Search
December 17, 2025

Posted on

BPA Predicts Energy Deficits Over Next 10 Years

The Bonneville Power Administration predicts even steeper energy deficits among its network of dams under firm conditions compared to predictions last year, according to the agency’s annual “White Book” study. 

BPA’s Pacific Northwest Loads and Resources Study, or the White Book, was issued May 29. It covers a 10-year period and provides predictions for the federal power marketer’s loads and resources, as well as the entire region’s retail loads, power supply obligations and resources. 

The 2025 White Book finds that under firm conditions, the federal system would have annual energy deficits between 2026 and 2035, ranging from deficits of 426 aMW to a high of 1,012 aMW.  

“Overall, these annual energy deficit projections are more than those projected in the 2024 White Book,” according to the study. In 2024, the White Book projected deficits ranging from 79 aMW to 303 aMW. 

The 2025 study also found that under median water conditions, the federal system could have a surplus ranging from 911 aMW and 364 aMW. The Northwest relies heavily on hydropower generation, which is notoriously difficult to predict and can fluctuate dramatically from year to year. 

“The federal system surplus/deficit forecasts generally have a positive relationship with water conditions,” the report stated. “Better water conditions generally yield more surplus overall. For example, the annual energy surplus can increase by over 4,000 aMW under better water conditions, while monthly surplus or deficit position can vary by over 5,500 aMW within the same year.” 

Meanwhile, the entire Pacific Northwest could have an energy surplus of 960 aMW in 2026 under firm water conditions, but this could drop rapidly to a deficit of 3,026 aMW by 2034. Under median water conditions, however, the region could have surpluses until 2032, according to the report. 

“This result was mainly driven by the increasing retail loads,” the report stated. “Overall, the annual energy surplus/deficit position projections are more surplus than forecasts from the 2024 White Book until the out years of the study period. Under median water conditions, the PNW region would begin to see energy deficits in the out years.” 

BPA’s White Book follows the Northwest Power and Conservation Council’s (NWPCC) initial 20-year forecast released in April. (See NWPCC’s Initial Demand Forecast Sees Sharp Growth for NW.) 

Energy consumption in the region has hovered around 20,000 to 22,000 aMW since 2010, according to NWPCC. But energy demand could skyrocket and reach between 31,000 and 44,000 aMW by 2046, with the largest growth expected from electric vehicles and data centers, NWPCC found. 

BPA noted in the White Book that: “Many factors contribute to the uncertainty of the longer-term resources outlook for the region, such as resource retirements and development, resource adequacy and the efforts surrounding it, and other federal and state policy mandates. As with resources, there is also much uncertainty with loads including the potential for electrification and data centers coming online.” 

“While regional analysis shows surpluses in the first two years of the 10-year study period with rapidly rising deficits in certain parts of the years following that period, BPA analysis shows periodic deficits for the entire study period,” BPA spokesperson Doug Johnson told RTO Insider. “Rapidly growing load forecasts and subtle changes in water volume and runoff over the period account for the growing deficits.”

Johnson pointed out that forecast certainty declines “the deeper you get into the 10-year period.”

“However, it looks like at some point during the study period BPA will likely need to secure the output of additional resources to meet its firm power obligations,” he said.

Posted on

N.J. BPU Backs New Grid Modernization Rules

Facing a dramatic electricity rate hike driven in part by a shortage of generation sources, the New Jersey Board of Public Utilities has approved new grid modernization rules that the agency says will make the process of launching new distributed sources easier and faster.

The board voted 4-0 on May 21 for rule changes the agency said will streamline the process by which distribution grid interconnection applications are handled. Among the changes are the enactment of more frequent updates to hosting capacity maps and a revised dispute resolution process, according to a statement from the board.

The new rules also include a “pre-application and verification process to provide applicants with an early indication of project feasibility and costs, and a requirement for utilities to have a web portal for a more consistent interconnection application process regardless of service territory,” the board said.

The approval came as state ratepayers on June 1 will see a 20% increase in the average electricity bill, which has stoked anger among lawmakers, ratepayer advocates and BPU officials. The increase, based on the prices in the state Basic Generation Service auction held in February, was affected by the dramatic price rise in the PJM capacity auction held in July 2024.

PJM officials say the increase stems in part from old fossil fuel power sources shutting down at a faster pace than new generation sources, mainly clean energy, are coming online. Both New Jersey and PJM forecast a major increase in electricity demand due to the proliferation of data centers, greater electric vehicle use, building electrification and other factors.

