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December 14, 2025

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Imperial Irrigation District Inks Agreement to Join CAISO Markets

The Imperial Irrigation District (IID) has agreed to join CAISO’s Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM), the ISO announced May 27.

CAISO said the publicly owned utility, based in Southern California’s Imperial County, has signed implementation agreements and will begin participating in the markets in 2028.

In a separate announcement on May 20, IID said its board of directors approved a $24 million budget amendment “to advance preparations for joining” WEIM and the soon-to-be-launched EDAM. The money will fund upgrades to the utility’s control infrastructure, telecommunications, metering and energy management systems, according to the announcement.

“As a large public power provider in California, IID is pleased to join both the Western Energy Imbalance Market and the Extended Day-Ahead Market,” Jamie Asbury, general manager at IID, said in a statement. “This is a significant step toward modernizing how we purchase and manage power, which will translate into savings for our ratepayers annually by giving us the ability to react much faster to energy market conditions. This also aligns IID more closely with emerging regional energy practices yet allows us to retain our independence as an energy balancing authority.”

IID serves about 165,000 customers in service territory covering 6,611 square miles that includes California’s Imperial Valley and parts of San Diego and Riverside counties. The utility controls about 1,100 MW of generation, including contracted resources, and operates more than 1,800 miles of transmission and 5,000 miles of distribution lines.

CAISO noted that when IID begins participating in the markets, “it will mark the first time all California balancing authorities are participating in ISO-operated electricity markets.”

The agreement between IID and CAISO comes shortly after California publicly owned utility Turlock Irrigation District announced it would join EDAM in 2027. PacifiCorp and Portland General Electric have agreed to begin participating in EDAM in 2026, with the Los Angeles Department of Water and Power and the Balancing Authority of Northern California set to join in 2027. (See LADWP Gets Board’s OK to Join CAISO’s EDAM and Turlock Irrigation District to Join EDAM in 2027.)

PowerWatch (formerly BHE Montana), PNM, NV Energy, Idaho Power and Arizona G&T Cooperatives have indicated they’re leaning toward EDAM as their preferred day-ahead market choice.

Changed Perspective

IID’s decision also is significant because of the district’s at-times contentious relationship with CAISO — and its past opposition to “regionalizing” the ISO.

In July 2015, IID filed an antitrust suit in the U.S. District Court of Southern California contending CAISO had gained monopoly power over the state’s transmission services and operations markets.

The suit alleged that — through a series of memos and public statements made between 2011 and 2014 — CAISO had “induced” IID to make $30 million in upgrades to Path 42, one of two transmission lines linking the utility district with the ISO.

CAISO had estimated the improvements would increase IID’s maximum import capability (MIC) into the ISO from 462 MW to 1,400 MW, but later downgraded the MIC to the previous level, citing closure of the San Onofre nuclear generating station as the reason for its decision, which IID contested. (See Federal Judge Upholds Imperial Irrigation District Suit Against CAISO.)

The two parties reached a settlement in the suit in 2018 after the ISO approved line upgrades that would allow more renewable energy to flow into the ISO from the utility’s service territory.

IID also opposed CAISO’s previous efforts to expand into an RTO, initiating a separate lawsuit in 2016 seeking to force the grid operator to publicly disclose protected information related to ISO-commissioned studies supporting regionalization.

Speaking at a joint California agency workshop in July 2016, IID’s then-General Manager Kevin Kelley said the utility opposed regionalization because it would require the state to relinquish oversight of an entity that suffered costly market manipulation during the 2000/01 Western Energy Crisis.

Kelley at the time said he suspected the “driver” of regionalization was a “for-profit corporation” — namely, PacifiCorp, which was the first utility to commit to joining both the WEIM and EDAM. (See Governance Plan Critics Urge Slowdown of Western RTO Development.)

But times have changed and IID’s energy consumption and customer base grow each year, with demand increasing, Robert Schettler, a spokesperson for IID, told RTO Insider.

“We’re out there making agreements ahead of time as best we can,” Schettler said. “But then sometimes the energy that we’re expecting isn’t available, and we have to go on the market and get it and pay market prices, and then we have to shift those prices to our customers, which has not been popular.”

IID hopes participation in the markets will broaden the utility’s reach and bring stability to fluctuating adjustment costs in customers’ bills. Additionally, IID has been around for 114 years, and entry into the markets comes as the utility has launched a 15-year plan to upgrade its infrastructure, Schettler noted.

