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December 21, 2024

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FERC Approves Fines on Batteries for Misleading Bids in CAISO

FERC has approved a consent and stipulation agreement between its Office of Enforcement and the operators of two battery storage projects in CAISO imposing nearly $3.5 million in fines on the companies for submitting inaccurate initial state of charge values that led to undue bid cost recovery (BCR) payments (IN24-13).

Sonoran West Solar Holdings 1 and 2, owned by RE Crimson, agreed to disgorge the $2,473,265 in BCR payments they received from Oct. 1, 2022, through Feb. 17, 2023, and pay a $1 million civil penalty to the U.S. Treasury. The companies stipulated to the facts of Enforcement’s investigation but neither admitted nor denied any violations.

The Sonoran entities each operate a battery at the Crimson Battery Project in California’s Riverside County. Crimson 1 is a 200-MW/800-MWh battery, and Crimson 2 is 150 MW/600 MWh.

According to the CAISO tariff, if a battery submits a day-ahead bid at 10 a.m., it has the option to forecast its state of charge at the beginning of the next operating day, referred to as the battery’s “initial state of charge.”

Enforcement found that during the relevant period, the Sonoran entities frequently submitted biddable initial state of charge parameters to CAISO that reflected a value that was other than a “forecasted starting physical location,” or the state of charge the batteries were forecasted to hold at the start of the real-time market.

The companies submitted initial state of charge values indicating their batteries would be available to receive discharge awards at midnight and the early morning hours of the following day. On average, Crimson 1 and Crimson 2’s initial state of charge values were 480 MWh and 426 MWh higher, respectively, than their telemetered state of charge at midnight.

Additionally, on Oct. 24 and Nov. 28, 2022, and Jan. 14 and 15, 2023, the companies submitted outage cards with a maximum stored energy of 0 MWh, indicating that the battery needed to be fully discharged in advance of the outage. As a result, they received day-ahead awards to discharge to sell energy prior to the outages.

Because the day-ahead bids were at or near the CAISO bid cap of $1,000, the awards were uneconomic and resulted in BCR payments they would not have obtained if they had submitted accurate information. CAISO’s Department of Market Monitoring flagged the payments and, after department inquiries and Enforcement’s investigation began, the Sonoran entities began implementing processes to minimize future likelihood that initial state of charge and maximum stored energy for outages would be misreported.

Enforcement determined that the initial state of charge values submitted to CAISO during the relevant period were “false and misleading” because they did not reflect a forecasted physical starting location, nor the reasonably expected availability of its batteries at midnight.

The companies also will submit an annual compliance monitoring report to Enforcement for at least one year.

In its Dec. 5 order, FERC found “that the agreement is a fair and equitable resolution of the matters concerned and is in the public interest.” It directed CAISO to allocate the disgorged funds in its discretion for the benefit of ISO customers.

CAISO and stakeholders have been working over the past six months “to evolve existing bid cost recovery rules for energy storage resources to ensure fair and equitable treatment of these resources and reduce unwarranted bid cost recovery payments,” ISO spokesperson Anne Gonzales said.

The ISO is kicking off a new initiative Dec. 11 to continue addressing the issue.

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SPP Board Approves Need Dates for Last ITP Projects

SPP’s Board of Directors finally approved the winter-weather staging of a pair of transmission projects that have been held up since October by stakeholder concerns over their need dates and whether they would be competitively bid.

During a virtual meeting Dec. 9, the board approved need dates for the two projects by endorsing the Markets and Operations Policy Committee’s votes the week before: a December 2028 date for the 345-kV Tobias-Elm Creek transmission line on the western side of SPP’s footprint and a December 2025 need date for the 345-kV Buffalo Gap-Delaware project from Kansas into Southwest Missouri. 

The latter project’s need date was amended from December 2028 during the MOPC meeting, overriding staff’s recommendation. (See SPP Stakeholders Endorse Need Dates for Delayed Transmission Projects.) 

The board’s approval completes the 2024 Integrated Transmission Planning assessment, a record-breaking $7.65 billion portfolio of 89 projects. The directors delayed a decision on the last two projects’ need dates — the earliest that staff identify a project is needed — after failing to reach consensus during several hours of discussion in their October meeting. (See SPP Board Approves $7.65B ITP, Delays Contentious Issue.) 

Evergy and other Missouri and Kansas stakeholders were particularly keen on moving up the 154-mile, $484.1 million Buffalo Gap-Delaware project, which brings a new extra-high-voltage source into Missouri that will support mitigation of Wichita-area congestion, Missouri system voltage and transfers from the SPP footprint into Missouri. The project was identified through a model based on December 2022’s Winter Storm Elliott that also analyzed 2025 and 2028. 

Evergy, with operations in both states, joined with City Utilities of Springfield (Mo.) and Liberty Utilities in filing a letter before the board meeting urging the earlier need date. They said establishing an immediate need-by date is consistent with SPP’s tariff and the ITP manual; the project will address reliability violations found in all the models and decrease the risk of load shed; and it has broad stakeholder support. 

“SPP took a novel approach this year to address resiliency projects by studying select winter weather events because they knew … there was a problem that needed to be addressed that hadn’t been addressed previously, and some of that work resulted in the single most cost-effective ITP in SPP history,” said Kayla Hahn, chair of the Missouri Public Service Commission. “Unfortunately, I’m concerned that that work could potentially be undercut by the delay of this particular project.” 

“We have known for some time that the environment created by our generational challenge will put pressure on many aspects of our processes and culture, whether it be setting a longer-term [planning reserve margin] fully assessing resiliency and winter weather scenarios, or assessing our short-term reliability project list,” board Chair John Cupparo said. “We will be facing unprecedented situations that may run counter to our experience on how to analyze and address these issues. How we respond to those situations may also deviate from historical practice but must still be consistent with our regulatory obligations and our mission.” 

The board’s Members Committee approved the Buffalo Gap-Delaware project with its advisory vote, 16-6, opposed primarily by renewable interests. 

