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April 28, 2025

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SPP MPEC Members Celebrate Markets+ Funding Order

DENVER — FERC’s approval of SPP’s Markets+ funding agreement and its recovery mechanism came as interested participants in the Western centralized day-ahead market were meeting with the snow-capped Rockies as a backdrop. 

They cheered when they were notified of FERC’s decision during their April 22 Markets+ Participant Executive Committee (MPEC) meeting. Then they went back to work. (See FERC Approves SPP’s Funding Plans for Markets+.) 

“We’re in go time,” MPEC Chair Laura Trolese, with The Energy Authority, told RTO Insider. 

“Getting the FERC approval was super exciting. We got FERC approval both on the Markets+ funding agreement but also the final order on the last items last week,” she said, alluding to the commission’s April 17 approval of SPP’s final compliance filing for Markets+. (See FERC OKs Final SPP Markets+ Compliance Filing.) 

“We needed those two things to move forward with implementation activities and timeline,” Trolese added. 

Joe Taylor, with Xcel Energy subsidiary Public Service Company of Colorado (PSCo), said his company was pleased with the approval, which he said was not unexpected. PSCo filed a request in February with the Colorado Public Utilities Commission to join Markets+ and recover costs from its funding agreement. (See PSCo Seeks to Join SPP’s Markets+.) 

Joe Taylor, Xcel/PSCo | © RTO Insider

“We made our filing assuming that [SPP’s request] was going to be approved, and it was,” Taylor said. “It was an expectation that the funding agreement would be approved, because then we can go forward and participate and execute that agreement.” 

SPP’s Carrie Simpson, who broke the news to MPEC, recognizes that Markets+ development faces a long and winding road ahead. 

“It’s just another important milestone. We’re grateful for it, and it will set us up for Phase 2,” she told RTO Insider. 

FERC issued two orders in approving SPP’s proposed funding mechanism: 

    • The first accepted SPP’s proposed $150 million Phase 2 funding agreement as a rate schedule under the Markets+ tariff, effective March 24 (ER25-1372).
    • The second granted SPP’s request to issue debt securities to cover the agreement and fund the market’s implementation over three years until its go-live date, effective April 21 (ES25-33).

SPP has set the go-live date as Oct. 1, 2027. 

In its Feb. 21 filings, the grid operator told FERC the funding agreement will ensure those participants that benefit from the market will fund its development and share in overhead costs. 

SPP said the funding agreement is a freely negotiated contract between the RTO and each of the eight entities that have agreed to participate in Phase 2 and provide collateral to SPP’s lender equal to the amount of their obligations: Arizona Public Service, Bonneville Power Administration, Chelan County (Wash.) Public Utility District (PUD), City of Tacoma, Grant County (Wash.) PUD, Powerex, Salt River Project and Tucson Electric Power. 

The funding agreement requires the entities to provide the collateral backstop to SPP’s lender in supporting the financing the RTO will use to develop Markets+’ systems, processes and operations during implementation. The collateral is equal to the amount of the entities’ Phase 2 obligations. 

SPP says the cost to repay the financing will be incorporated into Markets+ rates and will relieve participants from the burden of providing “large sums of money to directly fund Phase 2.” SPP is splitting the phase into two stages, with participants required at first to provide collateral equal to two-thirds of their Phase 2 obligation. The first stage expires six months after the initial funding threshold has been met, at which point participants must provide collateral equal to their full Phase 2 obligation. 

As a federal agency, BPA — the major industry player in the Pacific Northwest — can’t post collateral to back up its commitment. BPA instead will provide a letter of assurances from its COO that explains its authority to enter into the agreement and statutory obligation to pay part or all of its Phase 2 obligation, whichever is effective at the time.  

5 Steps of Funding

The funding agreement is composed of five stages: 

    • When the funding threshold is met by entities that are or represent at least two contiguous balancing authorities and not less than 200,000 GWh of 2023 net energy for load execute the funding agreement. That was met Feb. 13 when funding agreements first were signed. (See SPP Secures Funding to Begin Markets+ Phase 2.)
    • When financing conditions are met with the financing’s regulatory approval and when SPP executes the loan agreement.
    • When participants provide collateral to back financing determined by their Phase 2 obligation in the form of cash or a letter of credit. The obligation is the participant’s pro rata share of Markets+’s total cost less its Phase 1 and post-Phase 1 payments. (Funding participants withdrawing from the agreement must pay their Phase 2 obligation to SPP, protecting the remaining participants from the withdrawal.)
    • When SPP obtains funds drawn from the loan or received under the funding agreement to acquire, create and/or modify the systems and processes required to implement Markets+.
    • When financing costs are repaid after go-live. Phase 2’s implementation costs will be incorporated into market rates charged to participants through a tariff schedule. SPP will repay the financing as the costs are recovered and the lender authorizes the release of excess collateral on an annual basis. The funding agreement will terminate when SPP notifies participants that the financing has been fully repaid, including all principal, interest and fees.

FERC found the funding agreement will provide a framework for SPP to begin the market’s development phase. It said the funding participants’ provision of collateral and Phase 2 cost-recovery ensures that only Markets+ beneficiaries — and not SPP RTO members — are responsible for the development costs. 

The commission declined to direct SPP to provide a commitment that its RTO members will not be responsible for the financing costs. “SPP has already provided sufficient commitment that this will be the case,” FERC said. 

“In addition, the funding agreement itself does not implicate SPP RTO members in the event of a default or withdrawal of a funding participant,” the commission added. 

