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December 23, 2024

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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.

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FERC Rejects PJM and Transmission Owners’ CTOA Proposals

FERC has rejected revisions to PJM’s transmission planning process that critics argued would have impinged upon the RTO’s independence in favor of its transmission owners (ER24-2336, et al). 

The Dec. 6 order involves three separate filings, one of which is a complaint that moves the regional transmission expansion process (RTEP) procedures from the operating agreement to the tariff and others that would reform the Consolidated Transmission Owners’ Agreement (CTOA). (See PJM Members Vote Against Granting PJM Filing Rights Over Planning.) 

Transmission owners supported the rules. They were opposed by other stakeholders, including the Organization of PJM States, consumer advocates, municipal utilities, LS Power and environmentalists. PJM had to file the complaint because stakeholders rejected the proposal in an earlier vote.  

“We reject the CTOA amendments because we find that certain CTOA amendments contravene Order No. 2000’s requirement that RTOs be independent of control by any market participant or class of participants in both reality and perception,” FERC said. 

The proposed Article 7, Section 7.9, violates the independence principles of Order 2000 by providing transmission owners with an exclusive opportunity to affect what filings PJM submits under Section 205 of the Federal Power Act. Order 2000 requires organized markets to have a decision-making process that is independent of control of any market participant or class or participants, with which Section 7.9 conflicts. 

Section 205 filings could affect changes to the PJM tariff, Operating Agreement, Reliability Assurance Agreement Among Load Serving Entities in the PJM Region, or any document containing PJM’s rates and charges, or rules and regulations affecting or pertaining to such rules and changes. 

“While the basis of a dispute may be limited to disagreements over contractual obligations, the language of proposed Section 7.9 would allow PJM TOs to dispute any FPA Section 205 filing, not just a filing related to transmission planning, as long as PJM TOs contend that the FPA Section 205 filing could contravene Articles 2, 4, 5, 6 [and] 7 of Attachment B of the CTOA,” FERC said. 

The rules affecting the RTEP process also could affect the RTO’s independence requirements by giving transmission owners too much of a role. 

“While PJM TOs could not unilaterally (i.e., without PJM’s consent) amend the CTOA to include new transmission planning constraints or new substantive provisions that PJM must follow over commission regulations, such that they encumber PJM’s ability to maintain its status as an RTO, these provisions may provide a unique and exclusive opportunity in reality or in perception to unduly influence how PJM operates,” FERC said. “We find that it is inappropriate for PJM TOs to have a process for making potentially binding challenges to PJM’s FPA Section 205 filings that have not yet been filed with the commission.” 

One set of rule changes, called the Overlap Provisions, would have required PJM to consult with transmission owners when regional lines in the RTEP would address the same needs as a local line that is being proposed by a transmission owner. Those local lines still would be able to go forward if the transmission owner determined the RTEP line would not solve the need addressed by their project. 

Protesters argued such debates should be under FERC’s review, with the Harvard Electricity Law Initiative saying the commission previously rejected proposals to include substantive planning provisions in transmission owner agreements because they make more sense in the tariff that is subject to stakeholder participation and the rules give too much control to transmission owners. 

“We find that the Overlap Provisions do not predominantly affect PJM TOs’ rights and responsibilities; rather, they set out substantive transmission planning procedures related to the interaction between RTEP Projects and individually planned PJM TO projects, including when and how PJM and PJM TOs must consult regarding whether regional transmission solutions could more efficiently or cost-effectively address local transmission needs,” FERC said. “Because the Overlap Provisions address a substantive aspect of transmission planning in the PJM region and affect PJM’s regional transmission planning process, they should not be included in the CTOA.” 

The CTOA is meant to contain provisions that affect the rights and responsibilities of transmission owners and RTOs. The right to plan for local transmission is established clearly in other provisions of the CTOA. 

“The Overlap Provisions instead predominantly affect the substantive local transmission planning process, particularly in relation to how it might interact with PJM’s regional transmission planning process,” FERC said. “Although we recognize that the filing rights for Attachment M-3 are held by the PJM TOs, we find that it is not just and reasonable for the Overlap Provisions to be maintained in the CTOA.” 

Commissioner Mark Christie filed a concurrence with the majority, saying he agreed with the rejection of two Section 205 filings to amend the CTOA, and the result of rejecting the complaint that would have shifted the RTEP procedures from the Operating Agreement to the tariff. But he would support shifting the RTEP process to the tariff, without the other provisions infringing on the RTO’s independence, which is the position OPSI took. 

“The practical effect of moving the RTEP Protocol from the OA to the OATT is to transfer the authority over the RTEP’s development from the members of PJM to the PJM Board of Managers,” Christie said. “There is nothing intrinsically wrong in doing so; on the contrary, I agree in principle with OPSI that it should be done. The details of this move, however, are critically important.” 

