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December 16, 2025

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California’s ‘Pathways’ Bill Heading to Senate Floor

A California bill to implement the West Wide Governance Pathways Initiative’s Step 2 proposal is headed to the floor of the state Senate after being approved by the body’s Appropriations Committee May 23. 

The committee voted 4-1 to move Senate Bill 540 — known as the “Pathways” bill — out of the “suspense” process, part of a normal procedure in which bills are examined for their fiscal impact before being advanced to the floor for a second reading and debate. 

But questions remain about the exact content in the bill, especially related to amendments. 

SB 540 authorizes CAISO to 1) transfer its state-backed governance authority over its Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM) to the new, independent “regional organization” (RO) being developed by the Pathways Initiative; and then 2) join the RO as a participating member. (See Pathways ‘Step 2’ Bill Sets Conditions for EDAM Governance.) 

In late April, the Senate’s Judiciary Committee amended the bill to include several provisions intended to shield California’s environmental and energy policies from interference by the Trump administration through any potential backdoors opened by CAISO’s participation in the RO. (See California Lawmakers Seek to Trump-proof Pathways Initiative Bill.) 

Key among those amendments is a provision allowing the California Public Utilities Commission to direct the state’s investor-owned utilities to exit the RO if the new body’s market rules — or other public policies — become  “detrimental to California consumers;” the state’s renewable portfolio standards are “held invalid by [a] reviewing court on claims of impermissible discrimination;” or Trump or future presidents use emergency powers to require California to subsidize fossil fuels. 

Another amendment would prevent the RO from establishing capacity markets, which California consumer advocates worry would be used to support coal-fired generation the Trump administration is seeking to incentivize. 

According to one source not authorized to speak for their organization, the amendments have rankled some Pathways supporters, who are concerned the changes needlessly complicate the bill’s original intent.  

During a May 9 press briefing after the Bonneville Power Administration released its long-awaited day-ahead market decision in favor of Markets+, BPA Vice President of Bulk Marketing Rachel Dibble said the amendments “continue to erode the independence that was even in the initial bill, which we did not find to be superior to Markets+.” (See Debate Lingers After BPA Day-ahead Market Decision.)  

But the precise language of the bill emerging from the Appropriations Committee still is unclear.  

While the bill tracker on the California Legislature’s website indicates the committee voted with the recommendation of “do pass as amended,” multiple sources familiar with the legislative process said the bill could have been further altered in committee, with the previous amendments revised or potentially stripped out — although Appropriations amendments typically deal with fiscal matters. 

“Any bill that costs money or would bring in more than a certain amount of money is automatically moved to the suspense file in Appropriations. It can definitely be amended there,” according to a source familiar with California’s legislative process.  

That issue will become clearer when the Legislature prints and posts the next version of the bill, likely May 27, according to one source. 

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NYISO Seeking Info on Dispatchable Generation not in Queue

NYISO on May 21 asked developers to tell the ISO about any dispatchable generation projects that have not yet been submitted to the interconnection queue by June 13. 

Ross Altman, senior manager of reliability planning for NYISO, told the Transmission Planning Advisory Subcommittee that any responses would support the ISO’s Comprehensive Reliability Plan. 

“We are very concerned about the shrinking margins,” Altman said. “Just knowing that there’s anything else out there that’s early in the pipeline that could potentially be in service by the time we run into narrowing margins could be helpful for us in coming up with the Comprehensive Reliability Plan.” 

Altman said any projects submitted in response would be nonbinding and the ISO would respect all confidentiality requests from stakeholders. He said any information obtained through this request would be used “on an aggregated basis” and that the ISO would not identify any specific developers or locations. 

NYISO sent its request out to all stakeholders earlier in the week. The ISO is requesting the following information from developers: 

    • nameplate capacity (MW), or if a storage resource, energy capacity (MWh); 
    • fuel type and technology; 
    • location; 
    • anticipated project schedule and commercial operation date; 
    • ownership or development partners; and 
    • status of site control. 

Independent Power Producers of New York spokesperson Jordan Lomaestro told RTO Insider that IPPNY’s membership still was “digesting” the request and deciding whether to submit anything to NYISO. 

Lomaestro said IPPNY favored an all-of-the-above approach to new resources on the grid and noted its comments submitted to the Public Service Commission in support of any and all new technologies to support the state’s climate goals. 

Alliance for Clean Energy New York spokesperson Barry Wygel said the group did not have an official position on the request but noted that it “isn’t typical for NYISO.” 

“There’s some interest in seeing how the submitted information will be aggregated and what insights NYISO will share,” Wygel told RTO Insider. 

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SPP Readies Participants for Next Phase of Markets+

With FERC having fully blessed the Markets+ tariff, SPP has begun the day-ahead market’s transition to Phase 2 with the first of two webinars designed to educate potential participants on what lies ahead. 

