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November 14, 2024

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New Wash. Law Seeks to Accelerate Electric School Bus Adoption

Washington is poised to start significantly phasing in electric school buses after lawmakers approved a bill directing the state’s Department of Ecology to manage a program to help school districts convert their diesel fleets. 

But that might take decades: Washington has 10,460 school buses, but only 76 are electric. 

And the price tag? Still up in the air. Ditto with where the bulk of the money will come from. 

The reason for doing this? To cut the pollution getting into kids’ lungs.  

“It is as much about healthy kids as it is for the environment. … I understand the anxiety about this big change, but we can’t wait any longer. Our children’s future depends on this,” said Rep. Tana Senn, D-Mercer Island, who introduced House Bill 1368 to foster the switch from diesel to electric school buses.  

Washington is following the lead of New York, which has required school districts to purchase only electric buses starting in 2027 and convert their fleets by 2035. 

Diesel exhaust hovers around stopped buses, with children more susceptible to the effects because they breathe 50% more air per pound of body weight than adults, according to EPA and the National Institutes of Health. The fumes contain particulates that can lead to asthma and lung cancer. Diesel exhaust from school buses potentially affects one-third of U.S. students, their parents and educators each day. 

A Natural Resources Defense Council study concluded that a child riding inside a diesel school bus may be exposed to up to four times the level of diesel exhaust as someone riding in a car ahead of it. Exposure levels were higher in the back of the bus and when windows were closed. The study said children exposed to diesel exhaust while riding in a school bus for one to two hours a day, 180 days a year for 10 years might result in 23 to 46 additional cancer deaths per 1 million children. 

“I’m shocked and frustrated. I was exposed to unhealthy fumes just to go and from school,” Sarah Lo, a 17-year-old Seattle student, said at a Feb. 24 hearing on the bill before the Senate Ways and Means Committee.  

Relaxed Timetable

The Democratic-controlled Senate on March 7 passed HB 1368 along party lines. The bill will require the Ecology Department to manage grants to school districts to help replace their old diesel buses with electric buses, with funding priority for low-income districts. The districts will be required to buy electric buses when the total cost of owning such buses — which included buying and operating the buses and building the charging infrastructure — drops below the total costs for operating diesel buses. When that parity will be achieved is still an open question. 

The bill also requires the Office of Superintendent of Public Instruction to survey the state’s 295 school districts about how to proceed with adopting zero-emission buses. 

The House approved the amended bill March 6 along party lines. The main change eliminates a timetable to start a gradual but serious transition in 2027, substituting a more open-ended replacement schedule based on when it makes more financial sense to replace the buses. The expectation is that the total costs of buying and operating an electric bus will shrink over the years, Senn said.  

Currently, the average price of an electric school bus is $412,907, compared with $142,154 for a diesel or gas bus, OSPI said in an email to NetZero Insider. 

“This is to move it forward if and when we can move it,” Sen. Lisa Wellman (D) said during a March 1 Senate floor vote. 

Speaking during the same vote, Sen. Brad Hawkins (R) said, “The state is trying to get its tentacles in [school board business]. … This bill is like the Washington Legislature trying to become the local school board’s transportation director.” 

The state budget for fiscal 2024/25 includes $50 million in revenue from the state’s cap-and-invest program to go to economically disadvantaged school districts to immediately begin the transition. “We’re focusing first on those overburdened communities,” Senn said.  

‘Easier Said Than Done’

The changes in HB 1368 reflect concerns raised by school districts and OSPI on Feb. 24 as the bill went through the Senate. Several school officials favored the health and environmental benefits but worried about the originally proposed tight timetables, the massive need to install charging equipment and retrain mechanics to handle electric buses, and the challenge of finding all the money needed to accomplish these tasks. 

OSPI has not yet determined transition timelines for the revised bill, nor has it calculated overall cost estimates for a long-term, statewide transition.  

At the Feb. 24 hearing, Jon Holmen, superintendent of the Lake Washington School District, noted that his school system has more than 130 buses and replaces 10 per year. “Unfortunately, transitioning to electric buses is easier said than done. … We are ready and willing to do the transition, but we can only do so through a partnership and with ample support from the state.” 

“We want to make sure it works,” Mike Hoover, a lobbyist for the Washington State School Directors Association, said at the hearing. “We’ve had technologies overpromised before, and we hope this is not another taste of that.”  

Paul Marquardt, executive director of operations for the Bethel School District, said a typical bus run in his district is about 80 miles. “We would not be able to complete a run with an electric bus,” he said at the hearing. 

OSPI said small buses have an average range of 45-55 miles, while large buses can cover 70-90 miles. 

Senn said the legislation allows school districts to keep enough diesel buses to handle routes that are longer than the range of an electric bus. She expects electric bus ranges to increase as the technology improves. 

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PJM PC/TEAC Briefs: March 5, 2024

Planning Committee

Stakeholders Long-term Regional Transmission Planning Proposal

VALLEY FORGE, Pa. — The Planning Committee endorsed PJM’s long-term regional transmission planning (LTRTP) proposal during its March 5 meeting, advancing manual revisions that would expand the RTO’s planning horizon to 15 years. (See “PJM Presents Long-term Planning Proposal,” PJM PC/TEAC Briefs: Jan. 9, 2024.) 

The changes are centered around two base cases focused on reliability needs eight and 15 years out; two policy scenarios looking at new entry backed by state legislation eight to 15 years in advance; and an additional policy scenario including higher generation entry not backed by signed legislation. The two-year planning cycle would be extended to three years because of the increased number of scenarios. The proposal was endorsed by the PC with 66% support, setting it on a path to undergo a first read at the Markets and Reliability Committee on March 20 with an endorsement vote possible April 25. 

Thermal and voltage analyses would be performed on the eight-year base scenario, replacing the existing 10-year model for voltage analysis, and would then inform the five-year Regional Transmission Expansion Plan (RTEP) near-term process. Thermal and voltage analysis would also be performed on the 15-year scenario. 