FERC rejected several concerns raised by public interest organizations (PIOs) around BPA’s connection to the agreement. The groups, which include Northwest Energy Coalition, Idaho Conservation League and Public Citizen, said the agreement effectively would obligate Bonneville to participate in Markets+ ahead of issuing its formal record of its participation decision (ROD) on its day-ahead market participation because it would be on the hook for providing up to $40 million in implementation costs to SPP even before releasing the ROD. They contended that either SPP’s filing had mischaracterized BPA’s commitment to Markets+ or the agency had been engaging in a “sham” process regarding its day-ahead market decision. 

“We disagree with PIOs that the funding agreement requires Bonneville (or any other funding participants) to participate in Markets+,” FERC wrote. “As PIOs acknowledge, the funding agreement requires a funding participant to pay its Phase 2 obligations in the event it decides to withdraw from the funding agreement; however, the funding agreement does not obligate any funding participant to proceed with Markets+ participation.” 

The commission found in its second order that while SPP didn’t meet FERC’s interest-coverage ratio threshold, the grid operator cited other factors that gave it a “sufficient alternative basis” to determine the RTO had “reasonable prospects for being able to service the proposed new debt securities.” FERC said the Markets+ tariff, approved this year, will provide for the recovery of all of the proposed indebtedness’ financing costs. 

“Furthermore, we note that SPP has secured commitments from the funding participants, which guarantees that SPP will be able to repay its debt obligations related to Markets+,” the commission wrote. It added that SPP’s plans to recover the implementation’s costs will not make its RTO members responsible for the market’s costs. 

FERC set the loan’s interest rate not to exceed the total of a one-month secured overnight funding rate and a spread determined by the amount of cash collateral obtained from the funding participants. 

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N.J. BPU Backs Wind, Solar Adjustments Amid Dissent

New Jersey’s Board of Public Utilities backed measures to keep on track one of its three remaining offshore wind (OSW) projects and retool a large-scale solar incentive program, triggering two dissenting votes in a rare break in the board’s usual unanimity.

The two opposing votes highlighted the stresses within the board as it seeks to boost the state’s energy capacity to meet an expected future electricity generation shortfall and prepare ratepayers for a related rate hike of 17 to 20% on June 1.

The board voted 3-1 on April 23 to grant a deadline extension requested by Attentive Energy that would stay the enforcement of two obligations resulting from the board’s approval in January 2024 of the 1,342 MW OSW project. Without the stay, the developer would have had to pay a security commitment of about $16.7 million and a fee of $3.75 million that originally was due Jan. 24, 2025. (See NJ Awards Two Offshore Wind Projects.) The requirements now will be on hold until Jan. 24, 2026.

In an unrelated vote, the board also voted to modify the state Competitive Solar Incentive (CSI) program that awards incentives to so-called “grid scale” projects, those with a capacity greater than 5 kW. In a 3-1 vote, the board agreed to open the next solicitation — the state’s third under the CSI program — on May 4, 2025, with a goal of procuring 300 MW of solar generation capacity and 160 MWh of energy storage paired with solar.

In response to the last solicitation, in which two of the five project categories went unfilled, the board voted to broaden the permitted projects in the next solicitation to include those on open land in industrial and commercial complexes.

The board also agreed to set a different price cap — or limit — to the incentive level for each of the five categories of projects. The caps are designed to “balance the developers’ ability to seek a vital incentive with effective ratepayer protections,” according to a BPU staffer who explained the changes.

Board Dissent

In a rare display of opposition, Commissioner Zenon Christodoulou said he could not support the measure and attacked the process through which it was made.

While he didn’t specify the exact problems that triggered his concern, Christodoulou said he believes that “free market capitalism and creative innovations are the best ways to develop and improve products and services.

“Constraining mature industries by keeping them tethered and dependent on external subsidies ignores the full capacity of human ingenuity, market forces and competition,” he said. “And it passes that financial burden on to others: in this case, ratepayers.”

He acknowledged that “dissenting opinions are not common and quite often and unfortunately discouraged” on the board and said board discussions had “revealed a very shielded managerial process.”

“I have made my opinions known on many occasions over the last year and a half,” he said. “And I continue to observe that outside opinions, including mine and others, are dismissed and marginalized.

“This flawed internal process worries me deeply,” he said. “The lack of transparency, two-way communications and the palpable aversion to outside inputs troubles me.”

In response, BPU President Christine Guhl-Sadovy said that “not every outcome is going to be unanimous.”

“Agreeing to disagree is OK,” she said. “What we do know about solar and competitive solar and large-scale solar is that it helps to bring costs down for ratepayers by providing the necessary generation that we need, which you know, at this time is even more important than ever.”

She added that large-scale solar provides a “price suppression implication, and that’s really important for customers.”

The board also voted to open a new solicitation on April 30 of the state Community Solar Energy Program, offering 250 MW of capacity, with a closing date of May 13. The board order cut the incentive, from $90/MWh in the last round, to $80/MWh.

That 11% cut “represents a reasonable balance between the need to accelerate solar deployment in New Jersey without excessive immediate change and the need to keep costs manageable for ratepayers,” the board order said.

Mitigation Strategy

The votes come as the BPU completes a new state Energy Master Plan, a draft of which predicts a 66% increase in electricity demand by 2050. PJM has said the state, like others, faces a future generation imbalance that involves the rapid pace of fossil fuel plant closures, the far slower development of new generating sources and an expected demand surge propelled by electric vehicles and data centers.

State officials say the expected shortfall helped push up bid prices in the state’s Basic Generation Service auction, contributing to the upcoming 17 to 20% consumer rate hike.