“We’re really moving forward into … actually building out Markets+ and the systems, processes and procedures necessary to implement the tariff,” said Jim Gonzalez during the May 21 webinar. (A second webinar is scheduled for June 30.)  

“We’re ramping up that pre-planning work in order to hit the ground running full steam ahead when Phase 2 starts in earnest,” Gonzalez added. SPP’s senior director of seams and Western services since May 1, he said staff is gathering a list of potential market participants to understand who will participate in building system requirements and developing a readiness program to help work through the implementation effort. 

The RTO expects 13 entities initially to help fund Phase 2, most notably the Bonneville Power Administration, the Pacific Northwest’s 800-pound gorilla. (See BPA Chooses Markets+ over EDAM.)  

Those entities and other interested stakeholders must sign and submit one of three agreements through SPP’s Request Management System to continue engaging and voting as rostered members in the various Markets+ stakeholder groups: 

    • Funding agreements, for balancing authorities and their embedded entities. Under that agreement, they will provide collateral in the form of a letter of credit or cash that allows SPP to use debt to build the systems. 
    • Stakeholder agreements, for non-governmental organizations and others that don’t expect to be active market participants. 
    • Participation agreements, for entities in a BA without a funding agreement and that register the utility’s load. 

The stakeholder and participation agreements both come with $5,000 one-time fees, similar to SPP’s RTO participation model. The grid operator will waive the fee for nonprofit NGOs that can prove their status. 

SPP has set a soft deadline of July 23 for submitting the agreements and retaining seats on stakeholder groups. The Markets+ stakeholder groups must submit their roster nominations on that date. The rosters will be posted for the stakeholder-led Markets+ Participant Executive Committee’s approval and then confirmed by the MPEC during its Aug. 12-13 meeting in Portland, Ore. 

The Interim Markets+ Independent Panel, composed of three SPP board members that are overseeing the market’s development, then will confirm the chairs. 

“If you intend to participate with Phase 2 governance, we will need an executed agreement in any one of these three [categories],” SPP’s Kelli Schermerhorn said. 

Markets+ Phase 2 timeline | SPP

She warned attendees that participants who don’t sign one of the agreements will lose their seat on working groups or task forces.  

“Those Phase 1 agreements are going to cease to be effective,” Schermerhorn said. “Independent governance is a cornerstone of all SPP offerings. Our Markets+ design has been largely accomplished by these task forces and working groups.” 

Three other decision dates have been set as deadlines for balancing authorities, transmission providers or market participants if they want to be part of the initial market launch: Sept. 1 (BAs), Oct. 1 (transmission providers) and Dec. 1 (MPs). 

FERC in April approved the Markets+ $150 million funding agreement and its recovery mechanism. The commission also granted SPP’s request to issue debt securities to cover the agreement and fund the market’s implementation over three years until its scheduled Oct. 1, 2027, go-live date. (See SPP MPEC Members Celebrate Markets+ Funding Order.) 

The funding agreement requires the entities to provide the collateral backstop to SPP’s lender in supporting the RTO’s financing. The collateral is equal to the amount of the entities’ Phase 2 obligations.  

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

Funding participants withdrawing from the agreement must pay their Phase 2 obligation to SPP, protecting the remaining participants from the withdrawal. 

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Florida, Mississippi Utilities to Pay SERC $140K in Penalties

SERC has levied $140,000 in penalties against utilities in Mississippi and Florida for violations of NERC’s reliability standards, in two separate settlements recently approved by FERC. 

The settlements, submitted in April in NERC’s monthly spreadsheet notice of penalty, are with Florida Power and Light (FPL) for $120,000 and Mississippi’s Cooperative Energy for $20,000 (NP25-11). FERC said in a filing May 23 that it would not further review the settlements, leaving the penalties intact. 

Both settlements concern the standard FAC-008-5 (Facility ratings), which requires that transmission owners and generation owners have facility ratings for [their] solely and jointly owned facilities that are consistent with the associated … methodology or documentation for determining [their] facility ratings.” FPL’s noncompliance was discovered through a compliance audit; Cooperative self-reported its infringement. 

SERC conducted its onsite audit of FPL from June 20 to 24, 2022. The regional entity’s audit team walked down four transmission substations and found a 138-kV, 230-kV and 500-kV substation with incorrect facility ratings. 

Following this finding, SERC required FPL to walk down eight transmission facilities and eight generation facilities to look for more misratings. The utility found one incorrect rating among the transmission facilities, a 230-kV line that needed a 25% derate; at the generation facilities, FPL found one station with incorrect facility ratings, two more stations with incorrect or missing equipment ratings, and one where the walkdown could not be completed because the current transformers could not be verified without an outage. 

