to-cost ratio. 

“I think we have a major problem here on where we are on LRTP,” he told stakeholders, and advocated for a pause on the process to “come up with a portfolio with benefits that truly justify the costs.” At that point, Market Subcommittee Chair Tom Weeks asked the lMM to focus solely on issues germane to markets. He said the Market Subcommittee isn’t the venue to discuss transmission planning. The exchange was emblematic of some members maintaining that the IMM shouldn’t interfere with MISO transmission planning.  

“I don’t see such a clear distinction between planning and markets because of how they interact with one another,” Patton responded.  

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PJM MIC Briefs: Nov. 8, 2024

PJM Presents Issue Charge on Black Start Compensation

PJM’s Glen Boyle presented an issue charge focused on the potential for compensation for generators providing black start service to fall to zero in net cost of new entry (CONE) values in the 2025/26 Base Residual Auction (BRA). 

The problem statement says the drop in black start compensation would be an unintended consequence of a drop in net CONE that is likely to continue, or continue to go lower, in the following delivery year. Compensation is determined by multiplying net CONE, the amount of black start service provided and a 0.01 modifier for hydroelectric generators or 0.02 for combustion turbines and fuel-assured black start units. 

“This significant drop in revenues for resources on the Base Formula Rate may lead to black start units withdrawing from providing Black Start Service. This could result in reliability concerns or use of the reliability backstop if black start requirements can’t be met,” the problem statement says. 

Since black start is a voluntary service, Boyle said PJM is concerned that without proper compensation, generation may exit the market and leave PJM unable to procure resources for all zones. 

Stakeholders Endorse Expansion of Lost Opportunity Cost Credits for Renewables

The Market Implementation Committee endorsed revisions to Manual 28: Operating Agreement Accounting to include solar, hybrid and energy storage resources in the lost opportunity cost (LOC) credit calculation. The formula was developed for wind generation and is being expanded in accordance with FERC’s approval of PJM’s second phase of its hybrid resource rules (ER23-2484). (See “PJM Presents Conforming Revisions to Manual 28,” PJM MIC Briefs: Oct. 9, 2024.) 

The calculation multiplies the LOC deviation by real-time locational marginal prices, minus the total LOC offer, all of which is then divided into 12 months. The deviation is based on actual forecast output. 

PJM Drafting Second Cluster of CIFP Manual Revisions

PJM’s Skyler Marzewski presented the RTO’s timeline for seeking revisions to several manuals to implement aspects of its capacity market changes drafted through the Critical Issue Fast Path (CIFP) process last year and approved by FERC in January. (See FERC Approves 1st PJM Proposal out of CIFP.) 

The changes include summer and winter capability testing, which would be codified in Manual 18: generation operational testing. That would require revisions to manuals 14D, 18 and 28, and attestation requirements for dual-fuel units, which would come with changes to Manual 11. 

The manual revisions are set to go for first reads and endorsement votes at the MIC and Operating Committee in the first quarter of 2025, with an endorsement vote possible at the Markets and Reliability Committee at its April meeting. The changes are intended to go into effect at the start of the 2025/26 delivery year. 

PJM Details Path Forward on Reactive Power

PJM Assistant General Counsel Thomas DeVita outlined PJM’s plan to remove the reactive power compensation component of the energy and ancillary service (EAS) offset in accordance with FERC’s order that RTOs cannot charge transmission customers for receiving reactive power within a standard range (RM22-2). 

PJM was one of three RTOs granted a longer compliance filing timeline to allow for a transition mechanism for eliminating those revenues from its markets. But the commission specified that removing the reactive component from the EAS offset would need to be done in a separate docket apart from the compliance filing. 

DeVita said PJM plans to seek that change as part of a Federal Power Act Section 205 filing being written to revise the reference resource and treatment of reliability-must-run units in the capacity market. (See “OPSI Speakers Discuss Future Auction Design,” Panels Debate PJM Capacity Market Design at OPSI Annual Meeting.) 