Seeking a way to help ratepayers mitigate the increase, the board voted unanimously to enact a campaign to encourage ratepayers to reduce their energy use and to solicit proposals from the state’s utilities on how to achieve that.

“We understand that the timeline to turn around these proposals is short,” but the goal is to reduce ratepayer costs, said Guhl-Sadovy.

‘Pivot’ Needed

New Jersey planned to meet a portion of its future electricity demand with offshore wind. But the state’s three OSW projects struggled even before President Trump’s sweeping executive order on Jan. 20 temporarily froze the nation’s OSW projects.

New Jersey’s most advanced project, Atlantic Shores, received construction and operations plan approval from the federal Bureau of Ocean Energy Management in October, but the U.S. Environmental Protection Agency on March 14 placed a hold on the project. The state’s third project, the 2,400-MW Leading Light Wind, received a deadline extension from the BPU in September to give the developer time to find an economically viable turbine. (See EPA Puts Hold on Atlantic Shores OSW Permit.)

The upheaval in the sector began when developer Ørsted abandoned its Ocean Wind project in October 2023, citing cost and supply chain problems. (See New Jersey BPU Approves Invenergy Offshore Wind Delay.)

Commissioner Michael Bange, before voting against the order to extend the Attentive Energy deadline, said the board had done “everything it could to make offshore wind happen.” Yet a new approach is needed given that “the current federal administration is not in favor of it, and has done everything to stop it,” he said.

“We need to pivot and focus on storage, solar, energy efficiency and other ideas that can help reduce energy prices,” he said. “Even if offshore wind was possible in the future, we would have to start the bid process over, due to [the] tariff war in place, uncertainty of future pricing, supply chain issues and investment monies to support it.”

Christodoulou said he shares some of those concerns. But he said he would vote for the measure anyway, based on assurances from BPU staff that approving the deadline would not cost the state anything or set a precedent for the project or others in the future, and would keep the project viable.

“I’m hopeful, but not entirely optimistic, that this can get done at some future date,” he said.

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ACORE Report Explains How to Get Advanced Transmission in Regional Plans

If FERC Order 1920 is implemented correctly, it could expand the role of grid-enhancing technologies (GETs) and high-performance conductors (HPCs) to help meet surging power demand in the near term, according to a report prepared by the Brattle Group for the American Council on Renewable Energy.

Demand forecasts have grown significantly since FERC started the rulemaking process that produced Order 1920, report lead author and Brattle Principal Bruce Tsuchida said on an April 22 webinar. That comes on top of the underlying need to replace aging transmission, which the report estimated would cost $10 billion annually over the next decade.

“If you’re a state right now, and you’re looking at the wave of infrastructure that’s coming down the pipe to meet load growth, you probably are wondering, ‘how much is this going to cost me?’ And maybe, ‘how could I shave off some of that cost? How can I save some money?’” GQS New Energy Strategies Principal Liz Salerno said. “And advanced transmission technologies come right to the rescue here.”

GETs and HPCs are mature, proven technologies, and the report’s analysis found they can provide all seven benefits required for consideration under Order 1920, Tsuchida said in a statement.

“Transmission providers can use a holistic evaluation method when assessing various benefits and comparing potential transmission solutions,” he added. “These technologies will likely shine through as a lower-cost option to ensuring reliable, affordable power for ratepayers.”

Many utilities have not adopted advanced transmission technologies (ATTs) because they are unfamiliar with them, and their investment incentives are not aligned well with the technologies, Tsuchida said.

“There’s also the fact that a lot of the cost associated with transmission — for example, if there’s an outage, or if there’s congestion, or if there’s more investment needed — that is passed through to the end-use customers, while the transmission service providers may not necessarily feel that immediately,” he said.

Transmission needs are growing rapidly, so much so that the pace of traditional transmission development cannot keep pace. Traditional wire projects can take five to 10 years to develop and often are hindered by regulatory delays, the complexity of interregional coordination, cost allocation and permitting, the paper says.

“Because of the three characteristics discussed above (lower cost and speedier installation, complementarity to existing equipment, and portability and reversibility), ATTs can provide cost-effective solutions in a shorter schedule than relying solely on the traditional wires-based solutions,” the report says. “Additionally, the fragmented nature of transmission planning and cost allocation often stalls large projects; HPCs, through reconductoring, can reduce the scope of new upgrades, while GETs can offer incremental upgrades that align with the scenario-based, collaborative approach emphasized in Order 1920.”

ATTs need to be used in short- and long-term planning, with the report saying that splitting the various solutions into those two time frames (or even more granular ones) will allow planners to address challenges that span immediate needs and flexible goals.

GETs can provide near-term relief to transmission congestion and improve grid efficiency without the delays of traditional transmission investment. Both GETs and HPCs can help modernize the grid, integrate new technologies, and prepare for future demand and renewable growth in a cost-effective way, the report says.

Order 1920 requires grid planners to consider seven benefits of new transmission, two of which are temporary, such as lowering congestion from outages, and the mitigation of extreme weather events and unexpected system conditions. Assessing their benefits will require planners to consider shorter time frames than normal, the paper says.

“Associated with the new temporal scenarios to analyze, transmission providers will need to develop methodologies on how to consider benefits (and costs) over varying timelines,” the report says. “For example, evaluating a potential solution could require analyses over multiple timelines to capture the benefits and associated trade-offs among benefits (a solution could impact several benefits) over different timelines.”

