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December 17, 2025

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Calif. Lawmakers Seek More Accountability from CPUC

A California State Senate committee has advanced a bill aimed at increasing transparency and accountability of the state’s Public Utilities Commission (CPUC), as consumers grow increasingly irate over utility rate hikes.

Assembly Bill 13, introduced by Assemblymember Rhodesia Ransom (D), passed the Senate Energy, Utilities and Communications Committee on July 15 on a 16-0 vote, with one abstention. The bill now heads to the Senate Appropriations Committee.

And with a July 18 deadline looming for legislative policy committees to move bills, the committee considered a number of additional bills. Those included Assembly Bill 1408, which aims to make better use of surplus interconnection service, the unused portion of interconnection capacity at a power generator’s point of interconnection.

Geographic Diversity

AB 13 asks the governor and Senate to consider geographic diversity when selecting members of the California Public Utilities Commission. Currently, all five commissioners are from Northern California, in Pacific Gas and Electric territory, Ransom said.

The bill would require the CPUC to submit a report to the legislature within 15 days of issuing a decision in a ratemaking case, summarizing evidence used to support any rate increases and detailing the commission’s rationale for its decision.

“We are often blindsided and confused about some of these rate-setting cases,” Ransom told the committee. “And we want to have an ample opportunity to respond.”

Under AB 13, the CPUC president would be required to discuss rate affordability and recent rate-making cases during annual appearances before legislative committees, which already are mandated.

And the CPUC would be required to include in its annual report to the legislature the number of cases in which it failed to issue a decision within the statutory deadline. The provision could apply pressure to resolve rate cases faster instead of allowing them to drag on for years, according to San Diego Gas & Electric, which supports the bill.

“There’s no question in my mind that the PUC needs a little change in direction,” said Sen. Jerry McNerney (D), who serves on the committee.

McNerney said he’d like to see more Central Valley representation on the CPUC as well as other state commissions. He’d also like the CPUC president to appear before lawmakers more than once a year.

District Representation?

An earlier version of AB 13 would have required four of the five commissioners to represent different zones within the state, based on the four State Board of Equalization districts. The fifth commissioner would be an at-large consumer advocate.

But instead of a requirement for geographic representation, a committee amendment asks the governor and Senate to consider geographic diversity when selecting commissioners.

In 2022, lawmakers passed a similar bill, AB 1960, which said the governor and Senate “should consider” regional diversity in choosing commissioners.

But Gov. Gavin Newsom vetoed it, calling it “unnecessary.”

“There are other factors that must also be considered in making CPUC commissioner appointments, such as professional experience, knowledge and subject matter expertise, as well as diversity,” Newsom said in his veto message.

“Further, I am already deeply committed to boards and commissions that represent California’s diversity, including regional representation.”

Surplus Interconnection Service

AB 1408 by Assemblymember Jacqui Irwin (D) pertains to surplus interconnection service.

The unused interconnection capacity creates an opportunity to add renewable energy resources or battery storage at or near fossil plants, proponents said. It also may encourage the use of federal clean energy tax credits that will expire soon.

Irwin cited as an example the Ormond Beach generating station in Oxnard, which has a “huge” transmission infrastructure but is used only as a backup power source.

“That’s an example of an incredible opportunity to place renewable energy close by,” she said.

AB 1408 would require CAISO to consider surplus interconnection service in its long-term transmission planning. It also would require utilities to evaluate and consider surplus interconnection options in their integrated resource plans.

The committee’s final vote on the bill was 16-0, with one abstention.

The legislature begins its summer recess July 19, returning on Aug. 18. The last day for each house to pass bills is Sept. 12.

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Georgia Power to Add at Least 6 GW of Generation

Georgia Power will add at least 6 GW of new generation capacity by 2031 under the integrated resource plan approved July 15.

The IRP reflects heavy anticipated increases in demand. The utility had projected up to 8.2 GW of load growth when it submitted the plan to the Georgia Public Service Commission in January. (See Georgia Power Proposes Nuclear Uprate, Delay in Fossil Retirement.)

The final IRP approved by the PSC (56002) directs the 6-GW increase to meet that need and allows a maximum 8.5 GW, if the additional need can be proven.

The IRP also includes:

    • a $161 million budget for demand-side energy efficiency programs to help ease the strain on the grid;
    • a 10-year transmission plan to include upgrades across more than 1,000 miles of lines;
    • nuclear plant uprates;
    • modernization of the hydropower fleet;
    • upgrades and operating extensions for existing coal and natural gas power plants; and
    • a formal process to evaluate new grid-enhancing technologies, both to increase grid capacity and to better integrate solar and storage resources.

