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December 27, 2024

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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.”

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ERCOT Board of Directors Briefs: Dec. 2-3, 2024

The ERCOT Board of Directors signed off on staff’s recommendation to move forward with executing a reliability-must-run (RMR) contract for CPS Energy’s Braunig Unit 3 while deferring a decision on the gas plant’s other two smaller units until February or later. 

ERCOT General Counsel Chad Seely told directors Dec. 3 that deferring a decision on the other two units will give staff time to continue negotiations with CPS, CenterPoint Energy and Life Cycle Power over moving 15 large generators and their 480 MW of capacity from Houston to distribution sites in the San Antonio area. CenterPoint leased the generators from Life Cycle for $800 million in 2021, but the large units sat idle during July’s Hurricane Beryl and drew heavy criticism from Houston residents and Texas politicians. (See ERCOT to Recommend RMR Agreement for Braunig.) 

“We do believe it is a better reliable solution for the risk that we’re trying to address for the next couple of years until the transmission solutions come into play,” Seely said. 

ERCOT is exploring the generators’ use because Braunig Units 1 and 2 are smaller (217-MW and 175-MW summer max ratings, respectively) and are susceptible to forced outages. Staff said the mobile generators, with shorter ramp times than the gas units, are more flexible and “likely to be more reliable.” 

Staff expect to move forward in mid-December with a request for must-run alternatives (MRAs) to the mobile generation to better understand the market’s appetite for the solution. A previous solicitation for MRAs drew a single response from a 200-MW multi-hour energy storage resource. 

“We want to be fair to the market and see if there’s anything that could compete against the mobile gen,” Seely said. He said ERCOT then would move forward with a recommendation to the board in February or a special meeting soon thereafter. 

ERCOT said the two-year RMR costs will be lower than the value of projected systemwide load shed should the units retire, with Braunig 3 providing the best value. It has a budgeted cost of $76,888/MW for the two years, compared to $113,920/MW and $151,012/MW for Units 1 and 2, respectively. 

CPS told ERCOT earlier in 2024 that it planned to retire the three Braunig units, which date back to the 1960s, in March 2025. However, ERCOT said the resources, with a combined summer seasonal net maximum sustainable rating of 859 MW, were necessary to mitigate the risk of systemwide load shed for the next two years. (See ERCOT, CPS Energy Negotiating RMR, MRA Options for Retiring Units.) 

ERCOT expects the RMR contract for Braunig Unit 3, its first since 2016, to be effective until June 2027, when a new transmission line to the South is completed. 

“Once that line is completed, then the need is no longer there for the RMR unit,” ERCOT COO Woody Rickerson told directors. 

ERCOT Prepared for Winter

Noting that 2024 is likely to be the warmest year on record for the planet, ERCOT’s Chris Coleman, supervisor of operational forecasting, said weather conditions still could lead to extreme cold in January or February. 

“We’re in a pattern now where, when we get a warm, mild winter, more times than not, we’re seeing a cold extreme. … We’re in a pattern now that supports something like a [Winter Storm] Uri,” Coleman told the board, referring to the February 2021 winter storm that almost brought down the ERCOT grid and killed hundreds of Texans. 

Coleman said ocean and atmospheric conditions are very similar to those that preceded the 2021 storm. Five of the past eight winters have brought extreme cold to Texas, including the warmest winter (2016/17), the sixth-warmest (2022/23) and the 11th-warmest (2023/24). 

“The more I look at this winter, the more cold potential I see,” Coleman said. “This is like a tornado watch. Doesn’t mean a tornado is going to happen. It means conditions are there.” 

ERCOT CEO Pablo Vegas said the grid operator’s analysis has indicated a “slightly higher” reliability risk probability from last winter, driven largely by increased load on the system and reduced support from solar resources, which were valuable in meeting demand this summer. 

The grid operator set a new winter peak of 78.35 GW last winter but has added more than 10 GW of capacity since then. Solar resources accounted for 5,155 MW and battery storage 3,693 MW, with natural gas adding 724 MW. 

Vegas pointed to ERCOT’s weatherization program as “one of the most statistically significant changes … that has markedly changed the risk profile of the ERCOT grid.” He said staff have conducted 2,892 inspections of generators and transmission facilities since Uri, with two-thirds of the inspections taking place within the generation fleet. 