Compliance with Order 1920 is proceeding at different paces in some regions, with FERC having granted some extensions. In PJM, Maryland Public Service Commissioner Michael T. Richard said on the webinar the RTO is working with states and stakeholders on complying with the new rule.

“I do think we need to make sure this is not going to be just status quo; a new kind of [Regional Transmission Expansion Plan] that is just extended,” Richard said. “And in fact, it is going to be a planning opportunity with the states at the center. The core of the plan for the future needs to be how the states envision their resources … and then we can work to make sure that we all have the same goal: keep the lights on.”

While compliance is proceeding, GQS Principal and former FERC Chair Richard Glick (who launched the rulemaking process that led to Orders 1920 and 2023) said in a statement that those efforts will take time.

“In the meantime, action is needed to address more immediate threats to reliability and affordability,” Glick said. “This report shows that GETs and HPCs offer a near-term capacity solution while grid operators continue to plan the regional transmission lines needed to meet future challenges.”

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MISO: New Software Effective, Faster than Previous Queue Study Process

MISO has concluded that Pearl Street’s SUGAR automation software is an effective alternative to the power flow simulations it used to conduct to identify network upgrades for generation projects in the queue.  

MISO released an analysis comparing the software’s ability to pinpoint upgrade needs for new generation entering the system with MISO’s previous analyses on the 2021 cycle of generation proposals. The RTO said SUGAR performed at a 99.23% match rate with “minimal deviations” when searching for thermal constraints, a 100% match rate with some extra identified constraints when looking for flowgate limits and a 99.03% match rate when spotting voltage issues with “justified” minor violations.  

Ahead of the analysis, MISO said SUGAR would have to identify at least 98% of constraints uncovered through its legacy analyses to be considered a success. MISO said across all three comparisons — thermal, flowgate and voltage — SUGAR results aligned with MISO studies 99.2% of the time.  

MISO is using Pearl Street’s SUGAR (Suite of Unified Grid Analyses with Renewables) software to screen generation projects and perform the first phase of studies in the queue. It’s betting the tech startup’s assistance with conducting studies can dramatically accelerate its yearslong queue processing. Austin, Texas-based software company Enverus acquired Pearl Street in March. 

The RTO plans to start the first phase of studies on the 2023 batch of project proposals in July. It won’t begin analyzing 2025 entrants until the end of the year. MISO hopes to have all projects in those cycles striking interconnection agreements over 2026, with the still-in-progress 2022 cycle proceeding in the second quarter, 2023 in the third quarter and 2025 by the end of 2026. (See MISO Unveils Later Timeline for Queue Processing Restart.)  

MISO skipped acceptance of a 2024 queue class altogether. Throughout 2024, it delayed kickoff of studies on the 123 GW of projects that entered the queue in 2023 while Pearl Street assisted with modeling. 

MISO study region queue caps and project submittals as of April 2025. The East ITC study region has exceeded its queue cap. | MISO

The RTO hasn’t processed a new queue cycle in more than a year, saying it needs to introduce study automation and implement a megawatt cap to make processing requests less daunting. (See MISO to Skip 2024 Queue Cycle While it Automates Study Process with Tech Startup.) 

MISO found that SUGAR completed the first phase of interconnection studies faster while estimating similar costs for network upgrades. MISO said while it spent 686 days to ultimately estimate $13.36 billion in upgrades for the 2021 queue cycle of projects, SUGAR estimated $13.25 billion for the same batch of projects within 10 days.  

MISO staff at an April 22 Interconnection Process Working Group said SUGAR provided a good match for the RTO’s longer-form interconnection studies.  

“These results confirm that SUGAR can be utilized in MISO’s [first definitive planning phase (DPP)] studies with minimal impact to stakeholders while also providing significantly increased speed in conducting MISO DPP Phase 1 studies,” MISO wrote in its analysis.   

MISO said SUGAR results are in “excellent agreement” with MISO’s previous study process regarding flowgate project assignments. When hunting voltage constraints, MISO said SUGAR landed on 102 of the 103 constraints it previously identified while reporting six more that didn’t turn up in MISO studies. MISO said the additional constraints SUGAR called out are “deemed acceptable within the bounds of engineering judgment.”  

MISO also said SUGAR noted 259 of the 261 thermal constraints MISO previously reported. The RTO said it expected small deviations in the output of different powerflow tools.   

Meanwhile, one MISO region already has surpassed MISO’s newly enacted 50% of peak load annual interconnection queue cap. (See FERC Approves Annual Megawatt Cap for MISO Interconnection Queue.)  

The East ITC study region, which contains Michigan’s Zone 7, exceeded the cap at 29 submittals at 10.52 GW. Any other projects that hoped to enter under the 2025 cycle now must queue up for the 2026 cycle.  

MISO has been allowing projects to line up for 2025 queue processing since last year. Its cap for the 2025 queue cycle is nearly 78 GW. So far, MISO has recorded 154 project submissions at 41.64 GW.  

At the April 22 meeting, John Liskey, of the Citizens Utility Board of Michigan, said the resources that entered before the East region’s cap was exceeded contain a large amount of gas capacity, which could violate Michigan’s renewable energy standard of 50% by 2030 and 60% by 2035. 

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FERC Approves SPP’s Funding Plans for Markets+

DENVER — FERC, in two separate orders, approved SPP’s $150 million funding agreement for Markets+ and the funding mechanisms under which the RTO will finance the implementation phase of the market’s development.

News of the decision met with an enthusiastic response at a meeting of the Markets+ Participants Executive Committee (MPEC) in Denver.