The PSC vote to approve the IRP was unanimous. Opinions about the details of the IRP were not.

Environmental advocates and clean energy supporters are unhappy about Georgia Power increasing its reliance on natural gas and coal through upgrades and retirement delays for existing plants.

The Southern Alliance for Clean Energy called the IRP “dangerously short-sighted,” locking Georgia into a future use of coal and gas that will further burden ratepayers to the benefit of Big Tech — whose data center predictions are speculative and have “significant potential for overestimation of both energy and peak load.”

“The strides made in solar, storage, and customer programs for clean energy are sadly blunted by the continued investment in fossil fuel infrastructure in the approved IRP,” the alliance said. “On top of that, the fact that Georgia Power is authorized to seek certification for up to 8,500 MW of resource capacity after the IRP means there’s potential for even more spending on brand-new gas plants on the horizon.”

The Clean Energy Buyers Association was more complimentary toward the IRP, thanks to the inclusion of a new subscription option allowing commercial and industrial customers to work with developers to bring clean-energy projects into Georgia Power’s system. The association and the utility collaborated for more than a year on the measure.

“This is a meaningful step forward in helping customers match their growing energy needs with clean, customer-funded energy resources,” the association said.

Renewables are part of the IRP, just not as large a part as some would like.

Georgia Power plans to procure up to 4 GW of renewable resources by 2035, the first 1.1 GW through its competitive Utility Scale and Distributed Generation procurements, and it plans to raise its battery energy storage target above the current 1.5 GW.

The 4 GW of new capacity would bring the utility’s renewable portfolio to about 11 GW.

In a July 15 news release, Georgia Power said its projection of load growth by 2030 now is 8.5 GW, compared with a January projection of 8.2 GW and a 2023 projection of 5.9 GW.

In its own news release, the PSC noted the internal disagreements over load growth that led to the 6-GW/8.5-GW stipulation: “Georgia Power and the PSC’s Public Interest Advocacy Staff disagreed over the amount of new energy large-load customers were expected to consume over the next several years — although both sides did agree it would be significant.”

PSC Chair Jason Shaw said: “As data center construction continues in Georgia, this IRP puts us in a safe and secure spot to meet that energy need. This long-term plan continues to strike a balance between reliability and affordability.”

Commissioner Tim Echols said: “With unprecedented grid growth ahead for Georgia, this integrated resource plan puts us on the right path to meet everyone’s needs. I wish it had more solar, more storage, more energy efficiency — but it strikes a good compromise in the spirit of collaboration.”

In the IRP, Georgia Power said components of its generation mix for retail needs in 2024 included natural gas (40%), nuclear (29%), coal (16%), solar (6%), hydro (2%) and wind (1%).

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FERC Proposes to Eliminate Western ‘Soft’ Price Cap

FERC is moving to rescind the West-wide wholesale electricity price cap mechanism it instituted in 2002 in response to widespread price manipulation during the Western energy crisis of 2000/01, which resulted in rolling blackouts in California and famously led to prison sentences for leaders at energy trading company Enron. 

The commission on July 14 opened a Section 206 proceeding to examine discontinuing its policy of maintaining a “soft” price cap for short-term electricity sales in the West to prevent the exercise of market power in areas outside CAISO (EL10-56).  

Under the policy, any electricity sales exceeding the cap — currently set at $1,000/MWh — are subject to cost justification and refund upon review by FERC.  

(While the policy is referred to as the “WECC soft price cap,” WECC is not involved with it or any regional market operations.) 

“We preliminarily conclude that the requirement is no longer necessary to ensure just and reasonable rates and propose to eliminate it,” the commission wrote in the order establishing the proceeding. 

The proceeding comes a year after the D.C. Circuit Court of Appeals ruled the commission must apply the Mobile-Sierra doctrine when reconsidering a series of 2022 orders requiring electricity sellers to refund a portion of the high prices they earned during an August 2020 heat wave. (See FERC Must Apply Mobile-Sierra to Western Soft Cap Refunds, Court Finds.) 

That case dealt with the surging prices associated with tight electricity supplies stemming from soaring temperatures over Aug. 18-19, 2020, as CAISO scrambled to prevent a repeat of the rolling blackouts it was forced to order Aug. 14-15 — the first such blackouts in California in 20 years. 

During the heat wave, wholesale prices at Arizona’s Palo Verde hub on the Intercontinental Exchange (ICE) hit records of $1,515/MWh on Aug. 18 and $1,750 on Aug. 19, compared with average prices that summer of $52/MWh, according to filings Southern California Edison and Pacific Gas and Electric submitted with FERC to contest the prices. 

