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January 28, 2025

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New England Lobbyists Preview 2025 State Legislative Sessions

Government affairs experts previewing New England’s 2025 legislative sessions during a Jan. 24 webinar held by the Northeast Energy and Commerce Association outlined some key policy overlaps and notable differences among states.

Energy affordability will likely continue to be a major topic for all six states. The region is facing the need for major investments in the coming years to replace aging transmission infrastructure, keep up with load growth and interconnect new renewable resources, which threaten to increase the region’s already-high electricity prices.

“The key issue when it comes to energy in Connecticut is affordability,” said Nicole Tomassetti, an associate at Capitol Strategies Group.

Increasing electricity prices were a hot topic in the state in 2024, with Republican lawmakers unsuccessfully pushing for a special session to address the issue. Tomassetti noted that affordability concerns caused the state to abstain from selecting any power from the 2024 multi-state offshore wind procurement. (See Connecticut Closes the Door on 2024 OSW Procurement.)

But despite high energy prices, Connecticut Democrats performed well in November, achieving veto-proof majorities in the House and Senate.

With Democrat Ned Lamont in the governor’s office, “I don’t think we expect them to utilize that, but it does illustrate how they’ve expanded their hold on the legislature,” Tomassetti said.

Meanwhile, the public spat between the Connecticut Public Utilities Regulatory Authority and the state’s investor-owned utilities continued in 2024, centered around the utilities’ rate of return on their investments. (See The Rocky Road to Performance-based Regulation in Connecticut.)

“Things have been tense, and I think they’ve gotten tenser in the last couple months between the [electric distribution companies] and the regulator,” Tomassetti said.

NH Republicans Tighten Grip

In New Hampshire, Republicans also tightened their grip on all three branches of state government in November, gaining seats in both the House and Senate and maintaining Republican control of the governor’s office, replacing outgoing Gov. Chris Sununu with Kelly Ayotte.

With federal funding no longer coming in from the American Rescue Plan Act, balancing the state budget is the “number one priority” for New Hampshire lawmakers, said Heidi Kroll, vice president at J Grimbilas Strategic Solutions. Kroll said state agencies could face budget cuts in the range of 6% to 10%, though specific budget numbers have not been announced.

On energy policy, “affordability and reliability are the two buzzwords that we’re hearing most often,” Kroll said, adding that lawmakers will likely discuss potential changes to net metering and the state’s renewable portfolio standard, which is up for review this year.

Kroll added that she is still waiting to see whether the Ayotte administration will make any notable changes in energy policy from the Sununu administration. Ayotte has called for an “all-of-the-above energy strategy” that includes pursuing small modular reactors and hydrogen power, but has expressed concern about offshore wind in the Gulf of Maine.

Mass., RI Seek to Protect OSW

In contrast to New Hampshire, Massachusetts remains focused on standing up the region’s offshore wind industry and will likely be forced to go on the defensive to protect its nascent industry from a hostile Trump administration.

“I can’t underscore enough how important offshore wind is to the state’s clean energy and climate goals,” said Jen Gorke, principal at TSK Associates.

On his first day in office, President Donald Trump paused new leases and permitting approvals for offshore wind projects. (See Critics Slam Trump’s Freeze on New OSW Leases.) Meanwhile, uncertainty remains around whether the administration will target projects that have already been approved. Vineyard Wind 1, New England Wind, SouthCoast Wind and Revolution Wind all have approved construction and operation plans.

In response to a question at his confirmation hearing about offshore wind projects already underway, interior secretary nominee Doug Burgum said projects will be allowed to continue “if they make sense and they’re already in law.”

“The projects that are under construction, we need to make sure those can continue and are successful,” Gorke said, adding that states need to prepare for a “worst-case scenario from the federal government” and work together to prepare to take advantage of the next change in federal administration.

The Massachusetts legislature, which passed major climate and energy bills in 2021, 2022 and 2024, likely will not see another omnibus climate bill this year, Gorke said, adding that “2025 will largely be about implementation.”

However, legislators will likely work on smaller-scale efforts related to electricity rates, the state’s utility-run energy efficiency program and competitive electricity supply regulations, Gorke said.

Legislators “got really close to a compromise last year” on competitive supply reforms, Gorke said, expressing hope the issue “can be put to bed in a productive way this session.”

Rhode Island has similarly focused much of its energy policy on boosting offshore wind, said Matt Jerzyk, legal counsel at William A. Farrell & Associates.

The state has contracted for 400 MW of power from Revolution Wind — with Connecticut on the hook for the project’s remaining 304 MW — and recently selected 200 MW from SouthCoast Wind, with Massachusetts selecting the remaining 1,087 MW.

While SouthCoast has received its major federal approvals, it must still win some “ministerial federal approvals,” Jerzyk noted.

The project has “a whole host of state approvals to get through, but I think they’re still worried about the federal side,” he said. The project also has not yet finalized its contracts with the electric utilities in both states.

Vt. Dems Lose Supermajorities, Maine Looks to LTTP

In Vermont, the Republican party gained ground in both the House and Senate, with Democrats losing supermajorities in both chambers. Gov. Phil Scott (R) won reelection by a wide margin.

“There were a lot of veto overrides last year … that has changed now,” said Gabrielle Malina, government relations manager at Downs Rachlin Martin. Democratic lawmakers “will have to work more closely with Republicans and with the governor,” she added.

Scott and some legislators may seek changes to Vermont’s Global Warming Solutions Act, which was passed in 2020 and sets emissions reduction requirements through 2050. The state is facing a suit from the Conservation Law Foundation for not taking adequate action to comply with the law’s 2025 requirement.

“It’s hard to get a read yet whether there will be the political will to change it,” Malina said. “I think everybody’s pretty worried about the kind of lawsuits we’ll see when we get to 2030.”

For Maine, Jeremy Payne, principal at Cornerstone Government Affairs, highlighted the potential of the first Longer-Term Transmission Planning (LTTP) solicitation, which is being developed by ISO-NE at the request of the New England States Committee on Electricity (NESCOE). (See ISO-NE to Work on State-backed RFP for Northern Maine Transmission.)

The LTTP solicitation is intended to reduce transmission constraints in Maine and enable the interconnection of at least 1,200 MW of onshore wind.

“My hope is that this NESCOE process goes well,” Payne said. “If it does, then I think it could be easy to replicate going forward.”

He noted that key topics for the state will likely include potential changes to net energy billing, renewable energy solicitations and Gov. Janet Mills’ proposal to create a cabinet-level Department of Energy Resources.