Controlling Energy Costs

While the BPU has planned its grid modernization process for three years, the release comes as the agency looks for ways to get new sources online more quickly. (See NJ Regulators Seek ‘Proactive’ Grid Upgrade Plans from Utilities and New Jersey Opts to Explore Nuclear Options.)

BPU President Christine Guhl-Sadovy said the new rules mark a “pivotal step toward … making the interconnection process more efficient,”

“Increasing the number of distributed energy resources, including new solar projects, as quickly as possible is a key component of our comprehensive effort to drive down energy costs for ratepayers, and we are delivering on that effort,” she said in a statement.

The BPU says the rules will make it easier to get solar and storage facilities online, which the agency said in a statement are “some of the cheapest and fastest resources to come online” and will “reduce the peak energy forecasts for New Jersey.”

Doing so “decreases the amount of capacity New Jersey needs to buy, which in turn puts downward pressure on capacity prices for all ratepayers, helping save money via avoided costs,” the agency statement said. New Jersey is an importer of electricity because it does not generate enough in-state.

The BPU is working on finalizing a straw proposal for a program that would offer incentives to stimulate the development of storage projects. (See NJ BPU Updates Proposal for Storage Incentives.)

Posted on

CAISO Battery Storage Initiative Focuses on Outage Management, Nonlinearity

CAISO is moving ahead with a key initiative to resolve how battery storage resources function on the grid as the battery boom continues in the Golden State.

The ISO is prioritizing battery outage management enhancements, battery nonlinearity guidance and state of charge (SOC) clarifications in its storage design and modeling initiative that began earlier this year.

CAISO held a stakeholder meeting May 28 to address technical challenges associated with the increase in battery storage capacity on its grid, which has grown from 500 MW in 2020 to more than 11,000 MW in 2025.

CAISO’s current outage management system has served conventional resources effectively but does not easily convey a battery’s SOC limitations, CAISO said in an issue paper. Storage resources face limitations and outage types not covered in the outage management system that are unique to storage resources, such as negative minimum energy outputs.

There is a lack of clarity around how battery resources can accurately represent their availability to CAISO using the existing outage management system, CalCCA said in comments to CAISO. Another stakeholder in the initiative, Vistra, asked CAISO to clarify reporting thresholds for a battery’s SOC, specifically recommending the ISO add reporting requirements for changes that exceed 10 MW or 40 MWh, or 5% of registered values lasting 15 minutes or longer and within 60 minutes of discovery.

CAISO agreed with stakeholders about the need to align its outage management system with storage-specific outage types and characteristics. To do so, the ISO is considering implementing an outage card that can adjust a battery’s availability, maximum load, maximum energy and minimum energy values on one card.

Nonlinearity Options

Another key concern addressed by the initiative is battery storage nonlinearity, meaning the concept that batteries charge and discharge energy at a nonlinear rate. Nonlinearity complicates the modeling and control of battery storage resources, which in turn reduces a battery’s responsiveness and dispatch capability, CAISO said in the issue paper. Nonlinearity is comparable to gas generators that may take time to ramp up to reach their maximum dispatch, CAISO said at the meeting.

As a battery approaches its SOC limits, its maximum and minimum energy output are “greatly affected, potentially hindering its ability to respond to grid demands,” CAISO said. For example, a 100-MW battery storage facility might be able to charge or discharge only 50 MW at the extremes of its SOC.

“Nonlinearity is the area we got the most diverse comments,” said Sergio Dueñas, CAISO storage sector manager, at the working group meeting. “Everyone is getting more and more comfortable with the idea of, ‘Let’s pursue a [solution] in the near term and then move to a more doable solution in the long term.’”

CAISO is considering four ideas to account for nonlinearity, one of which is to use outage cards that indicate the effects of nonlinearity on ramp rates and maximum energy outputs. Currently, some market participants might be communicating the impacts of nonlinearity through outage cards that do not include all of these characteristics, since nonlinearity is not explicitly called out in the outage management system, CAISO said.

As a near-term solution, CAISO favors participants including a comment noting that an outage is related to nonlinearity. This near-term guidance will allow for resources shown as resource adequacy (RA) resources to be evaluated in the context of the RA availability incentive mechanism (RAAIM), the ISO said. The RAAIM provides incentives or disincentives for resources to help ensure they’re available for CAISO to meet reliability needs. If a battery resource is shown as RA and evaluated as RAAIM, then the battery would be accounted for according to its actual dispatch availability under instances of nonlinearity, CAISO said.