PJM’s Michael Herman said staff continue to view the RTEP process as focused on ensuring reliability through a holistic approach, and the new process would enhance the existing rounds of analysis by considering the impacts of a wider range of generation scenarios. He said there is potential for the policy scenarios to influence the scope of projects that PJM recommends be added to the RTEP, though more stakeholder discussions are needed to flesh out the process. 

“This is something PJM will have to continue to evaluate and discuss with stakeholders … but the way that PJM envisions this [is that] we can’t be performing the reliability base case in a silo,” he said. 

PJM Vice President of Planning Paul McGlynn gave the example of the reliability scenarios recommending the construction of a new line and the policy scenarios suggesting designing the line with a higher voltage. He said the policy analysis could also lead to PJM preferring expandable solutions. 

Paul McGlynn, PJM | © RTO Insider LLC

PJM’s Jonathan Kern said the distinction between the reliability and policy scenarios would allow the RTO to continue to follow cost-causation principles, adding that the planning process would first identify projects needed for reliability; anything needed to support assumptions beyond that would be allocated as State Agreement Approach projects. 

Paul Sotkiewicz, president of E-Cubed Policy Associates, said the proposal doesn’t follow market principles and would grant the RTO a power akin to developing its own integrated resource plans. He also argued that the quick-fix stakeholder process used to develop the proposal hasn’t allow for adequate stakeholder analysis of the impact the proposal could have. The quick-fix process allows for an issue charge to be brought concurrent with a proposed solution. 

“This is PJM having too much discretion about investments in our assets, whether they’re existing or potentially new,” he said. 

Stakeholders also questioned whether PJM has the authority to implement the changes through manuals revisions alone, arguing that revisions to the governing documents and FERC filings are necessary. 

Transmission Expansion Advisory Committee

PJM Updates RTEP and Market Efficiency Window Schedule

PJM is planning to open a 30-day RTEP window March 12 as part of the 2023 RTEP to address growing data center load in Columbus, Ohio, which is part of the AEP transmission zone.  

PJM’s Wenzheng Qiu told the Transmission Expansion Advisory Committee that there also are thermal violations identified in the PSEG zone around its Hinchmans substation and that the 500-kV Fentress-Yadkin line in the Dominion zone is nearing end of life. 

The window is shorter than the typical RTEP process because of the immediate-need nature of the violations. Qiu said the earliest PJM is likely to do a first read on projects it may recommend from the window is June. 

The RTO has completed the base case assumptions for the 2024/25 market efficiency cycle and is planning to open a competitive window in January 2025 to address congestion on several lines, PJM’s Nick Dumitriu told the committee. He said much of the new congestion identified since the previous base case is driven by changes in the load forecast, changing market conditions and the RTEP upgrades approved by the Board of Managers. 

Supplemental Needs and Project Proposals

FirstEnergy presented a project to replace two 230/46-kV transformers at its Yeagertown substation in the Penelec transmission zone because of their age and increased risk of failure. The cost to replace both is estimated to be about $7.5 million. Completion of the project is expected by Oct. 17, 2025. 

Also in the Penelec zone, the utility said there is a need to replace three segments of its 345-kV transmission corridor between the Erie West and Armstrong substations. The line was constructed more than 50 years ago and is experiencing deterioration of wooden H-frame structures. Sections of the corridor, which intersects with the Handsome Lake and Wayne substations, have experienced multiple unplanned outages since 2015. 

FirstEnergy also presented a proposal to replace three 500/138-kV transformers at its Cabot substation in the APS zone for $24.6 million. The transformers are nearing their end of life and seeing elevated maintenance issues. The transformers would be replaced on a staggered timeline, with the first installation slated to be completed by Dec. 31, 2027, and the third by June 30, 2028. 

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PJM MIC Briefs: March 6, 2024

VALLEY FORGE, Pa. — The Market Implementation Committee voted March 6 to endorse a PJM proposal to revise its approach to measuring and verifying the capacity provided by energy efficiency resources. (See PJM Seeking Expedited Approval of Energy Efficiency Changes.) 

PJM’s Pete Langbein said the proposal aims to clarify which baseline EE providers should use to measure the savings a resource can offer into a Base Residual Auction (BRA); require that they demonstrate to PJM that installations of the more efficient equipment was completed; and show they have exclusive rights with the owner of the equipment to enter its savings into the capacity market. 

The PJM proposal received 52% support, winning out over packages sponsored by CPower and Affirmed Energy, which respectively received 26% and 4% support. The question of whether stakeholders preferred the PJM proposal over the status quo originally tied, but multiple stakeholders cited challenges casting their ballots. The committee opted to reconsider the item, and support for the package grew to 61%. 

The changes are being brought under an expedited process with the aim of receiving stakeholder approval in time to implement for the 2025/26 BRA, scheduled for July. Redlines were first presented at the Feb. 22 Markets and Reliability Committee, where several stakeholders argued that the proposal is moving too quickly to ensure that it’s understood by market participants and fully vetted to prevent unintended consequences. 

The proposal would draw a sharper distinction between the standard baseline — which considers the last efficient equipment that could be installed versus the product being installed as an EE resource — and the current load baseline — which requires there be a cause-and-effect link between the revenues EE resources receive through the capacity market and their participation in the BRA. If a resource is eligible to use the current load baseline, the proposal would set a three-year limit on technical reference manuals (TRMs) to measure the load of the new equipment against; if no TRMs were available, EE providers would be required to use meter data. 

Independent Market Monitor Joe Bowring said PJM’s proposal does not go as far as he would like in tightening EE standards but that it would nonetheless improve market functionality. As he often does, Bowring noted that EE is not a resource in PJM’s capacity market and argued that it should not be paid through the capacity market. 

Affirmed’s Luke Fishback and CPower’s Ken Schisler raised issues they said would prevent EE providers from complying with the proposal. They argued that the three-year limit on TRMs would disqualify the majority of those produced by PJM states. Their companies had offered longer windows in their own packages. 