FPL then did an extent of condition assessment requiring walkdowns of all 1,822 transmission facilities and 180 generation facilities. It found 153 incorrect transmission facility ratings, including one facility that experienced an exceedance of the correct rating. The biggest derate required was 93% on a 115-kV line. For the generation facilities, 12 derates were required and three uprates. 

SERC determined the violation began June 18, 2007, when FAC-009-1 — the predecessor of FAC-008-5 — was in effect. The root cause was ineffective controls, specifically training management controls, validation controls and controls to ensure the utility’s management of change process was carried out successfully. The RE assessed the risk posed by the noncompliance as moderate. 

FPL’s mitigating actions include adding a training course on the FAC-008 worksheet to its learning management system, standardizing the procedure for walking down transmission and substation facilities, and improving the implementation of controls and ensuring they’re working as designed. 

Cooperative Discovered Repeat Issue

Cooperative notified SERC of its noncompliance Jan. 30, 2024. As with FPL, SERC determined the violation spanned both FAC-009-1 and FAC-008-5. 

The utility discovered during a substation facility walkdown that the current transformer (CT) rating factor for a gas circuit breaker was not on the CT’s nameplate. This GCB was older than the others in the same facility, which were installed on the same date.  

Upon reviewing the nameplate and electronic documentation, Cooperative could not find a correct CT rating factor. As a result, the utility had to change to a more conservative rating factor than the one that was in its database, requiring a derate on the affected line. 

Cooperative found no further CT rating factor issues on other substations. It went on to verify elements at five substations that had been walked down but later had field work done requiring another in-person examination. 

In the SNOP, SERC noted the violation began June 18, 2007, and ended Nov. 8, 2023, when Cooperative changed the CT tap setting to account for the CT rerating. The total duration of the infringement was more than 16 years. The RE said the cause of the violation was “an ineffective training program” that did not equip staff to recognize that the breaker was an older model that required a different CT rating factor. 

SERC observed that Cooperative has a history with this specific type of misrating. Cooperative and SERC settled in 2023 for a similar infringement, when the utility failed to consider CTs when determining facility ratings for its solely and jointly owned facilities. (See FERC Approves SERC Settlement with Mississippi Co-op.)  

Although that settlement did not result in a monetary penalty, the RE said it considered the utility’s history as an aggravating factor in determining the penalty for this case because the changes put in place after the earlier infringement should have detected this one. 

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Stakeholder Forum: The Facts About FERC Order 1920 and Why It’s Essential

By Gretchen Kershaw

As the tides of “deregulation” swell, I write to set the record straight on FERC Order 1920. As Mark Twain said, “Get your facts first, then you can distort them as you please.” Here are the facts. 

Gretchen Kershaw

We need a significant amount of transmission in this country. Study after study shows a pressing need today as well as in the future, and that need is driven by threats to the reliability and resilience of the grid, high energy costs, and congestion and constraints on the existing system. 

At the same time, demand is surging, driven by electrification, increases in domestic manufacturing, and, of course, new load from artificial intelligence (AI) data centers and other large customers. 

So, everyone is asking: How do we meet potentially exponential demand growth reliably and affordably? Generation will be needed, but it cannot meet this demand alone; transmission is essential. So is FERC’s Order No. 1920. Here are a few key facts. 

Fact 1: The status quo incremental and reactive approach to building the grid we need is the most expensive option and will contribute to rising electricity bills. FERC aimed to fix the broken paradigm with Order 1920, establishing a baseline across the country that reflects best practices, such as planning on a 20-year forward-looking basis. Well-planned transmission, as envisioned by Order 1920, benefits all users of our electric system. 

Fact 2: Well-planned transmission improves reliability and resilience. The reality is that all generators have outages, whether “behind the meter” or grid-connected. A more networked system, connecting areas that have peak loads and generation outages at different times, always has been the way to ensure steady power supply. 

Looking at extreme weather events, transmission consistently allows more resources to be shared across regions and move energy from where it is available to where it is needed. Witness Winter Storms Uri and Elliott, where regions that could import power avoided prolonged outages that plagued regions that were more islanded. 

As my colleague Michael Goggin says: We need a grid bigger than the weather. Building this insurance policy against future extreme events requires planning that is proactive and that accounts for a wide range of drivers and addresses uncertainty by identifying projects that are beneficial under multiple scenarios. 

Fact 3: Well-planned transmission saves consumers money. Electricity rates are increasing for several reasons, one of which is transmission. But despite transmission spending hitting an all-time high in recent years, the miles of new high-voltage transmission that is being built has dropped year-over-year. 