CAISO plans to publish a revised issue paper and hold another stakeholder meeting June 30.

Posted on

FERC OKs MISO Generation Replacements Connecting at Different Points than Predecessors

FERC has approved MISO’s new generation replacement provision that allows replacements to reconnect at more preferred points on the grid over clean energy groups’ concern that it plays favorites.

The commission said replacement generation in MISO should be able to link up at different points of interconnection (ER25-1802). MISO proposed that it would allow the interconnection point substitutions when they’re “electrically equivalent to the original point of interconnection” and when they don’t cause material adverse impact to MISO’s transmission system.

Clean energy groups, including American Clean Power Association, the Solar Energy Industries Association, Advanced Energy United and Clean Grid Alliance, had argued MISO’s proposal should be rejected because it’s unfair to other planned generating facilities. The groups said the plan would discriminate between similarly situated projects.

However, a group of utilities, including Alliant, Lansing Board of Water and Light, Consumers Energy, DTE, ITC, Michigan Public Power Agency, MidAmerican Energy, Muscatine Power and Water, Wolverine Power Supply Cooperative and WPPI Energy, said the proposal would allow replacement generation to connect at more favorable interconnection points that have similar impacts on the grid.

FERC decided the plan would allow “more cost-effective and timely replacement of existing generating facilities, which will help address regional resource adequacy needs and allow interconnection customers to avoid investing in redundant infrastructure.” The commission further said the replacement facilities would dodge duplicative contracts, deeds and site control costs that might come with both a new site for a replacement facility and “a path to connect that site to the original point of interconnection.”

The commission said it agreed with the Organization of MISO States that MISO’s plan would remain in keeping with MISO’s current methods for discovering and minimizing adverse impacts on the transmission system. FERC said it would pair “offering increased flexibility to interconnect new generation resources in a more efficient manner” with “supporting state resource planning and ratepayer affordability.”

FERC said the new prerequisites MISO placed on moving an interconnection point in addition to its usual replacement study process — interconnecting at the same voltage level, not introducing new constraints and not forcing a distribution factor change of more than 5% — “will ensure that an alternate point of interconnection is electrically equivalent to the existing point of interconnection.”

The commission disagreed with arguments that by allowing replacement facilities to move their points of interconnection, MISO was creating a process that more closely resembled a new interconnection request with the added bonus of skipping the queue.

“We do not believe that providing this limited flexibility to replacement generating facilities to interconnect at a different, but electrically equivalent, point of interconnection results in an unduly discriminatory interconnection process,” FERC wrote in the May 27 order.

FERC said MISO’s commitment to preventing a replacement generator from adversely affecting the grid should take care of clean energy groups’ concern that permission to move a point of interconnection would drive up network upgrade costs by replacements claiming spots on the grid that other interconnection customers had “reasonably expected” to use.

MISO has said its generator replacement process has been instrumental in limiting the impacts of power plant retirements. Since it began the process in 2019, MISO said it has accepted about 5.9 GW in replacement requests and is studying 4.9 GW of replacement requests.

The RTO expects 25 GW of coal retirements through 2030, up 5% from its 2024 forecast. In the same time frame, MISO’s membership plans to add about 10 GW of solar generation and significantly more gas generation.

Posted on

More Green Projects Halted amid Policy Changes

Clean energy and transportation project cancellations continue as 2025 rolls on, with analysis of public announcements showing investments of $4.5 billion abandoned in April alone.

Business advocacy group E2 on May 29 blamed uncertainties about finances and policy under the new Republican leadership in Washington. It tallied the impact so far this year at $14 billion in investments and 10,000 potential new jobs.

The two manufacturing and two generation projects that E2 counted as canceled in April far eclipsed the seven newly announced manufacturing projects announced in April, which carried a combined investment of only about $500 million. But the disparity was not as wide as it seems: The largest announcement — by the electric vehicle startup Slate — did not carry a price tag.

E2 Communications Director Michael Timberlake said in the news release that pending policy changes may add to the reductions.

“Now is not the time to raise taxes on clean energy and compound the business uncertainty that is clearly taking a greater and greater toll on U.S. manufacturing and jobs,” he said. “If the tax plan passed by the House last week becomes law, expect to see construction and investments stopping in states across the country as more projects and jobs are canceled.”