Langbein told RTO Insider that older TRMs may include equipment that is no longer representative of what is being installed in that region, possibly leading to an inflated baseline. 

Bowring said a five-year TRM may include data from at least three years prior to the TRM date and that the eight-year-old results are then used to estimate savings for four years into the future. The baselines even for a three-year-old TRM are not relevant to any actual savings, he argued. 

Schisler said PJM’s language requiring a causal link between capacity market participation and the revenues it offers comes from an understandable desire to ensure that capacity revenues are producing a reduction in load. But he argued the proposal is too strict and would exclude projects from participating in the market if they have multiple benefits, including capacity revenues. At the February MRC meeting, he gave the example of a project to improve home insulation that would reduce climate control load while also alleviating health issues from building materials exposed to humid air. 

Bowring said the fact that EE providers assert that there does not need to be a link between the wholesale PJM capacity market and the assumed savings for which customers pay $100 million per year demonstrates why EE should not be paid through the capacity market. He argued that the market is not intended as a vehicle to subsidize broader social goals. 

Fishback said Affirmed’s proposal was aimed at taking a more data-driven approach to the question of how often TRMs are updated and would have included updates to PJM’s attestation requirements, the way they verify installations and how they verify unique ownership of capacity rights. He said PJM’s language would likely prove especially onerous incentivizing adoption of efficient products through retailers. 

“This language as written in the redline runs the risk of taking the vast majority of utility programs and removing them from the table, because the majority of them are run through retailers and retailers will not be able to get an address for each lightbulb they sold,” he said. 

Fishback also argued that the changes are being made too quickly without any apparent need ahead of the next auction. He motioned to defer the vote to the April MIC meeting, arguing that the three proposals were similar in many ways and more time could allow for a compromise to be found. The motion failed with 57% in opposition. 

1st Read of Proposal on Capacity Obligations Resulting from Large Load Additions

Dominion Energy and American Electric Power presented a joint proposal to accurately assign the capacity obligations from large load additions (LLAs) to entities within a transmission zone, including entities operating under fixed resource requirement (FRR) and Reliability Pricing Model (RPM) rules. (See “Capacity Obligations for Forecasted Large Load Adjustments,” PJM MIC Briefs: Oct. 4, 2023.) 

When bringing the issue charge, AEP’s Josh Burkholder argued that the data center growth can lead to the obligation to procure capacity to serve that load being split between market participants in a transmission zone even when the load falls entirely within one’s footprint. 

In February, FERC granted AEP a waiver of the capacity obligation for four of its vertically integrated utilities to not include about 1,860 MW of data center load expected in AEP Ohio (ER24-545). The waiver is applicable for only the 2025/26 auction; in its filing, AEP noted that a stakeholder process had been initiated to consider changes to how capacity obligations for large load additions are calculated. (See FERC Grants AEP Utilities Waiver of Capacity Obligation.) 

Dominion has submitted a similar waiver request, though Old Dominion Electric Cooperative (ODEC) and Northern Virginia Electric Cooperative (NOVEC) have protested, arguing that the circumstances around the Data Center Alley in Northern Virginia differ from those AEP faced in Ohio (ER24-1037). 

The proposal would exclude LLAs from the calculation of base zonal scaling factors and apply that load to the obligation peak load (OPL) of the zone it is projected to be added to. LLAs are determined by PJM using information from load-serving entities about expected load growth and detailed in the RTO’s annual load forecast reports under Table B-9. 

Much of the discussion centered around how PJM uses the hourly load forecasts provided by LSEs to determine the LLAs it enters into Table B-9. 

ODEC’s Mike Cocco said that because the transmission provider will be assigning LLA directly to transmission-dependent utilities, this shifting of incentives and associated costs will necessitate the ability for the TDUs to provide their own LLA forecast to the Load Analysis Subcommittee. In addition, he could understand the arguments as to why the proposal should not be voted on without language detailing how PJM approves the LLAs, suggesting there should be some documented process PJM follows that should be established in the manuals. 

Dominion’s Jim Davis and MIC Facilitator Foluso Afelumo said changes to the development of Table B-9 are out of the scope of the issue charge approved in October. 

Rory Sweeney of NOVEC argued that because that process is not laid out in the manuals, it would not constitute a change to existing practices and therefore is within the issue charge’s scope. 

Bowring said the proposal needs to have explicit rules governing the treatment of changes in the load forecast for large loads. The final amount of capacity paid for is a result of a final forecast just prior to the delivery year that can vary significantly from the forecast in the proposal. The final forecast also defines the level of capacity transfer rights, the capacity market equivalent of financial transmission rights. 

Other Committee Business

The MIC endorsed a PJM quick-fix proposal seeking to outline its existing practices around interface pricing points, which groups buses together when calculating LMPs for energy transfers between external areas. The revisions to Manual 11 include a definition of interface pricing points and establish an annual review of power flow impacts on each interface and a recommendation from the Monitor to adjust the weighting of component interfaces to maintain congruity between prices and system conditions. 

PJM also presented a joint proposal with the Monitor to add more details to the parameters that synchronized condensers include in their market offers. PJM’s David Hauske said the proposal is focused on adding Operating Agreement and manual definitions of condense startup costs, condense-to-generate costs and condense energy use; there would be no change to PJM practices, he said. 

There will be some overlap between the 2025/26 BRA and the initiation of pre-auction activities for the following auction, Langbein told the committee. Pre-auction activity deadlines that will fall before the conclusion of the 2025/26 auction include: the deadline for planned resources to notify PJM of their notice of intent, minimum offer price rule certification, requests for an exception from the must-offer requirement, the Monitor’s posting of unit-specific energy and ancillary services (EAS) offset, and seller requests for winter capacity interconnection rights. Langbein said PJM is not currently considering any delay to the 2026/27 BRA, which is scheduled to open in December. 