Changes to the Tariff and Consolidated Transmission Owners Agreement would be required and are expected to be effective for the 2026/27 delivery year. 

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MISO Moves to Strike Emergency Demand Response

CARMEL, Ind. — MISO is poised to eliminate its emergency demand response participation option, framing it as a clunky and scarcely used source of emergency assistance. 

“This is an instrument that has been little used … and doesn’t have a lot of operator confidence around it, and therefore it will be retired from the MISO market systems,” MISO’s Mike Robinson said at a Nov. 7 Market Subcommittee meeting.  

MISO established emergency DR around 2007 to better compensate emergency resources. Robinson said emergency DR is called up in the latter stages of an emergency, after load-modifying resources and just prior to involuntary load curtailment. He said emergency DRs are relatively expensive, while load-modifying resources are price-takers and adequately cover MISO’s emergency needs. 

“These are not capacity resources; they’re not obligated to respond to capacity events,” he explained of emergency DRs. 

Robinson said MISO has called on emergency DR just once in its history to manage a transmission emergency from a transformer failure about a decade ago in southwestern Wisconsin.  

Since then, Robinson said, MISO operators occasionally have looked for emergency DR to manage situations but have found none to be available in the moment. Complicating matters, Robinson said a master list of emergency DR resources is maintained in a spreadsheet.  

“Operators have little confidence in them,” he said. “It’s a tool in the tool chest, you might say, but if you don’t use it, why have it?” 

Robinson described emergency DRs by invoking Jean-Baptiste Say’s phrase that “supply creates its own demand” from his 1803 book, “A Treatise on Political Economy; or The Production, Distribution and Consumption of Wealth.”  

MISO hopes to eradicate emergency DRs with FERC permission sometime in the first quarter of 2025. 

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MISO Sets Surplus Reserve Margin Requirement for LSEs Opting Out of Capacity Auction

CARMEL, Ind. — Load-serving entities that decide against participating in MISO’s capacity auction must secure anywhere from 1.5 to 4.2% beyond their reserve margin requirements in the 2025/26 planning year, MISO announced.  

For the upcoming planning year, MISO’s Neil Shah said MISO will impose a 3.1% adder in summer, a 2.1% adder in fall, a 4.2% adder in winter and a 1.5% adder in spring for LSEs staying out of the auction. Those percentages will be in addition to the 7.9% of 2025/26 planning reserve margin in summer, the 14.9% PRM in fall, the 18.4% PRM in winter and the 25.3% PRM in spring. The RTO revealed the values during a Nov. 6 meetup of the Resource Adequacy Subcommittee.  

Starting next year, LSEs that decide to opt out of the auction and sloped demand curve must secure more capacity than strictly necessary to meet MISO’s 1-day-in-10 years system reliability standard. The rule is a feature of MISO’s new sloped demand curve design in its capacity auction. (See FERC Approves Sloped Demand Curve in MISO Capacity Market.) 

The rule — expressed as “X% adders” beyond strictly necessary load obligations — attempts to create comparable treatment between LSEs that participate in the auction and are subject to the sloped demand curve with LSEs that opt out of the auction by assigning them similar reserve requirements. 

The adder is calculated by MISO simulating the additional megawatts that would have cleared had the capacity auction used a sloped demand curve for the past three planning years. Once it has enough actual data to draw on, it will stop using a simulation of clearing behavior.  

Shah said the adder rule makes sure LSEs “bring forward sufficient resources” based on how they would have cleared had they operated under the auction’s sloped curve.  

Load-serving entities and states can exercise an opt-out of the sloped demand curve and auction. For the 2025/26 planning year, those decisions are due to MISO by Jan. 15 and keep LSEs out of the auction for three years at a time.  

MISO’s auction window will open March 26 and close March 31. The grid operator plans to post auction results April 28. Load-serving entities should have submitted their seasonal peak demand forecasts to MISO at the beginning of November; they can expect their seasonal, availability-based capacity accreditation values from the RTO by mid-February.  