WEIM launched in 2014, and EDAM is slated to go online next spring. IID said in the news release that a “conservative estimate” shows the utility could save $12 million annually once both markets are in use.

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Uranium Mine Expansion Approved in Just 11 Days

Federal regulators are off to a running start on their expedited review of energy projects, greenlighting a uranium mine expansion in just 11 days. 

The Velvet-Wood site in southeastern Utah produced about 4 million pounds of uranium and 5 million pounds of vanadium from 1979 to 1984. Significant additional deposits are believed to remain in the ground, and owner Anfield Resources Holding has sought a modification of the existing plan of operation for the site that would result in 3 acres of surface disturbance. 

The Department of the Interior on April 23 implemented emergency permitting procedures for uranium, oil, gas, coal, critical minerals and other materials judged relevant to addressing Trump’s Jan. 20 declaration of a national energy emergency. 

Analysis of these proposals would take 14 or 28 days depending on their complexity, Interior declared, rather than the typical one or two years. 

On May 12, Interior announced it would start, conduct and complete the environmental review of the Velvet-Wood project within 14 days. 

On May 23, Interior announced it had found there would be no significant impact from the proposal, and that Interior has given Anfield all needed clearance to move ahead. It was the first expedited review of its kind, and possibly the first of many. 

“This approval marks a turning point in how we secure America’s mineral future,” Interior Secretary Doug Burgum said in the official announcement. “By streamlining the review process for critical mineral projects like Velvet-Wood, we’re reducing dependence on foreign adversaries and ensuring our military, medical and energy sectors have the resources they need to thrive. This is mineral security in action.” 

The accelerated permitting protocol was met with dismay by environmental advocates worried about the impact of rushed reviews. Uranium mining is a particularly sensitive issue for tribal nations in the U.S. Southwest that historically have suffered the effects of such operations. 

The May 23 announcement about Velvet-Wood came on the same day Trump issued executive orders easing the regulatory burden on nuclear developers and attempting to expand the supply chain in hopes of bringing new nuclear generation online, and quickly. (See Trump Orders Nuclear Regulatory Acceleration, Streamlining.) 

Reactor fuel is an important part of this vision, as almost all the uranium used for commercial purposes in the United States today is imported. Vanadium has strategic value as well, given its importance in steel alloys. 

Atlas Minerals extracted 400,000 tons of ore from the Velvet Deposit between 1979 and 1984. At grades of 0.46% and 0.64%, that yielded 4 million pounds of uranium and 5 million pounds of vanadium. 

Anfield bought the mines and the Shootaring Canyon uranium mill from Uranium Ore in 2015. It estimates the Velvet and Wood mines can yield enough ore to produce 4 million and 552,000 pounds of uranium, respectively, at grades of 0.29% and 0.32%. Roughly 1.4 times as much vanadium would be expected. 

Anfield CEO Corey Dias welcomed Interior’s decision in a May 27 news release: “This confirms our view that Velvet-Wood was well-suited for an accelerated review, given that it is a past-producing uranium and vanadium mine with a small environmental footprint. The company will now pivot to advancing the project through construction and, ultimately, to production.” 

The Shootaring Canyon Mill operated only briefly in 1982 due to depressed uranium prices. It is one of only three licensed, permitted and constructed uranium mills in the United States, Anfield said. 

Its radioactive source materials license is on standby, which would have to change to allow mill operations to resume, Anfield said, but the facility stands in what historically was one of the most productive U.S. uranium mining regions. 

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MISO Requires Load Shed in New Orleans to Avoid Grid Instability

MISO initiated an hourslong load shedding event in greater New Orleans over Memorial Day weekend with nuclear power outages appearing to play a role.

The RTO said on X that it ordered Entergy and Cleco to drop about 600 MW on the evening of May 25 to “maintain the reliability of the bulk electric system.”

“High temperatures in Louisiana led to higher-than-expected demand, and with planned and unplanned transmission and generation outages, MISO needed to take this action as a very last resort. MISO is coordinating closely with Entergy and Cleco to restore power as quickly as possible,” MISO wrote at the time.

Entergy New Orleans and Entergy Louisiana reported they initiated the rolling blackouts on MISO’s orders around 5 p.m. CT. Entergy said the “last resort” actions were to “prevent a more extensive, prolonged power outage that could severely affect the reliability of the power grid.”