“We’ve heard a lot about how these upgrades are needed for reliability. We’ve been burned by making decisions based on [transmission owners] saying one thing publicly but not moving forward on much-needed transmission,” EDP Renewables’ David Mindham said. “There’s currently no way to hold TOs accountable for not building transmission timely in SPP. If we have the later need date, these projects will be competitive, and that shines a big old spotlight on” the TOs. 

The committee approved the Tobias-Elm Creek Project, 11-7, with four abstentions. TOs were in the opposition, with some saying they still had questions over staff’s use of the winter models. The project is an 85-mile segment valued at $887.5 million. 

JTIQ NTCs Coming Soon

The board endorsed staff’s recommendation to approve the three SPP projects in the Joint Targeted Interconnection Queue (JTIQ) portfolio with MISO and directed the RTO to issue them notifications to construct. 

The three projects — a new 345/161-kV double circuit and rebuilt 161-kV lines near Omaha, Neb.; new 345-kV lines in Nebraska; and an expanded and rebuilt 345-kV substation in Sibley, Iowa — cost a combined $436 million, according to 2023 conceptual engineering and construction estimates. The JTIQ portfolio’s five projects cost a combined $1.6 billion. 

However, SPP and MISO expect a grant of up to $464.5 million in matching federal funds under the U.S. Department of Energy’s Grid Resilience and Innovation Partnerships (GRIP) program to offset some of the projects’ capital costs. (See MISO, SPP Ditch 90/10 JTIQ Allocation After $465M DOE Grant.) 

FERC in November approved tariff revisions and modifications to the joint operating agreement between the two grid operators that enshrines a structural and cost-allocation framework for the five 345-kV projects (ER24-2798, ER24-2825). The RTOs plan to allocate 100% of the projects’ costs to interconnection customers, consistent with the cost-causation principle. (See FERC Approves JTIQ Framework, Cost Allocation.) 

The effort began in 2020. The RTOs say the portfolio will enable between 28 GW and 53 GW of interregional generation capacity near their seam. 

The committee unanimously favored the motion, 22-0. 

Lang, Hough to Lead MOPC

By approving its consent agenda, the board sided with the Corporate Governance Committee’s recommendation that Omaha Public Power District’s Joe Lang and City Utilities of Springfield’s Olivia Hough serve as MOPC’s chair and vice chair, respectively. They will serve two-year terms expiring Dec. 31, 2026. 

The agenda’s approval also results in the following organizational group chairs for the next two years:  

    • Credit Practices Working Group: Caleb Head, Northeast Texas Electric Cooperative.
    • Economic Studies Working Group: Calvin Daniels, Western Farmers Electric Cooperative. 
    • Project Cost Working Group: Angie Anderson, Sunflower Electric Power. 
    • System Protection and Control Advisory Group: David Oswald, Liberty Utilities. 
    • Market Working Group: Richard Ross, American Electric Power. 
    • Operations Training Users Forum: Derek Stafford, Grand River Dam Authority. 
    • Generation Interconnection Advisory Group: Jason Tanner, NextEra Energy. 

All the chairs are incumbents except for Oswald and Tanner. Both are their groups’ vice chairs. 

The consent agenda also will revise the PCWG’s scope to include reviewing delayed upgrades and providing recommendations to the board in a timely manner. 

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NERC Board of Trustees Briefs: Dec. 10, 2024

In its last meeting of the year on Dec. 10, NERC’s Board of Trustees voted to adopt a number of new reliability standards, along with taking action on multiple organizational items, capping off what Chair Kenneth DeFontes called “an extraordinary year” for the ERO Enterprise.

Standards Approved for FERC Submission

Trustees first accepted CIP-003-11 (Cybersecurity — security management controls), produced by Project 2023-04 (Modifications to CIP-003). The new standard addresses the risk of grid-connected distributed cyber systems being targeted by malicious actors for use in a coordinated attack. It requires entities to implement controls on inbound and outbound electronic access, detection of suspicious or malicious communications, user authentication and disabling vendor electronic access.

Next, the board approved TPL-008-1 (Transmission system planning performance requirements for extreme temperature events). NERC developed the standard in response to FERC’s Order 896, which directed the ERO to develop a standard to require entities to plan for extreme heat and cold weather events. (See FERC Approves More Extreme Weather Rules.) The board’s approval means the standard can be submitted in time to meet FERC’s deadline of Dec. 23, 2024.

Trustees then moved to CIP-002-8 (Cybersecurity — BES cyber system categorization), which is intended to improve risk identification by ensuring transmission owner control centers that perform the functions of a transmission operator are identified correctly. Members approved this standard unanimously, as they did with the other proposed standards.

Finally, the board accepted BAL-007-1 (Near-term energy reliability assessments) and TOP-003-7 (Transmission operator and balancing authority data and information specification and collection). The standards will require entities to evaluate energy assurance through energy reliability assessments and develop corrective action plans or take other actions to address identified risks in the appropriate time horizons.

After the standards actions, the board approved NERC’s 2025-2027 Reliability Standards Development Plan (page 40 in the agenda). The RSDP lays out time frames and resources available for projects under development or expected to begin by the end of 2024.

Organizational Items Endorsed

The board next agreed to authorize a data request to assess the cold weather performance of generating units. The request will be issued under Section 1600 of NERC’s Rules of Procedure, initially in 2025 and annually thereafter; relevant entities must submit the required information by May 15 of each year.

Trustees also approved the ERO Enterprise Long-term Strategy, a document outlining key focus areas to guide NERC and the regional entities’ business planning practices starting in 2026, and 2025 Work Plan Priorities. The latter document lists the highest-priority items for 2025 as outlined in its 2023-2025 strategic plan.

Board members then approved a set of proposed compensation changes resulting from a market study performed earlier this year by Meridian Compensation Partners at the direction of NERC’s management. The ERO’s governance guidelines require NERC to perform such a study every three years, along with an annual review of trustee compensation.

As explained by Trustee George Hawkins, Meridian’s study found that NERC’s average trustee pay of $141,000 is “in the bottom half of the competitive pay range” and that “an increase in trustee compensation is warranted.” NERC’s Corporate Governance and Human Resources Committee recommended that compensation be adjusted over the next three years as follows:

    • Annual board retainer: from $135,000 currently to $150,000 in 2025, $160,000 in 2026 and $170,000 in 2027.
    • Committee chair fee: from $10,000 now to $15,000 in all three years.
    • Board chair retainer: from $47,500 to $55,000 in all three years.
    • Vice chair retainer: from $10,000 to $15,000 in all three years.

