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December 13, 2025

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NWPCC’s Initial Demand Forecast Sees Sharp Growth for Northwest

Annual energy demand in the Pacific Northwest could reach between 31,000 and 44,000 aMW by 2046, according to the Northwest Power and Conservation Council’s (NWPCC) initial 20-year forecast. 

The initial 20-year demand forecast, released April 29, does not account for cost-effective efficiency, rooftop solar or demand response that could reduce electricity demand. Council staff intends to release the final forecast by the end of 2026 after deciding how much of those resources they should include, according to a news release. 

The council is required under the Northwest Power Act “to develop a plan to ensure an adequate, efficient, economical and reliable power supply for the region.” NWPCC publishes a plan every five years, according to the council’s website. (See NWPCC Considers Trump, Data Centers in Regional Power Plan.) 

“Thanks to many months of work by Power Division staff, collaboration with regional partners and our new computer modeling capabilities, we now have a deep understanding of the potential future energy needs of our region,” Jennifer Light, power planning director at NWPCC, said in a statement. 

“This will help us develop the cost-effective resource strategy that will be robust across future load growth trajectories, while ensuring the Pacific Northwest’s power grid continues to be adequate, efficient, economical and reliable over the next two decades,” Light added. “We won’t take on this task alone. We invite and encourage public participation and collaboration from across the Northwest as we plan for the future of our power system throughout 2025 and 2026.” 

Since 2010, energy consumption in the Pacific Northwest region has hovered “around 20,000 average megawatts to 22,000 average megawatts,” Steven Simmons, senior energy forecasting analyst at NWPCC, said during a presentation of the initial forecast. 

The region experienced a winter peak of approximately 35,500 MW in February 2025, an increase over the previous winter peak of 35,100 MW in 2023. The region reached a summer peak of 33,300 MW in July 2024, according to the news release. 

Demand and peaks are showing no signs of slowing down.

The council tested five scenarios, and energy growth increases under all scenarios. The annual energy demand is projected to reach between 31,000 and 44,000 MW by 2046, depending on the scenario, and peak demands will range between 47,000 and 60,000 MW, the council stated. 

Though there is a mix of winter and summer peaking, historically the Pacific Northwest region is winter peaking. “However, in our forecast, we’re starting to see more summer peaks creep in, for sure, and definitely in some of the specific futures,” Simmons said. 

But the largest growth is expected from electric vehicles and data centers, according to the forecast. A major driver of the electric vehicle forecast is transportation policies in Oregon and Washington, said Tomás Morrissey, senior analyst with the council. 

“Probably the biggest driver in the model is the 100% new light-duty vehicle standards in Oregon and Washington that stipulate that light-duty vehicles starting in 2035 have to be electric,” Morrissey said. “And as you can imagine, that increases load across the system leading into 2035 as sales are ramping up and then continuing past 2035 as the vehicle stock turns over and becomes more and more electrified.” 

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State Regulators Weigh Drafting Alternative to MISO Tx Cost Allocation

Regulators of MISO states are mulling whether they should work together to offer up an entirely new cost allocation for the RTO’s long-range transmission projects.

The Organization of MISO States’ leadership said it will hold meetings on whether regulatory staff think FERC’s Order 1920 should open the door for a new cost-allocation design for MISO’s regional transmission projects. OMS members contemplated the idea at an April 28 meeting of the OMS Cost Allocation Principles Committee (CAPCom), with MISO South regulators appearing more open to shedding MISO’s current, 100% postage stamp allocation to load used for long-range transmission projects.

Order 1920 directs RTOs to involve states when developing or amending a long-term regional transmission cost allocation. It gives states the go-ahead to meet independently to negotiate and devise cost-allocation methods to offer to FERC in place of RTOs’ methods.

Regulators of some MISO states at the meeting said they’re ready to pursue something different, while others said the postage stamp status quo remains the best answer.

Minnesota Public Utilities Commissioner Joe Sullivan said OMS extensively examined MISO’s cost allocation when it began planning long-range transmission projects. (See FERC OKs MISO’s Bifurcated Cost-allocation Tx Design.)

He said he didn’t think OMS could do better this time around. “We had a really long process that I thought was really good about ex ante cost-allocation alternatives. I think I’m on record that we didn’t find anything better,” Sullivan said.

But Louisiana Public Service Commission attorney Noel Darce said MISO South states want a new method of subregional cost allocation in MISO, “something other than the postage stamp.”