“MISO is directing actions to be taken to restore the system to normal operations as quickly as possible and will direct Entergy to stop these outages as soon as the power shortfall no longer threatens the integrity of the rest of the electrical power system,” Entergy said in a press release at the time. Later that day, the utility issued a second release announcing MISO canceled further periodic load shed. Entergy said it would work with MISO to understand the sudden load shed directive.

Local news outlets reported that more than 100,000 customers around New Orleans were impacted by the controlled outages. Entergy said it restored power around 8 p.m. CT. Entergy and Cleco’s territories in Orleans, Jefferson, St. Tammany, St. Bernard and Plaquemines parishes reportedly were affected.

Cleco also confirmed it instituted rolling outages on MISO’s instructions.

“If the power supply cannot meet the demand, periodic power outages could be needed to protect the stability of the power grid and prevent widespread lengthy outages,” said Jennifer Cahill, director of corporate communications. “This was the case yesterday when we took the unprecedented step, as directed by MISO, to force outages to some customers in St. Tammany Parish.”

In a statement to RTO Insider, MISO again emphasized the temporary, periodic outages were its only remaining option to maintain reliability in MISO South. The grid operator did not disclose additional information on the incident.

“We will conduct a thorough assessment of the event and provide additional information once complete,” MISO spokesperson Brandon Morris said.

MISO’s real-time market notifications don’t list any emergency steps that might have preceded the event.

The outage could be the result of hot weather and nuclear power unexpectedly going offline. Entergy declined to comment on whether the nuclear outages contributed to demand exceeding supply.

MISO pricing the evening of May 25 | MISO

But Louisiana Public Service Commissioner Davante Lewis said Entergy’s 974-MW River Bend Nuclear Station in St. Francisville, La., tripped offline May 25 as Entergy attempted to restore it to service. The unexpected outage reportedly occurred at the same time Entergy’s Waterford nuclear plant in Killona, La., was on a scheduled outage. The Nuclear Regulatory Commission listed both reactors as offline before the holiday weekend.

Meanwhile, temperatures around New Orleans registered at about 90 degrees Fahrenheit.

Lewis told local station WWL-TV that the simultaneous scheduled and unscheduled outages should not have risen to a load shedding event. “That means there’s more to the story — either bad forecasting, bad modeling or higher demand than was projected,” he said.

Fellow Commissioner Eric Skrmetta said the load-shed orders arrived less than three minutes before action was required so utilities didn’t have the option to cut interruptible industrial customers first in an attempt to reduce demand. He said the notification time was “unacceptable” and said upcoming commission meetings would focus on appropriate notification times from RTOs before delivering load shed instructions.

Until now, MISO had directed load shedding just once in the past 17 years, ordering about 700 MW offline in MISO South during Winter Storm Uri in early 2021.

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PJM MRC Briefs: May 21, 2025

Stakeholders Endorse Proposal to Add Transparency to ELCC

VALLEY FORGE, Pa. — The PJM Markets and Reliability Committee endorsed by acclamation a proposal intended to add transparency to the RTO’s effective load-carrying capability (ELCC) process and how the ratings it produces contribute to resources’ capacity accreditation. (See “PJM Presents Proposal to Add Transparency to ELCC,” PJM MRC/MC Briefs: April 23, 2025.)

Providing more information to generation owners about the amount of capacity their units can provide is one of several areas where stakeholders have sought to make changes through the ELCC Senior Task Force. The MRC endorsed a proposal in March to add two resource categories and limit the Capacity Performance deficiency penalty rate for units whose accreditation falls between a Base Residual Auction and Incremental Auction. (See PJM Stakeholders Endorse Proposals to Rework ELCC Accreditation.)

The transparency proposal would create an exception to PJM’s confidentiality requirements to allow market sellers to request data showing the historic performance of the resource through June 2012, even if that extends prior to the owner’s acquisition of the asset. Proponents argued those data are integral to understanding how PJM determines the inputs driving the unit’s ELCC rating.

Before rounds of ELCC analysis are initiated, pre-study stakeholder sessions would be held to review the assumptions and updates to data inputs PJM is considering. Additional sessions would be held once the analysis is complete to discuss the results. PJM also would publish an annual report outlining the assumptions, methodology and results of the ELCC analysis, including any sensitivities.