Board advisory and liaison support fees would remain unchanged at $5,000 per year.

Board to Trial New Meeting Schedule

Chair elect Suzanne Keenan finished the meeting by presenting attendees with an updated schedule for board meetings that will see trustees gather in person more often.

For the past two years, NERC’s board has been holding two in-person meetings per year, in February and August. The May meeting has followed a hybrid format in which trustees and Member Representatives Committee members meet in person while other attendees join remotely, with the MRC and board’s final meetings of the year held entirely online.

Keenan said trustees have received feedback over the past two years indicating “a clear concern” among industry stakeholders about “the length of time without an in-person meeting between August and February.” As a result, the board decided on a new “cadence” of meetings that will debut in 2026.

Under the new schedule, Keenan said, the board will hold three in-person meetings each year, in February, June and October. The February meeting will be held at a hotel in the U.S., while the June meetings will alternate annually between NERC’s D.C. office and a hotel in Canada. For the October meeting, in years when the board meets in Canada, trustees and the MRC will gather at NERC’s D.C. office; in other years they will meet at a U.S. hotel.

Keenan said the board will consider 2026 and 2027 a “trial period” for the new schedule, with a review planned for December of both years to determine if any further adjustments are needed. She expressed hope that the schedule will “deconflict with some of the larger industry conferences” such as the annual CAMPUT conference of Canadian utility regulators held in May.

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NEPOOL Markets Committee Briefs: Dec. 10, 2024

ISO-NE continued work with stakeholders on its capacity auction reform (CAR) project at the NEPOOL Markets Committee (MC) meeting Dec. 10, previewing 2025 discussions on the transition to a prompt capacity auction.  

ISO-NE plans to kick off detailed discussions on a prompt capacity auction and associated resource retirement reforms in early 2025. The prompt changes are intended to reduce the time between capacity auctions and capacity commitment periods from more than three years to just a few months. 

The RTO intends to file these changes with FERC in late 2025 before starting work on a second filing focused on accreditation reforms and developing a seasonal capacity market. The filings are intended to be complementary, but the initial filing must be able to stand on its own. ISO-NE intends for both filings to take effect for the 2028/29 CCP (CCP19). 

For resource retirements, the move to a prompt auction would require the RTO to “decouple the deactivation process” from the capacity auction bidding process, Chris Geissler of ISO-NE said. While resources currently indicate their plans to retire through the forward capacity market, a prompt market would not provide enough time for ISO-NE to respond to these retirements before the CCP.  

When decoupled from the capacity market, “deactivation notices would be due less than four years in advance, but well before the auction is run to allow the ISO time to assess whether the deactivation raises any concerns with respect to local transmission security or market power,” Geissler said.  

The move to a prompt market also would require ISO-NE to evaluate how it treats resource entry. While the current forward capacity market allows resources that are not yet in operation to bid into the market, this has caused some “ghost capacity” issues, in which resources that fail to come online in time for the CCP affect the clearing price. 

“Under a prompt auction, where the auction is run much closer to the delivery period, new resource qualification can be substantially simplified,” Geissler said. “The shorter auction activity timeline and new resource qualification rules may alleviate the concerns about phantom entry and delayed operation that exist today.” 

IMM Report

Also at the MC, the ISO-NE Internal Market Monitor (IMM) presented its markets report for summer 2024, which found that “energy market outcomes were competitive, energy supply mitigation was infrequent and there was no evidence of impactful capacity withholding overall.” 

The overall wholesale market value increased by about 21% over the 2023 value, Kathryn Lynch of the IMM said. While gas prices were down by about 21%, this was offset by higher loads and resource retirements, Lynch noted. 

Real-time reserve payments also increased to nearly $24 million — compared to about $4 million in 2023 — because of longer capacity scarcity events, Lynch said.  

The system experienced two capacity scarcity conditions over the summer, which were driven by generator outages and high loads, Lynch said. Oil resources took a significant financial hit during these events, receiving more than $18 million in net pay-for-performance (PFP) charges across both events. Non-combined-cycle dual-fuel resources received more than $12 million in net PFP charges, and coal resources received nearly $4 million in charges. 

In contrast, imports performed extremely well during these events, earning nearly $29 million in net PFP credits, while nuclear resources and combined-cycle dual-fuel resources each earned more than $3 million in net PFP credits.  

MC Votes

Prior to the meeting, NEPOOL announced the MC has elected Ben Griffiths of LS Power as vice chair for 2025. 

The committee voted to approve market rule revisions clarifying the metering of storage as transmission-only assets. The MC also referred to the Generation Information System (GIS) Working Group a proposal from the Vermont Public Utility Commission to make changes to the GIS system “to reflect the addition of a new tier of resources to the Vermont Renewable Energy Standard.” 

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Virginia Legislature Report Tackles How to Meet Surging Demand from Data Centers

Even meeting half of the projected demand from new data centers in Virginia over the next 15 years will prove difficult, said a report released by a legislative commission. 

The Joint Legislative Audit and Review Commission (JLARC) released “Data Centers in Virginia” at a hearing Dec. 9. It included recommendations for legislative and other actions the state could take to deal with the rapid growth in electricity demand. 

If the sector continues growing at forecast rates, overall demand in the state is expected to double in the next 10 years, according to an independent forecast JLARC paid for, and that’s in line with PJM’s forecasts. 

“A substantial amount of new power generation and transmission infrastructure will be needed in Virginia to meet unconstrained energy demand or even half of unconstrained demand,” said the report. Building that infrastructure “will be very difficult to achieve, with or without meeting the Virginia Clean Economy Act (VCEA) requirements.” 

New solar facilities would have to be added at double the rate they were this year, more offshore wind than has been secured for even potential development would need to be built, and the state would have to add natural gas plants at a rate faster than the busiest period of their construction, which was from 2012 to 2018 in Virginia, said the report. 