Christie’s dissent argued that ISO/RTOs should not be treated as “quasi-governmental” agencies whose decisions are decided by rent-seeking participants with little role for state regulators as just another stakeholder. Giving PJM’s board full authority over RTEP would make sense, but not doing so while also giving special interest groups more influence over its decision-making authority. 

“So I see nothing inherently unjust and unreasonable in moving the RTEP Protocol from this unwieldy and special-interest driven process under the OA to the OATT, where the PJM Board can and should take full responsibility for development of the RTEP,” Christie said. “PJM would be free to provide for — and certainly should provide — ample opportunity for its members, as well as stakeholders and other interests, to comment on proposed amendments to the RTEP Protocol, but it should be the exclusive responsibility of PJM to develop and approve any changes to the rules by which the RTEP is developed and approved for submission to the commission.” 

While that change would make sense, it is vital to get the “replacement rate right,” and PJM’s filings fail on that, he added. The rules as proposed could have led to RTEP projects and local projects going forward that address the same needs, potentially wasting billions of dollars. 

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CAISO Considering Fast-start Pricing for Extended Day-Ahead Market

CAISO is considering how to apply fast-start pricing to the Extended Day-Ahead Market (EDAM), a topic that has been a sticking point for some as entities across the West decide whether to join it or SPP’s Markets+. 

Of the six FERC-jurisdictional organized markets, CAISO alone does not use fast-start pricing, a mechanism that factors the cost of starting and operating gas-fired peaking units into their wholesale market prices. 

In March, Western Energy Imbalance Market experts called for fast-start pricing as a method to provide more efficient price signals and fix certain price anomalies that can occur when least-cost dispatch starts up block-loaded fast-start units. (See WEIM Expert Calls for Fast-start Pricing to Address ‘Anomalies’.) The benefits of fast-start pricing also were highlighted in an “issue alert” published Aug. 28 by 10 entities that back the development of Markets+. (See 3rd ‘Issue Alert’ Compares Pricing Practices in Markets+, EDAM.) 

During a meeting of the Price Formation Enhancements Policy Development Working Group on Dec. 5, ISO staff and stakeholders considered how long fast-start pricing logic should apply in the real-time and day-ahead markets, as well as the implications for including fast-start pricing in EDAM. James Friedrich, lead policy developer at CAISO, highlighted the importance of amortization for the mechanism, as well as the challenges. 

“At its core, amortization is talking about fixed costs that generators incur when they start up and spread them out over time in a way that makes economic sense,” Friedrich said. “The challenge is that these costs are lumpy: They come all at once. We need to figure out a way to incorporate them into our per-megawatt-hour energy prices.” 

Without amortization, fast-start units that run for short periods rarely would be able to recover their fixed costs through energy market revenues alone, meaning the ISO would have to rely on uplift payments, Friedrich explained. By amortizing fixed costs and converting them into a per-megawatt-hour adder to the unit’s energy bid, the cost of serving load can be better reflected in the market price. 

“The key question that we’ll explore further … is exactly how we should spread these costs … across [both] the megawatts the unit produces and … the time it operates,” Friedrich said. 

Specifically, the ISO asked stakeholders to consider whether costs should be spread out across a unit’s entire minimum run time, concentrate the costs in the period the unit was needed or spread them out across the entire expected output run time. 

Some stakeholders questioned how much better off a particular resource would be under the fast-start pricing construct versus what it gets paid under the status quo. 

“Fast-start pricing is going to increase prices to customers, and in this initiative, I recall that the reason we’re looking at that is to improve price formation itself and, I would imagine, to try and attract higher- or better-quality resources,” said Stuart Kelly, a consultant at Utilicast. “But I’m trying to understand, is it really going to do that? How much better off is that higher-quality resource going to be under one of these examples here compared to the status quo?” 

In a 2016 Notice of Proposed Rulemaking (RM17-3), FERC suggested that costs should be included in prices only “during the resource’s minimum run time.” For start-up costs, the NOPR proposed to “amortize a fast-start resource’s start-up cost over the resource’s minimum run time and its economic maximum operating limit.” For no-load costs, FERC recommended dividing a fast-start resource’s no-load cost by the resource’s economic maximum operating limit. 

Attempting to amortize start-up costs beyond the minimum run time is “problematic,” FERC stated, because after the minimum, “the unit commitment algorithm may de-commit the fast-start resource if it is no longer economic, making the total run time unknown.”  

FERC eventually abandoned the NOPR and ordered specific changes in PJM, SPP and MISO. (See FERC Drops Fast-Start NOPR; Orders PJM, SPP, NYISO Changes.) 