Under the new auction setup, states in MISO are free to continue to set their own planning reserve margin that diverges from MISO’s. Should that happen, the RTO would isolate those LSEs’ load share and multiply it by the state’s chosen reserve margin. The LSEs’ final load share then would be removed from MISO’s planning reserve margin requirement. LSEs that still rely on MISO’s PRM will share the remainder of the requirement, spread pro rata.

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MISO in Agreement with IMM’s State of the Market Recommendations, Work Begins on 1

CARMEL, Ind. — MISO this year said it generally agrees with the six new market recommendations brought forward in its Independent Market Monitor’s annual State of the Market report and is working on one of them.  

Independent Market Monitor David Patton has debuted six market recommendations. (See MISO Monitor Spotlights Congestion Fixes, Market Mismatches in 2023.) He said MISO should: 

    • Develop a means to decommit resources that were committed in the day-ahead market. 
    • Create procedures outlining when it’s appropriate for its operators to derate transmission constraints to manage congestion. 
    • Require generation owners to fill out the reasons behind outages or outage extensions in the ticketing system the RTO uses to track scheduling.  
    • Use demand curves at the zonal level to better model demand in its local resource zones and produce more accurate local clearing requirements in capacity auctions.  
    • Align its definition of aggregate pricing nodes between its financial transmission rights (FTR) market and real-time and day-ahead markets. 
    • Enforce requirements for MISO’s 30-minute reserve product so it’s used instead of out-of-market actions to solve shortages.  

Of all this year’s new recommendations, MISO said it agrees most strongly with the suggested better guidance on when operators should derate transmission to manage congestion.  

“MISO is actively working on improvements to operators’ tools and procedures related to constraint management, including for out-of-market actions. Procedures will be revised as needed to offer further guidance to operators while maintaining operational flexibility,” MISO Director of Market Design and Development Zhaoxia Xie said at a Nov. 7 Market Subcommittee meeting.  

However, MISO said it would defer any action on creating individual downward-sloping demand curves for the 10 local resource zones in its capacity auction.  

MISO said though there might be value in fashioning separate sloped zonal demand curves, it’s going to do more evaluation on the IMM’s proposed solution.  

On the other hand, Xie said MISO is working in concert to synchronize the definitions of the aggregate pricing nodes and “minimize the gap” between the modeling for its FTR market and real-time and day-ahead markets. 

MISO similarly plans to collaborate with the IMM on possibly developing a means to recommend the decommitment of resources committed in the day-ahead market. However, Xie added that MISO members currently enjoy the financial and operational assurances they get in the day-ahead market while benefiting from being able to adjust offers in the real-time market to meet “their economic and operational needs.” 

As for gathering more detailed descriptions of the reasons behind generation outages, Xie said MISO recently dropped the ‘other’ option from its dropdown menu in its outage reporting software for members. She said MISO will do more to collect explanations for outages.  

“MISO plans to evaluate changes to the outage submission rules that ensure needed information is provided when tickets are submitted or updated,” Xie said.  

Finally, MISO said it plans to investigate how it can enforce short-term reserve requirements in load pockets. Xie said MISO shares the IMM’s concerns about operators increasingly using out-of-market commitments to “satisfy voltage and local reliability requirements in key load pockets.” 

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PJM OC Briefs: Nov 8, 2024

Stakeholders Endorse Quick Fix Solution on Day Ahead Scheduling Reserve Calculation

The Operating Committee endorsed a quick fix proposal to revise Manual 13: Emergency Operations to add transparency to the Day Ahead Scheduling Reserve (DASR), a figure that is calculated annually to determine when the 30-minute reserve requirement may be insufficient and emergency procedures necessary. 

The quick fix process allows for an issue charge to be voted on concurrent with a proposed solution. (See “Quick Fix Proposal on Day Ahead Schedule Reserve Calculation,” PJM OC Briefs: Oct. 10, 2024.) 