“Under Scenario 1, meeting unconstrained demand would require adding 150% more in-state generation capacity, 40% more transmission and importing 150% more energy,” JLARC staffer Mark Gribbin said at the hearing. “Under Scenario 2, which again is only half the demand materializes, we’re still looking at doubling existing generation, 35% more transmission and 55% more imports. In short, either scenario would require a massive increase in energy infrastructure.” 

The model predicts some of that infrastructure demand would be needed regardless of data center demand, but they are driving most of it, Gribbin added. 

The modeling also included scenarios where the Virginia Clean Economy Act was followed and those where it was not. All scenarios include some new natural gas power plants ranging from 9,900 MW to 11,900 MW in the low demand cases, and 15,300 to 19,000 MW in the high demand cases, with the climate law’s achievement representing the lower numbers. 

“If you look at those, they’re not that far apart in terms of what gets built,” Gribbin said. “The reason for that is because those VCEA renewable requirements do not apply to the co-ops.” 

While data centers exist in other parts of the state, they’re concentrated in Northern Virginia and in the territories served by co-ops, with JLARC expecting 60% of data centers to be located in co-op territory, he added. 

Northern Virginia is the largest data center market in the world, with 13% of all reported global capacity and 25% of capacity in the Americas, said the report. It is nearly twice the size of the second-largest market, Beijing, China, and three times the size of the second-biggest market in this hemisphere, Hillsboro, Ore. 

“The region’s role in the early stages of the internet’s development gave it a head start as a key data center hub,” the report said. “In the mid-20th century, early data processing companies contracting with government agencies and high-technology government labs were drawn to the region given its proximity to their federal government customers. The establishment of an internet exchange point in the 1990s further attracted major telecommunications and early internet companies to the region.” 

With the growth of the internet this century, the capacity in Northern Virginia, and in other parts of the state, especially along Interstate 95, continued to grow because locating data centers closer together cuts “latency,” which Gribbin said was a key to the sector’s expansion in the area. 

“If I have a data center here and a data center across the street, those two data centers can communicate a lot faster,” he added. “So, if I am browsing an internet site, or if I’m doing some sort of financial transaction, basically it speeds up how fast they can communicate. And, so, when you start putting more and more data centers and with more and more business customers next to each other, they can communicate very fast.” 

While hosting the largest concentration of data centers comes with issues, it also benefits the state to the tune of 74,000 jobs, $5.5 billion in labor income and $9.1 billion in GDP every year. Most of those benefits accrue during the construction of data centers. 

Data centers also can be a major taxpayer for their communities, though some have offered lower rates to attract them, with the report saying they range from between 1 and 31% of localities’ total revenue. 

Expanding the facilities away from the I-95 corridor to more economically distressed parts of the state could benefit those communities, but that brings up issues with latency and lack of local infrastructure, the report said. 

“However, these localities may be able to compete for data centers running certain artificial intelligence (AI) workloads, such as training,” the report said. “These localities could potentially become more attractive to the industry if they are able to proactively develop industrial sites suitable to data centers.” 

The report found that, so far, data centers are not driving bill increases for other classes of power customers, but with the major infrastructure needs on the horizon, that could change. 

“Even though current rate structures appropriately allocate costs across customers, data centers’ increased demand will likely increase system costs for all customers, including non-data center customers,” the report said. “This is because current utility rate structures are not designed to account for sudden, large cost increases from the construction of new infrastructure to serve a relatively small number of very large customers.” 

The typical residential customer could see their bills rise by $14 to $33 per month by 2040 depending on how many data centers are built, said the report. 

“Establishing a separate data center customer class is a first step utilities could take to help insulate residential and other customers from the energy cost impacts of the industry,” the report said. 

The report said co-ops treat data centers as their own separate class of customers already. It also suggests that Dominion Energy develop a plan to address the risk of any infrastructure investments being stranded with existing customers should the firm build infrastructure for data centers that do not come.  

Another policy lever the state has is its sales tax exemption for new data centers, which provided $928 million in tax savings to the sector last year. The capital-intensive industry views that as a valuable incentive, and other states competing with Virginia support it. 

The incentive has been in place since 2010 and is set to expire in 2035, and if the legislature let it lapse, development in the outer years would slow. The report also suggests cutting the incentive or tying it to requirements for data centers to maximize efficiency, or participating in demand response programs. 

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Pathways Step 2 Not Good Enough, Markets+ Backers Say

The West-Wide Governance Pathways Initiative still grapples with political uncertainties and governance concerns despite efforts to fix those issues as it seeks to create an independent “regional organization” (RO) to oversee CAISO’s Western electricity markets, proponents of SPP’s Markets+ contend.

The claim came in a Dec. 6 addendum to the first “issue alert” on governance the Markets+ backers published Aug. 7. The proponents have issued several alerts to highlight the purported advantages of Markets+ over CAISO’s Extended Day-Ahead Market (EDAM).

The contributors include Arizona Public Service, Chelan County PUD, Grant County PUD, Powerex, Public Service Company of Colorado, Salt River Project, Snohomish PUD, Tacoma Power, Tri-State Generation and Transmission Association and Tucson Electric Power — all of whom helped fund the Phase 1 development stage of Markets+.

The addendum is a response to the West-Wide Governance Pathways Initiative’s Launch Committee voting to approve its “Step 2” proposal, which divides functions between CAISO and the new independent RO backers seek to create to oversee the ISO’s Western real-time and day-ahead markets.

While recognizing the work that went into developing Step 2 and the “incremental benefits” it would provide, the Markets+ proponents argued the plan failed to resolve key issues, such as independent governance and broader political support.

The addendum noted that under Step 2, the Pathways Initiative must secure a legislative change in California to establish the RO and grant it power to set market policy for EDAM, while CAISO would “retain its current balancing authority and market operator roles.”

“The success of the Step 2 Proposal depends on uncertain future events including legislation in California that has not yet been developed or approved and subsequent implementation of that legislation by the California ISO Board of Governors and other entities,” the addendum stated.

Additionally, while Step 2 will “provide incremental benefits to all energy markets in the West,” the question of whether the proposed RO will be independent of CAISO has not been resolved, according to the Markets+ backers.