“I have some lovely breaking news. FERC has approved the funding agreement, the funding mechanism today,” Carrie Simpson, SPP vice president of markets, said at the meeting, prompting applause among committed members.

“These achievements represent meaningful steps in the progress towards launching Markets+ and bringing the West closer to realizing the substantial value of a robust regional market,” SPP COO Antoine Lucas said in an April 22 press release. “SPP is proud to see the hard work of the Markets+ stakeholders pay off in this series of approvals that clear the path toward market launch in 2027.”

Specifically, FERC approved the SPP Phase 2 funding agreement, which lays out how SPP will finance Markets+’s $150 million in implementation costs (ER25-1372).

Eight Western entities have signed the agreement as of April 16: Arizona Public Service, Bonneville Power Administration, Chelan County Public Utility District (PUD), City of Tacoma, Grant County PUD, Powerex, Salt River Project and Tucson Electric Power.

The agreement requires the entities to provide collateral to SPP’s lender to support the financing the RTO will use to develop Markets+ during the implementation phase. The collateral is equal to the amount of the entities’ Phase 2 obligations.

The recovery of the costs to repay the implementation financing “will be incorporated into the rates charged in the Markets+,” according to a frequently asked questions document posted on SPP’s website.

“This eliminates the need for the funding participants that participate in Markets+ to provide lump sums of money to directly fund Phase 2 outside of the specific circumstances outlined in the funding agreement (i.e., withdrawal, termination, default),” according to the FAQ.

A significant detail in the funding agreement order: FERC’s rejection of concerns raised by a group of public interest organizations (PIOs) around the Bonneville Power Administration’s connection to the agreement.

The PIOs protested that the agreement would effectively obligate BPA to participating in Markets+ even ahead of issuing its formal record of decision (ROD) on its day-ahead market participation because the agency would be on the hook for providing up to $40 million in implementation costs to SPP even before releasing the ROD. They contended that SPP’s filing had either mischaracterized BPA’s commitment to Markets+ or that the agency had been engaging in a “sham” process regarding its day-ahead market decision.

“We disagree with PIOs that the funding agreement requires Bonneville (or any other funding participants) to participate in Markets+,” FERC wrote. “As PIOs acknowledge, the funding agreement requires a funding participant to pay its Phase 2 obligations in the event it decides to withdraw from the funding agreement; however, the funding agreement does not obligate any funding participant to proceed with Markets+ participation.”

The commission also dismissed the PIOs’ concerns around how a funding participant such as BPA would cover its costs if it decided to withdraw from the market, saying the issue was out of scope for the order.

“In addition, because the funding agreement does not govern whether or how a withdrawing funding participant will recover its Phase 2 obligations after a withdrawal, we find PIOs’ arguments about Bonneville’s plan to recover such potential costs are outside the scope of this filing.

“We also find that PIOs’ arguments concerning Bonneville’s decision-making process related to Markets+ participation, including any associated communications with stakeholders, are outside the scope of the filing,” the commission wrote.

Funding Mechanism

The second order concerned SPP’s funding mechanism, which details how the RTO “will finance the implementation phase of the market’s development,” according to SPP’s news release (ES25-33).

The mechanism will entail SPP taking out a $150 million loan collateralized by the full funding obligation of each Markets+ participant, except BPA.

The commission approved the mechanism despite its failure to meet FERC’s interest ratio coverage screen, a measure of how readily an entity can cover its debt.

“SPP has cited other factors that provide the commission with a sufficient alternative basis upon which to conclude that SPP has reasonable prospects for being able to service the proposed new debt securities for which authorization is sought in the application, and to continue to be able to provide service as a public utility,” the commission wrote.

Tom Kleckner contributed to this article.

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FERC Approves PJM-Pa. Agreement on Capacity Price Cap, Floor

FERC has approved a PJM proposal to limit capacity prices to between $175 and $325/MW-day for the next two Base Residual Auctions (BRAs), resolving a complaint from Pennsylvania Gov. Josh Shapiro alleging there was potential for prices to soar above what is necessary to maintain resource adequacy (ER25-1357).

The commission found that PJM’s capacity market is facing conditions outside the bounds considered in the 2022 Quadrennial Review, noting the RTO’s filings highlighted a confluence of a tightened auction schedule, load growth, generation deactivations, a backlogged interconnection queue and external constraints to resource entry such as permitting and supply chain challenges.

FERC said in the April 21 order that PJM and the Shapiro administration proposed a temporary measure to add a “collar” to the clearing prices for the 2026/27 and 2027/28 capacity auctions while the RTO drafts long-term market changes in the current Quadrennial Review and implements a cluster-based approach to studying projects in its interconnection queue. (See PJM, Shapiro Reach Agreement on Capacity Price Cap and Floor.)

While the price band initially would be set at $175 to $325/MW-day, those values would be readjusted annually based on the accreditation of the reference resource — a dual-fuel combustion turbine generator — and therefore could change.

“We agree with PJM that the price cap and price floor will operate together to narrow the range of potential capacity price outcomes, which will reduce the price volatility under the existing” variable resource requirement curve, FERC said. “In accepting PJM’s proposal, we recognize that several commenters representing both suppliers and consumers support the proposal as a balanced, time-limited approach, and that several additional commenters do not oppose PJM’s proposal.”

The proposal was supported by the New Jersey Board of Public Utilities and Pennsylvania Public Utility Commission, as well as generation owners and utilities including Talen Energy, Constellation Energy, Calpine and Dominion Energy, who commented that it represents a temporary measure to keep costs reasonable while new market rules are developed through the Quadrennial Review.