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PJM OC Briefs: March 7, 2024

PJM Presents Monthly Operating Statistics, Low Spin Response

VALLEY FORGE, Pa. — PJM’s Stephanie Schwarz presented the RTO’s monthly operating statistics, which showed an average hourly forecast error of 1.26% for February and an hourly peak error just over 3% over forecast on Feb. 3.  

The month saw three shared reserve events, one spin event and three post-contingency local load relief warnings. 

During the Feb. 24 spin event, which lasted about 12 minutes, Schwarz said 36% of the 2,689 MW spin response assignment for generation materialized as well as 7% of the 262 MW assignment for demand response. The total penalty for the event was 1,967 MW out of a 2,951 MW spin assignment. Generation without a spin assignment increased by 1,777 MW during the event. 

The Reserve Certainty Senior Task Force (RCSTF) is considering changes to the reserve penalty rate for resources that fail to perform. Stakeholders in the OC argued that the response from generation without a reserve commitment shows there’s capability for intramarket resources to move on dispatch. 

PJM’s Glen Boyle said the underperformance Feb. 24 was concentrated in a few units and overall figures would have looked much better if those resources met their obligations. In response to questions about how reserve assignments interact with the basepoints resources are expected to follow, Boyle said assignments are not included in basepoints; however, the RCSTF is considering ways of aligning the two so that reserve resources can follow dispatch and provide reserves at the same time. 

PJM Preparing Forecast for April Solar Eclipse

Pre-eclipse solar generation could decline by as much as 85% during the solar eclipse expected on April 8 and diminished temperatures during the event could result in varying outcomes for demand, PJM’s Michael Stewart presented to the OC.  

Grid-connected solar generation could decrease by 1.8-6.7 GW based on cloud coverage, while the decrease in behind-the-meter solar could elevate net load by 4.8 GW on a sunny day or 2.2 GW under overcast conditions. Consumer behavior could also change load patterns, but the impact shouldn’t be as significant as that seen on holidays, Stewart said. 

PJM’s Joe Mulhern said more generation may be needed to compensate for decreased solar output, particularly on a cooler day. Eclipses tend to cause temperatures to drop by between 4 and 10 degrees, which could increase load on a colder day as heating load increases, or decrease load on a hot day as air conditioning switches off. The tipping point tends to be between 55 and 65 degrees, depending on the region, Mulhern and Stewart told RTO Insider. 

PJM Dispatch Manager Donnie Bielak said operators will be looking at best- and worse-case scenarios and will refine the actions that may be employed in the days leading up to the eclipse. 

A similar relationship between diminished solar output and lower air conditioning load was reported during the wildfire smoke that blanketed the Northeast during summer 2023. (See RTOs Report Diminished Solar Output, Loads as Wildfire Smoke Passes.) 

Periodic Review Manual Revisions Endorsed

Stakeholders endorsed revisions to Manual 12: Balancing Operations and Manual 37: Reliability Coordination through the documents’ periodic review.  

The changes to Manual 12 align language and diagrams with portions of Manual 11 pertaining to real-time market operations and bilateral transactions and added detail to the economic minimum and emergency minimum parameters requirements for hybrid resources. 

The revisions to Manual 37 reflect updated NERC standards around establishing and communicating system operating limits, such as thermal ratings and voltage or stability limits. 

PJM Provides Security Update

PJM’s Jim Gluck said cybersecurity professionals are recommending individuals restart their internet routers and install security software updates to mitigate the risk that they could be exploited by the hacking group Volt Typhoon, which was the topic of a cybersecurity advisory issued by the Cybersecurity and Infrastructure Security Agency last month. 

He also encouraged members to ensure that their data is secured both on internal networks and through any external parties they work with. He highlighted a data breach exposing a security vulnerability at a Canadian nuclear operator caused by an employee of a third party with access to the company’s data. 

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Colorado PUC Sets Rules for Electricity Market Participation

The Colorado Public Utilities Commission has issued proposed rules that would govern how it will review applications from state utilities wishing to join the various regional electricity markets being developed in the Western Interconnection. 

The rules implement a 2021 state law by setting out utility filing obligations, timelines, a legal standard of review and required PUC findings depending on the type of transmission utility, the nature of the market and relevant policy concerns based on prior commission studies, cases and comments (22R-0249E). 

The rulemaking includes 10 conditions for market participation that reflect state law and the PUC’s policies. They include grid reliability, emissions tracking, customer rate impacts and transmission expansion for investor-owned utilities. Utilities also can keep a percentage (35%, to begin with) of the savings they gain from the markets.  

PUC Chair Eric Blank said in an email to Western regulators that his agency’s primary concern is to develop a “consistent framework for tracking and accounting for [greenhouse gas] emissions” and maintain an interconnection queue process that allows winning projects to move forward in a timely manner. It also has more general concerns over rates, transmission expansion and seams. 

The commission said it is important for Colorado utilities, regulators and other stakeholders to become involved in market development before market operators submit their tariffs for FERC approval because any subsequent changes will depend on the markets’ governance structures and stakeholder processes. 

“Given these timing and other challenges surrounding the FERC approval and modification process, the best opportunity for Colorado utilities, regulators, customers, [independent power producers], clean energy advocates and others to shape the key aspects and structure of the regional market options may be prior to the FERC filings,” the PUC wrote. “Once a tariff is filed at FERC, additional changes can be challenging and time consuming to get approved and implement.” 

The PUC held a March 5 hearing on the rules and is currently gathering written feedback from interested parties. It plans a full review following the comment period, which ends April 5. 

Market Choices

Colorado utilities can participate in any of three regional markets currently planned for the West: 

    • CAISO’s Extended Day-ahead Market, which already has FERC approval and is due to go live in 2026. PacifiCorp and the Balancing Area of Northern California (BANC) are its only two committed participants so far, although the Los Angeles Department of Water and Power has signaled its intent to join. 
    • SPP’s RTO West seeks to extend the services SPP currently offers in the Eastern Interconnection. It, too, is targeted to go live in 2026 and has seven utilities evaluating whether to place their facilities under its tariff, which is expected to be filed midyear. 
    • SPP’s Markets+ and its bundle of proposed services that would centralize day-ahead and real-time unit commitment and dispatch across a large footprint in the Western Interconnection. A tariff filing is planned for the end of March. 