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El Paso Electric to Join SPP’s Markets+ in 2028

El Paso Electric says it will join SPP’s regional day-ahead Markets+ service offering in a “strategic move … tailored” to meet expected customer load growth and evolving needs. 

In a Jan. 24 press release, the Texas utility said it made the decision following an “extensive” evaluation process and its participation in CAISO’s Western Energy Imbalance Market. It said SPP’s experience as an RTO and its “proven track record of expanding renewable energy resources” make it a trusted partner. 

EPE plans to make the transition in 2028, a year after Markets+’s expected launch. The utility did not participate in the first phase of the market’s development and is the first new organization to join during Phase 2. It will sign the same Phase 2 funding agreement as current participants, SPP said. 

The RTO’s staff and more than 30 Western entities are working on the market’s second phase of development following FERC’s approval of the tariff Jan. 16. (See SPP Markets+ Tariff Wins FERC Approval.) 

SPP COO Antoine Lucas said he was excited to hear of EPE’s decision. 

“We look forward to welcoming them as a market participant,” Lucas said in a statement. 

“Markets+ will provide utilities across the region, including EPE, access to a diverse pool of energy resources, enabling a more efficient and reliable energy grid,” the company said in its release. 

It said joining the market will result in increased reliability, cost savings and clean energy integration, supporting its commitment to sustainability and clean energy goals and maintaining affordability for customers. 

EPE said its decision came after two years of collaboration and planning with stakeholders across the region. 

A Brattle Group market study released last August estimated EPE would see projected benefits of $19.1 million a year in EDAM, compared with $9.1 million for Markets+. (See Brattle New Mexico Study Shows EDAM Benefits Outpacing Markets+.)

The utility sits outside ERCOT in the Western Interconnection and is receiving reliability coordinator functions from SPP’s Western RC Services. It serves about 460,000 customers in 10,000 square miles of Texas and New Mexico, including the major cities of El Paso and Las Cruces, N.M. 

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PJM MRC/MC Briefs: Jan. 23, 2025

Markets and Reliability Committee

Stakeholders Endorse Changes to Generator Deactivation Requirements

VALLEY FORGE, Pa. — The PJM Markets and Reliability Committee and Members Committee endorsed a proposal to rework the RTO’s rules around generation deactivations, including a longer notification period, changes to components of the deactivation avoidable cost credit and adding transparency to the process. (See “First Read on Extended Notification Requirement for Deactivating Generation, Changes to Compensation,” PJM MRC/MC Briefs: Dec. 18, 2024.) 

The proposal would increase the advance notice a generation owner must provide PJM ahead of bringing a unit offline from three months to one year. The status quo deadlines for owners to file for exemptions from the requirement that they offer their resources into the capacity market if they intend to deactivate would remain unchanged. The PJM proposal was supported by the Deactivation Enhancement Senior Task Force (DESTF) in October 2024, winning out over alternatives from the Independent Market Monitor and Calpine, as well as a separate proposal by the RTO. 

The longer gap was sought to provide PJM with more time to conduct studies to identify any transmission violations that may be caused by a unit going offline and to make it more feasible for other resources or market participants to mitigate those issues rather than relying on costly reliability-must-run (RMR) agreements. 

Paul Sotkiewicz, president of E-Cubed Policy Associates, said the longer deadline, paired with a compressed Base Residual Auction (BRA) schedule, would prevent generation owners from being able to tell if their resources would be able to provide capacity in a delivery year before making the decision to deactivate. Given accelerating load growth and generation retirements, he said the proposal could imperil PJM’s efforts to maintain resource adequacy. 

“We believe that runs counter to the reliability of the system,” he said. 

The proposal would also increase the deadlines for all resources, Sotkiewicz argued, when only a few require RMR agreements. 

PJM Executive Vice President of Market Services and Strategy Stu Bresler said the submission of a deactivation notification does not prevent a generation owner from offering that unit into the capacity market and withdrawing the request if it clears. He acknowledged, however, that there could be staffing issues associated with that dynamic. 

Sotkiewicz responded that there are financing and debt issues associated with the determination to bring a unit offline that complicate the ability to undo the decision. It would also increase the administrative burden for PJM staff if resources are submitting and withdrawing deactivation notices that must be studied. 

“That’s not helping PJM because you’re ripsawing the system around in terms of planning,” he said. 

The proposal would also revise one of the two compensation mechanisms for resources operating on RMR agreements: the deactivation avoidable cost credit. It would remove the $2 million limit on project investments that can be recompensed, limit the annual adder on those investments to 10%, and remove a trigger that causes the credit to be paid through the daily deficiency rate rather than the deactivation avoidable cost rate (DACR) when the DACR and multiplier is greater than the deficiency rate. 

The changes to transparency would increase the amount of information published around responses to deactivation notifications, market power determinations, details of RMR agreements and the estimated RMR revenue allocation zonal rate. PJM’s Chantal Hendrzak said stakeholders have requested more transparency to understand the going-forward costs of RMR agreements. 

Susan Bruce, representing the PJM Industrial Customer Coalition, said the proposal is an improvement from a consumer perspective, albeit a minor one. She said the ICC is supporting the changes in a goodwill gesture with the hope that deeper changes to how RMR agreements are utilized will be pursued in the second phase of the DESTF’s work. The end product of those efforts should consider both the permanent design of the capacity market, with three-year forward auctions, and the current reality where auctions are held months in advance of their corresponding delivery year. 

“There is a need for thinking about some of those issues, both within the world that we live in now, where we are dealing with things in a whack-a-mole fashion and an accelerated auction timeline. But we also need to think about a time when we have a three-year forward” market, she said. “There is a place here for pragmatism, as well as creating certainty for this fragmented piece.” 

Monitor Joe Bowring argued that PJM’s proposal would not adequately address issues with RMR compensation; would not require RMR resources to document their actual costs; did not require a review of the need for and level of those costs; and should have required the notice be provided one year ahead of the BRA corresponding to the delivery year in which the unit would retire. 

Bowring said that under the normal capacity market timing, retiring resources have had to provide notice more than three years ahead of the relevant delivery year. The proposal also lacks provisions for addressing circumstances where RMR units underperform and would fail to address the inclusion of RMR resources in capacity auctions, he argued. 

Widened Scope for ELCC Issue Charge Approved

Stakeholders endorsed adding a key work activity (KWA) to an issue charge focused on how PJM’s effective load-carrying capability (ELCC) framework feeds into resource accreditation and the amount of capacity it may offer. 