“This includes a single shared tariff and an intertwined relationship across numerous areas, such as shared staffing, and financial and regulatory responsibilities associated with the organization being borne by CAISO,” the addendum said. “In addition, CAISO would be responsible for day-to-day market operations with limited supervision by the RO.”

The Markets+ backers contend it’s “not clear whether any future California legislation will enable the CAISO BAA to be part of any RTO governed by the RO.”

The addendum also raised concerns over transparency in the selection of the Step 2 Formation Committee, uncertainty about how the RO would address costs and cost allocation, and the risk to Western ratepayers outside the CAISO BAA “until a fully independent governance structure is eventually achieved (if ever).”

Pathways supporters have addressed some of the concerns raised in the addendum. In October, key backers of Pathways told state energy officials they’re confident California lawmakers will pass legislation next year to relax state oversight on CAISO’s markets and establish the RO. Pathways supporters in California have begun discussions with legislative staff who likely would contribute to crafting the bill.

The Pathways initiative also has won over previous skeptics, with the International Brotherhood of Electrical Workers indicating they will sponsor the legislation needed to implement Step 2.

Kathleen Staks, executive director of Western Freedom and Pathways Launch Committee co-chair, cited the Step 2 proposal in an email to RTO Insider on Dec. 9, stating the plan lays the foundation to “enable the West to create a suite of voluntary wholesale electricity market services as stakeholders and participants desire and require, with each state retaining its unique decision-making autonomies and participating on a level playing field.”

Staks noted that the Launch Committee “is not engaging in any legislative efforts” and “[a]ny future legislative needs will be determined by the RO and western stakeholders and the CA legislature.”

“The proposed legislative scope for 2025 does not include a change to the CAISO BAA,” Staks added. “The Launch Committee did include a section in the proposal about a potential scenario for co-optimization of the transmission system … that could be possible without further legislative change.”

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PJM MIC Briefs: Dec. 4, 2024

PJM Lays out 2nd Planned Capacity Market Filing

PJM Vice President of Market Design and Economics Adam Keech told the Market Implementation Committee on Dec. 4 that the RTO plans to file governing document revisions with FERC to expand the requirement that resources must offer into the capacity market to also apply to all resources holding capacity interconnection rights, namely intermittent, hybrid and storage resources.  

The proposal also may include related changes to the market seller offer cap (MSOC). 

A Members Committee meeting has been scheduled for Dec. 13 for PJM to consult with stakeholders on the proposal, and Keech said additional presentations are likely at the Markets and Reliability Committee’s Dec. 18 meeting. With the aim of having the changes effective for the 2026/27 auction, scheduled to be conducted in July, Keech said PJM is targeting making the filing by Feb. 4, which is the deadline for generators to withdraw their capacity status. 

PJM had signaled it was considering a proposal to expand the must-offer requirement in its request that FERC dismiss a complaint by several consumer advocates that the rules in place for the 2026/27 Base Residual Auction (BRA) would not adequately mitigate market power, among other concerns. The RTO argued that would resolve the advocates’ concerns (EL25-18). (See Consumer Advocates File Wide-ranging Complaint on PJM Capacity Market.) 

“PJM is actively considering whether there is sufficient time to fully develop a proposal that would expand the must-offer requirement to intermittent resources, capacity storage resources and hybrid resources without further delaying the BRA for the 2026/2027 delivery year scheduled for July 2025,” the RTO wrote. “If PJM determines that is possible, the Members Committee will be promptly consulted.” 

In response to a stakeholder question, Keech said the filing would not propose requiring demand response resources to offer into the market. 

Meeting materials posted for the Dec. 13 MC meeting state the proposal would use the Capacity Performance quantifiable risk (CPQR) value as a floor to the MSOC. Under the status quo, offers can be capped at zero, which PJM says can be less than their risk of taking on a capacity commitment. 

“This ensures that capacity market sellers can always submit an offer that reflects the incremental risk of taking on a capacity commitment,” according to the presentation. 

The materials also say PJM plans to allow segmented offer caps as part of the filing, which would allow weather-dependent generators to reflect increased risk at higher capacity commitments. 

Several renewable developers and their advocates objected to making changes of this magnitude in such a manner. 

“This is not a way to run a wholesale market and inspire stakeholder [and] investor confidence,” Tangibl Group Director of RTO and Regulatory Affairs Ken Foladare said. “We can’t keep going on this way.” 

In a series of reports on the 2025/26 BRA, the Independent Market Monitor argued that categorically exempting resources from the must-offer requirement suppresses supply and inflates clearing prices. It included a scenario in which the auction was run with a mandate that those resources offer into the market, which the report said would have reduced market seller revenues by over $4.1 billion, a 28.2% reduction. 

Monitor Joe Bowring told RTO Insider that PJM’s proposed MSOC approach would revive a component of an RTO proposal that was rejected by FERC in February. (See FERC Rejects Changes to PJM Capacity Performance Penalties.) He said it would take an incorrect view of resource risk by expecting intermittent resources to run at times they are unable to, and then allowing those generation owners to account for that in the CPQR component of their offer. Instead, he said PJM should exempt intermittents from underperformance penalties when they cannot operate because of ambient conditions and reflect that in allowable CPQR elements. 

PJM Seeks Revised Black Start Compensation

PJM’s Glen Boyle presented additional details on the RTO’s proposal to rework two formulas used to determine compensation for resources providing black start service. 

The change would replace the use of zonal net cost of new entry (CONE) values in the formulas with a five-year average of the RTO-wide CONE. The affected formulas are the NERC Critical Infrastructure Protection (CIP) rate and the base formula rate, the latter of which Boyle said is used by about 90% of black start units. There currently are no resources on the CIP rate, used for units that are designated as critical infrastructure by NERC. 

The proposal is in response to CONE values in several locational deliverability areas (LDAs) falling to zero in the planning parameters posted for the 2026/27 BRA, substantially reducing compensation for black start units under the status quo formula. The diminished CONE is fueled by a higher energy and ancillary service (EAS) offset for combined cycle generators — which is set to be used as the reference resource for the first time in the 2026/27 auction — and a greater spread between gas and electric prices generally increase energy market revenues for gas units. 