In his complaint, filed Dec. 30, 2024, Shapiro argued that between a backlogged interconnection queue and an auction schedule that has been delayed repeatedly to the point the 2026/27 BRA is set to be conducted within a year of the start of the corresponding delivery year, developers would have no opportunity to respond to high prices by bringing new resources to market.

In line with PJM’s proposal and statements to stakeholders when it was presented to the Members Committee in February, the commission’s acceptance of the filing included the dismissal of Shapiro’s complaint as moot. (See PJM Presents Capacity Price Cap and Floor to Members Committee.)

A maximum price point has been a part of the Reliability Pricing Model (RPM) since its inception, but the proposal represents the first instance of a price floor being included in auction rules. The Independent Market Monitor and North Carolina Utilities Commission protested against the minimum price, arguing it could require consumers to procure unneeded capacity.

The Monitor also argued that curtailment service providers may seek to take advantage of the price floor by offering a large amount of demand response resources, which the commission found out-of-scope as PJM proposed no changes to DR rules.

PJM said the floor would counterbalance the diminished maximum price by providing revenue certainty to market sellers, which would support near-term investments in capacity. It also wrote it would be unlikely the marginal resource would clear at $175/MW-day or less given the tight market conditions and that the 2025/26 BRA cleared at nearly $270/MW-day.

Shapiro also supported the price floor, arguing it would address the market uncertainty sellers are likely to face over the next two auctions.

The commission wrote that PJM demonstrated the capacity shortage seen in the 2025/26 auction — when just 20.7 MW of offered capacity did not clear — is likely to continue for at least the next two years. It noted that PJM anticipates 4 GW of load growth in the 2026/27 delivery year and 6 GW the following year.

“Given the facts and circumstances presented in this record, we find that the benefits of PJM’s proposed temporary price floor outweigh the potential risk of over-procurement, and therefore find PJM’s proposal for a temporary collar is just and reasonable,” FERC said.

The commission rejected a protest from coal trade association America’s Power that the proposed maximum price would prompt planned resources to drop out of the queue and cause existing generation to deactivate or seek to offer capacity to other regions. It cited analysis of resources that have deactivated in the past after operating on reliability-must-run (RMR) agreements with cost-of-service compensation, finding that a $500/MW-day clearing price would make half of those resources economic, while a $325 clearing price would make them all uneconomic.

The commission wrote that cost-of-service is not comparable to the revenues a resource receives from PJM’s capacity, energy and ancillary service markets.

FERC’s order follows several others approving PJM proposals to rework elements of its capacity market, including requiring intermittent and storage resources to submit capacity offers, including the output of units operating on RMR agreements in the supply stack and reworking how gas resources are modeled in the winter.

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Clean Path Transmission Plan Draws Support, Criticism

Stakeholders and advocates are sounding off for and against expedited review of the $5 billion-plus Clean Path transmission proposal that would feed power into New York City. 

Efforts to build the 175-mile underground HVDC line suffered a setback in late 2024 due to cancellation of a larger project in which it was packaged with 23 new wind and solar facilities in rural New York. (See $11B Transmission + Generation Plan Canceled in NY.) 

The New York Power Authority (NYPA) is pressing ahead on its own with the transmission component. (See NYPA Files Petition with New York PSC to Save Clean Path Project.) 

NYPA is asking the state Public Service Commission (PSC) to designate Clean Path a priority transmission project (PTP) (Case 20-E-0197) in hopes of accelerating its development and speeding up the benefits it would provide to the environment and to grid reliability. (See NYPA Argues Clean Path Potential Benefits Outweigh Cost.) 

NYPA estimates the cost of Clean Path at $5.2 billion. It proposes allocating 60% of the cost to NYISO Zone J (New York City), which could reduce its reliance on fossil fuel generation and enjoy cleaner air thanks to Clean Path, and 40% to rest of the state on a load-share basis. 

The PSC solicited comments on NYPA’s request in February, and the window closed April 21; a spokesperson said April 22 the comments will be reviewed but there is no timetable yet for further action. 

In the comments, advocates for environmental quality and for organized labor generally argued in favor of priority status for the proposal while many in the energy sector raised objections. 

These objections often focused on the need or lack of need for Clean Path, and the fact that the proposal differs substantially from the one first submitted. 

The original project, called CPNY or Clean Path New York, was a public-private generation-transmission proposal by NYPA and Forward Energy that won a state contract for Tier 4 renewable energy certificates. The contract was terminated in November, the partnership was dissolved, and Clean Path now is transmission-only. 

Among the comments: 

National Grid Ventures said without the 3.8-GW suite of renewable generation projects originally envisioned for CPNY, Clean Path should not be granted priority status. It further said the project itself should not proceed without independent verification of its need. It concluded: “If the commission determines the project is required and that it should be granted PTP status, then NYPA should be ordered to competitively solicit proposals and reserve the right for the commission to approve who NYPA ultimately teams with for the project.” 

PSEG Long Island supports designation as a priority transmission project on the belief that, because NYPA’s cost of debt is lower and it is tax-exempt, development costs and costs to customers would be lower than if a private developer did the work. 

Independent Power Producers of New York noted that CPNY won its state contract through a competitive solicitation and argued the PSC should consider new competitive solicitations to avoid burdening ratepayers with unnecessary costs. It added that renewable energy development is behind schedule in New York. “Thus, any ‘urgency’ to complete the Clean Path project is an overreach at best and should not outweigh the commission’s long-established precedent that competitive solicitations ensure the lowest cost for consumers.” 