MISO South never has been the site of construction for a regionally cost-shared transmission project.

While Order 1920 dictates that project costs are allocated ex ante, or before the projects are built, states also have the option to negotiate with one another for up to six months after RTOs approve transmission projects to devise an alternative cost-allocation agreement for select portfolios.

MISO would have to file with FERC any alternative, all-encompassing cost-allocation design from states or their one-off alternative cost-allocation agreements, even if the RTO disagrees with it and files its own alongside the states’ preferred approach. MISO also must file a backstop cost-allocation method to use if state negotiations break down. FERC and federal courts ultimately would make calls on which cost-sharing plan is most appropriate.

New Orleans City Council attorney David Shaffer said OMS first should check in among members to see whether the postage-stamp allocation remains appropriate, or whether “positions have changed.” He said OMS should tackle that first before devising the potential state agreement process or assisting MISO with creating a voluntary funding process for projects that may not meet the RTO’s benefit-cost ratio threshold.

Under Order 1920, MISO also must create a voluntary funding rule set that allows state entities and transmission interconnection customers the option to voluntarily fund some or all of the costs of proposed projects.

Shaffer said it’s worth checking whether the states still believe the current approach is relevant and see “if there could be consensus on an alternative.”

“I think we probably should address them individually,” Shaffer said of Order 1920’s to-do list.

“I think the question for us is: Do we want to take run at something different?” said Michigan Public Service Commission Chair Dan Scripps, also chair of OMS’s CAPCom.

OMS said it will conduct an internal poll among regulators to gauge interest in designing a new cost allocation to take to MISO, at the suggestion of Mikhaila Calice, a staffer at the Public Service Commission of Wisconsin.

Scripps said OMS likely will take advantage of MISO Board Week in Minneapolis in June to meet face to face and discuss allocation options versus MISO’s status quo.

MISO Sticks with Postage Stamp

Regulators asked if MISO is open to considering a new method of cost allocation.

Jeremiah Doner said based on MISO’s assessment of Order 1920, it believes its current, postage-stamp allocation is fitting.

Doner said MISO is “largely going to be leveraging and developing” compliance through its long-range transmission planning and that it plans to tell FERC the “story” of its planning philosophy.

MISO “would point to the entirety” of the current structure used in its long-range planning in its compliance, including its approved cost allocation for long-range transmission projects, Doner said.

Doner added that OMS would embark separately on its own evaluation of current cost sharing and alternatives.

Order 1920 prescribes RTOs open a six-month engagement period with states for allocation evaluation. MISO kicked off its state engagement period by sending a letter to the Organization of MISO States. Because it was granted an extension from FERC, the RTO’s state engagement period lasts from March 11, 2025, to March 11, 2026.

The Mississippi Public Service Commission and the Louisiana Public Service Commission filed a motion to extend the state engagement period between MISO and state regulators by another six months, through Sept. 11, 2026. The two have asked other state regulators to consider joining them in the request and said that “more time is needed to allow for complex cost-allocation discussions and a meaningful, consensus-based, long-term cost-allocation method and/or state agreement process.”

MISO South representatives pushing MISO to try alternate allocation methods isn’t new.

Prior to Order 1920, MISO itself suggested using a tailored allocation plan that involved splitting costs 50-50 between the MISO South subregion and the footprint’s smaller cost-allocation zones. (See MISO Suggests Changing Cost Allocation for South Projects.)

MISO South regulators and Entergy in early 2024 countered with a proposal that would assign 90% of costs based on adjusted production cost savings and avoided reliability projects; the remaining 10% would be divvied up among new generators interconnecting in MISO South using a flow-based methodology. (See Clean Energy Orgs Push Entergy Players to Consider Broader Cost Allocation.)

Doner said he expected the regional cost allocation directive of Order 1920 would be the most interesting portion of MISO’s compliance.

MISO has until June 12, 2026, to comply with Order 1920. It plans to hold discussions on its Order 1920 compliance at upcoming Planning Advisory Committee meetings.

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New York Caps Distributed Solar Funding Stream

New York’s distributed solar incentive program is ahead of schedule and under budget, so state regulators are reallocating some of its funding to other clean energy programs. 

Solar advocates and their allies in the state Legislature framed the decision as a misguided move that penalizes success, while the Public Service Commission framed its decision as recognition that the industry has matured. 