So, transmission owners are investing — not surprising, given our aging electric grid — but not adding new large-scale transmission capacity nearly fast enough. The National Transmission Planning Study, released by DOE last year, found the lowest-cost electricity system to meet future demand and reliability needs includes substantial transmission expansion — and that accelerated and coordinated expansion could save upward of $490 billion through 2050. We cannot afford to abandon Order No. 1920; instead, we should implement it faster to significantly benefit sooner. 

Fact 4: Order 1920 benefits all kinds of generation, and our country needs more transmission no matter the generation type. Abundant American energy supply is within reach. But we cannot access it reliably and affordably without transmission. 

Let’s be clear: Utilities are investing more than ever in upgrading a rapidly aging grid. Order 1920 provides a collaborative road map for more efficient and cost-effective grid upgrades. Grid hardening is critical, as is squeezing more from our existing system by deploying grid enhancing technologies and high performance conductors. 

Congress knew this when it acted, on a bipartisan basis, to establish federal funding programs in the Infrastructure Investment and Jobs Act in 2021 for just this type of investment. Regrettably, delays in these critical enhancements may indeed happen, but not from Order 1920; instead, delays may happen from blocking use of federal funds specifically for these needs. 

Those are the facts. How impactful Order 1920 will be is yet to be seen, but to cut it off at the pass is to threaten grid reliability and resilience, impose higher costs on consumers, and threaten America’s ability to compete in the global AI race. 

Gretchen Kershaw is chief operating officer and vice president of strategy at Grid Strategies LLC. 

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CAISO Approves $4.8B Transmission Plan to Support 76 GW of New Capacity

CAISO’s Board of Governors has approved the ISO’s 2024/25 transmission plan to build out 31 new projects in the region over the next eight to 10 years. 

Of the 31 approved projects valued at $4.8 billion, 28 are for reliability purposes for $4.6 billion. By 2039, California will need 76 GW of additional capacity to meet increasing building electrification and electric vehicle loads, CAISO wrote in the plan. 

The plan’s most expensive project is the North Oakland Reinforcement Project, estimated at $1.1 billion and with an online date by 2032. The project includes the Port of Oakland, which is experiencing rapid load increase due to industrial and commercial growth, EV charging and electrification loads.  

The project is meant to meet increasing demand without relying on local Oakland thermal generation units, CAISO wrote in the plan. Demand is forecast to increase from 377 MW in 2024 to 458 MW by 2039 in the region. CAISO and Pacific Gas and Electric should attempt to accelerate the completion of the project prior to 2032, Teri Dean Alderson, assistant general manager at Alameda Municipal Power (AMP), said in comments to CAISO. 

The second-most expensive project in the plan is the $700 million Greater Bay Area 500-kV Transmission Reinforcement project, which has an online date of 2034. The area could have a deficiency of about 5,000 MW by 2039, which significantly surpasses the available transmission resources and internal generation capacity, CAISO said in the plan. The forecast supply shortage is caused by the potential loss of two of the three 500/230-kV transformer banks at Metcalf or loss of the two 500-kV sources to Metcalf and Moss Landing substations, CAISO said. 

About $290 million of the remaining funding is allocated for three policy-driven transmission projects. Policy-driven transmission projects enable the grid to support local, state and federal directives, with most of these projects focused on meeting California’s renewable energy goals, CAISO said. 

From a systemwide resource assessment, CAISO is going into a period of greater uncertainty as load growth continues to accelerate, Neil Millar, CAISO vice president of transmission planning and infrastructure development, said at the May 22 Board of Governors general session meeting. 

“Not only are the peak loads growing, but our load factor and winter peak loads are growing, which is a success of building and transportation electrification,” Millar said. “Those are creating additional challenges that the state agencies are taking into account.” 

Having more transmission project options is important because “we don’t know what things are going to look like four years from now [at the federal level],” Millar said. However, CAISO also must follow state policies and cannot afford to let transmission projects be a barrier to achieving state policy goals, he said. 

At the same time, CAISO should consider the risk of policy changes affecting expensive transmission projects, such as two transmission projects in the North Coast region, which are to support future offshore wind power in Humboldt County, Millar said. CAISO has selected Viridon to build these future OSW transmission projects for up to $4.1 billion over the next eight to 10 years. (See CAISO Chooses Viridon to Develop Humboldt OSW Transmission Projects.) 

The projects were designed to be the right first step, but CAISO recognizes that the resource requirements for the lines can grow beyond their initial design, Millar said.  

“We were also very clear in bidding those projects that there is inherent uncertainty in those resource types and as a result those projects have a higher risk of potential cancellation,” Millar added. 

The transmission plan also emphasizes non-transmission alternatives, such as energy efficiency and demand response programs, renewable resources and energy storage systems. Battery energy storage has made up the vast majority of new resources in CAISO’s region in recent years. As of April, more than 12,000 MW of battery storage capacity is online in CAISO’s region, with an additional 15,000 MW planned to be available by 2028. 