In 2022, FERC issued a series of decisions rejecting the justifications of sellers who sold electricity at those price levels during the event, having found that the ICE index prices reflected scarcity conditions and that the selling companies had failed to justify their premiums based on costs, as required under the soft cap framework. 

The commission also rejected the sellers’ contention that it must apply the Mobile-Sierra standard to the transactions because the contracts had been freely negotiated between the buyers and sellers and had not harmed the public interest. 

The commission held that it had the authority to enforce the soft cap through refunds without conducting a Mobile-Sierra public-interest analysis because the soft cap was part of the sellers’ filed rate — a finding the D.C. Circuit rejected when it said FERC was required to conduct such an analysis before ordering refunds. 

“Even assuming that the soft-cap order was incorporated into sellers’ tariffs and contracts, the commission did not displace the Mobile-Sierra presumption in the soft-cap order itself, and so that presumption continues to apply to the sellers’ contracts,” the court found.  

‘Substantially Different’ Market Landscape

In the July 14 order instituting the soft cap proceeding, the commission recounted the D.C. Circuit’s findings and noted that, while FERC has over time revised the soft offer cap to reflect increases in CAISO’s caps, it has never reassessed whether the framework is necessary to ensure just and reasonable rates in the West. 

The commission wrote that the region’s wholesale market landscape in 2025 is “substantially different than in 2002,” when it created the soft cap.  

“At that time, the commission sought to address the widespread effects of the Western energy crisis and establish robust, stable and competitive bulk power markets across CAISO and WECC outside of CAISO’s footprint,” it wrote. “As part of that effort, the commission recognized the interdependency of the CAISO and WECC markets and adopted the soft price cap outside of CAISO while the commission, CAISO, market participants and stakeholders pursued holistic reforms to CAISO’s organized wholesale markets.” 

Regional market changes since then “call into question the need for” the soft cap, FERC said. 

“In addition to the continued development and refinement of the CAISO market, the West now features widespread adoption of centralized real-time energy imbalance markets,” the commission wrote, referring to CAISO’s Western Energy Imbalance Market (WEIM) and SPP’s Western Energy Imbalance Service (WEIS). 

The commission also noted it has approved tariffs for two day-ahead markets expected to go live in the next two years — CAISO’s Extended Day-Ahead Market (EDAM) and SPP’s Markets+ — as well as authorizing expansion of the SPP RTO footprint into the Western Interconnection. 

“Notably, these real-time and day-ahead markets encompass transactions over the majority of the same spot markets to which the WECC soft price cap applies. These markets also include robust market monitoring and mitigation that addresses the potential exercise of market power in those constructs,” FERC said, adding that market monitoring and mitigation in the more centralized markets “also has a disciplining effect on associated bilateral markets.” 

“Given these developments, we preliminarily conclude that the WECC soft price cap is no longer needed to discipline WECC spot market sales activity,” the commission said. 

The commission also pointed out that the Energy Policy Act of 2005 has given it “more robust legal authority and monitoring capabilities to address wholesale market misconduct” and greater authority to pursue allegations of price manipulation in its jurisdictional markets than it had when it established the soft cap in 2002. 

Furthermore, the commission said it “preliminarily” concluded that the “filing burden” associated with the soft price cap “is no longer warranted, given the limited monitoring benefits that it provides.” It said the requirement “imposes costs on market participants and the commission and creates uncertainty for individual transactions while those filings are pending review at the commission.”   

“Given the developments noted above, and the D.C. Circuit’s clarification of how the currently effective soft cap operates, we question the benefit of requiring individual sellers to submit an informational filing for spot market transactions above the $1,000/MWh threshold simply to facilitate the commission’s review of those sales through the Mobile-Sierra framework,” FERC wrote. 

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Calif. Pathways Bill Delayed After Orgs Withdraw Support, While Newsom Signals Backing for Effort

The author behind the bill that would allow CAISO to relinquish market governance to an independent “regional organization” (RO) delayed a hearing scheduled for July 16 after several organizations withdrew support for the proposed legislation.

SB 540, which passed in the California State Senate in June, was set for a first hearing in the State Assembly’s Utilities and Energy Committee but was delayed until after the Legislature’s summer break at the request of the bill’s author, Sen. Josh Becker (D). (See ‘Pathways’ Bill Passes California Senate on 36-0 Vote.)

Meantime, Gov. Gavin Newsom and Assembly Speaker Robert Rivas on July 16 both signaled their support for efforts to expand California’s involvement in regional electricity markets, although spokespersons for each pointed out they were not necessarily backing SB 540.