E2 and the Clean Economy Tracker have been following public announcements of job-creating green projects since passage of the Inflation Reduction Act in August 2022. They have tallied 390 major proposals across 42 states and Puerto Rico that carry planned investment of $132 billion and the hiring of 123,000 permanent workers.

From January 2023 through April 2025, 45 projects have been canceled, closed or downsized, accounting for commitments of $16.7 billion in investments and nearly 20,000 jobs.

Twenty-seven of the 45 announcements came after the election in November 2024 of President Donald Trump, who had pledged a strong reversal of President Joe Biden’s support for clean energy and clean transportation. The Trump administration’s rapid-fire policy changes have complicated efforts, and the current version of the budget bill would provide further costs and hindrance.

E2 noted the irony contained within the geography for the proposed and canceled investments: More than 61% of all clean energy/transportation announcements have been in Republican congressional districts, and they account for 72% of planned job creation and 82% of planned spending. More than $12 billion of the $16.7 billion in canceled investments were to have been made in Republican districts.

Posted on

FERC Declines MISO Queue Cap Rehearing Requests

FERC is resolute in its support of MISO’s annual megawatt cap in its generator interconnection queue.

The commission rejected rehearing requests that framed the queue cap as discriminatory, preferential and riding roughshod over state authority (ER25-507).

FERC in late January gave MISO the go-ahead to impose an annual megawatt cap on the generation applications it accepts in its interconnection queue. The cap limits megawatt values of queue cycles to 50% of MISO’s non-coincident peak among its five study regions. (See FERC Approves Annual Megawatt Cap for MISO Interconnection Queue.)

Two study regions — East and Central — already have exceeded their megawatt caps for the 2025 cycle. Across all regions, MISO has a 77.82-GW cap for the 2025 cycle. As of mid-May, it has fielded 50.13 GW across 176 submissions.

MISO South regulators in early March asked FERC to reconsider its approval of MISO’s queue cap. Led by the Mississippi Public Service Commission, regulators argued the cap needs an exemption for state-designated necessary resources. They asked FERC to backtrack and either reject MISO’s plan or condition it on MISO including an exemption for the states, saying the MISO plan tested the very limits of cooperative federalism.

In its May 27 order, FERC decided it didn’t transcend its statutory authority and infringe on state jurisdiction by allowing the queue cap, even though the cap will have “incidental effects” on state jurisdiction. It said the Supreme Court already decided those inadvertent encroachments are of no legal consequence. FERC also said that despite Southern regulators’ prerogatives, the commission is allowed to consider “resource adequacy concerns in exercising its jurisdiction.”

FERC also said it judged the queue cap plan as fair and reasonable without the state exception and would not order MISO to include one.

Clean energy groups also argued against FERC’s acceptance of the cap. They said FERC should reconsider because MISO didn’t have a strong rationale for the cap and said the cap itself will introduce undue discrimination and preference among developers vying for a spot on the MISO grid.

FERC disagreed with the groups, who said that in accepting the cap, the commission abandoned standardized generator interconnection processes established under FERC Order 2003. FERC said the clean energy groups should have raised the argument sooner in proceedings but said “in any event,” the queue cap followed Order 2003’s “recognition of independent entity variations for RTOs/ISOs.”

FERC also said it found nothing amiss with MISO’s first-come, first served aspect of the cap to determine cutoff points. The commission disagreed with the groups that argued prioritization could create an unfair environment by incentivizing projects to line up for exploratory or speculative positions. Instead, MISO ultimately would study submitted interconnection requests as part of a cluster. FERC said projects that entered too late to beat the cap simply would be subjected to a later cluster of projects.

Posted on

MISO: New Orleans Area Outages Owed to Scant Gen, Congestion, Heat

MISO has shed light on the reasons behind the Memorial Day weekend load-shed event in southeast Louisiana, describing a system taxed by early summer heat and rife with congestion and unavailable generation.

Executive Director of Market Operations JT Smith said there were “a number of” planned and unplanned generation outages coupled with higher-than-normal temperatures that paved the way for challenges headed into the weekend.

“We approached some pretty warm days for the season down there,” Smith said during a Reliability Subcommittee meeting May 29. He added that evening peaks with “early summer heat” can be a hazardous time.