Stakeholders Applaud, Question Plan

In comments to CAISO, Caitlin Liotiris, principal at Energy Strategies, said one notable enhancement to this year’s transmission plan is the additional transparency regarding CAISO’s process for reserving deliverability for long lead-time resources.  

“The [plan] specifies the long lead-time resources in the base portfolio and the amount of deliverability that is being reserved for them,” Liotiris wrote. 

However, staff with California Wind Energy Association (CalWEA) said CAISO’s transmission plan “does not fulfill … CPUC’s request to plan transmission for the 5.2 GW of in-state wind energy.”  

“CalWEA is primarily concerned with the Southern California Edison Northern and San Diego Gas & Electric study areas where wind development interest is currently the strongest,” CalWEA staff said.  

In the SCE Northern area, CPUC requested that CAISO plan for 564 MW of full capacity deliverability status. Of this 564 MW, only 100 MW has been awarded that status. CAISO therefore must plan for 464 MW, CalWEA staff wrote.  

In next year’s transmission plan, there likely will be a fairly heavy emphasis on load-growth related reliability projects as CAISO transitions to a higher long-term expectation of growth, Millar said. 

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Amid Fraud, MISO Plans Stricter Testing of Demand Response

MISO said starting with the 2026/27 planning year, it will require its demand response resources to demonstrate actual demand reductions through tests to weed out imposters in the capacity market.  

“We need to see everyone perform a real power test,” Joshua Schabla said during a May 21 Resource Adequacy Subcommittee meeting. 

MISO said requiring real power tests with actual load cuts decreases the likelihood that resources fraudulently register in capacity auctions. MISO currently allows its demand response fleet to submit mock tests or opt out of testing. Under the new regime, real power tests would be required annually for at least one hour. Exceptions would be limited to trusted performers with a history of responsiveness and overrides because of state regulations.  

Schabla said the last time load-modifying resources were deployed was Dec. 22, 2023, long enough to need renewed proof that the resources can discount load levels.  

MISO said it would file the changes with FERC at the end of May for a June 1 go-live date. The grid operator said the “rapid” deadline would ensure all demand resources have the summer to perform a test in preparation for the 2026/27 planning year.  

MISO would permit waivers of testing requirements only in two limited circumstances: when a test is precluded by regulatory restrictions, or when a resource requesting a waiver hasn’t amassed any penalties in the past three planning years, hasn’t changed its registered value in the past three years and — also in the last three years— has made at least an 80% reduction of the maximum accredited value it has requested for the upcoming planning year. 

Schabla said testing waivers should be reserved for resources that have shown to be “solid” through scheduling instructions or MISO-initiated tests. 

MISO also plans to stop letting aggregated demand response drop to a firm service level for testing. The RTO’s pending demand response accreditation filing before FERC similarly cuts the firm service level-reduction option for aggregations. Schabla said “gaming opportunities are substantial” when aggregated resources can specify a firm service level baseline.  

MISO recognizes two types of demand response: those that make megawatt reductions and those that drop to a predetermined firm service level.  

The stricter testing is part of MISO’s larger reining in of demand response following a handful of FERC investigations and findings that companies have manipulated the capacity market. MISO in March proposed an overhaul of its capacity accreditation methods for demand response that would be based on whether they can help during system risk. (See Stakeholders Ask FERC to Soften MISO’s Proposed DR Accreditation.)  

A few months before its April capacity auction, MISO said it would hold its demand response to heightened testing requirements. (See Following DR Exploitation, MISO Announces Stiffer Requirements Before Capacity Auction.) The new tariff filing would solidify the change going forward.  

MISO’s Independent Market Monitor recently predicted more enforcement actions from FERC on the horizon for bad actors among MISO’s demand response fleet. During the Organization of MISO States’ Resource Adequacy Summit in May, Patton said a planned data center has been collecting demand response payments even though its construction location remains an empty field. (See “IMM: Problem Remains with ‘Not Real’ DR,” MISO CEO: Slim Reserves Not Necessarily Bad.)  

Schabla read from lines from recent FERC orders levying penalties on companies that have offered phantom demand response to prove the point that MISO needs stricter testing requirements.  

“I hope you can agree with us that we need to put in controls today” that demand response resources can prove they can reduce demand, Schabla said.  He said it’s “clear we need to act, and we need to act fast.”  

MISO said the “lack of a real power test was specifically cited in several recent FERC orders and stipulations as helping to perpetuate the fraud.” 

For the 2025/26 planning year beginning June 1, MISO said it cleared about 3.7 GW of demand resources that waived the requirement to perform a real power test.  