SB 540 is part of the West-Wide Governance Pathways Initiative, an effort to create an independent RO to govern CAISO’s Western Energy Imbalance Market and the soon-to-be-launched Extended Day-Ahead Market (EDAM). The effort aims to assuage concerns that the ISO — whose Board of Governors are appointed by California’s governor — would act solely in the state’s interest.

“The hearing was delayed with the support of the Senate and Assembly in order to have more time to iron out some details with the bill,” Becker’s press secretary, Charles Lawlor, told RTO Insider. “There is a huge, diverse coalition behind this bill. Conversations are active and ongoing. Our collective work is going to continue over the summer, and our goal is to move the legislation when we’re back in August or September.”

The move comes after 21 organizations, including the Environmental Defense Fund, PacifiCorp, Advanced Energy United, Amazon and Portland General Electric, changed their position to “oppose unless amended” on SB 540.

In a July 11 letter, the coalition said it opposed an amendment creating a new Regional Energy Market Oversight Council responsible for ensuring CAISO’s participation in the regional energy market “serves the interests of the state.” (See Amended ‘Pathways’ Bill Boosts — and Complicates — Calif. Protections.) The new council would be authorized to mandate withdrawal if those interests are compromised.

The coalition requested lawmakers remove the amendment, stating “the language in this section mandates the withdrawal of California entities from the market without exception or discretion, which is unacceptable.”

“Market rules should be established based on facts, evidence and reliable data rather than fear,” it wrote. “Even if withdrawal from the market were to be a prudent action, the mandated 120-day time frame is far too short and exposes California customers to serious reliability concerns, especially during periods of peak demand. Lastly, this language inadvertently asserts new [California Public Utilities Commission] jurisdiction over the state’s publicly owned utilities, which is inappropriate and must be removed.”

The coalition also argued lawmakers should remove revisions to California’s Renewables Portfolio Standard Program and restrictions on a future market. It noted that some entities in Colorado, New Mexico and Idaho are at a crossroads on whether to join EDAM or SPP’s Markets+.

“A smaller market for California means less cost savings, a less reliable grid and more climate-harming emissions,” the coalition wrote.

Leah Rubin Shen, managing director at Advanced Energy United, commended the legislature for delaying the hearing to “ensure a productive path forward that preserves the widely supported core purpose of the bill: to facilitate California’s participation in an expanded Western electricity market that provides robust state policy and consumer protections.”

“The stakes are too high for California to walk away, especially as trading partners across the West weigh their options,” Rubin Shen said. “Our shared vision remains clear: A strong regional electricity market that includes California will benefit the entire West by lowering costs, increasing reliability and delivering clean energy across the region. With continued commitment to passing a workable bill this year, we can achieve this goal.”

Meanwhile, The Utility Reform Network (TURN) has changed its opposition to neutral after the bill was amended to address the organization’s concerns that handing over governance to an RO could lead to increased federal intervention and undermine the state’s clean energy goals. (See California Lawmakers Seek to Trump-proof Pathways Initiative Bill.)

“We need a very enhanced level of protection and guarantees that this entire experiment is voluntary and that the state of California has … full control over whether we would continue to participate over time,” Matthew Freedman, staff attorney at TURN, said in an interview.

“We’re mindful of the [Trump] administration’s threat to force utilities throughout the West to subsidize legacy coal-fired generation that might be at risk of retirement, either under Section 202 of the Federal Power Act, or sent through some other mechanism that they invent,” Freedman added. “We want to make sure that this regional market is not weaponized against California.”

But Katelyn Roedner Sutter, California state director at the Environmental Defense Fund, said in an interview that fears the federal government will get involved are overblown, and that the bill makes clear California’s existing climate or clean electricity policy will not change.

“None of this … is going to impact our renewable portfolio standard. And the same is true for other states. Other states get to uphold their existing policy as well,” Roedner Sutter said.

“Where the real concern seems to come from is our relationship with FERC,” Roedner Sutter noted. “And I think what people who raise that are not understanding is that CAISO [tariff revisions] … already have to go before FERC. That is the case right now; … that relationship does not change in any way with this bill or with California entities being part of a regional electricity market. So, nothing is actually changing about our relationship with FERC.”

In separate statements released July 16, Gov. Newsom and Speaker Rivas both pointed to California’s “opportunity” to improve electric reliability and affordability through increased regional coordination.