CAISO and SPP also both have imbalance markets operating in the interconnection. The PUC noted Colorado participants in the latter’s Western Energy Imbalance Service (WEIS) market suggest that optimizing dispatch in real time has already reduced curtailment and lowered production costs in Colorado. 

SPP has already been working with Western stakeholders to develop a market solution, best practices, rules and protocols that support the Northwest’s only cap-and-trade program in Washington. Spokesperson Meghan Sever said the RTO is reviewing the proposed rules and has been working “extensively” with the Colorado commission and utilities on GHG emissions tracking and accounting. 

“We foresee no issue complying with the proposed rule as drafted,” Sever said. “While these proposed rules are more directed toward Colorado utilities, SPP sees no barriers in our ability to comply with the proposed rule.” 

Colorado Springs Utilities (CSU) and Tri-State Generation and Transmission Association are among the state’s utilities that are evaluating SPP RTO West. Both are already members of the RTO’s WEIS market that went live in 2021. 

Steve Berry, a senior public affairs specialist with Colorado Springs Utilities, said it is premature for the utility to offer a formal position on the proposed PUC rules. 

“We’ve been an observer of the process up to this point,” he said. 

Tri-State did not return a request for comment. It has already told the PUC it intends to transition its load within the Western Area Colorado Missouri balancing area, which includes portions of Colorado, Wyoming, Western Nebraska, New Mexico and Arizona, into RTO West in April 2026.  

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DMM: CAISO Transfer Limitations During Q3 Heat Waves Led to Price Disparities

Limits on imports from the Western Energy Imbalance Market into the CAISO balancing authority area between July 25 and Nov. 16, 2023, led to increased transmission congestion in the ISO’s 15-minute-ahead market and lower prices in the five-minute market, the Department of Market Monitoring told stakeholders March 6. 

While CAISO operators’ actions helped the ISO maintain reliability during a brutal summer in the West, “it is not clear why the CAISO area continued these transfer limitations after the mid-August heat wave and through Nov. 16,” the department said. It recommended “that CAISO work with stakeholders to consider other methods of achieving the intended reliability outcomes without creating the large and systematic modeling differences between the 15-minute and five-minute markets.” 

Presenting the department’s State of the Market report for the third quarter of 2023, Ryan Kurlinski, senior manager of market and policy analysis, said CAISO operators began limiting WEIM import transfers for the hour-ahead and 15-minute markets in late July when stressful weather conditions led to high levels of unfulfillable self-scheduled exports. (See CAISO DMM: High Exports to Southwest Led to July EEAs.) The limitations were then lifted in the five-minute market. 

The limiting action was taken to mitigate the risk that during critical hours, internal generation and hourly block intertie schedules could be displaced by WEIM imports that might not materialize in real time. CAISO issued energy emergency alerts on three days in late July but was not forced to shed load. 

“This limitation on these tight days did have the intended effect of reducing advisory WEIM imports into CAISO and replacing it with increased hourly block imports and decreased exports out of CAISO,” Kurlinski said. “While that limitation had the intended reliability impact, it also significantly impacted the rest of the West,” driving down prices. 

Load adjustments in the hour-ahead and 15-minute markets were lower on average in the third quarter than those in the same quarter in 2022, though after July 20, they rose back to 2022 levels of about 2,000 MW. 

“The combination of high load adjustments in the 15-minute market and much lower adjustments in the five-minute market contributed to the lower average prices in the latter market,” the report says. “When the CAISO balancing area limited WEIM transfer imports to zero in the hour-ahead and 15-minute markets, most of the WEIM footprint was collectively export constrained at a lower price based on regional supply conditions outside of the CAISO area,” the report reads. 

Kurlinski used transfers in and out of Arizona Public Service as an example. Before the transfer limitation was implemented, there were significant transfers from APS to CAISO and other BAs, but after the limitation was put in place in the 7-8 p.m. hour on July 26, dynamic transfers from Arizona to CAISO stopped.  

The “DMM has recommended that CAISO work with stakeholders to consider if there may be other methods or other ways to try to achieve the same reliability outcomes that the CAISO BA is trying to achieve but without potentially creating this significant difference between the 15-minute market and five-minute markets,” Kurlinski said. “At the very least, it would be good to have a more transparent discussion about what the ISO is seeing in its systems that would lead them to do this again and to be more transparent about when they are going to do this.” 

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Powerex Report Expands NW Cold Snap Debate

A new report from electricity marketer Powerex adds to the expanding debate around what transpired on the Western grid during a January cold snap that saw the Northwest forced to import large volumes of power in the face of record energy demand and tight supplies. 

The storm saw five balancing areas — including the Alberta Electric System Operator — enter various levels of energy emergency alerts (EEAs), with one critical EEA-3 declared in the U.S. Northwest.  

The March 6 report from the Vancouver, Canada-based company, which markets BC Hydro’s surplus generation and manages a sophisticated trading operation that covers the Western Interconnection, represents yet another salvo in the dispute over the Jan. 12-16 winter freeze that plunged the Northwest to near-record low temperatures.  

The ensuing disagreement about how energy flowed during the event has largely reflected fault lines among Western electricity industry stakeholders in the contest between CAISO’s Extended Day-Ahead Market (EDAM) and SPP’s Markets+. The debate is sharpening as the Bonneville Power Administration nears the release of its market “leaning” in April. (See NW Cold Snap Dispute Reflects Divisions over Western Markets.) 

Powerex so far is the only Western entity to tentatively commit to Markets+. Its report, “Analysis of the January 2024 Winter Weather Event,” amplifies the view held by some Northwest stakeholders that the region largely weathered the event because of support from the Desert Southwest and the Inland West — and not CAISO and other California balancing areas. 