Under the upcoming summer clearing price of $666.50/MW-day, the grid operator said a 10-MW demand resource can expect to be compensated $613,180 over the season.  

MISO said, in total, auction revenue this year for demand response resources that have waived a real power test is about $282 million.  

“There’s a great deal of money to be made in our capacity market,” Schabla said. He added that it’s appropriate for demand resources to flock to MISO’s market to offer their capabilities but, “if we’re going to pay that much money, it has to be real.”  

Schabla said MISO is looking for “reasonable requirements, reasonable barriers” when attracting demand response, although he admitted nothing would be a “panacea” that would completely defeat fraud.  

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MISO Stakeholders Request Theoretical 2025/26 Auction Clearing Sans Sloped Curve

Stakeholders continue to ask MISO to crunch hypothetical auction clearing prices absent the RTO’s new sloped demand curve that sent prices past $660/MW-day for summer.  

During a May 21 Resource Adequacy Subcommittee meeting, multiple stakeholders asked MISO staff to publish 2025/26 hypothetical auction clearing prices through a simulation with the old, vertical curve. The exchange led Independent Market Monitor David Patton to chime in to defend MISO’s installment of a sloped demand curve.  

The 2025/26 planning year auction marked the first time MISO used a sloped demand curve, meant to procure more capacity than strictly necessary to meet MISO’s one-day-in-10-years reliability standard. MISO ultimately cleared 137.5 GW, more than the 135.3 GW it designated prior to the auction to meet its one-day-in-10-years reliability standard, at a cost of $666.50/MW-day for the upcoming summer. (See MISO Summer Capacity Prices Shoot to $666.50 in 2025/26 Auction.)  

“Given that we just switched from a vertical demand curve to a sloped demand curve,” it’s appropriate for MISO to show what the clearing would have been with a vertical curve, WEC Energy Group’s Chris Plante said during the meeting.  

WPPI Energy’s Steve Leovy said he failed to see how MISO could claim that its sloped demand curve “enabled MISO to secure more capacity at a significantly lower price,” as the RTO claimed in its presentation. He asked which alternate reality MISO used as a comparison.   

MISO Resource Adequacy Manager Andy Taylor said MISO’s comparison “is not a counterfactual to” the old, vertical demand curve, but a counterfactual to other sloped demand curve designs.  

MISO develops its sloped curves by assessing the value of additional capacity beyond the one-day-in-10-years standard relative to its price. If the cost isn’t too steep, MISO shapes the slopes with the OK to clear extra megawatts.  

MISO said had the auction cleared only to its initial planning reserve margin requirement of 135.2 GW, prices would have been $846/MW-day based on the sloped curve it ultimately used.  

Plante said MISO’s comparison is “very confusing to a casual observer.”  

Clean Grid Alliance’s David Sapper said he didn’t believe MISO’s auction clearing process as described in its business practice manual makes sense. He asked MISO to redraft a process that could be more readily understood. 

Sapper said he also was “dismayed” that FERC Chair Mark Christie, whom he said is consequential in RTOs’ capacity auction changes and “a scholar and a gentleman,” didn’t seem to understand auction clearing processes.  

“He seems to have thrown up his hands that they’re impenetrable,” Sapper said.  

Minnesota Power’s Tom Butz said prices this year “rocketed up to CONE-like values” and it seems they will be there for the foreseeable future. 

But IMM David Patton said, “for the first time,” auction clearing prices in MISO reflected the marginal value of capacity. Patton said the auction clearing an additional 2% in capacity is a good thing despite what stakeholders might think.  

“I know this is a shock with prices being high, but we do find that this is going to set up for a much more reliable system,” he said. Patton said prices should compel utilities and regulators to make more informed decisions in integrated resource plans and selecting resource retirement dates.   

Patton estimated summer prices would have been about $20/MW-day under the old, vertical curve. But he cautioned that hypothetical, low prices aren’t as attractive as they appear.  

“What you should take away from that is: Our previous market was flawed and wouldn’t have produced prices in line with reliability,” Patton said.  

Had inexpensive capacity prices held court for another planning year, Patton said it wouldn’t meet any “fundamental objectives of the capacity market to set prices this way.”  

During the April 29 auction results call, Taylor said had MISO used its vertical curve, the auction would have produced “extreme, very low or very high” pricing outcomes as it has in years past.  

At the time, Clean Grid Alliance’s David Sapper asked if MISO would commit to re-running the auction if it’s discovered the RTO drew on incorrect inputs in its sloped curve. MISO counsel Michael Kessler said it would be “highly unusual” for FERC to order any capacity auction to be rerun.  

The 2025 auction results are poles apart from auction results a decade ago, when Southern Illinois’ Zone 4 clearing price of $150/MW-day sparked concerns that pivotal supplier Dynegy manipulated capacity availability to raise prices. (See FERC Sets Dynegy’s MISO Market Manipulation Case for Hearing.)  