“We have the opportunity to expand regional power markets that help drive down energy costs and increase grid reliability — or we can turn our backs on this proven model and opt for higher costs and power outages,” Newsom said. “The answer is clear: California must further enable continued cooperation with Western partners to secure our clean, reliable and affordable energy future. This is our best shot at lowering energy costs. Now the legislature must take action this year and deliver for the people of California.”

“There is an urgent opportunity now — this year — to lower energy costs for California families and businesses, and we can help achieve this by expanding regional collaboration,” Rivas said. “California must continue to lead and step up, or others will. We need to continue to facilitate cooperation with our Western neighbors through a voluntary, regional power market, because that is our best path toward driving-down costs and delivering a sustainable, reliable, affordable energy future for Californians. Let’s get this done now.”

Robert Mullin contributed to this article.

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NYISO: LBMPs Spiked in June from Heat Wave

ALBANY, N.Y. — The heat wave at the end of June caused the average locational-based marginal price for the month to increase dramatically, NYISO told the Business Issues Committee on July 16.

The LBMP jumped from $36.99/MWh in May to $58.96/MWh, nearly 49% higher than that of June 2024’s $39.68.

“June 2025’s average year-to-date monthly cost of $77.60/MWh is a 90% increase from $40.78/MWh in June of 2024,” said Zachary T. Smith, newly promoted to NYISO director of market solutions. Smith’s promotion was announced as he began the presentation.

Natural gas prices were slightly lower in June, at $2.27/MMBtu compared to $2.34 in May, but they were up about 30% year-over-year.

Smith said the higher LBMPs were driven by the extreme heat at the end of June. (See NYISO Issues Energy Warning as Heat Wave Boils New York.) The heat caused shortage pricing because of a lack of energy reserves. NYISO had to make emergency purchases from neighboring regions. (See NYISO Details Late June Heat Wave for Reliability Council.)

Given the current and recent weather, NYISO likely would see high prices in July, too, Smith said.

“We’re not done with heat waves,” he said. “We might see [load] of over 30,000 MW today.” During the June heat wave, demand reached over 31,000 MW.

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Virginia SCC Orders Changes to Dominion Energy’s IRP Process

The Virginia State Corporation Commission determined in an order issued July 15 that Dominion Energy’s 2024 Integrated Resource Plan was legally sufficient, but it ordered changes to the utility’s future IRPs.

“The commission emphasizes, though, that such acceptance does not express approval in this final order of the magnitude or specifics of Dominion’s future spending plans, the costs of which will significantly impact millions of residential and business customers in the monthly bills they must pay for power,” the SCC said.

State law requires at least 15 years of planning in an IRP, but it gives the regulator flexibility to require more time. Dominion must file plans that look 20 years out, in line with PJM’s 20-year forecast window. That also will help the IRP be better coordinated with the utility’s planning to meet Virginia’s renewable portfolio standard.

The utility also will have to submit at least one scenario where its generation plans are in line with the default carbon targets in the Virginia Clean Economy Act.

In the next IRP, Dominion will have to model increasing its annual build limits for storage and investigate long-duration storage as those technologies become commercially viable. Dominion also must model higher levels of efficiency for 2026 through 2028, which will influence its use of demand-side management.

Its next filing also must include a narrative discussion of its potential use of grid-enhancing technologies and advanced conductors, especially using them to ensure reliability and safeguarding the physical and cybersecurity of the distribution system.

Dominion will be required to keep using PJM’s demand forecast, minus efficiency targets and separating out the load associated with data centers, the order said.

A statement from the utility welcomed the SCC’s thorough review and said it would follow the new requirements for its future IRPs.

“Our customers are using 5% more power each year, and demand is expected to double in 10 years. This is the largest growth in power demand since the years following World War II,” a Dominion spokesperson said in the statement. “We’re focused on serving our customers’ growing needs with reliable, affordable and increasingly clean energy. We’re investing in new power generation from every source, grid upgrades to strengthen reliability and energy efficiency programs to help our customers save.”

Most of the new power generation being developed is from carbon-free resources, including the Coastal Virginia Offshore Wind project. It’s the largest offshore wind project being built in the country, and Dominion has the third largest solar fleet. The growing demand also will require natural gas, because renewables are not always available, the company said.

Clean Virginia, which was an intervenor in the IRP case, welcomed the changes from the SCC but called for further reforms so that monopoly utilities no longer control the planning process.

“This latest order underscores how broken Virginia’s energy planning process is,” said Clean Virginia Deputy Director Dyanna Jaye. “Year after year, Dominion files plans that ignore clean energy requirements, lock in expensive fossil fuel infrastructure and drive up electric bills. By recognizing the harm this process can cause to Virginia families and businesses, the commission has taken a step in the right direction by calling for significant reforms moving forward.”