The 30-minute reserve requirement is set at the greater of the primary reserve requirement, active gas contingency or a flat 3,000 MW, which PJM has argued is not flexible and does not account for operational risks. An earlier proposal to shift to a requirement based on load forecast error and forced outage rates was rejected by stakeholders in July. (See “Stakeholders Endorse Reserve Rework, Reject Procurement Flexibility,” PJM MRC Briefs: July 24, 2024.) 

The DASR is the sum of the three-year average underforecast load forecast error (LFE) and generator forced outage rates (FOR), which currently results in a 74,257-MW peak load threshold after which 30-minute reserves are considered inadequate.  

The manual revisions are intended to clarify how operators use DASR. No change is proposed to the functioning of 30-minute reserves. They are set to go for a first read at the Markets and Reliability Committee (MRC) on Nov. 21, followed by a vote Dec. 18. 

PJM Presents Revisions to Manual 1 Addressing Hybrid Resource Rules, Loss of EMS Real Time Assessment

PJM presented a quick fix proposal to revise Manual 1: Control Center and Data Exchange Requirements to clarify its communication processes and data collection protections. The language is scheduled to be voted on at the Dec. 5 OC meeting and, if endorsed, at the Jan. 23 MRC meeting. 

The changes would add more detail to its backup communication methods to be used in the event of widespread SCADA software outages, as well as alternatives ways of conveying data to PJM during a SCADA outage, such as a cyberattack. The package also includes clarifications around PJM’s view-only mode to protect Inter-Control Center Communications Protocol (ICCP) data from potential errors during planned maintenance. 

The RTO also first read a set of revisions to Manual 1 identified through its periodic review, which would update several definitions to be more precise and consistent with other manuals. The language also includes requiring that the state of charge be conveyed by SCADA for open-loop hybrid resources, a requirement that already stands for close-loop hybrids.  

PJM Seeks Advance Notice of Expected Maintenance Outage as RTEP Upgrades are Scheduled

PJM is requesting that generation and transmission owners increase coordination around planned outages while a significant number of transmission assets are taken offline to build upgrades under the RTO’s 2023 Regional Transmission Expansion Plan Window 3. The work ramps up in 2026 and continues through 2030, with the number of outages exceeding 30 in some months. 

Transmission owners are asked to review planned outages for conflicts with the scheduled upgrades, provide PJM with a preferred timeline for their outages and fill out the RTO’s Prioritization Scoring Matrix. Quarterly meetings are being held with transmission owners and developers within the six zones affected by the RTEP projects to bolster the coordination efforts. 

On the generation side, any units in the BGE, PEPCO, Dominion and surrounding regions with outages expected over the next two to three years are asked to provide advanced notice as early as those outages can be foreseen. PJM’s Joe Rushing noted that generation outages require only a 30-day notice. The extent of the transmission work that will be conducted will limit the number of generators that can be taken offline at a given time.  

Congestion and increased use of emergency procedures, such as post contingency local load relief warnings (PCLLRWs), are likely throughout the duration of the RTEP work. 

October Operating Metrics

Presenting the October operating metrics, PJM’s Marcus Smith said October saw both hourly and peak load forecast error fall below the 25-month averages, with an hourly rate of 1.32% and peak forecasts off by 1.46% across the month. Underforecasts exceeding PJM’s 3% error rate benchmark were seen Oct. 3 and 6, while overforecasting was seen Oct. 22 and 31. 

The month saw one spin event Oct. 22 that lasted 6 minutes and 11 seconds and a generation response rate of 95% and demand response (DR) deployment at 151% of dispatch. One shared reserve event, two high system voltage actions and 16 PCLLRWs were implemented in October as well.  

Security Briefing

PJM Director of Enterprise Information Security Jim Gluck said the FBI is warning that renewable generation increasingly is being targeted by attacks to steal technology, render systems inoperable for ransom and disrupt generation operations. 

The Infrastructure Information Sharing and Analysis Center (ISAC) has published a research paper detailing several threats to infrastructure in the leadup to the November 2024 elections, including “hacktivist” attacks and state-sponsored actors. As a precaution, PJM implemented a conservative operations procedure the night of Nov. 5 through midnight the following day. 