The additional KWA seeks to “explore potential reforms that may provide greater certainty in ELCC accreditation and/or allow market participants to better manage potential changes in ELCC accreditation between the time of the BRA and the final ELCC values determined for a delivery year.” 

The paragraph added to the issue charge was revised during the meeting to include other relevant planning parameters to allow the work to also consider impacts to the stability of financial transmission rights. 

The discussion was sparked by rising load growth in the preliminary 2025 Load Forecast, particularly in the winter, leading PJM to consider revising the ELCC values of resources participating in the third 2025/26 Incremental Auction, as well as the installed reserve margin (IRM) and forecast pool requirement (FPR) for the auction. 

Mike Cocco, of Old Dominion Electric Cooperative, said the change is warranted to address the risk capacity providers face if their accreditation shifts after the BRA, forcing them to buy capacity in the IAs or face deficiency charges. 

E-Cubed’s Sotkiewicz said the issue demonstrates that PJM needs to stop moving items through the stakeholder process without doing the analysis and full stakeholder discussion, because there have repeatedly been unintended consequences. “We need to think things through very clearly, and we are not learning the lesson,” he said. 

The overall issue charge also seeks to provide capacity sellers with more certainty around how changes to their resources will affect accreditation and improve the investment signals sent by accreditation. Other KWAs include education about the historical data included in ELCC, key design principles and criteria for accreditation, alternative methods and inputs that can be used in the marginal ELCC framework, and developing proposals to revise ELCC. 

The issue charge aims to have governing document revisions filed with FERC in the first quarter so the changes can be implemented for the 2026/27 BRA, scheduled for July. The work is being conducted by PJM’s ELCC Senior Task Force, which is also considering a handful of issue charges brought by LS Power to evaluate the transparency and functionality of the framework. (See “Discussions on CETL Shifted to ELCC Task Force,” PJM MRC/MC Briefs: Dec. 18, 2024.) 

Revised Incremental Auction Parameters Endorsed

The committee endorsed revised ELCC ratings and a lower FPR value for the third 2025/26 IA, reflecting a shifting resource mix and performance data pushing risk toward the winter. 

The endorsement is advisory to the PJM Board of Managers’ decision on whether to approve the figures. 

Most resource types saw their ratings stay flat or within 1% of the ratings used during the BRA, but offshore and onshore wind saw theirs increase by 3% and 2%, respectively. Storage ratings decreased most sharply for four-hour batteries, with the impact muted the longer the duration, and landfill gas intermittent generation decreased by 3%. 

The available installed capacity decreased from 191,693 MW to 188,920 MW, causing the FPR proposed for the IA to fall from 0.9387 to 0.938. The IRM and capacity benefit of ties would remain the same. 

The class rating changes were in line with a shift toward winter risk, which accounts for 87.8% of expected unserved energy (EUE) risk under the proposal, up from 86.9% in the BRA. The changes were less substantial than values PJM had presented to the Planning Committee earlier in January, as the RTO decided not to continue using preliminary data from the 2025 Load Forecast in the proposal. The original values saw 96.2% of EUE risk concentrated in the winter, driving sharper changes in ratings and auction parameters. 

PJM’s Andrew Gledhill told the MRC that the 2025 Load Forecast would be used for the capacity emergency transfer objective and reliability requirement, but not the ELCC class ratings. (See “Stakeholders Discuss Revised IRM and FPR Values for 3rd Incremental Auction,” PJM PC/TEAC Briefs: Jan. 7, 2025.) 

PJM CEO Manu Asthana said there are improvements to be made to how ELCC models extreme weather and performance data. While load forecasting tends to look at 50/50 cases, it’s the 90/10 case that is driving the risk modeling, particularly the January 1994 cold wave. He said PJM is looking at spending more time considering how the edges of the data are reflected in its modeling. 

E-Cubed’s Sotkiewicz said that raises questions of whether reliability risks are being driven by historical data or PJM’s selection of which data to include. He also argued that the impact of the load forecast on accreditation has created a dynamic where demand is determining the amount of available supply, running contrary to economic principles. “If our accreditation is affected by the load forecast … then this is a modeling that is not working,” he said. 

Sophia Dossin, of Middle River Power, said there is a broader gap around being able to hedge capacity market risk, particularly around the prospect of changing accreditation. 

Performance Strong During Record Winter Peak

PJM Director Operations Planning Dave Souder said there was excellent coordination between the RTO and its transmission and generation members as it set a new winter peak load of 145 GW on Jan. 22 as a winter storm brought freezing temperatures across the footprint. (See related story, PJM Sets Record Winter Peak Load.) 

Several emergency procedures and alerts were announced ahead of the storm, including maximum generation and load management alerts, some of which remained in place until the end of the storm Jan. 23. Souder said two other days exceeded 140 GW during the storm, and it was possible that two of the top five winter peaks were set that week. 

Based on unit start-up requirements, low ambient operating temperature limits and historical performance, Souder said about 50 GW of resources were determined to be at risk going into the storm, leading PJM to preschedule resources and avoid cycling them on and off. 

Rebecca Stadelmeyer, of Gabel Associates, said the lack of coordination between the electric and gas sectors was on display during this storm and must continue to be a focus of stakeholder efforts. She noted that scheduling fuel over long holiday weekends was one of the core focuses of efforts following the December 2022 Winter Storm Elliott, and generators reported significant losses over the Martin Luther King Jr. Day weekend after procuring packages of fuel that ultimately was not consumed. (See “Stakeholders Endorse Revised Proposal to Align Energy, Gas Schedules,” PJM MRC/MC Briefs: June 27, 2024.) 

“It doesn’t seem to be changing anytime soon,” she said of the gas industry’s rules for fuel procurement. 

PJM Senior Vice President of Operations Mike Bryson said it’s an issue the RTO must “wrestle with” because the long weekends remain a challenge for dispatchers and generators. 

PJM’s Bresler said emergency procedures continue to not be fully reflected in market prices, which is part of the issues being addressed by the Reserve Certainty Senior Task Force. 

Other Committee Business

Stakeholders deferred action on revisions to Manual 14H: New Service Requests Cycle Process that PJM said would clarify the site control requirements for projects in the interconnection queue. The RTO has argued that the language is necessary to create a clear set of rules to apply to all generation projects, but developers have argued that the proposal is too onerous and would require holding onto unneeded land to comply. (See “Vote on Site Control Requirements Deferred,” PJM MRC/MC Briefs: Dec. 18, 2024.) 