Dominion said it was focused on keeping rates affordable and delivering value for its customers.

“Our residential rates remain below the national average, and they’re projected to grow by less than 3% a year,” its spokesperson said. “At the same time, we’re delivering more reliable service by burying power lines in the most outage-prone areas. That’s substantially reducing storm-related outages and shortening restoration times for our customers.”

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CGA Says New MISO Info Guide on Queue Fast Lane Shows Plan is Unfair

The Clean Grid Alliance claims that new information MISO has released on its interconnection queue fast lane definitively shows the plan would be detrimental to independent power producers and should be rejected by FERC.  

The clean energy advocacy group wrote to FERC July 15 that a newly released informational guide from MISO that describes how the express lane would be rolled out if approved proves the plan is unfair (ER25-2454). Clean Grid Alliance said the guide, published July 11, contains a detail that would leave load-serving entities and their affiliates free to scoop up nearly 74% of the project threshold that could be allotted under the express lane.  

MISO in early June refiled its fast-track proposal, this time with a 68-project limit that includes special reservations for retail choice states and independent power producers to advance their generation projects. MISO designated 10 of the 68 project slots for IPPs only. It said the dedicated spaces would discourage LSEs from using a tactic of refusing to enter into agreements with IPPs for the remaining 50 project slots. (See MISO’s Queue Fast Lane, Take 2, Nets Déjà vu Arguments.)  

But CGA said the guide’s “generalized other agreement category” shows that LSEs would get preferential treatment and could shut IPPs’ projects out of the 50-project fast lane if the two don’t have a legally binding agreement according to MISO. MISO said it won’t consider letters of intent, memorandums of understanding or term sheets as adequate for offtake agreements.  

“There might have been some glimmer of hope that the generalized other agreement category would not afford LSEs unfettered veto power. However, that too has now been shut down,” CGA said. “MISO’s recent post puts the nail in the coffin to IPP participation in the 50-project category. LSEs will unequivocally be able to raise a unilateral barrier to IPP participation and say no.”  

CGA said MISO’s definition of legally binding agreements leaves only power purchase or similar offtake agreements and “build-own-transfer” agreements as valid avenues to the lion’s share of the fast lane. The alliance said LSEs “would wield unchecked market power to simply say ‘no’ to an agreement with an IPP, leaving LSEs with exclusive use of the 50 projects as they desire, including self-supply or contracting with an affiliate.”  

CGA told FERC the wording in MISO’s guide attempts to add a late-stage revision to which interconnection requests can enter the fast lane. It also said the seemingly new requirement “follows MISO’s pattern in this docket to continually revise its filed proposal.” The alliance said that by burying the new condition in an information guide, MISO shut out public comment and FERC’s ability to review the proposal in its totality.  

“MISO did not apprise the commission of this legally binding substantive change to the other agreement category,” CGA wrote and again urged FERC to reject the plan.  

At press time, MISO hadn’t responded to RTO Insider’s request for comment on CGA’s claim.  

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NYISO Management Committee Liaison Brief: July 15, 2025

ALBANY, N.Y. — The NYISO Board of Directors has approved the right of first refusal for transmission owners’ tariff revisions for economic and reliability projects. The board also approved the PJM joint operating agreement for the Dover phased array regulator substation. (See NYISO Management Committee Briefs: June 30, 2025.) 

In a presentation to stakeholders, Board Chair Joseph Oates ran through a laundry list of items the board covered over two days of management meetings. He reported that the board is pleased with the discussion of the ongoing capacity structure review with market participants. The board also reviewed the preliminary setup of the System and Resource Outlook study, which eventually will involve meetings with stakeholders.  

Oates said the board also reviewed the status of the project prioritization process and had received the results of the 2025 quarterly internal audit. Physical and cybersecurity program updates were reviewed. He also mentioned a “strategic discussion” about short- and long-term demand forecasting. 

Oates did not provide details of these reviews or status updates. Stakeholders did not ask questions.  

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FERC Opens Door for PJM to Refile RTEP Protocol Proposal

FERC has opened the door for PJM to resubmit a previously rejected proposal to shift its Regional Transmission Expansion Plan (RTEP) protocol from its Operating Agreement to its tariff, while dismissing a rehearing request for a connected proposal by the RTO’s transmission owners (ER24-2336).  

PJM’s RTEP protocol proposal had been linked with another proposal by several transmission owners to revise the RTO’s Consolidated Transmission Owners Agreement (CTOA), including adding “overlap provisions” that would have required PJM to consult with TOs before proceeding with a regional project that would address the same need as a local, supplemental project proposed by a TO.  