The report also notes that Powerex itself aided its southern neighbors during the freeze. It additionally delves into the capacity and fuel supply challenges that confronted the Northwest and concludes with a set of recommendations to the region to prepare for similar future events — all of which notably exclude participation by CAISO. 

Interpreting the Data

Powerex’s report shows peak demand in balancing areas across the U.S. Northwest during the cold snap generally ranged about 2 to 6% higher than during a similar weather event in December 2022, with comparable temperatures. In PacifiCorp’s West area, the peak was 6.7% higher than during the 2022 event, while Seattle City Light’s peak was 6.2% higher and Idaho Power’s 5% higher. British Columbia set a new demand record Jan. 12, beating its previous mark by 3%. 

“This is consistent with recent projections of accelerating demand growth for U.S. Northwest utilities,” the report said, citing last year’s forecast from the Pacific Northwest Utilities Conference Committee. 

Powerex’s account of how power flowed across the Western Interconnection during January’s five-day event aligns with two separate assessments from the Western Power Pool (WPP) and the Public Power Council (PPC).  

Relying on Open Access Same-Time Information System (OASIS) transaction schedules, BPA’s Pacific AC Intertie data, Energy Information Administration interchange data and figures from CAISO’s OASIS, Powerex estimated that the U.S. Northwest hourly net energy imports averaged 4,745 MW during the 4 p.m.-to-8 p.m. periods of peak demand during the January event.  

The “most significant” source of supply during those hours, Powerex said, originated in the Rockies (2.399 MW exported) and Desert Southwest (2,765 MW exported) regions, with power from the latter being wheeled through California into the Northwest. Canada — mostly Powerex — also exported an hourly average of 336 MW directly to the U.S. Northwest. 

“In contrast, [CAISO], and other California utilities that are not part of [CAISO], were net importers on average of approximately 443 MW (189 MW and 254 MW respectively) during these peak demand hours,” the report said, repeating a point made by the WPP and PPC in their analyses. 

Across the full 120 hours of the January event, the U.S. Northwest imported an hourly average of 5,241 MW, Powerex said, with the Southwest exporting an hourly average of 3,223 MW and the Rockies 2,399 MW, with Canada exporting 481 MW. Over the same period, CAISO and other California BAAs were net importers of 49 MW and 489 MW, respectively, the report said. 

“Imports and exports can be the result of bilateral transactions arranged prior to the operating hour and scheduled through e-Tags under the contract-path framework, or they can be the result of participation in the Western EIM, which optimizes transfers based on available supply and transmission service across the footprint,” Powerex said. 

The report cites WEIM data showing the Northwest received an average of 348 MW of supply from the WEIM across all hours and 164 MW during the peak hours. It notes that “most of the [Northwest’s] imported supply was transacted in the bilateral markets (including exports from the CAISO using the intertie bidding framework and contract path scheduling), with the Western EIM providing a relatively small volume.” 

CAISO contested that characterization of energy flows in its own 80-page analysis detailing how the ISO and the WEIM supported the Northwest during the cold snap. (See NW Freeze Response Shows WEIM Value, CAISO Report Says.) 

CAISO’s report, also published March 6, said the ISO “became a net exporter over the Martin Luther King Jr. Day weekend for all hours of the day, excluding WEIM transfers,” with hourly exports in the day-ahead and real-time markets exceeding 6,000 MW.  

The ISO said WEIM transfers into CAISO stemmed from not limited supply within CAISO but instead the “economic displacement and opportunities optimized by the market and bounded by the transmission and transfers availability in the wider footprint.”  

“The market identified least-cost solutions within the wider WEIM footprint, transferring lower-cost electricity from the Southwest into California,” the CAISO report said. “These transfers allowed exports scheduled in the day-ahead and hour-ahead markets to flow to the Northwest, replacing more expensive generation while managing congestion on key transmission lines.”  

‘Distinct Reliability Challenges’

The Powerex report highlights “two separate and distinct reliability challenges” confronting the Northwest during the deep freeze: “inadequate capacity during peak demand hours” and “insufficient fuel supply across the multiday event.” 

Regarding fuel supply, the report notes that BC Hydro and BPA hydroelectric generators associated with the largest storage reservoirs can operate “at or near maximum output across all hours of a multiday weather event,” but run-of-river hydroelectric facilities don’t have that option. 

“The region’s dependence on these hydroelectric generation facilities gives rise to a risk of fuel supply insufficiency during weather events lasting multiple days, such as the January 2024 event,” Powerex said. “The risk that other variable energy resources, such as wind facilities, may also experience persistent reduced output during a multiday weather event also contributes to fuel supply risk.” 

Powerex said that risk was evidenced by the fact that U.S. Northwest wholesale electricity prices were high in both the day-ahead and real-time market across all hours of the event, including in the WEIM, where prices hovered near caps.   

The fuel supply risk also was apparent in the number of EEAs declared outside peak demand hours, including one during the overnight hours when demand was relatively low — “indicating a reliability challenge other than a lack of generating capacity to meet peak demand, such as a lack of fuel supply,” Powerex said. 

WRAP Enhancements

The report concludes with four key recommendations for the U.S. Northwest. 

The first is for the region to consider making “enhancements” to the WPP’s Western Resource Adequacy Program (WRAP) before it begins its first binding winter season, which could be as early as 2026/27.  

Given the surge in peak demand compared with the region’s December 2022 event, Powerex calls for the WRAP to potentially revise its winter peak demand assumptions, evaluate how well demand response (DR) programs reduced demand during the January 2024 event and “explore a regional discussion of the opportunities” to expand the use of DR during such multiday events. The report also asks the WPP to evaluate how WRAP resources performed during the event to get a better read on the current resource adequacy situation and identify ways to improve the program. 

The report’s first recommendation also contains a provision asking the WRAP to consider modifying how it transitions to its binding phase by accounting for utility capacity deficiencies that result from delays in obtaining interconnection for resources. 