More sensitivities could be conducted after the analysis, such as developments in the load forecast, weather data or resource performance.

Independent Market Monitor Joe Bowring asked PJM to produce a legal opinion outlining its perspective that it can share confidential information from a prior resource owner to a new owner without permission from the former. PJM legal staff said their client is the RTO, not the Monitor, after which a member also requested more information on PJM’s legal reasoning.

Discussion of CETL Deferred

The MRC voted to delay consideration of an issue charge focused on a “disconnect” between PJM’s winter-skewed risk modeling and the use of summer peaks to calculate capacity emergency transfer limits for locational deliverability areas. (See “LS Power Seeks Issue Charge to Align CETL Calculation with Winter Risk,” PJM PC/TEAC Briefs: Oct. 8, 2024.)

LS Power Director of Project Development Tom Hoatson, who made the motion to defer, said he believes the issue is intertwined with the concept of a seasonal capacity market and suggested the two should be discussed together. He also said the stakeholders and PJM engineers who would lead the work are the same employees engaged with discussions on other areas of the ELCC paradigm, presenting workload challenges.

Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), said the issue charge, which was sponsored by LS Power, was well developed and broached an issue of importance to consumer advocates. He said they could support a delay of a few months, but not longer.

The motion to defer until “stakeholders undertake work on a seasonal capacity construct” was endorsed with the support of all sectors except end-use customers.

Stakeholders Torn on Further SATA Education

Stakeholders held mixed perspectives on whether to recommence work on an issue charge seeking to establish rules for storage acting as a transmission asset (SATA), with some feeling more education is warranted and others arguing it’s time to move on to proposal development.

PJM Director of Stakeholder Affairs Dave Anders said that, after a series of presentations at the Operating Committee in recent months, he believes the education component of the work has run its course and said the issue charge is slated for an endorsement vote at the MRC’s June 18 meeting. He added that approving the issue charge does not mean further education and stakeholder discussion cannot happen.

The committee voted in October 2024 to delay acting on the issue charge until PJM had completed education sessions at the OC, both to allow stakeholders to focus on several capacity market proposals being considered at the time and to bring them up to speed on a SATA proposal last considered in 2021. The OC’s sessions focused on the 2021 proposal, how SATA could impact operations and FERC’s regulatory authority. The issue of developing rules for SATA was brought by PJM in September 2024, nearly four years after members voted to delay further activities on the subject until market rules for storage had been established. (See “Vote on Issue Charge to Establish SATA Rules Deferred,” PJM MRC Briefs: Oct. 30, 2024.)

Constellation Energy’s Juliet Anderson said there are unanswered questions around where SATA would fall into the federal and state jurisdictions over transmission and distribution networks. She noted that the October 2024 deferral delayed action on the issue charge until education at the OC had been completed.

Bowring asked whether PJM believes it’s appropriate to proceed without a more complete understanding of how SATA could impact market operations. Anders responded that market impacts fall under the issue charge’s key work activity 6.

Poulos said most issue charges have a significant educational component, so it’s surprising to him there’s opposition to continuing that work here. He said SATA is a priority for advocates who see it as a valuable tool for resolving reliability issues, and they’re frustrated that barriers are being put up to having the subject discussed further.

Exelon Director of RTO Relations and Strategy Alex Stern said there have been several discussions over the past five years to determine whether storage can act as transmission. In that time FERC has issued policy statements, and other RTOs have developed their own rules, while PJM has been blocked artificially from advancing the discussion by stakeholders using pre-education as a pretext for delay, he said. Whether or not stakeholders want to proceed with establishing a SATA framework, he said, their position should be made clear and communicated to the states, which have been pushing for increased storage deployment.

“I’d just as soon like to know whether this is something we can have in the toolkit or not,” he said.

PPL’s Robin Lafayette said SATA has been discussed at more than 30 meetings and is clearly a tool PJM believes it needs to have available.

“Other ISOs and RTOs have found ways forward on this issue, and I do acknowledge some of the issues raised by some of my colleagues on interactions with the markets,” he said. “PPL strongly supports trying to find a way forward on this issue; even if it is a targeted, limited tool, it could be a valuable one.”