MISO to Allow Resources with Provisional Agreements to Provide Capacity

At the same resource adequacy meeting, MISO said it will take steps to allow resources with provisional generator interconnection agreements (GIAs) to offer capacity in MISO’s seasonal capacity auctions if they can deliver.  

MISO’s tariff expressly prohibits resources with provisional GIAs from participating in capacity auctions. MISO announced it will pursue a turnaround on its longstanding policy and open the auction to the resources with the provisional agreements starting with the 2026 seasonal capacity auction.  

“We would like these resources to participate in the planning resource auction as well, provided they’ve procured deliverability,” Taylor said.  

Taylor said the “current length and state” of MISO’s interconnection queue might have influenced MISO’s rethinking of the nearly complete resources’ ability to furnish capacity.  

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Trump Orders Nuclear Regulatory Acceleration, Streamlining

President Donald Trump moved to speed up nuclear power development May 23 with a series of executive orders designed to ease federal regulations on the sector. 

The measures require the Nuclear Regulatory Commission to issue timely licensing decisions, allow construction on federal lands to serve national and economic security, attempt to re-invigorate the nuclear energy industrial sector and allow for reactor design testing at nuclear laboratories. 

The end goal is to quadruple U.S. nuclear power production by 2050. A shorter-term goal is to have three new experimental reactors online by July 4, 2026. 

Nuclear industry executives spoke appreciatively as they watched the president sign the orders, and advocacy groups not present at the ceremony issued a chorus of supportive comments. 

But others raised concerns about the Trump administration speeding up review of nuclear development and construction, particularly as the industry attempts to pivot from time-tested designs to new and unproven technologies. 

The narrative of commercial nuclear power in the United States is well-known: The nation pioneered the industry and built the largest reactor fleet in the world, then stepped back, completing zero commercial plants for 30 years. The nation’s first new reactors in a generation were completed recently, far behind schedule and at stunningly high cost. 

One after another, Trump and his invited speakers blamed this turn of events on federal over-regulation and said the executive orders would change that. 

“We’re not going to have cost overruns,” Trump said. 

“It’s time for nuclear, and we’re going to do it very big.” 

Reactions

The reporters gathered for the ceremony asked the president two almost cursory questions about the safety of nuclear energy, then quickly switched to tariffs and other topics. 

Trump replied that nuclear generation has become very safe. 

Neither he nor any of the speakers or questioners present drew any correlation between nuclear generation becoming safer at the same time as regulations on it were becoming more strict. 

But others made that connection. 

Edwin Lyman, director of nuclear power safety at the Union of Concerned Scientists, said in a news release: “By fatally compromising the independence and integrity of the NRC, and by encouraging pathways for nuclear deployment that bypass the regulator entirely, the Trump administration is virtually guaranteeing that this country will see a serious accident or other radiological release that will affect the health, safety and livelihoods of millions.” 

Shortly after Trump was inaugurated and began to assert power over independent federal regulators such as the NRC, Allison Macfarlane, the NRC chair from 2012 to 2014, warned in the Bulletin of the Atomic Scientists about the dangers of faster, looser regulation of the next generation of reactors now being designed: “These proponents — some with no experience in operating reactors — want the NRC to trust their simplistic computer models of reactor performance and essentially give them a free pass to deploy their untested technology across the country.” 

But others cheered Trump’s moves. 

Constitution CEO Joe Dominguez was present at the signing ceremony. 

“The problem in the industry has historically been regulatory delay,” he said. “Mr. President, you know this because you’re the best at building big things. Delay in regulations and permitting will absolutely kill you.” 

He also noted “silly questions” by the NRC, such as the investigations into whether new reactors are suitable for a site adjacent to reactors that have been operating safely for decades. Addressing that one line of inquiry has cost Constellation $35 million each in three application processes, he added. 

Jacob DeWitte, CEO of fast reactor developer Oklo, also was present for the signing and said, “Nuclear is a manifestation of energy dominance” and “changing the permitting dynamics is going to help things move faster.” 

ClearPath Action CEO Jeremy Harrell said in a news release: “These executive orders take a whole-of-government approach to move quickly in support of new deployments.” Harrell also called for additional policy and financial support from Congress. 

Nuclear Innovation Alliance CEO Judi Greenwald applauded the Trump administration’s goals with the orders but raised concerns about some parallel actions: “Adequate staffing and funding are required for these goals to be met. Recent DOE staffing reductions and proposed budget cuts undermine the department’s efforts and make it harder to implement these executive orders.” 