Alliance for Clean Energy New York supports priority designation as a way of addressing future reliability and transmission security deficiencies; reducing the need for more expensive local generation to meet the locational minimum installed capacity requirement in Zone J; and facilitating development of renewable resources upstate, where the HVDC line would originate. 

New York Transco — which is collaborating with NYPA on another major downstate transmission project, Propel NY Energy — said NYPA has not demonstrated that Clean Path meets the criteria for priority designation. It also questioned whether Clean Path could unbottle existing renewable capacity in the region and said NYPA has failed to support the cost recovery mechanism it proposed. 

Consolidated Edison Co. and four other utilities said the PSC should deny NYPA’s request because NYPA had not shown a need for urgency and its petition lacks sufficient analytical support. 

The president of a residents’ association at a public housing project near Clean Path’s planned southern terminus said her neighborhood long has been plagued by poor air quality from nearby fossil-burning plants and the new line would provide relief. “I respectfully ask the commission to approve this project and move it forward. Our community can’t wait any longer.” 

U.S. Sen. Charles Schumer and U.S. Rep. Dan Goldman, both New York Democrats, recited a list of benefits Clean Path is expected to offer and said priority status should be granted. 

Con Edison Transmission recited a list of deficiencies it said exist in the Clean Path petition and said priority status should not be granted. 

New York State AFL-CIO President Mario Cilento said: “We support designating this project as a priority transmission project because it will create good union jobs and help achieve the state’s emissions reduction goals.” 

Multiple Intervenors, a collection of 55 large energy consumers statewide, faulted the 60-40 cost allocation split on several levels and urged a 75-25 split instead, placing most of the cost where most of the benefit would be realized: Zone J. And they said the 25% share should be spread across the entire state — not the rest of the state excluding New York City. 

New York City urged priority designation for Clean Path for all the benefits it would provide but urged transparency on the cost of the project. It said it does not object “for now” to footing 60% of the cost, but said the split should be revisited if power begins to flow from downstate to upstate. (New York’s vision is that offshore wind farms someday may accomplish this feat.) 

The city also wants clear indication that the 40% is to be spread across the rest of the state — not across the entire state including New York City. 

The Census Bureau estimates New York City is home to 42% of the state’s residents. 

NYISO estimates the generation mix on the New York City grid is almost 90% fossil-powered, while parts of the upstate grid are almost 90% emissions-free. 

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Calif. Senate Committee Backs Pathways Initiative Bill

A California state Senate committee voted unanimously in favor of the Pathways bill, bringing the Golden State closer to allowing CAISO to cede oversight of its energy markets to an independent regional organization (RO). 

Members of the state Senate Energy, Utilities and Communications Committee on April 21 voted 17-0 in favor of Senate Bill 540, dubbed “Pathways,” sending the proposed legislation to the Senate Judiciary Committee for a hearing April 29. 

The bill is the product of the work of the West-Wide Governance Pathways Initiative, the nearly two-year effort to support the expansion of CAISO’s Western Energy Imbalance Market (WEIM) and soon-to-be-implemented Extended Day-Ahead Market (EDAM) to entities outside California by shifting governance of the markets from the ISO to a proposed independent RO. 

Democratic Sens. Henry Stern and Josh Becker introduced the bill in February. During the April 21 hearing, Becker noted the legislation comes as SPP prepares to launch its own day-ahead market, Markets+, which already has attracted participants. (See Pathways ‘Step 2’ Bill Introduced in Calif. Legislature.) 

“Why do we need to do this now? The urgency is that if we don’t act quickly, we risk having less ability to trade with other regions and impact the clean energy resources available across the West,” Becker said. “Regions are getting tired of waiting for us and are considering joining Southwest Power Pool’s Markets+. If they do, they will stop trading with California and also in this WEIM I mentioned earlier, and have less need to make other bilateral trades with California.” 

Becker said participation in the RO is voluntary, adding that California retains its right to set its own energy policy goals and doesn’t have to join unless “specific, stringent guardrails are met.” 

Reached for comment about Becker’s statement, SPP spokesperson Derek Wingfield told RTO Insider: “Markets+ creates additional opportunities for Western entities and will not inhibit trade among them, including entities in California.” 

Stern, meanwhile, contended Pathways would allow California to tap into a wider market of clean energy resources, saying “if we don’t reach beyond our borders and allow for other cleaner renewables to be able to come in and balance our grid depending on the time of day, we’re gonna have to find that power somewhere. And right now, we are literally paying for it, and we’re not just paying for it with taxpayer dollars, but it’s in our lungs, it’s in environmental injustices everywhere.” 

Representatives from the International Brotherhood of Electrical Workers, Natural Resources Defense Council, Environmental Defense Fund and others supported the bill during the hearing. 

Opposition, Concerns

However, lawmakers also heard from opponents, including the Center for Biological Diversity, the California Solar & Storage Association and Californians for Green Nuclear Power. 

Bill Julian, former legislative director of the California Public Utilities Commission, opposed the bill on behalf of himself and former CPUC President, Loretta Lynch. 

Lynch, in a previous meeting, contended many of the arguments favoring Pathways rely on hypothetical scenarios in which EDAM would consist of participants from all Western states. This is unlikely, Lynch said, noting that several entities already have decided not to join EDAM. (See Pathways Initiative Receives Praise, Skepticism at Calif. Hearing.) 

Though the committee voted unanimously to pass the legislation, some lawmakers voiced concern about the lack of certain provisions in the bill. 