“While PJM has received no indication of credible threats to the power grid at this time, our government partners have encouraged the industry to remain alert to an elevated risk environment. Out of an abundance of caution, … PJM … will establish a more conservative posture,” the alert stated. 

The RTO also is monitoring the possible impact of a breach at Schneider Electric, where about 40 GB of records were compromised and could be released to the public if a ransom is not paid. 

Gluck recommended that members ensure employees use multifactor authentication and default passwords are not used. 

PJM Presents 2024 Winter Study

PJM’s Mark Dettrey presented the 2024/25 Winter Study prepared by the Operations Assessment Task Force (OATF) to evaluate the risk landscape for the season. While some switching, phase angle regulator (PAR) adjustments and re-dispatch may be required to address transmission violations, no reliability issues were identified under the 50/50 or 90/10 load forecast studies. (See PJM OC Briefs: Oct. 10, 2024.) 

The report expects 177.6 GW of cleared capacity and fixed resource requirement (FRR) resources will be available, as well as 2.2 GW of resources that historically have been available under the study conditions. It assumes 5.5 GW will be exported under the scenario analyses, 18 GW of generator outages and 7.1 GW of load management being deployed. 

The RTO is projected to maintain an 8.7-GW reserve margin under the low wind and no solar scenario, which reduces available generation by 3.1 GW. That margin shrinks to 7.1 GW under the largest gas/electric contingency, which would take 4.7 GW of generation offline. 

The report also included a scenario developed on experiences during December 2022 Winter Storm Elliott, increasing forced outages to 46 GW, which would lead to a reserve margin deficiency of 13.8 GW. The scenario is not included in the reliability analysis but was developed as a numbers game to be informative. 

Other Committee Business:

PJM’s Pete Langbein presented the 2023/24 Load Management Event Summary, which showed that emergency and pre-emergency DR performance was “very good, well north of 100%” across the delivery year. While there were no events requiring load management deployment, testing showed a 122% response rate reflecting 1,614 MW in overcompliance. 

Stakeholders endorsed revisions to Manuals 3 and 10 drafted through the documents’ periodic review. The changes to Manual 3: Transmission Operations include language to reflect existing practices on facility ratings, shifting which section details Automatic Remediation Action Scheme (RAS) operating criteria, and updating several notes and links. 

The Manual 10 language clarifies how the quantity of energy offline during an outage should be reported for inverter-based resources in eDART and more explicitly states that forced outages must be completed before work can begin on a planned outage. 

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Newsom Convening Legislature to Protect California ‘Values,’ Policies

California Gov. Gavin Newsom is convening a special session of the state legislature to take steps “to safeguard California values” — including the fight against climate change — ahead of President-elect Donald Trump’s second term. 

In a proclamation issued Nov. 7, Newsom (D) said he wants lawmakers to consider additional funding for the state Department of Justice and other agencies so they can quickly challenge actions taken by the Trump administration. The special session will begin Dec. 2. 

“The consequences of his presidency for California may be significant and immediate,” Newsom said in the proclamation. 

Those consequences include potential actions such as dismantling clean vehicle policies “that are critical to combating climate change,” the proclamation states.  

Another concern is that Trump will block federal disaster response funding to California as political retribution. During his campaign, the former president threatened to withhold wildfire aid to the state if Newsom didn’t back his policies. 

Newsom also wants to fend off potential Trump administration attacks on reproductive freedoms and immigrant families in California. 

Past Experience

During Trump’s first term as president, California filed more than 120 lawsuits challenging actions taken by his administration. Newsom said he’s been working with the attorney general’s office for over a year to prepare for the possibility of a second Trump term. 

The additional funding Newsom seeks would help ensure the state can file litigation immediately and seek injunctive relief against federal actions. 

“We’re working closely with the governor and the legislature to shore up our defenses and ensure we have the resources we need to take on each fight as it comes,” California Attorney General Rob Bonta (D) said in a statement. 