“This has more than exceeded what the [Public Utility Commission’s] requirements for the inspections on the cyclical basis have been,” Vegas said. “We think it’s important to stay ahead of this because of the really high impact the weatherization program does have on the reliability of the fleet.” 

Misc. Approvals

Two transmission projects, a price correction and a protocol change, previously endorsed by the Technical Advisory Committee, all cleared the board with little discussion: 

    • The $202.2 million Oncor Delaware Basin Stages 3 and 4 Project came out of the 2019 Delaware Basin Load Integration Study and addresses reliability issues in West Texas. The project includes upgrading an existing capacitor station, building 22 miles of double-circuit 345-kV lines and 41 miles of 138-kV lines, and converting 41 miles of 138-kV lines to 345 kV. It is expected to be completed in 2027. 
    • American Electric Power’s Brownsville Area Improvements Transmission Project, a $423.8 million initiative addresses thermal overloads on 106 miles of 138-kV facilities in the Rio Grande Valley with either new or upgraded infrastructure. The project has a May 2029 in-service date. 
    • A price correction was issued for the Nov. 1 operating day after several real-time intervals were “significantly affected” by an incomplete weekly database load update. The largest dollar impact to any counterparty was about $2,758, above the criteria for a price correction. 
    • A Nodal Protocol revision request (NPRR1247) requires ERCOT to use a consumer energy cost reduction test to measure congestion cost savings when evaluating economic transmission projects. Generators and marketers opposed to the NPRR cited a lack of transparency and control over the methodology for incorporating “fictitious generation” to solve power flow issues with the projected load growth. 

TAC Membership Approved

Twenty-seven incumbents will return to TAC in 2025 following the board’s approval of its 30-member slate of representatives. 

Oncor’s Martha Henson replaces colleague Collin Martin in the Investor-Owned Utility segment; Vitol’s Seth Cochran, a previous TAC member, replaces National Grid Renewables’ Matthew Morais in the Independent Power Marketer’s segment; and Brazos Electric Cooperative’s Kyle Minnix replaces Pedernales Electric Cooperative’s Eric Blakey, a longtime representative in the Cooperative segment. 

Jupiter Power’s Caitlin Smith plans to return as TAC’s chair, and Henson is expected to replace Martin as vice chair. The committee’s leadership elections and those of its subcommittees will be held before its Jan. 22 meeting. 

ERCOT’s Day to Retire

Betty Day, ERCOT | ERCOT

The board meeting was the last for Betty Day, ERCOT’s chief compliance officer, who is retiring after 24 years with the grid operator and more than 30 in the industry. 

Vegas credited Day with being critical to the development of the zonal and nodal markets, and for integrating cyber, physical and emergency management and maturing the security function. 

“The time I’ve spent here at ERCOT has been the highlight of my career,” Day said after recognition from Vegas and board Chair Bill Flores. “The people have been amazing, both within the organization and with stakeholders, board members and countless people. I can’t even begin to name them all.” 

The directors also welcomed Ben Barkley to the board as the newly appointed CEO of the Texas Office of Public Utility Counsel. Gov. Greg Abbott appointed Barkley as CEO on Dec. 2, making him eligible for OPUC’s board seat. He previously was assistant general counsel for the Office of the Governor. 

ESR Revision Back to TAC

Directors remanded back to TAC a protocol change (NPRR1246) and related changes to the Nodal Operating Guide (NOGRR268), Other Binding Documents (OBDRR052) and Planning Guide (PGRR118) that insert terminology associated with energy storage resources into the protocols. The change aligns the ESRs’ provisions and requirements with those for generation resources and controllable load resources. 

Staff said the recent approval of NPRR1188, which modified the dispatch and pricing of controllable load resources, had a “cascading impact” on baseline language used in other revision requests. Seely said staff will work on additional ERCOT comments and clean up language before sending the change to TAC for its consideration. 