PJM’s Kevin Hatch presented a first read on revisions to Manual 13: Emergency Operations to establish a new procedure for wildfires. Staff meteorologists would evaluate and discuss wildfire risks with transmission and generation owners, conduct future and real-time studies to identify transmission assets that may need to be taken out of service and coordinate with TOs to cancel future transmission maintenance and bring offline assets back into operation as needed. TOs would be responsible for monitoring red flag warnings and high risk conditions, notifying PJM of lines that may need to be de-energized, and re-evaluate the ratings of any facilities impacted by wildfires. 

PJM’s Ben Miller presented revisions to Manual 40: Training and Certification drafted through the document’s periodic review. The proposal would update references to reflect organizational changes and clarify how members should respond to PJM data verification requests. It is set to go for an endorsement vote on Feb. 20. 

Members Committee

Stakeholders Endorse Process for Proposals Rejected by FERC

The MC endorsed revisions to Manual 34: PJM Stakeholder Process to create a pathway for considering how to proceed after FERC rejects a member-endorsed proposal. 

The language states that within 90 days of FERC rejecting a filing, PJM may present the order to a senior standing committee and recommend next steps. The presentation may be made on the RTO’s own initiative or following a stakeholder request. The discussion may include changes to the proposal that could be made, restarting the stakeholder process or following a new path. 

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Ariz. Commissioner Questions Utility Decisions to Join SPP’s Markets+

Arizona Corporation Commissioner Kevin Thompson on Jan. 24 said he thinks his state’s four major utilities may have erred in committing to joining SPP’s Markets+ instead of CAISO’s Extended Day-Ahead Market (EDAM).

Thompson shared his views during a California Energy Commission workshop exploring the impacts on California of the West-Wide Governance Pathways Initiative’s effort to create an independent “regional organization” (RO) to provide governance to CAISO’s EDAM and Western Energy Imbalance Market (WEIM).

In a joint announcement issued last November, Arizona Public Service, Salt River Project, Tucson Electric Power and UniSource Energy Services said they planned to start participating in Markets+ in 2027, citing the potential to realize a combined $100 million in benefits from the market. (See 4 Arizona Utilities Commit to Joining Markets+.)

Speaking during a panel featuring four Western utility commissioners who signed the July 2023 letter launching the Pathways Initiative, Thompson said he urged his state’s utilities to delay their decisions until developments played out around the initiative’s “Step 2” plan, which include an effort this year to pass a bill in California authorizing CAISO to both hand off its oversight of market rules to the proposed RO and participate in the new entity.

“I think Arizona’s utilities jumped the ball a little bit,” Thompson said. “I think they jumped out there ahead of their skis, and I asked them if they would just allow this to work itself through and see where it ends, because this could be the next best thing since sliced bread. You won’t know if you don’t see it through.”

As a publicly owned utility, SRP is not subject to the jurisdiction of the ACC, while the state’s investor-owned utilities have a relatively free hand in deciding on a day-ahead market. APS, SRP and TEP all currently participate in the WEIM but have been firm supporters of the development of Markets+ as an alternative to the EDAM, in large part because of their concerns about CAISO’s state-controlled governance framework.

New Mexico Public Regulation Commissioner Pat O’Connell echoed Thompson’s comments, saying, “It will be interesting to see if we can overcome this governance issue” and questioned “how well those [Arizona utility] decisions will age.”

“As the economic studies suggest, not well,” O’Connell said, referring to the series of economic studies published over the last year showing most Western utilities would financially benefit more from a single electricity market that includes California than in a scenario in which the region is divided into two markets.

Among those studies was a Brattle Group analysis showing that New Mexico’s utilities would realize greater savings from EDAM even if their larger Arizona neighbors joined Markets+, a finding that prompted Public Service Company of New Mexico (PNM) to commit to the CAISO market. (See Brattle New Mexico Study Shows EDAM Benefits Outpacing Markets+ and PNM Picks CAISO’s EDAM.)

“One of the things you learn by working in the planning world is that — especially in electricity — it’s least-cost if we can share” resources, O’Connell said, referencing his past experience working for utilities, including PNM.

O’Connell pointed out that New Mexico’s potential for developing both wind and solar resources is much larger than its energy demand, which means that “it has a lot to a lot to contribute to California in terms of providing low-cost wind resources.”

“All those things were in my head when we gathered together and started talking about, ‘How can we create the broadest possible footprint for regional coordination?’ And that immediately made sense to me: that that is something worth pursuing,” he said.

None of the Arizona utilities responded to a request for comment on the commissioners’ statements.

Regardless of the direction the Arizona utilities take, Thompson said he is “committed to staying on” with Pathways, an effort he likened to the drafting of the Declaration of Independence.

While acknowledging Markets+ supporters’ concerns that CAISO could have continued outsized influence within the new RO, Thompson expressed hope that Pathways participants can address that when they embark on the effort’s “Step 3” process to refine the RO and possibly broaden its authority.

“As the states and the stakeholders continue to work through Step 2 and move to Step 3, I think you’re going to see a lot of the details work themselves out,” he said.

“This is something that was built from the ground up,” he continued. “You know, it would have been too easy to follow a PJM model or the other models in the north and the east. We’re not PJM; we’re not the east. We’re the West, and we’re unique in that.”

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FERC Drops Consideration of GHG Policy Statement for Gas Infrastructure

FERC on Jan. 24 issued an order terminating its proceeding on the consideration of greenhouse gas emissions in natural gas infrastructure project reviews (PL21-3). 

“Having thoroughly reviewed that record, we are now withdrawing the draft GHG policy statement and closing that proceeding,” FERC said. “We find, based on the record that has been developed, that the issues addressed in that proceeding are, in general, better considered on a case-by-case basis, when raised by parties to those proceedings, as the commission has done following the issuance of the draft.” 

The proposed policy statement dates back to former Chair Richard Glick’s tenure, and opposition to it from former Sen. Joe Manchin (I-W.Va.) helped sink his re-nomination. FERC did not move forward on the draft for the rest of President Joe Biden’s term, during which Commissioner Willie Phillips served as chair. (See Glick’s FERC Tenure in Peril as Manchin Balks at Renomination Hearing.) 