The fight against climate change has strong support in the state. Voters on Nov. 5 passed Proposition 4, a $10 billion climate bond measure to fund wildfire programs, clean energy and other projects. (See Calif. Lawmakers Send $10B Climate Bond Measure to Nov. Ballot.) 

“This result demonstrates voters want California to be at the forefront of climate action because our health, lives and livelihoods are at risk,” Katelyn Roedner Sutter, the Environmental Defense Fund’s California state director, said in a Nov. 6 statement.  

Waiver Battle

California’s zero-emission vehicle regulations are a key concern for the state under the new Trump administration. In 2022, the state adopted rules banning the sale of new gas-powered cars in 2035; the sale of new diesel trucks will be prohibited starting in 2036. 

California may set its own zero-emission vehicle and tailpipe emission standards instead of implementing federal standards under a provision of the federal Clean Air Act. The state must submit its emission rules to EPA and receive an EPA “waiver of federal preemption” before a rule may be enforced. 

Other states have an option to adopt California emission regulations rather than follow federal standards. 

California’s right to set its own standards was revoked in 2019 during Trump’s first term, and then reinstated in 2022 under the Biden administration. The reinstatement was challenged by Ohio and 16 other states along with oil and gas interests. A federal appeals court rejected the challenge in April 2024. 

In 2020, while California’s emissions waiver was suspended, six automakers entered into voluntary agreements with the California Air Resources Board (CARB) to reduce greenhouse gas emissions of their vehicles each year through 2026 and speed the transition to zero-emission vehicles. 

Stellantis entered into a similar agreement with CARB in March 2024. 

CARB also made a deal with truck manufacturers in July 2023 called the Clean Truck Partnership. In exchange for CARB giving manufacturers more flexibility to comply with its regulations, the truck makers pledged to meet California’s vehicle standards, including a requirement to produce and sell only ZEVs starting with model year 2036.  

The manufacturers agreed to stick with their commitment even if the regulations face legal challenges and regardless of CARB’s overall authority to implement those regulations. (See CARB, Manufacturers Partner to Support Clean Truck Rules.) 

Airline Partnership

California continues its trend of voluntary agreements with industry. On Oct. 30, CARB announced an agreement with Airlines for America, which represents almost a dozen major airlines, regarding increasing the availability of sustainable aviation fuel. 

CARB and Airlines for America will work to ensure that at least 200 million gallons of cost-competitive, sustainable aviation fuel is available to airlines in the state by 2035. 

The amount would meet about 40% of intrastate travel demand and is a more-than-10-fold increase from current levels, CARB said. 

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Proposal to Refine Bid Cost Recovery for Storage Passes Unanimously

The CAISO Board of Governors and Western Energy Markets Governing Body on Nov. 7 unanimously passed a proposal to modify the calculation used to determine bid cost recovery payments for storage resources.  

The product of four months of intense stakeholder engagement, the proposal aims to address what ISO staff and stakeholders identified in 2022: that BCR provisions for storage resources don’t align with the intent of BCR. (See CAISO Proposal Seeks to Refine Storage Bid Cost Recovery.) 

The initiative, which kicked off in July, identified 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 their combined BCR and market payments. 

Resources receive BCR payments when market revenues don’t cover the resource’s bid costs, such as startup, minimum load and transition costs. BCR also incentivizes resources to follow dispatch and bid efficiently by removing risk if the dispatch doesn’t cover costs.  

But bids for storage resources are largely driven not by the cost to produce energy in a given interval, but rather by their state-of-charge limits. The ISO noted that a combination of ancillary service awards or self-provisions for regulation-down in the real-time market, coupled with relatively high energy bids, resulted in unusually high BCR payments to storage resources.  

The final proposal recommends revising the calculation of real-time BCR for storage resources by basing the bid cost on an alternative to eliminate the opportunity for strategic bidding that inflates BCR.  

For resources dispatched up, the alternative would be the minimum of the bid and the maximum of three alternatives: the real-time default energy bid, the real-time market-cleared price, or the day-ahead market-cleared price. For resources dispatched down, the alternative would be the maximum of the bid and the minimum of the three alternatives.  