The New York State Energy Research and Development Authority in January 2024 had proposed leaving the entire $421 million surplus in NY-Sun to additional solar development. 

The Public Service Commission took comments on the matter (Case No. 21-E-0629), then voted unanimously April 25 to use $150 million on additional solar incentives that benefit low-income customers and $153 million on NYSERDA to use for future clean energy programs. The remaining $118 million was money that was to be repurposed from other allocations to fund NY-Sun but now will not be. 

NYSERDA explained in its Jan. 4, 2024, filing that the surplus was generated largely by the tax policies contained within the Inflation Reduction Act signed into law in 2022, a year after the PSC approved New York’s 10-GW Distributed Solar Roadmap. 

The IRA provisions are under direct threat of revision or revocation, as are other federal funding streams to states for various initiatives not favored by the Trump administration, such as those promoting solar power generation and economic justice. 

The PSC’s April 24 order does not directly address this, or the fact that the Trump administration has actively attempted to claw back certain funding awarded during the Biden administration, such as EPA grants. 

There does seem to be some tacit acknowledgement of the situation, though, as when the order states: “The commission highly encourages NYSERDA to evaluate how [EPA grant] funding could be creatively used to further support the commission’s clean energy and distributed solar objectives, while also supporting low-income customers and disadvantaged communities.” 

There also appears to be an acknowledgment of the impact New York’s expansive decarbonization ambitions will have on ratepayers who already face high utility costs. The $3 billion NY-Sun program is funded through utility bills. 

In a formal statement after the PSC meeting, Chair Rory Christian recognized all these things, saying the order gives NYSERDA “flexibility to adjust incentive levels to respond to market conditions, ensure efficient use of program funds, and … continue to monitor changes in federal energy policy.” 

“With these changes,” he added, “we will be able to expand our capacity to additional crucial policy matters, including, critically, energy affordability.” 

The economic disparity of rooftop solar deployment has long been recognized. Many lower-income residents do not own their own homes or have rooftops suitable for the installation of panels. 

New York’s efforts to promote community solar have attempted to address this by giving lower-income communities a chance to benefit from off-site solar, and the changes to NY-Sun are designed in part to accomplish the same thing. 

Due to the various policies, distributed solar has proliferated in New York to the point that it is a national leader in community solar capacity. The state surpassed its original goal — 6 GW of distributed solar by 2025 — a year early and has set a new target of 10 GW by 2030. (See NY Surpasses 6 GW of Distributed Solar Capacity.) 

All this stands in marked contrast to the slow pace of large-scale renewable development in New York and has led advocates for distributed solar to urge more policy support, with a further increase in the target to 20 GW. 

During the public comment period, the New York Solar Energy Industries Association endorsed NYSERDA’s initial request to retain the surplus funds within NY-Sun. 

“The highest priority now should be authorizing the reinvestment of the surplus funds as soon as possible to avoid any lapse in the NY-Sun program,” it wrote Oct. 31. “This decisive action will not only support New York’s ambitious clean energy goals, but also foster a more inclusive and resilient energy future for all New Yorkers.” 

NYSEIA joined other organizations and legislators in a joint statement April 28 criticizing the PSC’s decision. It notes prominently the sharp changes in federal funding streams. 

One problem with New York’s regulatory mechanisms is they can take a long time to reach a conclusion, and the parameters on which a proposal is based sometimes change as stakeholders, politicians and bureaucrats research, create, discuss, revise and debate the provisions of a particular rule or regulation. 

Nearly six years after the state Legislature mandated 100% zero-emissions energy by 2040, for example, there still is no decision on the politically fraught question of what will constitute zero emissions. 

When NYSERDA noted in January 2024 that money was flowing out of Washington to subsidize distributed solar, President Biden still was in office and photovoltaic installations were starting a record-setting run that would reach nearly 50 GW nationwide by the end of the year. 

As the PSC voted to cap NY-Sun funding, more than a year later, the message from Washington is “drill, baby, drill” and widespread federal layoffs and funding cuts target environmental initiatives. 

Sen. Pete Harckham (D), chair of the state Senate Environmental Conservation Committee, recently introduced the Accelerate Solar for Affordable Power Act (S.6570). ASAP would raise New York’s rooftop and community solar goal to 20 GW by 2035 and direct the PSC to implement reforms to the utility interconnection process to lower costs and accelerate deployment. 