The formula is one of several areas of PJM’s capacity market affected by a net CONE of zero. Nonperformance penalty rates also would fall to zero in those LDAs, and the variable resource requirement (VRR) curve, which defines the slope of the market’s demand curve, would become substantially steeper. (See “Proposal to Modify Capacity Market Components,” PJM Stakeholders Wary of Expedited Interconnection Proposal.) 

Boyle said decreasing revenues could cause resources to cease black start participation, prompting PJM to hold more requests for proposals for the service and resources that require capital upgrades to be committed at greater cost. 

While the change would not affect the capital cost recovery avenue for black start compensation, Boyle said that is available for units that would require upgrades to provide the service with the ultimate goal of transitioning them to the base formula or CIP rate. 

Bowring said there is no logical tie between net CONE and the costs for a generator to provide black start service. He said PJM should work with stakeholders to find a replacement formula that does not include CONE as an element and that does include the actual costs of providing black start service plus an incentive.  

Bowring also said proposals to index a net CONE value to inflation ignore the fact that one-half of the formula, the net revenues, moves with market energy prices and does not move with inflation. The higher the net revenues, the lower the net CONE, and vice versa, he said. 

PJM Preparing to Implement New Synchronized Reserve Deployment

PJM’s Michael Olaleye reminded the committee that the RTO is preparing to roll out changes to its synchronized reserve deployment dispatching process and seeks stakeholder feedback this winter. 

In addition to the existing spin status notification and all-call notification, dispatch instructions for synchronized reserve events will be sent as updates to reserve units’ basepoints. (See “Stakeholders Endorse Reserve Rework, Reject Procurement Flexibility,” PJM MRC Briefs: July 24, 2024.) 

Any resources with real-time synchronized reserve assignments that don’t see an update to their basepoints should deploy their full commitment in response to any all-call signal. For DR resources, dispatch instructions will be sent through DR Hub. 

PJM is in the process of testing its automatic generation control software and aims to implement the changes around Dec. 16 to be ready for winter operations. A notification will be out a week in advance. 

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PJM PC/TEAC Briefs: Dec. 3, 2024

Planning Committee

Stakeholders Endorse Quick-fix Revisions to Site Control Manual Requirements

The PJM Planning Committee endorsed revisions to Manual 14H to clarify the changes developers can make to the site control requirements for their projects at different phases of the interconnection process.

Brought as a fast-track item, the proposal was voted on concurrently with the issue charge. (See “PJM Floats Fast Track Proposal on Site Control Modifications for Queue Projects,” PJM PC/TEAC Briefs: Nov. 6, 2024.)

The changes state that facility sites can be reduced so long as they continue to meet the minimum acreage and energy output provided in the project application. Developers can add parcels to a project at Decision Point 1 so long as they are either adjacent to the site or evidence of easements is provided. If the energy output is reduced, the land requirements also correspondingly would go down.

The revisions expand language at Decision Point 2 stating there are no specific site control evidentiary requirements associated with that phase to include that “site control must be maintained throughout the cycle process.” A note also would be added stating that parcels can be added similarly to DP1, with the caveat that a one-year term would be imposed from the end of Phase 2 of the relevant study cycle. Parcels also would be allowed to be removed.

No additions would be permitted at the final Decision Point 3, but reductions would be allowed so long as the acreage-per-megawatt and evidentiary requirements continue to be met. Once a generator interconnection agreement is signed, any site control changes would require a necessary study agreement (NSA) to determine permissibility.

The revisions also would correct Exhibit 10 in the manual, which inadvertently used a diagram from another exhibit when describing how generators interconnect to existing transmission substations.

PJM’s Jonathan Thompson said the revisions were drafted following stakeholder feedback seeking more leniency in site control requirements after the RTO published guidance to developers in the spring.

Preliminary Large Load Adjustment Requests for 2025 Load Forecast

PJM’s Molly Mooney presented preliminary figures for large load adjustments (LLAs) that may be included in the upcoming 2025 load forecast, expected to be published before the end of January.

Compared to the LLAs included in the 2024 forecast, the adjustments would increase from about 20 GW to about 37 GW by 2030. That figure includes LLAs that PJM expects will be accepted for the forecast, which shaves about 14.4 GW off the LLA that utilities submitted for inclusion in their forecasts. The adjustments span about a dozen zones and include data center and manufacturing loads, as well as voltage optimization projects.

“We understand this is a challenging issue because of the size of the load and the speed,” Mooney said.

James Wilson, a consultant to state consumer advocates, said PJM does not have ways of ensuring that LLA requests submitted by utilities are not duplicates of projects that are being considered at sites across multiple zones. While the estimates are likely to be accurate at least a few years out, he said it is not clear how strong the figures are well into the future, raising the possibility that there could be significant transmission buildout that consumers must pay for without assurances that it is necessary.

“We’re really left with no idea how firm this forecast is on a year-by-year basis,” he said.

Paul Sotkiewicz, president of E-Cubed Policy Associates, said more transparency is needed around how LLAs are submitted by utilities and then how PJM determines which will be included in the forecast.

PJM Seeks Stakeholder Attention on Spare Equipment Requests

PJM Executive Director of System Operations Dave Souder presented a request for the Transmission & Substation Subcommittee to review the Spare Equipment Philosophy to consider if the guidelines are adequate for extreme weather conditions that cause extended equipment outages.

The subcommittee would consider expanding the document to include equipment likely to fail during extreme weather, the feasibility of a targeted return to service that requires keeping spare equipment on hand and the logistics of delivering that equipment as part of restoration plans.

Transmission Expansion Advisory Committee

PJM Unveils Recommended Projects for 2024 RTEP Window 1

PJM plans to recommend $5.8 billion of transmission upgrades in the first window of the 2024 Regional Transmission Expansion Plan (RTEP) to allow rising demand in the east to be matched with expected generation entry in the west.

The proposal is set to go for a second read at the Transmission Expansion Advisory Committee’s Jan. 7 meeting, with Board of Managers approval likely to be sought in the first quarter of 2025.