The TO proposal also would have established a conflict mediation process for instances when a TO contended that an action by the PJM Members Committee conflicts with the CTOA.  

PJM and the transmission owners had asked the commission to consider both filings as one proposal, arguing that one could not be approved without the other. 

But in a December 2024 order rejecting the proposals, the commission found the CTOA changes would impinge on PJM’s independence by providing TOs with an exclusive opportunity to affect filings PJM is able to submit under Section 205 of the Federal Power Act. (See FERC Rejects PJM and Transmission Owners’ CTOA Proposals.) 

At the same time, FERC also rejected PJM’s proposal to shift the RTEP protocol to the tariff because of its tie with the CTOA revisions, while also finding that PJM had not made the case that keeping the planning protocols in the OA renders the RTO’s governing documents unjust and unreasonable. 

The July 14 rehearing order again rejected the CTOA revisions, saying they would grant TOs too much influence over PJM’s decision making on planning, extend Mobile-Sierra protections to the revised language and place “substantive transmission planning rules in the CTOA.” 

“The CTOA amendments go beyond changes to enable this transfer and also would restrict PJM’s ability to make independent FPA Section 205 filings that PJM TOs believe contravene the CTOA, add substantive transmission planning rules to the CTOA, and grant the Mobile-Sierra public interest standard presumption to several CTOA provisions,” the commission wrote. “Thus, the broad cumulative effect of the integrated package of filings would be to shift the ability to influence PJM’s FPA Section 205 filings from a diffuse right shared by the Members Committee representing diverse interests to a concentrated right possessed by a single class of stakeholders, the PJM TOs. Moreover, PJM TOs’ new rights would be housed in the CTOA and granted Mobile-Sierra protections, which would raise the bar for any future changes.” 

However, the commission withdrew its determination that PJM’s proposal had not met the FPA Section 206 burden of showing that the OA is unjust and unreasonable with the inclusion of the RTEP protocol, instead dismissing the proposal as moot given the rejection of the intertwined CTOA revisions. 

“We emphasize that our dismissal of the PJM complaint here does not preclude a future filing proposing to move the RTEP protocol from the OA to the tariff. The PJM board has the authority to petition the commission under FPA Section 206 to modify any provision or schedule of the OA that the PJM board believes to be unjust, unreasonable or unduly discriminatory,” the commission wrote. 

‘Resounding Victory’

Ari Peskoe, director of Harvard’s Electricity Law Initiative, said the rehearing order protects PJM’s independence and creates an uphill battle for TOs appealing the commission’s determination. 

“The rehearing order cements a resounding victory for the region’s consumers,” Peskoe told RTO Insider in an email. “The utilities’ proposed CTOA would have compromised PJM’s independence by letting the utilities interfere with PJM’s decision-making processes, particularly about transmission planning. That’s why state regulators, consumer advocates, generators and public power lined up against the CTOA. Because FERC reiterated three separate and independent reasons for finding the utilities’ CTOA deficient, the utilities will have a nearly impossible task in trying to convince the D.C. Circuit to reverse FERC’s order.” 

Peskoe also argued the CTOA revisions were not legally necessary for PJM to transfer the RTEP protocol to the tariff and the RTO can pursue the changes on their own merits. 

“With FERC’s modification, PJM is now free to try again — on its own — to move the regional transmission planning provisions from the operating agreement to the tariff. However, rather than filing a complaint, PJM should try to work with its members to see if there’s a deal on governance that might be acceptable to a majority of its members and to state regulators,” he said. 

PJM did not respond to a request for comment on whether it plans to refile the proposal or thinks that would require a fresh consultation with its membership. 

Alex Stern, Exelon director of RTO relations and strategy, said the utility expects PJM and member TOs to continue working to find solutions to ensure the grid keeps up with accelerating load growth. Defending PJM’s proposal to transfer the RTEP protocol during a May 2024 Members Committee meeting, he said TOs would be giving up stakeholder process veto rights over planning as part of the proposal in an effort to ensure PJM has the authority it needs to plan projects that can facilitate the clean energy transition while meeting reliability challenges. (See Members Vote Against Granting PJM Filing Rights over Planning.) 

“We are still reviewing the order, and there is still an appeal pending,” Stern said. “The CTOA is the foundation of the relationship between the transmission owners and PJM. Both are bound by this agreement and mutual responsibilities to work with one another. Nothing in FERC’s order changes that. We expect the TOs and PJM will continue to discuss ways to ensure PJM has the necessary tools to plan transmission to support load growth, including AI needs, and the evolving grid.” 