The board’s consent agenda included six other NPRRs, two NOGRRs, an OBDRR and two PGRRs that will: 

    • NPRR1180, PGRR107: incorporate a 2022 state law requiring any ERCOT reliability transmission project review to include the historical load, forecast load growth and additional load seeking interconnection. 
    • NPRR1239, NOGRR266: move reports that don’t contain ERCOT critical energy infrastructure information (ECEII) from the market information system’s secure area to the public ERCOT website. 
    • NPRR1240, NOGRR267, PGRR116: move reports that don’t contain ECEII information from the secure area to the website. The change also conforms the rules with current posting practices, including those for maintaining ECEII lists of equipment in the outage scheduler; making the annual planning model data submittal schedule available in the model-on-demand (MOD) application; and posting weekly demand forecasts, demand analyses for 36 months and beyond, metrics of forecast error, and assessments of chronic congestion on the website. 
    • NPRR1249: requires ERCOT to publish shift factors for all active transmission constraints in the real-time market. 
    • NPRR1254: requires resource entities to submit the initial resource registration data for a generator interconnection or modification (GIM) project four months prior to target inclusion in the ERCOT network operations model. This gives ERCOT and the entities one month to address errors or deficiencies. 
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Former FERC Commissioners Discuss Accommodations to States in Order 1920-A

Several former FERC commissioners on a webinar hosted by the American Clean Power Association on Dec. 5 said the revisions made in November’s Order 1920-A generally are promising for getting transmission built.

“I actually think that the commission ended up in, mostly, in a very positive place,” said former FERC Chair Richard Glick, now with GQS New Energy Strategies.

Most of the comments supported the approach to planning that FERC stuck with on rehearing, which is to move toward longer-term, scenario-based planning for the grid, noted Glick, who launched the Advance Notice of Proposed Rulemaking that led to 1920.

But FERC wound up granting states even more of a role in cost allocation. (See FERC Order 1920-A Wins Approval with Accommodations to States.)

“At the end of the day, if the states don’t buy off on a cost allocation mechanism, it’s very difficult to move forward with transmission projects,” Glick said. “So, you see in MISO, for instance, where there’s been a lot of state discussion, they’ve made a lot of progress because of that.”

The revisions in Order 1920-A ensured FERC would review any cost allocation agreement proposed by the states, even if the regional transmission provider does not support it. Glick said he was hopeful that would win over more states.

While Tony Clark — a former FERC commissioner who now is executive director of the National Association of Regulatory Utility Commissioners — joked that it’s hard to say that 50 states have any single opinion, early indications are his members appreciate the direction the commission went with Order 1920-A.

Some of the states supported the initial version of Order 1920, but there was enough opposition that NARUC filed a rehearing request that argued for a bigger role for state utility regulators.

“Almost universally, at least from states that I’ve heard from to this point — whether they were in the camp of ‘we like 1920,’ or whether they were in the camp of ‘we didn’t like 1920; we want changes to be made’ — the response has been positive,” Clark said.

While the order faces some litigation, with initial appeals filed before FERC issued 1920-A, NARUC’s major focus is going to be on implementation now, Clark said.

“I’m sure we will continue to participate and watch closely compliance filings,” he continued. “As we learned with Order 1000, there’s sort of the original order phase, and then there’s the compliance filing phase, which is also a very, very big part of it, because that’s where a lot of the small decisions get made — small decisions that have a big impact in implementing the order itself.”

The original Order 1920 gave states a more formal role than they had under the standard Order 1000-based rules that preceded it, said former FERC Commissioner Allison Clements, who voted for the original order in May. (See FERC Issues Transmission Rule Without ROFR Changes, Christie’s Vote.)

“I think the pendulum has switched the other way, and that’s to say the states have gotten a whole lot of opportunity here,” Clements said. The rule changes favoring states will lead to a lengthier, more complex planning process, and Clements said she was unsure how much that would wind up benefiting consumers. “Be careful what we wish for,” she cautioned.

One of the changes in Order 1920-A was to give states up to one year, instead of just six months, to negotiate cost allocation rules if they need more time, said ACP Senior Counsel Gabe Tabak. Many regions should take advantage of that extra time, which will mean a longer compliance process.

“If they can come to an agreement to have a parallel approach filed alongside it in the compliance filing, there will be a lot of pressure on transmission providers to file something that the states have agreed to, rather than make a compliance filing that risks letting FERC choose a different option that the states prefer,” Tabak said.

Transmission providers are not likely to file a clashing cost allocation with FERC, but assuming they do make a “jump-ball filing,” then the commission might not like either one, at which point it is unclear what would happen, Clements said.