Cost amortization varies across markets. In ISO-NE, MISO, PJM and SPP, start-up costs are amortized across the resource’s maximum output and minimum run time. In NYISO, the adjusted cost for output levels that are less than or equal to the output level that minimizes average cost is equal to that minimum average cost. 

ISO-NE had argued that implementing fast-start pricing in the day-ahead market would be a “complex and time-consuming endeavor” that would have limited benefits because most fast-start resources are committed in real time.  

“Day-ahead markets typically have much more flexibility and options to meet load, which reduces the likelihood of needing to commit fast-start units,” Friedrich said. “Even without explicit fast-start pricing in the day-ahead market, virtual bidding may bridge the gap here, and market participants that anticipate fast-start pricing impact in real time may adjust their day-ahead positions accordingly, which would converge the prices naturally between the two markets.” 

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Stakeholders Seek More Details on BPA’s ‘Evolving Grid’ Projects

Stakeholders are urging the Bonneville Power Administration to provide more transparency regarding the agency’s multibillion-dollar initiative called the Evolving Grid Project (EGP).

BPA launched the effort in April 2023 to address Oregon and Washington clean energy targets, new renewable resource additions, increased electrification of transportation, industry and buildings, and the growing need for resiliency in the face of extreme weather events.

BPA is working on 23 transmission projects with an estimated cost of $5 billion under the EGP. The proposed projects resulted from reliability studies, forecasts and BPA’s 2023 Transmission Service Request Study and Expansion Process (TSEP).

The initiative aims to increase capacity and spur regional growth in BPA’s service area. The agency announced the first 10 “EGP 1.0” projects in July 2023 and revealed the second batch in a news release Oct. 15.

However, during the agency’s Evolving Grid stakeholder workshop Dec. 4, participants called for more clarity about how the EGP will affect customers, funding decisions and other projects the agency is working on.

Lauren Tenney Denison, director of market policy and grid strategy at the Public Power Council, said some EGP decisions on the business case could have benefited from robust public conversations and processes, as has been the case with other BPA projects.

“And so when the first Evolving Grid projects moved through, it was like, ‘Whoa, we didn’t talk about that,’” Denison said.

Some participants in the meeting also targeted a chart in BPA’s presentation, in which the agency outlined factors to distinguish between “regionally needed projects” (RNPs) that would fall under EGP standards and “customer needed projects” (CNPs) that would benefit only a small set of customers.

RNPs would have to meet criteria such as being “critical for load service,” providing transmission service for a “substantial” amount of “mature” generation, supporting the region’s resource diversity and offering “regional level support of public policy.” CNPs, on the other hand, would not represent an expansion of the main grid, would require “substantial customer commitment” to avoid resulting in an incremental rate increase and would possibly provide interconnection for projects that are “not very mature.”

Approval of any project would be subject to the discretion of BPA Administrator John Hairston, agency officials noted.

Gray Area

Denison sought more clarity on whether a customer must meet all criteria to have a project developed under EGP and why some projects fall in a gray area.

“Probably nothing checks every box, and something checks a lot of boxes, or half the boxes,” Denison said. “So just understanding a little bit more of how that balances with how BPA is both looking at the projects coming through TSEP, but also how BPA is evaluating from a larger perspective what it needs to call something an evolving grid project and what that means for the other work that BPA has going on too.”

BPA staff presented a chart showing how the agency differentiates transmission projects. | BPA

Henry Tilghman, a consultant representing the Northwest & Intermountain Power Producers Coalition, similarly argued the chart should be considered a spectrum, saying it’s “a concern for NIPPC that there isn’t more transparency around why some projects become considered regionally needed and why some are not.”

Tilghman also called for more details on the different factors in the chart to help customers better understand how the administrator determines which projects fall under EGP standards.

Jeff Cook, BPA’s vice president of transmission planning and asset management, said the agency would investigate how it can increase transparency in the process.

“I know overall, BPA is working on transparency as a general theme, regardless,” Cook said. “We’ve had numerous discussions with various groups, whether it’s projects, how we prioritize them, how we rank them … what’s the status of them. So, we’ll kind of weave that into that whole discussion around transparency, but that’s a key theme that BPA is working on already.”

Richard Shaheen, BPA senior vice president of transmission services, agreed, saying the agency wants to share accounting principles and legal principles. However, he noted that balancing transparency and speed of delivery can be tricky.

“Public processes take time, weeks and weeks off, you know, arranging discussions and follow-ups and so on and so forth,” Shaheen said. “So I’m not disagreeing with the desire, and we want to provide that transparency, but I also want everyone to kind of be conscious of not sacrificing delivering projects as expedient as possible.”