“This new transition framework may include a requirement that entities demonstrate that their current capacity deficits are temporary, or otherwise provide confidence of meeting resource adequacy requirements by the end of the new transition period,” Powerex wrote. 

Circumventing California

Powerex’s second recommendation calls for the Northwest to use existing transmission facilities to increase import capability directly from the Southwest and Rockies regions. The report says that “additional supply appears to have been available in the Southwest and Rockies, but access to this supply appears to have been primarily limited by inter-regional transmission service.” 

Bound up in this recommendation is a criticism of CAISO’s practices and a plug for Markets+ 

“Transfers of electricity across the West are limited by contract-path scheduling limits on key transmission paths. In addition to applying to deliveries of forward, day-ahead and real-time bilateral transactions, these limits are also applied by [CAISO] to transfers between BAAs in the Western EIM and will be applied in its proposed EDAM,” the report says. “In contrast, organized markets elsewhere in the U.S. — as well as the proposed [SPP] Markets+ platform — do not generally layer contract-path limits on top of standard flow-based transmission limits.” 

The report’s third recommendation, for the Northwest to upgrade and build new transmission connections with the Southwest and Rockies regions, includes another critique of CAISO practices. During the January event, Powerex and other Northwest entities have contended, the $650/MWh wholesale power price spread between the Northwest and Southwest was squeezed by congestion charges at CAISO’s border with Oregon. An additional 2,000 MW of direct transfer capability with the Southwest could have saved the Northwest $140 million and reduced the region’s reliability risk, Powerex said. 

“Notably, roughly half of the deliveries from the Southwest and Rockies region to the U.S. Northwest region during the event flowed through California, and particularly through the California ISO’s service territory. Transmission service through the California ISO’s service territory is provided under different terms and conditions than transmission service provided throughout the rest of the West,” the Powerex report said. 

CAISO has sought to address that contention, arguing that it is the only balancing authority in the West that uses mechanisms to manage transmission congestion in the day-ahead market and that it cannot overlook resolving situations in which it can foresee stress on a portion of the grid. The ISO’s March 6 report said EDAM “provides additional mechanisms for managing congestion on either side of balancing area borders for participating entities and provides transparency on the distribution of congestion revenues collected through nodal pricing.” 

Overcoming Fuel Supply Challenges

Powerex’s fourth recommendation urges the Northwest to consider how specific resources and resource types contribute to the fuel supply challenges that can arise during multiday events like the January cold snap.  

The report notes that resources with “base load or dispatchable capabilities,” such as hydro with longer-term storage — like that operated by BC Hydro — as well as nuclear, gas, coal and geothermal resources, “are able to contribute at a very high level” to meet the region’s RA and fuel supply challenges. 

“At the other end of the spectrum are shorter and medium duration storage facilities, such as batteries and pumped storage hydro,” the report says. “These technologies contribute substantially towards meeting capacity challenges (through 4-hour or longer discharge cycles) but do little to address (and may actually exacerbate) multiday fuel supply challenges, as they do not provide net energy over the course of one or more full charging/discharging cycles (i.e., they actually consume energy across each day of a multiday event due to cycle losses).” 

The report also points out that solar and wind resources might contribute differently from each other, with solar providing “little to no benefit” for capacity challenges occurring after sunset, while wind could be available during those intervals, depending on conditions. 

“At the same time, these same solar resources may provide a greater contribution to fuel supply challenges over multiday events than wind resources, since wind resources may be more susceptible to multiday periods of little or no wind output,” the report said. 

“Ultimately, the WRAP may need to evolve to include additional resource adequacy requirements associated with multiday fuel sufficiency requirements,” it said. 

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Veteran Monitor McDonald to Lead ERCOT’s IMM

The Texas Public Utility Commission said March 11 that Jeff McDonald, a 22-year market monitoring veteran, has been hired as director of ERCOT’s Independent Market Monitor. 

He replaces Carrie Bivens, who resigned as the IMM’s director last year. 

McDonald spent nearly eight years at ISO-NE as its vice president of market monitoring. Before that, he held several managerial positions during 14 years with CAISO’s Department of Market Monitoring. 

He will be responsible for collaborating with the PUC to detect and prevent market manipulation and identify potential design improvements for the ERCOT market, the commission said.  

“Jeff’s deep expertise and decades of experience make him the perfect person to lead the IMM team in Texas and ensure the market is operating efficiently, fairly and competitively,” Potomac Economics President David Patton said in a statement. 

Potomac Economics has served as ERCOT’s IMM since 2005, when the organization was created. It recently was awarded another contract to monitor the market through 2027. 

Bivens resigned in November after 3.5 years as the IMM’s director following several disagreements with PUC and ERCOT leadership. She cast doubt on the performance credit mechanism pushed by former PUC chair Peter Lake and defended before the ERCOT board an IMM report that said the grid operator’s newest ancillary service “likely” raised the real-time market’s energy value by at least $8 billion. (See Bivens Resigns as ERCOT’s Market Monitor.) 

McDonald joins Potomac Economics from Concentric Energy Advisors, where he was the firm’s vice president. He holds a Ph.D. in economics from the University of California, Davis, a master’s in natural resource economics from the University of Massachusetts, Amherst, and a bachelor’s in agricultural and managerial economics from Cal Davis. 

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Texas Regulators Slow PCM’s Development

Texas regulators have pumped the brakes on the proposed performance credit mechanism’s (PCM) development, making it clear that they and stakeholders will be involved in the market tool’s design. 

“We need broader input, not just from commissioners, but also from stakeholders,” Public Utility Commission Chair Tom Gleeson said during the agency’s open meeting March 7. 

ERCOT staff filed a memo before the meeting outlining a study approach for designing a PCM strawman. It identified 37 design parameter decisions and an evaluation methodology to select the final design, with several options for each parameter decision (55000). 