FERC had issued the policy statement in February 2022, explaining that it would presume that projects with estimated GHG emissions of at least 100,000 metric tons of carbon dioxide equivalent per year will have a significant impact on climate change — requiring that the commission conduct an environmental impact statement — unless the developer can rebut that presumption with evidence. The policy was strongly opposed by Republican Commissioners James Danly and Mark Christie (the latter of whom became chair Jan. 20). 

But a month later, FERC walked back the policy, labeling the statement as a draft and inviting comments on it, on top of the tens of thousands of comments it had already received when it issued its Notice of Inquiry the year before. (See FERC Backtracks on Gas Policy Updates.) The commission simultaneously did the same thing with a separate statement that updated its 1999 policy on granting gas pipelines certificates of public convenience and necessity. That docket began with an NOI issued in 2018 and was only mentioned in last week’s brief order (PL18-1). 

All three Democratic commissioners — Phillips, David Rosner and Judy Chang — wrote a joint concurrence, saying that since they have been on FERC, they have followed the law when evaluating applications for natural gas infrastructure. 

“The consideration of greenhouse gas emissions in our review of natural gas infrastructure projects has been one of the most challenging issues before the commission for several years,” they said. “The extent to which the commission must account for the project’s GHG emissions and in turn the impacts on global climate change has been debated and litigated at length before the commission and the courts.” 

The courts have continued to hand down rulings on cases that implicate FERC’s environmental reviews of gas infrastructure, including remanding cases in which they find its analysis lacking, the Democrats said. 

While the policy statement is being dropped, the three commissioners said it has provided information that has proven useful for FERC as it developed its current, bipartisan case-by-case approaching to reviewing the climate impacts of natural gas infrastructure. 

FERC’s approach to GHGs has evolved, and in complying with the National Environmental Policy Act, it estimates reasonably foreseeable emissions attributable to a proposed project; provides a qualitative discussion on potential adverse impacts from those emissions; compares them to state or national levels; and calculates monetized values, the commissioners said. FERC also expects developers to evaluate technically and economically feasible strategies to cut emissions during construction and operation. 

“All of our colleagues have joined us on orders using this approach to comply with our NGA and NEPA obligations,” the Democrats said. “Critically, the courts have upheld it. If this approach is continued, it will provide more certainty for all parties and stakeholders, fulfill the commission’s obligations to consider environmental impacts in its decisions and inform the public regarding the basis for those decisions.” 

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FERC Approves CAISO Energy Storage Bid Cost Recovery Changes

FERC on Jan. 24 approved CAISO’s tariff revisions related to real-time bid cost recovery rules for energy storage resources. 

The ISO sought revisions on the grounds that the existing bid cost recovery structure allowed for unwarranted compensation at higher value than actual costs, creating an incentive to bid in a manner that would result in excessive payments (ER25-576). 

Without the tariff changes, CAISO said, “scheduling coordinators for storage resources may exploit market buy-backs and sell-backs through strategic bidding to inflate bid cost recovery payments even more.” 

From January 2022 to September 2024, storage resources received bid cost recovery payments totaling $58 million, CASIO told FERC, most of which reflect real-time cost recovery payments. 

This is a much higher portion of bid cost recovery payments compared with the portion of energy that they provided to the grid, CAISO said. It said a 2024 report by its Department of Market Monitoring (DMM) found numerous situations where storage resources might receive inappropriate bid cost recovery payments. 

CAISO indicated also that storage is a rapidly growing energy sector — battery resources participating in CAISO markets expanded from about 500 MW in 2020 to more than 10,000 MW in October 2024, with 3,500 MW of it in the Western Energy Imbalance Market.  

After four months of intense stakeholder engagement, the CAISO Board of Governors and Western Energy Markets Governing Body unanimously approved the changes Nov. 7. (See Proposal to Refine Bid Cost Recovery for Storage Passes Unanimously.) 

In comments to FERC, DMM said it did not oppose the tariff revisions as a temporary short-term measure because they would limit inappropriate payments and limit the potential for gaming the bid cost recovery rules for batteries. 

DMM said it supports CAISO’s continued effort to further refine the rules through a new stakeholder initiative, but said these changes by themselves are insufficient because they address only the bid-cost component of the bid cost recovery calculation, which reduces gaming potential but does not address inefficient bidding incentives created by the revenue portion of the calculation. 

As such, DMM said, the tariff revisions do not address the core problem: that the payments remove storage resources’ exposure to real-time opportunity costs, creating incentives that can lead to inefficiencies and reliability issues. It said it hopes CAISO will promptly propose additional changes that will address this. 

In its Jan. 24 order, FERC accepted the proposed changes effective Dec. 1. 

It wrote: 

    • “We find that the revisions can help mitigate the magnitude of unwarranted or inflated bid cost recovery payments to storage resources, especially in real-time.” 
    • “With respect to bid cost recovery related to incremental energy, we find CAISO’s proposal to use the lower of a resource’s real-time energy bid or proxy (the maximum of a resource’s day-ahead LMP, real-time market default energy bid or real-time LMP for that interval) provides a reasonable representation of the operational nature of storage resources.” 
    • “With respect to bid cost recovery related to decremental energy, we find CAISO’s proposal to use the greater of a resource’s real-time energy bid or (the minimum of) the aforementioned proxies better reflect the costs of providing decremental energy.” 

FERC also wrote that some of the “core problems” DMM cites are beyond the scope of the proceeding but added that it found CAISO’s proposal a reasonable first step to mitigating real-time bid cost recovery payments. And it encouraged the efforts by CAISO, DMM and stakeholders to further refine the tariff. 

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WPP Stronger After Modernizing, Staff Hires, CEO Says

TEMPE, Ariz. — The Western Power Pool faced “real potential weaknesses” in 2024 due to staff shortages and outdated financial and accounting systems that needed to be addressed quickly, the organization’s leadership said during WPP’s annual member meeting in Tempe on Jan. 24.

Following the WPP’s Board of Directors approval of a 13% budget increase — from approximately $13.4 million to $15.3 million — for the 2024/25 fiscal year, the organization embarked on a hiring spree to improve operational oversight and meet future challenges, WPP CEO Sarah Edmonds said during the meeting.

The new hires include a chief financial officer, board administrator, human resource manager, program management analyst, technical trainer and graphics designer. Edmonds said WPP also modernized its finance and accounting practices by moving from manual spreadsheets to automated systems.

“We do need to keep adding people, but not at the scale of last year,” she added. “That was a serious and somewhat urgent investment for some areas of real potential weaknesses that we needed to address quickly.”