1st Read on Uplift Formula Proposal

PJM Senior Director of Market Settlements Lisa Morelli presented a first read on a proposal to rework how balancing operating reserve (BOR) credits are calculated, including a new metric to determine whether a resource is following dispatch signals. (See “Stakeholders Narrowly Endorse Uplift Changes,” PJM MIC Briefs: April 2, 2025.)

The proposal would replace the three desired megawatt metrics used to determine deviation charges with a new tracking ramp-limited desired (TRLD) metric, which would compare actual output to how a resource should be operating if it had followed dispatch instructions. Morelli said the existing metrics are limited to how dispatch instructions and resource output change over five-minute intervals, which can mask when a resource is deviating from instructions by small amounts over a long period, particularly because there is a 10% margin before a resource is found to be deviating.

The BOR credit formula also would be revised to take the lesser of real-time output or the TRLD, adjusted for a unit’s ramping parameters. The period for which a resource is eligible for uplift also would be realigned to when its commitment began and continue through either the minimum run time parameter or the end of the commitment.

Depending on how a unit operates, the proposal either could lead to increased uplift payments or higher deviation charges, Morelli said, adding that PJM and the Monitor, which jointly sponsored the proposal at the Market Implementation Committee, aimed to take a balanced approach to how uplift would be affected by the proposal, rather than just reducing the amount of uplift paid.

If endorsed, a soft launch would be rolled out at the end of 2025 or early 2026, starting with calculating how the TRLD would affect settlements and communicating that to market sellers through their Market Settlements Reporting System reports. Changes to actual settlements would not come for another year once the full implementation begins.

Gregory Pakela, manager of regulatory affairs for DTE Energy Trading, said the proposal could have significant impacts during periods of high system stress and asked if PJM could conduct backcasts on how it would have changed settlements during the two winter storms in early 2025, when conservative operations were initiated.

Morelli said PJM has conducted limited backcasting, but there’s a balance between the number of staff hours that fully recalculating results would take versus the benefits. She said PJM is comfortable that the proposal is worth moving forward with.

Vistra’s Erik Heinle said the phased implementation process allows market participants to have more understanding of how their resources would fare under the proposed paradigm. Having the opportunity to spend a year understanding how TRLD would determine when a unit is following dispatch and the ability to update the unit’s parameters based on that information is crucial, he said.

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EBA Event Examines History of Electricity Demand Growth as Industry Tackles New Wave

WASHINGTON — The return of rapid load growth still is a relatively new phenomenon for the power industry, but demand has seen such cycles several times before, speakers said at the annual half-day meeting of the Energy Bar Association’s Electricity Steering Committee.

Electricity started off as a niche product, with fully distributed power generators serving mansions and some industrial customers in the late 19th and early 20th centuries, recalled Hannah Wiseman, professor of law at Penn State University.

Appleton, Wis., was home to the first grid in the country, with a hydropower dam serving multiple homes and the lights dimming as water flow slowed.

At first, industry preferred distributed power, and residential customers used electricity only for lights, but that expanded to new products like electric clocks. It was not until World War I that industrial use took off and the grid as we know it started to be patched together, Wiseman said.

“We start to see more centralization, and we start to see more federal involvement, which means we also start to see more public involvement in power,” Wiseman said. “So the War Department in World War I became directly involved in determining where the electricity needed to be generated most.”

The department helped to wring efficiency out of the grid by determining when coal power needed to be dispatched due to hydropower not producing enough to meet demand, she said.

Under the New Deal, electricity service started expanding to more rural areas, such as through the Tennessee Valley Authority. Then World War II and its demands on industry made the backbone transmission system developed in the 1930s a valuable investment. Demand surged during the war as industry built massive fleets of airplanes that needed aluminum, she said.

“Historians say that that previous buildout that was in the 1930s was viewed as an overbuild,” Wiseman said. “Private industry said: ‘Will the rural customers … use this much power? Do we need all this transmission?’ It turned out to be quite important.”

After the war came the golden age of the investor-owned utility, when demand grew by 416% between 1949 and 1969, with residential demand growing even faster at 540%, Harvard Law School’s Ari Peskoe said.

There was a massive housing boom after the war, and the electric industry tried to maximize their individual power demand.

“If you get what was called ‘a total electric home’ at the time, where it’s using electricity for heat, hot water for cooking; that’s a massive increase in the amount of electricity that house is going to consume,” Peskoe said.