Director of Transmission Planning Sami Abdulsalam said it should come as no surprise to stakeholders that significant load growth is driving the need for new transmission in this window, noting that similar factors have been at play in previous RTEP cycles as well. One of the aspects PJM considered when selecting proposals for the 2024 RTEP was expandability to allow additional upgrades to be added in future windows if the load growth continues.

“The 2024 RTEP Window 1 addresses accelerated load growth in various areas of the PJM footprint, changes in the mix of generation resources and the resulting shifts to regional power flows,” the RTO said in an announcement of the recommended projects. “The forecasted load growth is driven in part by data center load additions and the electrification of vehicles and building heating systems.”

The package includes a Transource Energy project to construct a new 765-kV line running from American Electric Power’s John Amos substation in West Virginia through the Welton Springs site to a new 765/500-kV Rocky Point facility in Virginia. Rocky Point would be tied into the 500-kV Doubs-Goose Creek, Doubs-Aspen, and Woodside-Goose Creek lines. Construction of the corridor from John Amos to Rocky Point would be assigned to First Energy, with Transource doing upgrades in the AEP region.

Another Transource proposal in Virginia that PJM plans to recommend would build a 765-kV line to the south from the Yeat substation through North Anna to Joshua Falls. A Dominion Energy proposal was selected to build a 500-kV loop tying a new Kraken facility into North Anna and Yeat. Transource would be assigned the southern corridor, while Dominion would construct the Kraken loop.

Transource’s southern corridor was selected in part because of its timing flexibility, with components like a new 765/500-kV Vontay substation able to be delayed until load materializes. Several substations were proposed to the north of that corridor, which PJM determined could be supplemented by the 765/500-kV Yeat facility.

Residents from Maryland and Northern Virginia spoke against the portfolio at the meeting, saying it would continue to burden residents along existing corridors and could require the taking of homes through eminent domain.

Abdulsalam stressed that PJM does not make the final route selection, which would be determined by the selected transmission developers in conjunction with state regulators.

Supplemental Projects

AEP presented a $453 million project to rebuild around 68 miles of the 345-kV Olive-Reynolds line in Central Ohio to address degradation of infrastructure along the corridor. The project is part of a larger effort to replace about 1,114 miles of paper expanded/air expanded (PE/AE) conductor in the utility’s footprint as they reach the end of their useful lives and concerns mount about core corrosion with that technology. The project has an expected in-service date of May 30, 2031.

Public Service Electric and Gas presented a $64.5 million project to construct a new Pemberton substation in New Jersey along its 230-kV Lumberton-Cookstown line. The project would address a contingency overload at the Lumberton facility, which serves 17,000 customers with a station capacity of 59.41 MVA. A peak load of 73.2 MVA was observed at the site in 2022. Pemberton would be equipped with two 230/13-kV transformers, with a projected in-service date in December 2029.

Dominion presented an $88 million project to construct two new 230-kV lines between the Devlin and Pegasus substations in Northern Virginia to mitigate a 300-MW load drop violation identified in the 2024 do-no-harm analysis. The new lines would follow a new right of way with $40 million of land acquisition expected and $33 million of line infrastructure needed. An additional $15 million would cover new breakers and equipment at the two substations. The project is in the conceptual phase with an in-service date of June 15, 2029.

Another Dominion project would build a new substation, to be named Pegasus, to serve a data center complex in Prince William County with a total load exceeding 100 MW. The $28.5 million project would cut Pegasus into the existing 230-kV lines between Hornbaker and the Pioneer and Liberty substations. It is in the engineering phase with a projected in-service date of April 14, 2027.

A $14 million project would construct a new Bristow substation along the 230-kV line from Hornbaker to Nokesville to serve a data center complex in Manassas with a projected summer 2029 load of 213 MW. The complex would be situated adjacent to Hornbaker, requiring the line to Nokesville to be re-terminated at Bristow, which then would be connected to Hornbaker with two 230-kV tie lines. The project is in the engineering phase with a projected in-service date of April 30, 2028.

Dominion also presented a $36.9 million project to build a new substation, named Meadowville, to serve a data center in Chesterfield County that is expected to see 300 MW of load by 2029. The facility would be adjacent to the planned Sloan Drive substation and would be connected by two 230-kV lines terminating into a six-breaker ring configuration. The project is in the engineering phase with a projected in-service date in the first quarter of 2028.

A co-located substation named White Mountain would serve an additional data center adjacent to Meadowville with a projected 2029 load of 100 MW. The $19 million project would be cut into the 230-kV Meadowville-Sloan Drive line and is in the engineering phase with an in-service date in the first quarter of 2028.

A 300-MW contingency violation was identified with the new Dominion substations in the Sloan Drive region, as the load would be served by two sources at the Allied and ICI substations. Dominion presented a $92.7 million project to add a third avenue for power to flow into the region by constructing a line from Meadowville, through the existing Enon substation, to Sycamore Springs. The Enon site would be expanded as part of the project, and the 230-kV Enon-Sycamore Springs line also would be rebuilt with double-circuit structures. The project is in the engineering phase with a projected in-service date in the fourth quarter of 2028.

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PJM OC Briefs: Dec. 5, 2024

Manual 1 Revisions Endorsed 

The Operating Committee endorsed a pair of revisions to Manual 1: Control Center and Data Exchange Requirements, updating definitions to be clearer and more in line with other manuals through the document’s periodic review and approving a quick-fix proposal to detail alternate communication methods available as backups if SCADA software fails. (See “PJM Presents Revisions to Manual 1 Addressing Hybrid Resource Rules, Loss of EMS Real Time Assessment,” PJM OC Briefs: Nov 8, 2024.) 

The quick fix, which allows a proposal and issue charge to be voted on together, adds language on PJM’s AltSCADA communication process for transmitting inter-control center communications (ICCP) links between transmission owners and PJM using PJM’s SecureShare protocol and spreadsheet file formats. The revisions also include requirements for alternate data and expand PJM’s view-only mode for preventing ICCP data from being edited during planned maintenance windows where the risk of incorrect data being submitted is increased. 

PJM’s Ryan Nice said the AltSCADA proposal covers a wide range of catastrophic SCADA errors at a low cost and provides a lot of value. Some TOs are integrating the alternate modes into their systems, and he’s hopeful more will as well. 