For example, Democratic Sens. Benjamin Allen and Aisha Wahab expressed concern about California’s ability to withdraw from the RO under the legislation. 

Allen pointed to comments by groups like The Utility Reform Network (TURN) that have argued the bill’s language is not strong enough to protect from the risk of penalties against the state or utilities if California withdraws. 

Committee member Susan Rubio urged Becker to explore further consumer protections. 

Becker noted that the groups behind the bill are looking at amendments and plan to move forward with some suggestions, even some from opposing parties like Lynch. 

“Certainly, you have my commitment to work with you and make sure that by the end of this process there’s a bill that we’re all comfortable with,” Becker said. “And then, as just a reminder, we’ll have at least two years with the legislature able to weigh in before we join.” 

The Pathways bill states that CAISO can decide whether to join the RO-governed market on or after Jan. 1, 2027. 

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FERC Partly Approves NYISO Order 2023 Compliance Filing

FERC has approved most of NYISO’s proposed plan to comply with Order 2023, denying several of its proposed variations to the commission’s pro forma rules and directing the ISO to submit an additional compliance filing in 60 days (ER24-1915, ER24-342). 

Issued in July 2023, the order directed grid operators to revise their generator interconnection procedures to a “first-ready, first-served” cluster study process. It revised the commission’s pro forma procedures while allowing for independent entity variations to account for regional differences. 

For NYISO, this meant altering several of the order’s time frames to align with its current Class Year study process, which already used a clustered approach, with queue position playing a limited role. For example, the ISO asked for 596 days to complete the overall study process, slightly more than the order’s maximum of 585, and proposed that its customer engagement window be 70 calendar days, instead of the order’s prescribed 60. 

FERC accepted most of these in its April 17 order because it found they “accomplish the purposes” of Order 2023 and would give both NYISO and its interconnection customers flexibility.  

While several parties protested the proposed 596-day time frame, the commission said “NYISO’s cluster study process has a unique study structure and requirements due to its proposed single, two-phase study process, which already incorporates restudies and does not have a separate facilities study. Thus, the timeline of the proposed NYISO cluster study process is appropriately compared to the timeline of pro forma study process including the pro forma LGIP facilities study timing, contrary to the contentions of” the protesters. 

The commission, however, denied the ISO’s proposal to not allow interconnection customers to use third-party consultants to perform study work. While it argued “that study elements need to be sequenced and managed in a particular order, NYISO does not explain why a third-party consultant could not perform its study within that time frame,” the commission ruled. The variation would not “accomplish the purposes of the cluster study to increase efficiency and provide greater certainty to interconnection customers,” it said. 

FERC also denied NYISO’s proposal to apply penalties only at the end of the process, and not at the end of Phase 1. The commission said this did not provide a sufficient incentive for NYISO to complete Phase 1 in a timely manner. 

And FERC denied NYISO’s proposal to use a 300-day affected-system study timeline, saying it would bring the ISO out of step with neighboring regions that adhere more closely to the pro forma 150-day timeline. FERC told it to either revise the timeline to 150 days in its compliance filing or justify its proposal. 

Finally, FERC rejected NYISO’s method for allocating the costs of several studies as outside the scope of Order 2023, but without prejudice, giving the ISO the opportunity to file it as a separate proposal. 

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MISO, PJM Forgo Typical Interregional Studies for Novel Transfer Work

MISO and PJM will not take on customary interregional planning studies this year, deciding they have enough on their plates with a new and in-progress joint transfer study.

The grid operators announced they would devote their attention throughout 2025 to their interregional transfer capability study (ITCS), a new type of study that might yield projects that allow for a greater volume of transfers. (See Smaller Projects Expected from Maiden MISO-PJM Joint Tx Study and OMS, OPSI Pen 2nd Letter to MISO and PJM to Compel Meaningful Interregional Planning.) The two decided against undertaking a more traditional coordinated system plan, which could result in more expensive interregional market efficiency projects, or their established, smaller targeted market efficiency project study.

MISO and PJM arrived at the conclusion after conducting an annual issues review designed to look for transmission opportunities. The process is required under their joint operating agreement.

The RTOs said there’s a possibility their ITCS changes the way the two manage future interregional studies. They said their transfer study could lay the “foundation for assessing future coordinated planning needs.” MISO and PJM are working from a blended, long-term model that combines the RTOs’ assumptions to identify system needs in the transfer study, a first for two major North American RTOs.

“By focusing our efforts on the ITCS, we aim to gain a clearer understanding of emerging transfer limitations and deliverability issues across the seam. The insights gained through this study will help guide future planning activities and determine whether additional interregional analysis or project development is appropriate in subsequent years,” MISO and PJM said in an April 18 emailed statement to their stakeholders.

The two said they would update stakeholders as the transfer study progresses and if “planning needs arise that warrant further coordination.”

MISO and PJM so far have identified more than 30 shared reliability, transfer and economic issues that could form the basis for upgrades under the ITCS.

In an emailed statement to RTO Insider, MISO said the goal remains to develop a draft portfolio by the end of 2025. MISO said it and PJM plan to open a monthlong stakeholder comment period at the end of April to solicit solutions.

MISO and PJM previously said they would focus on equipment upgrades and projects that can use existing rights-of-way in the first transfer study. They said the study, combined with FERC Order 1920, could open the door for longer-term interregional planning and greenfield projects.

MISO and PJM historically have approved one interregional market efficiency project in 2020 and four sets of the smaller targeted market efficiency projects aimed at relieving congestion since 2017. They haven’t completed an interregional transmission planning study since 2022.