From 1970 to 1990, demand grew by 100%. A survey by the Department of Energy in 1979 found homes that only had electricity used three times the amount of power as homes that had another fuel such as gas or oil, Peskoe said. The industry tried to maximize those total electric homes with direct financial incentives and via advertising in the early days of television.

“There’s some great commercials there,” Peskoe said. “You can see Ronald and Nancy Reagan promoting all sorts of electricity use in the home.”

The rapidly growing demand coupled with efficiencies from new, larger power plants meant that adding capacity to the grid lowered costs for everyone, Peskoe said. That led to similarly rapid growth in power demand, which had to be managed either by taking turns building new plants or working together on joint projects.

“Consistent with Section 202(a) of the Federal Power Act, the Federal Power Commission was focused on encouraging utility coordination at the bulk power system,” Peskoe said. “So, for instance, in 1964, it publishes a two-volume national power survey, and the theme of that is basically the benefits of coordinated growth. That is, utilities ought to be interconnecting more. They ought to be trading more. There ought to be more joint planning, even potentially joint dispatch.”

That all should sound familiar to anyone who knows the FPC by its newer name, FERC, and while the commission, states and industry are grappling with demand growth and the need to meet it now, the days of power too cheap to meter are over.

Former FERC Commissioner Philip Moeller, who recently left the Edison Electric Institute, started at the commission in 2006 when the economy was booming, but then the 2008 financial crisis hit. That contributed to low demand growth, but it also led central bankers to cut interest rates to zero in advanced economies.

“We had a period of extraordinary monetary policy where interest rates were basically zero for almost 10 years,” Moeller said. “I mean, that’s an exaggeration, but not too far off.”

In a capital-intensive industry where investments last for decades, the cost of borrowing money is important, Moeller said. Those zero interest rates are a thing of the past. But when it comes to the electric industry, the regulatory framework also is vitally important, said Moody’s Ratings Vice President Jairo Chung. About 50% of the credit risk in Moody’s analyses comes from the regulatory side of things.

“We look at the judicial underpinning of the regulatory framework where the authorities operate,” Chung said. “So, this could be state regulation, but also federal-level regulation, and we also look at the consistency and predictability of the law.”

Other ratings agencies assign utility credit scores to states, but Moody’s instead is more granularly focused on how specific utilities work within their state frameworks because that can vary across firms under the same jurisdiction, she said.

Maryland People’s Counsel David Lapp criticized agencies that rank states because he has found the rankings to be arbitrary, with different agencies scoring his state very differently.

“My primary concern as the customer advocate is regulators overusing or being oversensitive to how a rating agency may categorize the state as a whole,” Lapp said. State rankings can change, with no impact on a utility’s credit rating, which is more important to investors than ratepayers, he said.

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Clean Energy Facing Grim Financial Environment in N.J.

MONTCLAIR, N.J. — The double whammy of federal funding disruption and predictions of a dramatic surge in electricity demand will require state government to implement resource adequacy and financial support policies for new energy sources, speakers at a recent energy conference said.

The loss of federal support as the Trump administration redirects federal efforts toward fossil fuels, coupled with declining interest from private funders, has thrown clean energy financing into turmoil, said Abhay Pande, managing director of Princeton Capital Advisors, at the Clean and Sustainable Energy Summit 2025 on May 14.

Assessing the financial environment now facing clean energy developers, he said, “two words jump out — chaos and unprecedented, maybe unprecedented chaos.”

Historically, projects have been funded by private capital and corporate venture capital, he said. Government funding has supported “early-stage project development around the country, construction and actually building out and scaling,” he said.

“Almost all of these have changed in the last year, and almost none of them for the better,” Pande said. “So for everything that’s going to happen going forward, the solution is going to be the state.”

Investors Looking Elsewhere

The funding problem was one of several challenges addressed in what conference organizers called “A Resilient Future” in the face of expected demand from EVs, data centers and other energy uses. (See N.J.’s Power Future Clouded by Data Center Uncertainty.)

The conference came a few days before the House of Representatives on May 22 approved the Trump administration’s budget bill, which would repeal or phase out many clean energy tax credits. The budget now will be considered by the Senate. (See House Passes Reconciliation Package that Would End Energy Tax Credits.)