Staff also suggested a timeline that includes three stakeholder workshops and PUC approval of the final design in early 2025. ERCOT would then develop necessary protocols and, following commission approval, “evaluate” the PCM’s implementation. 

“This timeline that’s laid out in in your filing is very compressed, it’s very rushed, and it completely leaves out the commission in terms of workshops and engagement and any kind of stakeholder feedback over here,” Commissioner Lori Cobos told ERCOT staff. 

Gleeson called the implementation evaluation in ERCOT’s timeline “open ended.” 

“That wasn’t a completion timeline,” he said. “There’s still work to be done in ERCOT through their protocols and through their system upgrades. The actual implementation of this would still be much further, so I just don’t know that we have enough information now to have a timeline somewhere in 2026, 2027 mean anything at this point.” 

Further complicating the timeline is ERCOT’s development of real-time co-optimization, scheduled to be deployed by Dec. 31, 2026. That market tool is designed to improve energy procurement and dispatch. 

Cobos laid out a schedule beginning with PUC staff filing a memo before the commission’s March 21 open meeting providing their input on ERCOT’s proposed design parameters. The PUC again would consider the PCM during its April 11 open meeting before handing over its feedback to the ISO. That would move the date for the grid operator’s first workshop from March 26 into April, with stakeholders submitting feedback to the PUC. 

The commission agreed at least one of the workshops, likely the first, should be held at the PUC’s offices, and that the Independent Market Monitor and ERCOT staff conduct separate studies on the mechanism’s market effects. 

“We need to have two data points, two views of how the PCM is going to cost and affect the market,” Commissioner Jimmy Glotfelty said, stressing that design decisions are policy questions best taken up at the commission. 

ERCOT has engaged Energy and Environmental Economics (E3) to support the strawman’s development. E3 also worked with Astrapé Consulting at the PUC’s direction to evaluate the PCM and five other potential market reforms. While the study did not recommend the PCM, then-Chair Peter Lake determined the mechanism would best incent more dispatchable generation. (See Proposed ERCOT Market Redesigns ‘Capacity-ish’ to Some.) 

The PCM establishes a reliability standard and corresponding quantity of performance credits (PCs) that must be produced during the highest reliability risk hours to meet the standard. Load-serving entities can purchase PCs, awarded to resources through a retrospective settlement process based on availability during hours of highest risk, and trade them with other LSEs and generators in a forward market; generators must participate in the forward market to qualify for the settlement process. 

The PUC adopted the PCM for inclusion into the ERCOT market in January 2023. Also last year, Texas lawmakers passed a bill (HB 1500) establishing legislative guardrails for the PCM’s implementation. 

The commission determined the PCM’s $1 billion annual cap, as set by the Texas Legislature, is an “absolute” annual cost cap, not an average annual cap. 

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MISO Lodges 2nd Complaint Against SPP over Disputed Crypto Load on M2M Flowgate

MISO has registered a separate complaint with FERC to retract market-to-market coordination with SPP on a contentious flowgate persistently taxed by a North Dakota cryptocurrency mining operation.  

MISO said it wants refunds for its members and for FERC to end what it calls “improper M2M coordination activities” on the 230-kV Charlie Creek flowgate because it cannot offer meaningful congestion relief (EL24-85). The grid operator sought fast-tracked treatment and said its complaint should dovetail with an initial complaint submitted by Montana-Dakota Utilities Co. (See Crypto Load on MISO-SPP M2M Constraint Draws Complaint from Montana-Dakota Utilities.) 

MISO repeated concerns made in the original complaint that the flowgate, which serves the 200-MW Atlas Power Data Center, has cost its members more than $38 million in “unnecessary, unjust and unreasonable M2M charges.” (See SPP, MISO Clash over Crypto-strained M2M Flowgate.) 

MISO said SPP is violating their M2M coordination procedures under the RTOs’ joint operating agreement by refusing to lift the line’s M2M status. It said the flowgate is being used to “address local congestion issues in a load pocket located in [SPP] … where MISO has no regional flows and is unable to relieve congestion due to the lack of generation.” MISO asked for refunds for M2M charges associated with the flowgate from April 1, 2023, onward.  

Additionally, MISO asked FERC to pronounce it and SPP’s current M2M coordination termination process unreasonable and discriminatory because MISO doesn’t have recourse to revoke congestion management even when it’s unhelpful, leaving its members on the hook for millions. MISO also said it didn’t have faith that it and SPP could revise the provisions in their interregional coordination process without FERC guidance.  

“This finding will ensure that the dispute that led to this complaint does not occur again and is promptly remedied, as both MISO and SPP appear to agree that changes are needed while disagreeing on how those changes should be implemented. MISO will work with SPP to develop appropriate revisions, but MISO does not believe that even a mutually collaborative effort, without the benefit of such a threshold FERC finding, providing a firm timeline and prescribed compliance process, would be effective or expeditious,” MISO wrote.  

MISO said M2M coordination on Charlie Creek should have ended as soon as the Atlas Power Data Center began operating early last year. 

MISO said neither it nor SPP have adequate generation to relieve the constraints “exacerbated” by the cryptocurrency facility situated in the Williston Load Pocket (WLP). It also said it and SPP have no “economic” M2M coordination available to them, with SPP acknowledging in a 2021 transmission planning report that the “root” of the issue lies in “the lack of transmission to accommodate the level of transfers required to serve the forecasted load in the future, contributing to a weak system unable to maintain acceptable voltage levels.” 

“In fact, congestion in the WLP stems primarily from a local reliability issue and the best solution is to build additional transmission,” MISO argued, saying the “obvious ineffectiveness” of the M2M coordination should be clear to FERC.  

SPP has asked FERC to deny Montana-Dakota Utilities’ complaint, maintaining that the M2M activation and congestion coordination is permitted according to the joint operating agreement. It has said it and MISO are working through the disagreement, though MISO has said negotiations are at an impasse, which effectively works as SPP blocking any hope for an M2M cancellation.