‘An Incomplete Approach’

In an opinion published Nov. 1, CAISO’s Market Surveillance Committee (MSC) agreed with the proposal, but indicated it should represent only a first step. 

“We definitely agree with the ISO and the Department of Market Monitoring that there are important incentive problems that can result in both significant financial transfers that we believe are unearned in the form of excess bid cost recovery and, very importantly, market inefficiencies in terms of insulation from incentives that real-time prices are supposed to provide,” MSC Chair Ben Hobbs said in a Nov. 1 meeting. 

The first goal should be to eliminate BCR “phantom losses” that result from including resource charging bids and discharge offers in the BCR calculation.  

“We believe that this goal is likely to be partially but not completely accomplished by implementation of the ISO proposal,” Hobbs said.  

The ISO’s Department of Market Monitoring (DMM) also showed cautious support of the proposal, viewing it as an interim solution that didn’t fully address both concerns.  

According to Adam Swadley, DMM manager of market policy and analysis, the proposal targets the bid cost component of the BCR calculation by limiting bids used in the real-time BCR calculation but does not affect the revenue portion, allowing storage operators to remain insulated from real-time prices.  

“DMM does not oppose management’s proposal. However, we do view it as an incomplete approach that does not address the underlying efficiency issues of the current BCR rules applied to batteries, and therefore we strongly encourage the ISO to immediately continue working with stakeholders to develop a more complete and effective solution for the fundamental problems,” Swadley said. 

The ISO is kicking off a new storage design and modeling initiative next month to continue addressing the first concern related to real-time prices.  

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CAISO, WEM Boards Approve Pathways ‘Step 1’ Tariff Amendments

CAISO’s Board of Governors and Western Energy Markets (WEM) Governing Body on Nov. 8 approved ISO tariff amendments needed to implement the West-Wide Governance Pathways Initiative’s “Step 1” proposal, which would refine four key characteristics in the governance documents and the tariff.  

The proposal seeks to elevate the power of the Governing Body by granting it “primary” authority over rule changes affecting CAISO’s Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM), compared with the “joint” authority it currently shares with the ISO board.  

The tariff amendments will modify the markets’ dispute resolution process to include a dual filing option and augment language considering the public interest. (See CAISO, WEM Boards Approve Pathways ‘Step 1’ Plan.)  

When they approved the Step 1 proposal in August, the ISO and WEM boards directed CAISO to prepare revisions to governing documents for later approval. Implementing the changes would require amendments to three governing documents and a section of the tariff.  

Changes to the charter for EDAM and WEIM governance include:  

    • Adding refinements to the mission of the WEM Governing Body as it relates to considering the public interest and respecting state and local authority.
    • Revising the process for approving tariff amendments within the shared authority from the joint authority to the WEM Governing Body having primary authority, with approved amendments being placed initially on the consent agenda of the ISO board. 
    • Revising the dispute resolution process to add a dual filing with FERC as a possible means of resolving a sustained disagreement between the two bodies. 
    • Adding that the WEM Governing Body may initiate a review of governance if a majority of EDAM entities announce plans to leave EDAM.

      Section 6 of the charter, which established the WEM Body of State Regulators, will be amended to clarify that the BOSR can provide opinions to FERC regarding any proposed tariff amendment within the scope of the Governing Body’s authority.        

Additionally, references to “joint authority” will be revised to say “primary authority” in the corporate bylaws and decisional classification guidance for the WEM Governing Body. Tariff language also will be amended to enable dual filing.  

The changes won’t occur until a trigger mechanism is enabled, which is achieved when utilities outside of CAISO’s balancing authority area representing equal to or greater than 70% of the ISO’s load have executed EDAM agreements. To avoid uncertainty about when the changes go into effect, management added a step that requires revised documents to become effective upon certification by the ISO’s CEO or COO.  

While the trigger isn’t expected to be enabled until sometime in 2025, the ISO seeks approval of the changes now to allow time for FERC to issue an order on a tariff amendment.