“Certainly, the question of the jump-ball is likely to be litigated, in addition to others who think maybe it’s moved too far toward giving states authority that they shouldn’t have,” she added.

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CGA Latest to Nudge MISO to Simultaneously Contemplate New Load and New Generation

Clean energy organizations are prodding MISO to contemplate prospective load and generation simultaneously, with Clean Grid Alliance asking MISO to coordinate its annual transmission studies with its interconnection queue studies.  

CGA said doing so would allow the grid operator to better accommodate new large load additions.  

Speaking at a Dec. 4 Planning Subcommittee teleconference, CGA’s Rhonda Peters said MISO should adopt a policy of sharing new large load data from transmission planning in interconnection studies and conversely, including signed generator interconnection agreements (GIAs) into the year’s current Transmission Expansion Plan (MTEP) studies.  

Peters said if MISO cross-shares data, some generation and nearby large loads can be paired up, negating the need for some extensive network upgrades on the transmission system. 

“Large loads can utilize new generation directly or locally, removing the need for longer or large transmission line network upgrades to move new generation to traditional load centers,” she explained.  

Peters said though the definitive planning phase studies of MISO’s queue start with the latest MTEP modeling and list of new transmission projects at the time, that snapshot quickly becomes outdated, as getting through the queue can take up to five years and MISO doesn’t periodically update models. MTEP, on the other hand, works from an annually updated model that includes large load additions that have been accepted as a reality, with MISO racking up a fresh transmission portfolio every year.  

Peters said that to execute a data-sharing practice, MISO could simply add a check for a “load expansion project” into its business practice manuals describing interconnection studies. MISO’s manuals already stipulate that planners should check the most recent MTEP projects during the study process to figure out if a constraint is set to be mitigated by a transmission project that was approved while a generation project was advancing through queue studies.  

On the MTEP side of the coin, Peters said MISO today allows only fully executed GIAs into its MTEP modeling. However, she said “a generator nearing completion of a GIA may mitigate the need for costly transmission to add new large load.”  

MISO could consider letting a large load customer link up with a generator still in the queue by striking an agreement with the generation developer and providing a surety worth 25% of the proposed generator’s construction costs, Peters suggested. She said that way, generation is likely to be built.  

“MISO has not yet been receptive to policy mechanisms that would pair large load and generation projects while each [is] going through their respective processes,” Peters added.  

Peters said the added considerations can help MISO tackle the unprecedented load growth it’s set to encounter.  

“Certainly we’ve heard from the states that they’re worried about these large load additions,” Peters said, noting that thermal generation takes a few years to construct after an up-to-five-year interconnection queue wait.  

“We just can’t respond that quickly to some of these rapid load additions,” Peters said. “If a load and generator can come together, they can basically net out and help themselves.”  

Peters acknowledged that CGA’s appeal is similar to NextEra Energy’s recent request that MISO create a dedicated study and registration process for new generation contingent on large loads. (See “NextEra Makes 2nd Overture for Bundled Studies,” MISO Previews Future Projects to Improve System Planning.)  

But Peters said NextEra asked MISO to consider only already matched-up load and generation. She said CGA is asking MISO to consider “even circumstances where there’s no affiliation between the generator and the load, but they’re willing to become affiliated.”  

MISO Senior Manager of Resource Utilization Kyle Trotter said at first blush, MISO is hesitant to make any process dependent on large loads, which could wind up not being realities on the system.   

“It’s one thing to have a project dependent on a network upgrade. It’s another thing to have a project contingent on a large load that may not materialize,” Trotter said. 

“The generator interconnection takes five years, while load additions take 1.5 years, creating a fatal flaw in concurrent coordination of the respective models and processes. This leads to inaccuracies and inefficiencies in both processes that prevent viable project development and impose a significant, obstruction in the MISO market,” Clean Grid Alliance’s David Sapper said at an August Market Subcommittee meeting. “This is not hyperbole; this is serious stuff.”  

Sapper said from his “economist, lizard brain,” MISO could get a jump on preparing for massive loads down the road and make constructive use of its overflowing interconnection queue, which it currently insists is too large.  

During the Dec. 4 Planning Subcommittee, WPPI Energy’s Steve Leovy asked that MISO develop a formal response to CGA’s request.  

Trotter said MISO plans to return to an upcoming Planning Subcommittee to give its official perspective on the request.