In the April 28 statement, Harckham chided the PSC, saying NY-Sun largely is responsible for the success of small-scale solar in New York. “Putting the brakes on this clean energy momentum, which is creating thousands of green jobs and saving ratepayers millions of dollars, makes no sense at all,” he said. “In fact, we should be doubling down on this program’s success and ramping up gigawatt goals instead of standing pat and congratulating ourselves on a job well-done in the middle of our climate crisis.” 

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DNV Finds Long-term Optimism for Energy Transition

The 2025 edition of DNV’s Energy Industry Insights report finds long-term optimism that the energy transition will continue but widespread uncertainty about its direction in the near term. 

Trade agreements and tariffs drive the pessimism while growth of the world’s population, economy and need for electricity drive confidence that electrification — with its promise of greater energy security and energy independence — will continue. 

But the uncertainty has been palpable lately. 

The Global Economic Policy Uncertainty Index spiked in early 2025 as President Trump was hitting his stride in his second term and as DNV was conducting its survey. It eclipsed its previous record high, set in early 2020 as the scope of the COVID-19 pandemic became apparent. 

“To think that, by this metric at least, we are in more uncertain times than April 2020 shows just how much disruption and unpredictability there is in today’s policy environment, much of it caused by national issues, such as energy security, self-sufficiency and shifts in voter sentiment,” the authors write. 

By contrast, there is no doubt about the value prospect of electrification or the threat posed by greenhouse gas emissions, they write, and a successful transition remains possible, with sufficient investment. 

The transition also remains necessary, DNV Energy Systems CEO Ditlev Engel said in an April 29 news release accompanying the report. 

“A successful energy transition is not impossible, but the urgency to accelerate action has never been greater,” he said. “The path to a cleaner, more sustainable energy future is inherently complex and uneven, but delay is not an option. Immediate, coordinated efforts are essential to ensure momentum is not lost.” 

Lucy Craig, DNV’s director of energy systems growth, innovation and digitalization, said technology will play a critical role in the energy transition.  

“As the energy system becomes more electrified, distributed, interconnected and dynamic, adopting a whole-systems approach will be essential,” she said. “This means viewing the energy system as an interconnected whole, one that enables greater efficiency, flexibility and resilience.” 

Craig said 64% of respondents say a whole systems approach is impossible without fully digitalized infrastructure and 59% plan to boost their spending on digitalization, including artificial intelligence. 

Data show planned 2025 investments in various energy technologies have decreased from 2024. | DNV

Some other takeaways from the 2025 report: 

    • 55% of respondents say the energy transition is accelerating, compared with 72% in 2024 and 79% in 2023.
    • 51% say a successful energy transition will negatively impact some communities.
    • 31% identify expansion of energy storage technologies as key to accelerating the energy transition.
    • 96% of those in the power sector see a need for urgent investment in grid modernization, and more than 75% see outdated grid infrastructure as a barrier to renewables adoption.
    • 50% of those in the renewables sector expect to meet revenue targets, and 43% are optimistic about profits, down from 75% and 67% three years ago.
    • 39% of those in renewables expect to increase investment in the next 12 months.
    • 31% identified expansion of energy storage technologies as key to accelerating the energy transition.
    • The top five barriers seen to investments contributing to the energy transition are policy uncertainty, capital outlay, regulatory constraint, profit limits and infrastructure shortcomings.

This is the 15th edition of DNV’s annual report.  

It is based on the comments of more than 1,100 senior professionals in the energy industry surveyed by the Norwegian company. They are heavily weighted toward Europe (54% of respondents) and Asia (22%), with North America third at just 12%.

The majority of respondents came from the renewables (35%) and oil/gas (33%) sectors, with the electric power industry third at 17%. 

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BESS Companies Propose $100B to Grow U.S. Battery Industry

The U.S. energy storage industry proposes to invest $100 billion in U.S. grid-scale battery manufacturing and procurement by 2030.

The April 29 announcement came via the American Clean Power Association (ACP), and it came with a major caveat: A pro-business environment with supportive tariff, tax and permitting mechanisms will be needed if this commitment is to be fulfilled.

These preconditions speak directly to the uncertainty facing the U.S. clean energy sector since January, when President Donald Trump took office with a pro-carbon/anti-renewable message, and his Republican allies took control of both houses of Congress.