MISO ordered an approximately three-hour, 600-MW load-shedding event in Greater New Orleans the evening of Sunday, May 25 to avoid bigger reliability issues. (See MISO Requires Load Shed in New Orleans to Avoid Grid Instability.)

During the first hour of the load-shed event, electricity prices were in the negative — as low as ‑$400/MWh around the Mississippi Delta — while prices in southern Louisiana soared past $2,000/MWh. Electricity appeared undeliverable into the greater New Orleans area because of a lack of transmission.

Smith said MISO operators began noticing congestion problems on Wednesday, May 21. By the weekend, operators were “battling congestion all over the place” in Louisiana, Smith said. He said MISO was keenly aware that it was “important for the transmission system to hold up” with reduced generation and warm weather.

Generation was available outside Louisiana, “but you could just not get it in” because of the congestion on May 25, Smith said. Smith said MISO’s pricing map showed “a lot of red” in southeast Louisiana and “a lot of blue and purple sitting out” north, indicating high prices butting up against negative-cost, trapped generation supply.

Smith said there were a lot of “infrastructure availability” issues May 25. He said operators contended with unusual flow patterns and “import limits not usually seen.”

Leading up to the event, MISO was identifying post-contingent positions on transmission lines. Smith said the RTO conducted several on-the-spot analyses to see if any potential congestion problems could rise from localized system operating limit issues to the more serious and widespread interconnection reliability operating limit (IROL) issues.

Smith said that “unfortunately on the 25th,” MISO identified a constraint north of Lake Pontchartrain that presented as 125% over its limit.

“It was identified to have cascading potential, putting at least 1,000 MW of load at risk,” said Smith, calling it a “very significant” issue that necessitated MISO’s call for Entergy and Cleco Power to shed load.

Members of the Louisiana Public Service Commission and the New Orleans City Council have expressed concern over the short notice on the power deficit and have vowed to get answers. Smith said that unfortunately when an IROL is identified, MISO has precious little time to correct it. Nevertheless, he said the RTO would review its communication protocols and see if it can improve notification time. It will have more information to share at its Board Week meetings in June, he said.

“We’ll be looking to improve that posture overall,” Smith said. “Since then, it has been a whirlwind of data collection. It’s an unfortunate situation, but one that can come up from time to time.”

Reliability Subcommittee Chair Ray McCausland, of Ameren, told stakeholders that information still is scarce because the meeting was a mere four days after the event and “there’s a lot to discover.” From his experience in control rooms, he said he was surprised that MISO wasn’t forced to “sacrifice” more megawatts given the situation.

Michigan Public Power Agency’s Tom Weeks asked if an earlier order of conservative operations may have helped the situation.

Smith said MISO had very few options in the moment, and a conservative operations declaration would not have returned enough equipment to service to make a difference.

Entergy: Nuclear Gen Offline Days Before Event

Meanwhile, Entergy has challenged Louisiana regulators’ narrative that its two offline nuclear plants played a major role in the blackouts.

In a statement to RTO Insider, Entergy said its own models did not indicate load-shed conditions, but “MISO uses a different model and has a broader view of system conditions, which MISO is able to see due to its status as the regional transmission coordinator.”

“Entergy had been monitoring load conditions due to warmer-than-typical weather, but as noted, its models did not show the need for load shed,” Entergy spokesperson Brandon Scardigli said in a statement.

Entergy also said the implication that the nearby, offline River Bend nuclear plant exacerbated circumstances might not stand up to scrutiny.

“While the River Bend generating unit was offline during the event, it had been out for several days before the event, and its outage was accounted for in the generation that Entergy Louisiana and Entergy New Orleans made available to MISO and in MISO’s own modeling,” Scardigli said.

River Bend reportedly shut down unexpectedly on May 21 because of a leak in its cooling system. The Union of Concerned Scientists released a May 27 report in which it singled out River Bend for being one of the most problematic nuclear plants in the U.S. in terms of regulatory violations.

Entergy added that its refueling outage at the nearby Waterford 3 plant was within the norm, as it routinely plans maintenance in the spring and fall. Entergy said the outage was scheduled months in advance.

“The timing of the planned outage was to ensure that this important unit is up and running during the summer months when customer usage is high,” Scardigli said.

Episode Spurs Calls for MISO South Tx Planning

The rolling blackouts have revived debate around MISO South’s lack of regional transmission projects and webwork of load pockets.