WPP coordinates six stakeholder-driven programs aimed at improving the power grid in the West, including the Western Resource Adequacy Program (WRAP) and Western Transmission Expansion Coalition (WestTEC). All these programs have experienced growth in scope and regional expansion at a time when WPP’s “house wasn’t really properly in order,” Edmonds said.

Edmonds also acknowledged that WPP historically has not been as transparent as it should be.

However, the efforts to boost staffing and modernize WPP’s financial structure have paid off, according to board Chair Bill Drummond. He noted that WPP “has been almost like a startup in many respects. It has scaled up to such an amazing degree.”

Moving into 2025, Drummond said the financial and accounting systems are “in great shape now. Got that where it needs to be.”

Edmonds said cybersecurity is the next target area. She noted that’s an area not unique to WPP and has also been underinvested in “given the kinds of threats that are out there on the system today. So that’s up next, and we’ll stay always nimble and vigilant.”

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USEA Forum Charts New Focus on ‘All-of-the-above’ Energy Policies

WASHINGTON, D.C. ― Karen Harbert, CEO of the American Gas Association, was the first to speak at the U.S. Energy Association’s 21st Annual State of the Energy Industry Forum and set a jubilant tone for the fossil fuel leaders at the Jan. 23 event at the National Press Club. 

“We’re the cool kids now,” Harbert said. “We have to go first.” 

An ongoing cold snap in the Midwest and East Coast has meant record use of natural gas, she said.  

“We are the biggest part of the power generation fleet right now. We’re over 40%, and that’s going to continue to grow with the onset of data centers, advanced manufacturing and strategic industries. So, gas is back. … We’re popular, we’re affordable, we’re efficient and we’re clean.” 

Coming three days after President Donald Trump began his second term with a flurry of executive orders promoting a major increase in U.S. fossil fuel production, the event reflected the quickly shifting landscape of national energy policy and the resulting shift in industry priorities and narratives. (See What is and isn’t in Trump’s National Energy Emergency Order.) 

All-of-the-above strategies for meeting the exponential demand growth from artificial intelligence and megawatt-guzzling hyperscale data centers were a key theme at the day-long event, as was the desire for “durable,” bipartisan legislation to streamline and accelerate permitting.  

No one mentioned climate change, or even Biden’s signature climate legislation, the Inflation Reduction Act, at least not by name.  

Like Harbert, the CEOs of all the major fossil fuel trade associations exuberantly staked out their claims as preferred providers of the reliable, affordable, “clean” (or at least “cleaner”) power that data centers and U.S. consumers need. Leaders of renewable energy groups ― solar, hydropower and nuclear ― argued for their essential role in the diverse, carbon-free energy mix the high-tech hyperscalers want.  

Mike Sommers, CEO of the American Petroleum Institute, began his pitch by noting that no one on the forum’s first panel had mentioned the words “energy transition.” 

“We’re at a moment today where we’re transitioning from the energy transition to energy reality, and energy reality is that all of us are going to be using a heck of a lot more energy in the future, particularly in the developing world,” Sommers said. 

The U.S. is best positioned to meet that global demand because of its “strong regulatory structure,” he said. “We produce oil and gas cleaner than any other country in the world.” 

Michelle Bloodworth, CEO of America’s Power, the coal industry’s trade association, talked up the value of coal’s ability to deliver power in extreme weather events “because it has 90 days of onsite fuel. It’s hard to beat this onsite fuel when it’s really, really cold.” 

But even Bloodworth said support for coal “doesn’t mean that we don’t support wind and solar. Again, we need them all. We need to keep all the existing resources that we have until all this new generation” comes online. 

Renewables Retrench

Jason Grumet, CEO of the American Clean Power Association, led the retrenchment of renewables, dissociating his organization from former President Joe Biden’s goal of a 100% decarbonized grid by 2035. It was, he said, “a narrative that was not our own.” He and others pointed to a combination of natural gas and renewables as a likely and pragmatic way forward. 

“The notion that molecules and electrons actually have political affiliation” needs to be set aside, Grumet said. The challenge and opportunity before the industry is to “show what it’s going to take to meet this demand in the time frame we need it.”  

“Every technology has strengths and weaknesses,” Grumet said. “The ability to build renewables fast is one of those strengths; intermittency is one of those weaknesses, and that’s why we have to be combined … to come up with a rational policy.” 

Abigail Ross Hopper, CEO of the Solar Energy Industries Association, said she would not support a 100% solar-powered electric system primarily because the U.S. should not be dependent on any one source of power.  

Like Grumet, she talked about the speed and scalability of installation that solar brings to the table, but also the reliability benefits of distributed as opposed to centralized generation.  

Distributed “makes a ton of sense” for addressing congestion on the grid, Hopper said. “Adding solar plus storage, other kinds of storage … that gives the grid more resiliency; that gives so [many] different ways of getting around outages. That allows consumers, if you have [solar] at your home, to be more secure.” 

Rich Powell, CEO of the Clean Energy Buyers Association, stressed the role that data centers and other large energy consumers in his organization now play in the energy landscape, with their commitments to carbon emissions-free energy. 

CEBA’s definition of emissions-free covers a broad range of technologies, from wind and solar to carbon capture and sequestration, making the group’s collective economic impact potentially significant, Powell said. 

USEA

Talking natural gas and solar at the USEA forum (from left): Mark Menezes, USEA, Dena Wiggins, Natural Gas Supply Association; Abigail Ross Hopper, SEIA; and Fred Hutchison, LNG Allies. | © RTO Insider LLC 

CEBA’s 400 members represent about $22 billion in market capitalization and 10% of all U.S. energy demand, providing significant demand and market signals, he said. An upcoming CEBA report will “sum up all the remaining demand signals for carbon emissions-free electricity in the United States alone, as part of an attempt to help grid planners who are thinking about new transmission that would be required to move new electrons to sources,” he said.  

Transmission expansion and flexibility will be essential, said Arshad Mansoor, CEO of the Electric Power Research Institute.  

“The changes we have seen in 12 months, we have not seen for the last 100 years,” Mansoor said, calling the speed of demand growth “unprecedented.” Borrowing Trump’s rallying cry, he said, the industry’s response must be to “build, baby, build,” but to do so in a smart way. 

“There is 15 to 20% of [grid] capacity that is there today that can be unleashed if we can find some [way] for resources like data centers to back up the grid for 1% of the time,” Mansoor said. “Fifteen to 20% of the grid is supporting electric demand for 87 hours in a year; so, we see flexibility as a huge need.” 