Threats of tariffs, the potential end of tax credits and rapid-fire policy changes have contributed to widespread pullback on manufacturing initiatives in the renewables sector.

The Clean Investment Monitor reported April 24 that while $9.4 billion in new clean energy manufacturing projects were announced in the first quarter of 2025, there also were $6.9 billion in cancellations, the most ever in a single quarter.

Against this backdrop, Jason Grumet, CEO of ACP, said the battery industry’s $100 billion commitment is important not only for the energy sector but for the nation itself.

“The energy storage industry is providing essential power when needed most while boosting domestic manufacturing and creating jobs across the country,” he said in the news release. “Today’s historic commitment will invest billions of dollars into American communities and position the United States as a manufacturing leader in battery technology that is critical to national and grid security.”

This is a variation of the message offered since Election Day by ACP and most other renewable energy advocates, emphasizing the economic, practical and political importance of clean energy investment and limiting or omitting any reference to its environmental benefits.

Data show the potential expansion of energy storage in the U.S. | ACP

Trump already has targeted offshore wind with damaging directives, despite that message. How effective the message will be in winning support for battery energy storage systems (BESS) remains to be seen.

Batteries can be an important counterpart for intermittent wind and solar generation, but here again, ACP played up the other roles BESS plays:

“Energy storage optimizes all existing power generation, lowering energy bills and hardening the grid against extreme weather events like blizzards and heat waves,” ACP wrote. “As the economy grows, energy storage provides important peaking capacity, freeing up more gas generation to serve as base load and enabling more energy production.”

ACP noted that U.S. battery installations have increased 2,500% since 2018; batteries saved Texas more than $1 billion in energy costs in 2024 alone; 25 new or expanded grid-scale battery factories are being planned or built nationwide; and storage projects are under construction in 31 states.

ACP said U.S.-made batteries could satisfy 100% of projected domestic energy storage demand by 2030 — if the support exists to grow the ecosystem.

“Without a pro-business policy approach that ensures enough certainty to sustain these significant investments, there is a risk that America loses out on both becoming a global battery manufacturing leader and meeting the economy’s rapidly growing energy needs,” it said.

Executives of Clearway Energy Group, Eolian, Fluence, Form Energy and LG Energy Solution Vertech voiced their support in the ACP announcement, which was accompanied by an expanded explainer citing major storage manufacturing or deployment projects by Fluence, Form, LG, Powin, Salt River Project/Ørsted and Tesla.

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NERC Finds Growing Shortfall Risk in Canada

Interregional transfers are likely to become increasingly important to Canada in the coming decade, NERC said in a supplement to the Interregional Transfer Capability Study, with Québec especially vulnerable to energy deficiencies in extreme weather. 

The release of the Canadian analysis April 29 represented the conclusion of the study process that began with the passage of the Fiscal Responsibility Act of 2023, which ordered NERC to analyze current transfer capabilities between transmission planning regions in North America. The ERO also was directed to recommend prudent additions to transfer capability that could strengthen grid reliability and ways to meet and maintain total transfer capability. NERC released the ITCS in three installments, concluding in November 2024. (See NERC Releases Final ITCS Draft Installments.) 

The installments released in 2024 included transfers from Canadian provinces to the U.S., but not the other way around, and also did not study transfer capabilities between provinces. Congress mandated only that NERC study transfer capability within the U.S. But the ERO said in 2024 that the ITCS “would be incomplete without a thorough understanding of the Canadian limits and available resources.” Canadian government and industry stakeholders also requested that NERC extend the study to their territory, according to the supplement. 

NERC’s goal with the Canadian analysis was to apply “the same yardstick” that it did with the U.S. planning regions, Manager of Transmission Assessments Saad Malik said in a webinar accompanying the report’s release. As with the earlier components, the ERO developed its analysis based on historic weather conditions from 2019 to 2023, along with synthetic modeled datasets from 2007 to 2013, for a total of 12 weather years. 

NERC used the weather data to test performance of the regions across each hour of 2033, using the load and resource mix predicted in the ERO’s 2023 Long-Term Reliability Assessment, to identify potential energy deficiencies. The ERO then looked for transfer additions that could address them. 

A “potential for energy deficiency” existed in all 12 weather years for Nova Scotia, the report said, with five other provinces showing possible deficits in some years. Extreme cold weather drives the shortfalls in Québec and Alberta, along with one weather year in Saskatchewan; another weather year sees heat-driven shortfalls in Saskatchewan, with similar results across five weather years in Ontario. 