Greenwald added that the alliance has long thought the NRC needed to be more efficient, but sees it making significant progress and feels it important this not be undermined by staff cuts or conflicting directives: “NRC effectiveness, efficiency and independence are critical to the public, the industry and potential customers of U.S. nuclear technology both here and abroad.” 

The Orders

President Trump signed five executive orders May 23, four of them pertaining directly to nuclear energy and the fifth requiring federal research agencies to conform to Gold Standard scientific practices. 

The nuclear executive orders are lengthy and detailed. 

The NRC order, for example, specifies: 

    • reorganization and staff cuts, including a reduction in personnel and functions of the Advisory Committee on Reactor Safeguards; 
    • wholesale revision of NRC regulations and guidance; 
    • adoption of fixed deadlines; 
    • an expedited pathway for approval of reactors already tested by the departments of Defense or Energy; and 
    • consideration of nuclear energy’s economic and national security benefits alongside the traditional safety, health and environmental considerations. 

At times, the wording is blunt in its criticism of the NRC: “A myopic policy of minimizing even trivial risks ignores the reality that substitute forms of energy production also carry risk, such as pollution with potentially deleterious health effects.” 

Trump did not mention in his order that he also has moved to ramp up those other forms of energy production and remove safeguards against their deleterious effects. 

Other actions ordered by Trump include: 

    • A nuclear reactor will be built and operational on a domestic military base within three years. 
    • The departments of Energy and Defense will explore categorical exclusions under the National Environmental Policy Act for the construction of advanced nuclear reactor technologies on federal sites. 
    • The State Department and other agencies will aggressively explore opportunities for export of U.S. nuclear technology to allies to bolster the U.S. nuclear industrial sector. 
    • DOE will release at least 20 metric tons of high-assay low-enriched uranium into a readily available fuel bank for private sector projects operating nuclear reactors to power AI infrastructure at DOE sites. 
    • The “severely atrophied” domestic nuclear fuel supply chain will be expanded. 
    • All relevant federal agencies will work together to develop solutions for the “difficult problem” of treatment of nuclear waste. 
    • Multiple efforts will be undertaken to build a workforce that can do all of these things. 
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DOE Orders Michigan Coal Plant to Reverse Retirement

Energy Secretary Chris Wright issued an emergency order May 23 that seeks to keep Consumers Energy’s 1,560-MW J.H. Campbell coal plant in West Olive, Mich., running past its May 31 retirement date. 

“Today’s emergency order ensures that Michiganders and the greater Midwest region do not lose critical power generation capability as summer begins and electricity demand regularly [reaches] high levels,” Secretary Wright said in a statement. “This administration will not sit back and allow dangerous energy subtraction policies to threaten the resiliency of our grid and raise electricity prices on American families.” 

The Office of Cybersecurity, Energy Security and Emergency Response issued the order under Section 202(c) of the Federal Power Act, which is in accordance with President Trump’s Executive Order Declaring a National Emergency. (See Trump Seeks to Keep Coal Plants Open, Attacks State Climate Policies.) 

Section 202(c) effectively is a federal backstop for reliability-must-run deals to keep power plants needed for reliability open, overruling environmental laws in the process. Recently, it has been invoked for brief periods. The Trump administration’s order signals a more aggressive use of the authority. 

The rule was used in 2005 to keep power flowing to the White House by preventing the closure of coal plant across the Potomac River in Alexandria, Va. 

Consumers signed a deal with Michigan regulators in 2022 that it would stop burning coal by the end of 2025. (See Michigan PSC Oks CMS Plan to End Coal Use by 2025.) 

“We’re officially retiring our J.H. Campbell Complex beginning in early 2025,” the utility’s website said. “This will allow us to get closer to end coal use by 2025, lower our carbon footprint and add more renewable energy for us to deliver.” 

DOE cited NERC’s recent Summer Reliability Assessment that listed the Midcontinent ISO (and several other regions) at an elevated risk for outages this summer due to a narrow reserve margin. The order declares an emergency on the grid to keep the J.H. Campbell plant open. 

“Its retirement would further decrease available dispatchable generation within MISO’s service territory, removing additional such generation along with the other 1,575 MW of natural gas and coal-fired generation that has retired since the summer of 2024,” the order said. 

The retirement was in MISO’s and Consumer’s summer forecasts, as was a new 1,200-MW natural gas plant it purchased, which expected sufficient capacity to meet peak demand, the order said. 

“For the duration of this order, MISO is directed to take every step to employ economic dispatch of the Campbell Plant to minimize cost to ratepayers,” the order said. “Following conclusion of this order, sufficient time for orderly ramp down is permitted, consistent with industry practices. Consumers Energy is directed to comply with all orders from MISO related to the availability and dispatch of the Campbell Plant.” 

The secretary’s order directs Consumers to file waivers needed for compliance with FERC. It also directs the plant to follow environmental laws while producing power.