The Louisiana-based Alliance for Affordable Energy circulated a one-pager after the load-shed event that said the longer MISO South waits on transmission planning, “the longer consumers remain vulnerable to load-shed events.” It said the RTO needs expanded transmission capacity between its Midwest and South regions to alleviate the South’s load pockets.

“Corporations like Entergy have long fought efforts to do this because it could negatively affect their bottom line by forcing them to compete with other electricity producers, and the [Louisiana PSC] and New Orleans City Council have often had their backs in doing so. It’s time we put the people of Louisiana and New Orleans first — increasing transmission means we will be better protected from grid failures and will also help to bring down costs,” the group wrote.

However, Southern Renewable Energy Association Transmission Director Andy Kowalczyk cast doubt on the notion that more Midwest-South transmission could have helped the load pocket in this situation. He pointed out at the subcommittee meeting there was plenty of available generation below MISO Midwest that could not reach Louisiana.

The alliance also said earlier investments in locally available renewable energy and battery storage could have offset the need to shed load.

Finally, the organization said the Louisiana PSC and New Orleans City Council should demand information from Entergy and Cleco. It faulted the PSC for dismantling a statewide energy efficiency program weeks before that could have dampened demand. (See Louisiana PSC Scraps Statewide Energy Efficiency Program.) The PSC has reverted to utility-led programs for energy efficiency.

Posted on

Amended ‘Pathways’ Bill Boosts — and Complicates — Calif. Protections

The latest version of California’s “Pathways” bill strips out a previous amendment that would have given state regulators authority to order utilities to withdraw from the West-Wide Governance Pathways Initiative’s “regional organization” (RO) under certain circumstances.

But that doesn’t mean the bill has been slimmed down. Just the opposite, in fact.

Instead, a newer iteration of the bill replaced that provision with a lengthier one prescribing a more complicated process for undertaking the same action, while adding a slew of other conditions intended to protect California’s policies and ratepayers.

“In short, this new provision reflects the delicate negotiation between California and the rest of the West as they figure out how to marry their energy systems,” Lincoln Davies — professor of law and executive director of energy, resource and environment programs at the University of Utah’s S.J. Quinney College of Law — told RTO Insider in an email.

“This should be expected, and this bill is still a strong step in the right direction. It would ensure RO independence but give California assurance it can exercise its sovereign power to protect its citizens,” Davies said.

Senate Bill 540 emerged from the Senate’s Appropriations Committee on May 23 in a 4-1 vote recommending that the full house pass the legislation as amended, but the exact content of the amended bill remained a mystery until the Legislature printed and posted it May 28. (See California’s ‘Pathways’ Bill Heading to Senate Floor.)

The newest version removes language the Senate Judiciary Committee added in April to address the concerns of constituents and lawmakers who fear that CAISO’s membership in the proposed independent RO could provide a backdoor for the Trump administration to compromise California’s ambitious environmental and clean energy policies. (See California Lawmakers Seek to Trump-proof Pathways Initiative Bill.)

To prevent that outcome, the Judiciary Committee inserted an amendment stipulating that the California Public Utilities Commission could direct its jurisdictional utilities to withdraw from the RO if the new entity’s rules were to become “detrimental to California consumers.”

The amendment also mandated withdrawal if the state’s renewable portfolio standard is “held invalid by [a] reviewing court on claims of impermissible discrimination” or if the Trump administration — or future administrations — invoke emergency powers that require California to subsidize fossil fuel generation.

That amendment has been deleted, only to be replaced by a more complex one that outlines the creation of a new Regional Energy Market Oversight Council designed to ensure “that participation in a regional energy market serves the interests of the state.”

The council would consist of the CPUC president; the chair of the California Energy Commission; the chairs of the Senate Committee on Energy, Utilities and Communications and Assembly Committee on Utilities and Energy; and the state’s attorney general, with the AG serving as chair.

It would be charged with approving “initial participation” in the RO by California’s “electrical corporations” and load-serving entities and, “at any point” after that approval, determining whether those entities “should be required to withdraw from an energy market governed by the independent regional organization” after convening a public meeting on the matter.

In its capacity for making RO withdrawal decisions, the council also would be responsible for reviewing the RO tariff both before and after FERC approval, as well as for monitoring any “subsequent actions” related to the market that might:

    • weaken or invalidate California’s RPS;
    • require the state, CAISO or any LSE to procure or subsidize fossil fuel generation located outside California; or
    • result in “adverse impacts on California’s resource planning, procurement, environmental, reliability or other applicable public interest policies.”