Fixing NEPA and ‘Overreaching’ EPA rules

Building on the impetus of Trump’s executive orders, both fossil fuel and renewable energy leaders continue to call on Congress for “durable” permitting reform, though their legislative priorities vary. 

Dena Wiggins, CEO of the Natural Gas Supply Association, said, “fixing NEPA has got to be Job 1.” What that means in her view is that environmental reviews under the National Environmental Policy Act should be “procedural … not outcome-determinative.” The law should be interpreted as not requiring “an agency to take a particular action as a result of [its] analysis,” she said. 

Fred Hutchison, CEO of LNG Allies, wants to rein in NEPA-related litigation. “We have to stop the ability of any litigant who wants to attack a licensed project,” Hutchinson said. “Whether it’s a pipeline, whether it’s an LNG facility, when you’ve gotten your licenses and a contract, all of the appeals are settled.” 

Such reforms must be “legally durable,” so courts cannot put a hold on a licensed project that is under construction, he said. 

For Maria Korsnick, CEO of the Nuclear Energy Institute, the priority is preparing the Nuclear Regulatory Commission for the next generation of reactors and cutting permitting times from five or more years to 18 to 20 months. 

“What [the NRC is] really comfortable with are these large reactors; they understand the regulation around them,” Korsnick said. “But the new [reactors] that are coming … they’re going to come in all shapes and sizes and run in different ways.  

“So, we want them to get better at saying, ‘I understand this design; let me target the regulation just to this design.’ … Especially if it’s a small modular reactor, even a smaller micro reactor, we want them to sort of take a fresh look.”   

After permitting reform, the fossil fuel industry will continue to push for regulatory repeals and rollbacks that Trump has called for in his executive order on Unleashing American Energy. 

Bloodworth specifically called for action on “overreaching EPA regulations,” including the rules on power plant emissions, mercury emissions and the “Good Neighbor rule” requiring states to submit plans for limiting interstate emissions.  

Repeatedly raising concerns about reliability disruptions and price increases, Bloodworth said, “The EPA should immediately stop implementing those rules. … They need to look at different interpretations of those rules” and replace them with “sensible environmental policies.” 

Rolling back regulations, however carefully targeted, can’t ensure community buy-in or prevent opposition at the local level, which often presents some of the toughest obstacles to getting projects approved and built. Hopper pointed to county-level moratoria and bans on new solar projects as an example of the need to ensure NEPA reform includes “stakeholder engagement and building an understanding of the assets and the benefits that are coming to communities.” 

As the number of new projects waiting for permits and interconnection continues to grow, “we can’t just, like, shove more stuff through the system,” she said. 

IRA Tax Credits

While the IRA’s clean energy tax credits were not specifically targeted in Trump’s executive order on energy, they are definitely in congressional crosshairs as Republican lawmakers start looking for funding cuts to offset extending the 2017 Tax Cuts and Jobs Act.  

The House of Representatives Ways and Means Committee recently circulated a 50-page list of potential funding cuts and savings, with a repeal of “green energy tax credits” the first of dozens of proposed changes to tax regulations. Such IRA rollbacks could provide an estimated $796 billion in savings over 10 years, according to the list.  

The list also proposes cuts to the 45Q, 45U and 45Z tax credits for, respectively, carbon capture, nuclear and tech-neutral clean technology. Without providing detail, the list says the cuts would “reduce government intervention in the energy industry that props up the green energy sector and distorts market competition” and save $404.7 billion over 10 years.  

But congressional Republicans may face challenges here as the leaders of industry trade groups at the USEA forum said they will work to protect tax credits that benefit their members.  

In addition to Bloodworth’s support for 45Q, Pat Vincent-Collawn, interim CEO of the Edison Electric Institute, said “energy tax credits are driving innovation, creating good American jobs and economic opportunity, and helping electric companies [meet] the rapidly growing demand for electricity while keeping customer bills as low as possible. It is important that lawmakers protect these tax credits.” 

Maintaining tax credits that support clean tech supply chains was another point of agreement. Hopper pointed to the massive buildout of solar manufacturing in the U.S. since passage of the IRA. “We have gone from very little solar manufacturing capacity in the United States to, by the end of this year, being able to produce enough solar modules to provide for our entire domestic need.” 

CEBA’s Powell made a direct connection between maintaining the tax credits and another of Trump’s top priorities, keeping electric bills low. “The marginal cost of new generation sets the price for everything,” he said. “If you effectively increase the price of that new generation by removing the incentives currently available to it, we’re going to see all electricity prices rise.” 

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Voltus Files Complaint to Hit Brakes on MISO’s Stepped-up DR Testing

Voltus has filed a complaint with FERC against MISO, alleging that the RTO’s “11th-hour” changes in testing and contract proof requirements ahead of the spring capacity auctions will harm demand response resources and affect rates (EL25-52).

In its Jan. 24 complaint, Voltus said MISO is essentially imposing “new terms and conditions” on DR by cracking down on power tests and requiring more detail in contracts. It said the RTO had “moved the goalposts” after testing deadlines passed and with just 45 days to go before the March 1 auction registration deadline.

Voltus asked FERC to deem MISO’s stricter testing and contractual requirements unenforceable because they stand to affect rates and had not been filed with FERC for approval. It said that without action, all the 450 MW of load-modifying resources (LMRs) it intends to offer in the 2025/26 capacity auction is at risk of disqualification. The company requested that FERC fast-track its complaint and respond no later than Feb. 14.

Voltus argued that MISO performed an about-face in late December when it announced to market participants via email that “real power tests” would be limited in duration to LMRs’ individual stated response times. That means an LMR with a six-hour response time would have a maximum of six hours to demonstrate it could scale back usage. Before then, Voltus said it was MISO’s practice to allow DR resources a full day to drop load by at least 50% for real power testing.

But that wasn’t the only deviation from MISO’s recent testing practices, Voltus told FERC. The RTO announced at the Resource Adequacy Subcommittee’s (RASC) meeting Jan. 15 that it would require all LMRs using a firm service level threshold to measure reductions to show in testing that they can cut use to that level and that the reduction be at least 50% of the LMR’s registered value. (See Following DR Exploitation, MISO Announces Stiffer Requirements Before Capacity Auction.)

Finally, MISO announced that market participants must be able to show that their LMR contracts are active for all seasons their resources offer their services. Contracts themselves must detail response time, how the LMR achieves demand reduction, and specify how many megawatts or to what firm service level end-use customers agree to curtail, the RTO said.