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$92B in Power, Data Center Infrastructure Planned in Pa.

New technology and energy facilities are planned for Pennsylvania at a cost of more than $90 billion, including multiple power plants and data centers, possibly co-located.

President Donald Trump, cabinet secretaries, the state’s junior U.S. senator and leaders of industry-leading firms in both sectors announced the projects July 15 at the Pennsylvania Energy & Innovation Summit in Pittsburgh.

The vision they laid out breaks down to $56 billion in new energy infrastructure and $36 billion in new data centers. Trump and most of the other speakers framed the announcement as progress toward — and evidence of — the energy dominance the nation must have as it pursues its new Golden Age.

“Get ready, lots of jobs, lots of success, really, a beautiful thing, it’s going to be beautiful to behold,” Trump said.

He called EPA Administrator Lee Zeldin “the most important man on the dais” for his role in easing the regulations and limitations that could slow progress toward that goal.

U.S. Sen. Dave McCormick (R), hosting the event at Carnegie Mellon University, said he believed people will look back at the day as a seminal moment in the history of the state and perhaps even the nation.

Trump, McCormick and many others continued the narrative that vast amounts of power are key to dominating the artificial intelligence sector, which in turn is key to the United States’ future leadership role in the world.

Neither Trump nor any of the speakers who followed him indicated where the new generation equipment would be sourced for all these projects. It is widely reported to be in short supply with a long waiting list for new machinery.

Projects announced or mentioned at the event include:

    • Blackstone plans to invest more than $25 billion in Pennsylvania’s digital and energy infrastructure; subsidiary QTS already has acquired multiple data center sites in the northeast area of the state and will seek partners for the buildout. An additional $60 billion of in-state investment is expected to result.
    • PPL has formed a joint venture with Blackstone to invest in new gas-fired power plants.
    • Transmission operator FirstEnergy plans to spend $15 billion on infrastructure, personnel and processes to upgrade the grid in Pennsylvania through 2029.
    • Google, which plans $25 billion in data center construction and AI infrastructure across the PJM footprint in the next two years, announced a framework agreement with Brookfield Asset Management to deliver up to 3 GW of hydropower across the United States — the first deal of its kind — starting with two Pennsylvania facilities rated at 670 MW.
    • Google also plans to expand a previous grant to train new electricians in Pennsylvania and says it will offer free AI training to every small business in the state.
    • AI hyperscaler CoreWeave says it will commit more than $6 billion to equip a new data center in Lancaster and will be the tenant of the site.
    • Constellation Energy, which is investing $1.6 billion to restart the former Three Mile Island Unit 1 near Harrisburg, plans to perform 340 MW of uprates on its Limerick Clean Energy Center, Trump said, though Constellation itself said that work depends on securing customer commitments for the increased output.
    • Westinghouse Electric, headquartered in suburban Pittsburgh, plans to collaborate with Google Cloud to use AI tools to enhance and streamline construction and operation of nuclear plants. Westinghouse in June announced it is working to start construction of 10 new reactors — a $75 billion proposition — nationwide by 2030.
    • As announced in April, data centers and the nation’s largest gas-fired power plant are planned for construction where Pennsylvania’s largest coal-fired plant once stood, in Homer City, at a cost of $15 billion.

As he cheered the Homer City project, Trump lamented that he could not follow through on his campaign trail promise to save the coal plant there.

But he reminded the summit audience that the rule within his administration is that coal can be referenced only as “beautiful coal.”

The gesture seems not to have infused the U.S. energy sector with the same level of enthusiasm so far — no one has announced construction of a new coal plant, only delays on retirements of existing facilities.

However, the president’s cheerleading for coal resonates with many in Pennsylvania, once the nation’s leading coal producer and still the third-highest coal-producing state.

The Keystone State is a fossil powerhouse, in fact: It was the birthplace of the modern petroleum industry and, thanks to hydrofracking technology and a massive shale formation, it is now the No. 2 natural gas producer in the nation.

It’s also the second-highest state for electricity generation and is home to the second-most productive nuclear fleet.

Any of those technologies would be fine to power a data center boom in Pennsylvania, Trump allowed, then added a dig at one of his favorite targets: wind turbines.

“They’ll be powered by maybe nuclear, maybe gas, maybe coal … they won’t be powered by wind because it doesn’t work.”

No worries: Pennsylvania is far down in the ranks of wind-powered states, cranking out only 2.7% as much as nation-leading Texas in 2023.

To round out the picture, Pennsylvania has the fourth-highest amount of carbon dioxide emissions, behind the much more populous Texas, California and Florida.