The amendment also makes the council respsonsible for protecting ratepayers by authorizing the new body to order utilities to withdraw from the RO if the organization or the federal government take measures that cause the cost of California’s regional market participation to exceed benefits over a two-year period.

The council also could order withdrawal if the RO fails to fully compensate California ratepayers for CAISO’s costs to provide the RO with “any services, facilities, equipment and property, including intellectual property,” or if the RO doesn’t hold both ratepayers and the ISO “harmless” for legal claims arising from the operation of the regional market.

The new amendment further prohibits CAISO from modifying its own tariff in relation to the RO without the council’s approval.

Getting Hitched

Sources familiar with the California legislative process have told RTO Insider that the Appropriations Committee’s process of adding amendments to bills is something of a black box — and that appears to be the case for SB 540.

One source close to the SB 540 effort said it was unclear exactly which lawmakers added the amendments, or why. The office of the bill’s sponsor, Sen. Josh Becker, had not responded to questions as of press time.

But Davies said he thinks the new provision seeks to achieve three objectives.

“First, it creates a checkpoint for California electricity providers for entry or exit into these new markets. Under the prior version of the bill, this was left mostly to self-execution, with an express reservation of PUC authority to order withdrawal. Now, companies need to ask ‘mother, may I?’ to get in or out of the markets,” he said.

“Second, it spreads authority across multiple entities rather than concentrating it in the CPUC. The prior withdrawal provision left sole authority to the CPUC to act. Now, the council would have representatives from multiple agencies, both chambers of the Legislature and the attorney general.”

The third objective could be the most fundamental, according to Davies, because it aims to allow California to maintain control over its policies while still providing for independent governance of CAISO’s markets.

“This is understandable, particularly given how federal energy policy is developing right now, including the White House specifically naming California energy policy as a target for federal action in executive orders,” he said.

Davies noted that “any bill that erodes the independence of the new RO is certain to crater a broader Western market,” and that the widest possible market is in the interest of all participants, including California.

“At some point, of course, everyone will need to end the courtship and just decide to get hitched or not,” he said. “This bill should make that possible — to the benefit of California, the climate and the broader West. Anything that moves more control to California likely will not.”

Posted on

WECC Report Highlights Larger Loads, Longer Emergencies

Peak demand in the Western Interconnection hit a record high of 168.2 GW in 2024, reflecting “early effects” of the growth in large loads such as data centers, according to a new WECC report.

Peak demand in the interconnection has grown 8.5% since 2015, when it was 155 GW. The 2024 peak demand, reached on July 10, was the fifth time in the past 10 years that a new record has been set.

Annual demand also set a new record in 2024 of 926,000 GWh.

“Demand growth is higher today than at any other time in the last 20 years,” WECC said in its 2025 State of the Interconnection report, released May 22.

Large-load challenges have been the topic of WECC webinars in recent months, and the organization commissioned a report from Elevate Consulting on large load risks in the Western Interconnection. (See IBR Lessons Can Guide Data Center Challenges, WECC Report Finds.)

WECC’s State of the Interconnection report highlights the large load experience of Arizona Public Service (APS), which expects its annual energy needs to grow by almost 24 GWh between 2023 and 2038. The utility attributes nearly 80% of that growth to data centers and large industrial and manufacturing facilities, especially semiconductor chip factories.

From 2023 to 2031, APS expects nearly 40% growth in its annual peak demand.

Forecasting Issues

The unprecedented growth in demand is creating forecasting challenges, WECC said.

At the interconnection-wide level, annual demand forecasts have been close to actual demand for the past five years, WECC said. But some balancing authorities seem to be better at forecasting than others, according to the report, which pointed to an unnamed BA that had forecasts averaging 32% over its actual demand in all forecast years. And forecasts from other BAs sometimes turn out to be less than actual demand.

“It could be a concerning indicator that demand forecasting practices vary widely,” the report said.

To meet the growing demand, resources are being built at a faster rate. More than 24 GW of new resources were added in 2024, far more than the 10-year annual average of 7.4 GW. The 24 GW represented 80% of the new resources planned to be built last year.

“The West will have to build at the 2024 rate at least to meet forecast demand,” the WECC report said.