The Inflation Reduction Act’s investment tax credits and production tax credits, which are a target for reduction in the budget talks, have played a significant role in keeping down energy production costs, Pande said. The credits have helped reduce solar costs “potentially on a per megawatt hour basis by 50%, reducing wind by 30%, even reducing nuclear by about 20%,” he said. Nuclear power, however, got a big boost from Trump on May 23. (See Trump Orders Nuclear Regulatory Acceleration, Streamlining.)

The elimination or reductions under discussion for other sources could have a “huge impact in the resource adequacy, as far as money goes in, in terms of investments,” Pande said.

Staff cuts at the Department of Energy also likely will hamper project development, he said. That has included downsizing at the federal Loan Programs Office, which provided funding for clean energy projects under President Joe Biden.

Meanwhile, private sector funders have their own challenges, he said.

“The private equity community continues to have a ton of money that they raised from pension funds and endowments and sovereign wealth funds over the last five years,” Pande said. “But they’re having a hard time finding a way to make attractive returns — the 15-ish percent that they need per year.”

In the search for attractive investments, “there’s some re-shifting of private equity and investing, which over the last 10 years has overwhelmingly shifted to renewable, and is now in transition back to fossil fuels,” he said. Some investors have left energy altogether to invest in artificial intelligence and biotechnology, he said.

“We’re certainly facing headwinds,” Pande said. “But it creates an important role for states and state governments to fill some of the gaps that at least allow early-stage developers and new technology [to start projects], at which point the private sector will jump in.”

Headwinds, but Sustained Interest

There are some bright spots outside the United States. “The global commitment towards investing in energy transition really hasn’t changed,” Pande said. “The sovereign wealth funds in the Middle East and Asia and Europe are as committed, possibly even more, to investing in renewable energy than they ever were.”

There is a “lot of appetite” in Middle Eastern sovereign and European sovereign wealth funds to invest in the U.S. energy transition, Pande said. And there still is interest from some U.S.-based investors as well, he said.

“The interest in ensuring long-term sustainable investing continues,” he said. “People talk about it less, because there was some backlash from a number of state pensions and so forth in the past. But in talking to — certainly the U.S., major endowments and pension funds — that commitment hasn’t changed at all. They just don’t mention it as much because they don’t want to pick a fight with anybody right now.”

Studying Resource Adequacy

Coinciding with the conference, New Jersey Gov. Phil Murphy (D) took steps to address the pending 20% increase in electricity for the average ratepayer set to begin June 1.

The hike stemmed from the New Jersey Basic Generation Service auction in February, which state officials say was in turn shaped by the PJM capacity auction in July 2024. The auction concluded with prices — $270/MW-day — about nine times higher than the previous auction.

PJM officials say the rising prices are due to the unforeseeable spike in demand and state policies that are shutting down old, mostly fossil-fuel sources of energy at a faster rate than replacement sources — mostly clean energy — are coming online.

Murphy directed the New Jersey Board of Public Utilities (BPU) to “open a new proceeding on resource adequacy” that would evaluate proposals to bring more generation online quickly. He directed the agency to “continue to determine how New Jersey can best achieve its reliability, equity and clean energy objectives while keeping costs to consumers as low as possible.”

The proceeding also will look at “whether New Jersey is best served [by] the regional capacity market administered by PJM” and directs the BPU to “identify policy opportunities to mitigate increased ratepayer costs due to demand growth driven by data center proliferation.”

Preethy Thangaraj, deputy director of Murphy’s Office of Climate Action and the Green Economy, said at the conference that the governor’s directive is his response to the state facing steep load growth.

“We have volatile energy markets. Things are very complex, and how we deal with resource adequacy is also evolving,” she said. “The state has been very focused on ensuring that we really leverage every tool in the toolbox to make sure we are responding to the market conditions.”

That will include the state having an “important role to play in funding the incremental cost between what we consider to be the status quo, traditional technologies to new technologies,” she said.

Changing Demand Patterns

Creating more generation will require a range of solutions, said Larry Barth, director of corporate strategy at New Jersey Resources, which operates solar and gas generation facilities.

“There are tradeoffs in every one of these generation resources. Solar is great for decarbonization, but it’s not necessarily great for resource adequacy,” he said. “Gas is something you can fire up at a moment’s notice, but it’s not necessarily going to help us with emissions.”