November Operating Metrics

PJM saw a 1.25% hourly and 1.44% peak forecast error rate in November, both below the 25-month rolling average, according to lead engineer Marcus Smith. Three days saw underforecasting error just over the RTO’s 3% benchmark target on Nov. 10, 15 and 28. Cooler than expected temperatures were factors for all three days, as well as overcast conditions and rain on the 10th and 28th.  

The month saw three shared reserve events, three spin events, one conservative operations alert and 12 post contingency local load relief warnings (PCLLRWs). Two shortage cases were approved Nov. 22 due to generators tripping offline and interchange. 

The spin event was issued Nov. 10 and lasted 10 minutes and 49 seconds. A total of 1,919 MW of reserves were committed, including 481 MW of demand response (DR) with an average response rate of 77% — higher for DR resources at 94%. 

Other Committee Business:

The day-ahead scheduling reserve (DASR) value for 2025 increased to 4.5% for 2025, up 0.1% from the previous year, setting the minimum operating reserve that will be in place Jan. 1. The value is a combination of the three-year average load forecast error, which was 2.19%, and forced outage rate, at 2.31%. Stakeholders endorsed revisions to Manual 13: Emergency Operations during the Nov. 8 OC meeting to codify how the DASR is used to determine when the 30-minute reserve requirement may be insufficient. (See “Stakeholders Endorse Quick Fix Solution on Day Ahead Scheduling Reserve Calculation,” PJM OC Briefs: Nov 8, 2024.) 

The committee endorsed by acclamation revisions to Manual 14D: Generator Operational Requirements drafted through the document’s periodic review. The changes are set to be considered by the Markets and Reliability Committee during its Dec. 18 meeting.  

Language presented during first reads of the document that would have added a new Section 8.4 detailing the rules for repowering a wind generator was removed following stakeholder feedback, with some of the provisions instead included in Attachment E and Section 8.2.1. 

An existing requirement that new resources must submit reactive capability curves to PJM before entering commercial service would be clarified, as well as a requirement that such generators complete reactive testing within 90 days of beginning operations. A note was added to Section 10 stating that information about black start is confidential and clarifying data sharing around cold weather operating limits.  

PJM’s Eli Ramsay notified the committee that the RTO will open its winter fuel inventory data request from Dec. 5 through 16 to catalog fuel availability at the start of the season. The request will remain open through March 15, with updates requested during the first week of each month. 

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FERC Fines PSE&G $6.6M for Inaccurate Info on Transmission Line

FERC on Dec. 5 approved a settlement between its Office of Enforcement and Public Service Electric and Gas imposing a $6.6 million civil penalty on the utility for allegedly “failing to fully and accurately provide information” to PJM about a project to rebuild its 230-kV Roseland-Pleasant Valley (RPV) transmission line (IN21-5).

The $546 million project was included in PJM’s 2018 Regional Transmission Expansion Plan (RTEP) after PSE&G determined the line had reached the end of its useful life. That determination was supported by presentations staff made to PJM that stated external consultants found that hundreds of steel lattice towers exceeded 95 to 100% of their loading capability and dozens had “foundations requiring extensive reconstruction.”

According to the approved agreement, those presentations did not specify that the consultants were directed to use an assumption that 10% of the steel on the towers had eroded away and omitted 12 pages of another consultant report from 2013 that found no tower foundations in need of replacement. The utility also did not provide PJM with a 2016 report finding a smaller number of foundations were in need of rebuilding.

“The relevant PSE&G external consultant’s Jan. 12, 2016, report would have informed PJM directly from such consultant materials that such consultant found a total of only eight towers on the Branchburg-to-Pleasant Valley segment of the RPV line to have one or more legs with foundation condition D — wherein the precise words ‘complete failure of concrete foundation requiring extensive engineered foundation reconstruction’ were used by PSE&G’s external consultant,” FERC said. “PSE&G did not provide to PJM the external consultant report.”

In a statement to RTO Insider, PSE&G said, “RPV is a needed part of the PJM transmission system. Before it was rebuilt, it was one of the oldest lines on PJM’s system, with 90% of its towers being built between 1927 and 1930. We have worked cooperatively with FERC in their review and have implemented processes to ensure such issues do not arise again.

“FERC did not challenge the end-of-life determination that determined the need to rebuild the RPV line to ensure reliability and system benefits such as enhanced reliability. FERC’s review found that there were inaccuracies in materials that were provided to PJM as part of the approval process in 2017.”

In an email, PJM spokesperson Susan Buehler told RTO Insider, “PJM relies on information provided to us by asset owners to make important decisions that impact the power system and consumer costs. That information must be precise and truthful, and action taken by the FERC in this matter reaffirms this principle.”

Presentations the utility made to PJM before the project was accepted into the RTEP said that 67 towers had “foundations requiring extensive reconstruction,” but consultants recommended leg foundation rehabilitation for just eight towers. In discussions with FERC investigators, PSE&G said it included 59 towers with foundations that the consultant recommended for “repair via replacement or reinforcement.”

Estimates were also provided to PJM about the number of towers that exceeded loading capabilities, but PSE&G did not disclose that those figures were mathematically derived based on assumptions about steel erosion, rather than inspections of the infrastructure. That assumption was itself based on “extrapolation of corrosion measurements made by another external consultant who had actually inspected and measured towers in the field.” PSE&G reported that 221 towers exceeded 95% of their loading capability and 143 exceeded 100% based on those assumptions, but the consultant found that only 75 exceeded 95% of their loading capability and only four exceeded 100%.

The agreement also states that PSE&G did not raise the possibility of repairing the towers, nor provided examples of similar work that the utility routinely conducts. It notes that specifying costs is not required by the RTEP process.

“For instance, the relevant PSE&G external consultant’s 2016 report identified eight steel lattice towers having a total of 10 legs in foundation condition D — i.e., ‘requiring extensive engineered foundation reconstruction.’ PSE&G routinely paid such external consultant to perform such work for a cost on the order of $20,000 to $40,000 per concrete leg foundation,” FERC said.