Of the new generation added last year, 5.5 GW was natural gas. About three-quarters of the new additions were inverter-based resources: 8 GW of solar, 3 GW of wind and 7 GW of battery storage. That brought the interconnection totals for solar, wind and battery storage to 44 GW, 39.3 GW and 16.7 GW, respectively.

The WECC report also tallied system events across the Western Interconnection.

The number of energy emergency alerts (EEAs) rose sharply, from 21 in 2023 to 30 in 2024. Last year’s total included 18 Level 3 EEAs, the most serious of the three levels in which rolling blackouts may be deployed. Nearly half of those events took place in January 2024 during winter storms Heather and Gerri.

EEAs also lasted longer in 2024. EEA-1 events, in which energy conservation is called for, averaged 4.47 hours last year compared to 1.94 hours in 2023.

The average duration for all EEAs was 4.28 hours in 2024 compared to 2.47 hours the previous year.

“Extreme weather (variability and extreme temperatures) continues to be the biggest driver of EEAs across the interconnection as it leads to surging demand and the potential to impact generation,” WECC said in the report.

Posted on

SERC Outlines Gas-electric Issues for State Regulators

Speakers at a SERC Reliability-hosted webinar urged state lawmakers, policymakers and regulators to do their part to promote coordination between the natural gas and electric industries to reduce the risk of serious grid incidents like those that occurred in the winter storms of 2021 and 2022. 

SERC held the webinar to provide state-level stakeholders with an overview of the increasingly interdependent gas and electric systems — a topic that has sparked concern in the ERO Enterprise — and suggest ways they can help with the stress during times of increased demand, especially extreme cold periods when gas is needed for electricity generation and home heating. 

Marty Sas, SERC’s manager for reliability assessment, shared some of the regional entity’s concerns in its most recent Regional Risk Report. Sas warned that the ongoing replacement of coal-fired generation by intermittent resources like solar and wind generation has led to “an increased dependency on natural gas” for dispatchable energy. 

“That increases some vulnerability to supply disruptions. Limiting fuel flexibility can threaten generation availability,” Sas said. “Diversifying our fuel mix and enhancing infrastructure resilience are key actions that need to be taken as we move forward around these ever-changing resources and the dependency on natural gas.” 

Heather Polzin, SERC’s senior reliability adviser, added that the gas system also relies on electricity. She cited a 2023 study by Carnegie Mellon University noting that about 10% of pipeline compressor stations in the U.S. are electric-powered “and thus vulnerable to electric power outages.” The study suggested that an outage at one such station “can significantly reduce gas available to downstream generating stations,” leading to outages “as large as or larger than the most severe single-cause failure currently considered in electric reliability planning.” 

Polzin said the topic of gas-electric coordination is particularly prominent for SERC, which “is roughly 50% reliant on natural gas-fueled generation.” In some areas, this dependence is even greater: 75% of the generation in Florida is gas-fired, Polzin said, and nearly 68% of generation in MISO South is gas-fired. The presence of oil and gas refineries in the region presents another challenge. 

“We certainly think of [this] a lot as a winter problem, because of that competing demand with home heat, and you don’t have that in the summer,” Polzin said. “But one of the big risks that we have in the summertime is that over 50% of the [U.S. natural gas] refining capacity is on the Gulf Coast. … Even if a hurricane is not going to be a direct hit, [refineries] often will close down pre-emptively to protect the refining capacity. So that’s one big issue.” 

The speakers reviewed some of the recommendations from FERC and NERC’s joint reports on the 2021 and 2022 winter storms, which included requiring natural gas infrastructure operators to maintain cold weather preparedness plans and creating regional natural gas reliability coordinators similar to the ERO Enterprise. They suggested that regulators and policymakers improve their awareness of their states’ electric and gas systems. 

“Is your state one of the five states that provides about 70% of all the total [U.S.] dry natural gas production?” Polzin said, referring to Texas, Louisiana, Oklahoma, Pennsylvania and West Virginia. “Do you know the percentage of the generation resources in your state that rely on natural gas? [SERC] can help you with this information. And do you know which natural gas pipelines your state relies on to produce electric energy, whether they’re interstate or intrastate pipelines, [and] what difference does it make? We can also help with this.” 

Sas emphasized that gas is likely to remain a major part of the generation mix because of its usefulness for providing reliability services. However, he urged listeners to pursue policies that promote diversity of resources while encouraging “cross-sector coordination between gas and electric utilities” and maintaining an awareness of regional risks as outlined in the ERO’s annual risk reports.