A further complication is that demand peaks are changing, said Jason Lemme, managing director at Hartree Partners, an energy and commodity trading company. PJM now sees its highest peaks in the winter, with a recent, near-record peak in the early morning of Jan. 20, he said. That is different from past peaks, which occurred in the summer in early evenings, driven by demand for air conditioning use, he said.

Summer peaks, occurring when the sun is out, can be met with solar generation. But a recent 7 a.m. winter peak occurred in the dark, when solar was inactive, he said.

The state also should consider greater use of excess capacity in its gas-fueled generators, he said. Due in large part to the impact of emissions restrictions under the Regional Greenhouse Gas Initiative, these plants are much more efficient than those in Pennsylvania, Ohio and elsewhere, using less gas to produce the same amount of electricity.

“Why don’t we increase the utilization of assets that we already have in the state that are incredibly efficient to begin with?” Lemme asked. “And that, I think, goes a long way to solving part of the problem that we have, at least in the state in the near term.”

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NYISO Outlines Storage as Transmission Proposal

NYISO on May 20 presented an outline of how it plans to implement storage-as-transmission assets (SATAs), drawing critiques from stakeholders representing end-use customers and generators.

The ISO has been working on storage as transmission since 2023. It would allow energy storage systems to act as regulated transmission, making them eligible for cost-of-service rate recovery and to be considered as solutions for transmission needs in the ISO’s planning processes. This would mean that SATAs would not be dispatched via the wholesale market beyond what would be necessary for them to remain ready to withdraw or inject into the grid.

Katherine Zoellmer, a market design specialist for NYISO, explained to the Installed Capacity Working Group that SATAs would only be considered as transmission solutions for needs arising from N-1-1 contingency events. The ISO would dispatch all SATAs for direct charging and discharging manually. Zoellmer said NYISO wants to limit SATAs to 20 MW per substation and to 200 MW across the New York grid. The ISO wants these rules in place to reduce the impact of SATAs on the wholesale market, she said.

That prompted questions from stakeholders. Kevin Lang, representing New York City, said it seemed strange to focus on market impacts when anything, including adding generation, has a market impact.

“I understand your concern about the impacts on the market, but are you looking at the benefits of storage as transmission? That it could be a lower-cost option for consumers?” Lang asked. “It just seems like you’re focused on one small piece.”

Zoellmer responded that the ISO was committed to evaluating SATAs “consistent with other transmission solutions.”

Other stakeholders said the N-1-1 contingency was restrictive in terms of which problems SATAs could solve. Another stakeholder said it seemed like restricting SATAs from market-based compensation might discourage investment by developers in other market-based storage in the same area.

When the discussion turned to megawatt limits, Lang voiced his disappointment.

“These are ridiculously low numbers for a storage resource that could take the place of a multibillion-dollar transmission line,” Lang said. “It’s really troubling here that your focus is, again, not on the benefits, but how we need to avoid impact.”

Multiple Intervenors — an association of large industrial, commercial and institutional energy consumers — asked whether the ISO could share the reasoning behind its approach. Zoellmer said the ISO would “take that back” for consideration.

In a post-meeting interview, Zoellmer clarified that the megawatt limits on SATAs were intended to make it easier for operators to manage their dispatch. When asked if there was a software solution to dispatch, Zoellmer explained that programming software to restrict SATA resources so they aren’t being dispatched constantly was a challenge, which is why manual operation was being considered only for now.

Winter Reliability Capacity Enhancements

Michael Swider, senior market and technologies strategist for NYISO, presented questions the ISO was considering as it moved forward with the Winter Reliability Capacity Enhancements project, its effort to make the capacity market reflect the shift of New York’s peak demand from summer to winter.

NYISO is evaluating whether the methods for determining the seasonal ICAP demand curves and reference points for capacity prices are working. Beginning with the 2025/26 capability year, the ISO is using reference points adjusted by the relative risk in each season.

Swider cited the “winter-to-summer ratio,” defined as the average amount of available capacity in winter relative to summer over a historical three-year period. As the resource mix changes, the ratio may no longer represent which resources are available. The ISO and the New York State Reliability Council have brought this up in other contexts, specifically the winter gas constraints white paper. (See Winter Fuel Constraints Concerning for NYISO.)

Swider also discussed adjusting the “zero crossing point” of the demand curve to retain price stability and a stakeholder proposal to amplify price signals in the capacity market during peak months.

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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.