MISO staff said they were forced to double down on existing testing requirements after a handful of companies were caught manipulating the DR market in recent FERC investigations. Staff at the time said MISO’s testing requirements are already on the books and that it was merely renewing its enforcement.

Voltus itself recently agreed to pay a $18 million civil penalty after FERC investigated the company for reportedly falsifying registrations and overstating capacity from 2016 to 2020. (See Voltus Agrees to $18M Fine to Settle DR Tariff Violations in MISO.)

MISO’s tariff instructs market participants who wish to register LMRs to conduct real power tests if they have not previously responded to an emergency. The tariff also requires market participants to have “contractual rights” with their resources.

However, Voltus argued that MISO has not defined a “real power test” in its tariff or Business Practices Manuals. The company said it has seen efforts to define DR testing in stakeholder committees repeatedly “fizzle out.”

Because MISO and stakeholders have never settled on a definition, the company argued, FERC should act to make sure market participants registering LMRs who relied on the RTO’s typical guidance in recent years for the 2025/26 auction are treated fairly.

MISO’s late December email came after registration for the 2025/26 planning year had already begun and days before LMRs’ testing deadline, Voltus said. And it wasn’t until the Jan. 15 RASC meeting — after the LMR testing deadline passed — that MISO announced that it would require aggregators of retail customers demonstrate “contractual control” of their demand resources and resubmit registrations that lack details, it said.

“MISO’s beyond-the-11th-hour changes to these requirements will have catastrophic impacts on market participants,” Voltus said, adding that it’s now impossible for market participants to retest LMRs while still meeting the RTO’s original end-of-the-year deadline for testing.

Voltus argued MISO’s seemingly new contract specifications are discriminatory because aggregators are now held to a different standard than utilities. While aggregators must submit the more detailed contracts, utilities only must show that customers are enrolled in their DR programs. Voltus argued that MISO did not attempt to explain the disparate treatment.

The company also said it’s “unlikely” that contracts between aggregators and their customers “will include all the exact information MISO is now (for the first time) mandating be included.”

“As a result of these changes, all of the demand resources Voltus intended to register as LMRs to participate in the [Planning Resource Auction] for the 2025/2026 planning year may be disqualified entirely,” Voltus said, explaining that “none” of its customer contracts contains all the data MISO is seeking. It said that as of Jan. 24, it’s still waiting for MISO to confirm whether it will accept additional documentation detailing curtailment plans that it has submitted.

“While Voltus has curtailment plans for each of its customers, those curtailment plans are not codified in the contract. Similarly, while some of Voltus’ customer contracts specify the [firm service level] to which the customer commits to drop, in many cases that information may be contained elsewhere (e.g., in an email confirmation or other document extraneous to the contract),” Voltus said.

Voltus said that of its 450 MW of LMRs, 112.7 MW are from those that on paper no longer pass MISO’s real power testing requirements, either because of new time span limits or the firm service level stipulation. The company said it communicated testing requirements to customers using RTO rules in the last four planning years.

“MISO’s 11th-hour change in methodology therefore forced Voltus to choose between two terrible options: (1) not register these demand resources, losing revenues and failing to satisfy its commitments to these customers; or (2) register such demand resources as ‘untested,’” the company wrote.

Voltus told FERC it was forced to submit the 112.7 MW as “untested,” which it said will increase its potential penalty exposure by $3.16 million per market dispatch and up its collateral requirement by $270,480.

The company predicted that “hundreds of megawatts of demand resources” will be unable to register to participate in MISO’s seasonal capacity auctions by the March 1 registration deadline. It warned of “cascading impacts” where aggregators and other market participants will be forced to find replacement capacity or default on bilateral contracts.

Voltus said that while it does not oppose MISO’s attempts to strengthen its requirements, the grid operator should not be allowed to “unilaterally impose new requirements on market participants with no basis in the tariff.”

MISO told RTO Insider via email that it is “reviewing the complaint to determine our response” but declined to comment further.

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Western Regulators Clarifying Their Role in Markets+

Arizona Corporation Commissioner Nick Myers, chair of the Markets+ State Committee, said Jan. 24 that he is drafting a response to FERC’s requested compliance filing to clarify some of the key points raised in the commission’s approval of the day-ahead market’s tariff (ER24-1658). 

Myers, vice chair of the ACC, told the MSC that his letter will explain the regulatory group’s structure and how it will be funded by SPP. The MSC comprises regulators from most Western states who provide their perspective on Markets+’s development and operations. 

“I think this reply would be more of an informal response, as it is a point of clarification other than actual comments, but open to feedback from you all,” Myers told the MSC. “I do think having as many as MSC members as possible behind that would be beneficial and helpful and also just keeps everyone on the same page with where these discussions are at moving forward.” 

FERC conditionally approved the market’s tariff Jan. 16. The commission found the tariff was still “insufficiently clear” on some points and directed a compliance filing that is due Feb. 15. (See SPP Markets+ Tariff Wins FERC Approval.) 

Commissioner Mark Christie (now chair) and Commissioner David Rosner filed a joint concurrence to FERC’s order, expressing their concern with governance and ensuring “robust” state involvement in the market’s development. They urged SPP to ensure that the MSC, and its Regional State Committee in the Eastern Interconnection, have the ability to provide adequate independent staff support and the means to maintain dedicated staff, similar to the structures of the Organization of PJM States Inc. and Organization of MISO States. 

The Western Interstate Energy Board currently serves as the MSC’s staff support. WIEB’s Gia Anguiano, who supports the MSC, said SPP staff will visit Christie and Rosner in D.C. this week to discuss their concurrence in a “little bit more detail.” She said there have also been discussions to have the two commissioners participate in an MSC meeting. 

“[We] really want to get to the root of their concerns around [their concurrence] and see what we can do to further address it,” Anguiano said. 

FERC Commissioner Judy Chang issued a separate concurrence that noted the tariff leaves some uncertainties about key market design details, such as transmission capability rules, greenhouse gas pricing and potential seams issues, between Markets+ and CAISO’s competing Extended Day-ahead Market. 

“I think the biggest point in Commissioner Chang’s concurrence is just really to make sure that the market is operating at its greatest potential and for the consumer’s benefit,” Anguiano said. 

SPP has said the compliance filing will require adding six sentences to and deleting one from the 650-page tariff. (See SPP Markets+ Tariff a ‘Home run’, Staff Says.)