In all, the ERO recommended nearly 14 GW of additional transfer capability, which it said would address all of the resource deficiencies. By contrast, the U.S. component recommended 35 GW of added capacity across the U.S. planning regions but said even these additions would not be enough to resolve all deficiencies. 

The Canadian analysis noted that several provinces now have greater transfer capability with their U.S. neighbors to the south than with other provinces. For example, British Columbia has 2,170 MW of capacity into Washington state and 2,795 MW the other way, compared to, respectively, 855 MW and 1,000 MW into and out of neighboring Alberta. These figures apply to winter; summer transfer capabilities differ slightly in most cases. 

Ten gigawatts of additions were recommended for Québec alone, which the study noted is likely to experience difficulty meeting growing demand in the next 10 years, with which local generating capacity is not projected to keep pace. The additions were recommended from New York (4,200 MW), Ontario (2,600 MW), New England (2,600 MW) and New Brunswick (900 MW). Additional recommendations included:  

    • Nova Scotia: 500 MW from New Brunswick.
    • Saskatchewan: 500 MW from MISO West.
    • Alberta: 600 MW from Saskatchewan.
    • Ontario: 1,600 MW from PJM East (900 MW), MISO West (400 MW) and Manitoba (300 MW).

The MISO West-to-Saskatchewan and PJM East-to-Ontario transfers are potential new interfaces. 

In a media release, NERC CEO Jim Robb said the combined Canada and U.S. analyses represented “an unprecedented and vital assessment” that “provides a complete picture of the crucial role that interregional transfer capability across Canada plays in assuring the reliability and resilience of the interconnected North American grid.” 

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California Lawmakers Seek to Trump-proof Pathways Initiative Bill

New amendments to California’s proposed Pathways bill will include protections against possible attempts by President Donald Trump to influence the state’s energy markets, such as pushing it to buy power from coal-fired generators.

Democratic State Sen. Josh Becker presented the proposed amendments during a California Senate Judiciary Committee hearing April 29. The committee unanimously approved all the changes in a late-night vote, sending the bill on to the Appropriations Committee.

The changes follow concerns from consumer advocacy groups like The Utility Reform Network (TURN) that handing over governance of CAISO’s energy markets to a proposed independent regional organization (RO) could undermine the Golden State’s clean energy goals. (See California Lawmakers to Discuss Amendment Requests to Pathways Bill.)

“Some opponents have raised reasonable concerns … and I appreciate those and will continue discussion,” Becker said. “I believe the committee amendments not only address these concerns but further strengthen the protections in this bill.”

Senate Bill 540, or Pathways, is the product of the work of the West-Wide Governance Pathways Initiative, an effort to support the expansion of CAISO’s Western Energy Imbalance Market (WEIM) and soon-to-be-implemented Extended Day-Ahead Market (EDAM) to entities outside California by creating a new independent RO to govern rules for CAISO’s markets while leaving key elements of the ISO’s balancing authority area intact.

Under the bill’s first iteration, California could not join the RO market before mid-2027. But with amendments, the timeline would be pushed to January 2028, according to Becker.

This gives stakeholders “a full three years of watching the new administration, seeing what it does and what it attempts to do regarding California’s energy markets” before any final decision is made, Becker said.

The amendments also clarify that the RO cannot establish capacity markets. This is to prevent the Trump administration from forcing California to buy coal, Becker said. He added that the strategy to use capacity markets to incentivize coal “is outlined by Project 2025.”

“We cannot establish capacity markets under this bill or establish any mandatory reserve or resource adequacy requirements,” Becker said.

Additionally, the tariff filed with FERC “cannot assess any cost of fossil fuel generation resources to California participants. E.g. can’t force California to pay for coal generated in Wyoming,” according to Becker.

Becker also said electrical corporations must leave the RO if one of three things happen: market rules or public policies turn out to be “detrimental to California consumers”; renewable portfolio standards are “held invalid by reviewing court on claims of impermissible discrimination”; or Trump or future presidents use emergency powers to require California to subsidize fossil fuels.

“We now have it in the bill, if any of those things happen, automatic required withdrawal,” Becker said.

Other amendments include:

    • Require the RO’s governing documents and tariff approved by FERC to respect the authority of each state and manage energy markets consistent with existing California protections.
    • Allow participants to withdraw without penalties.
    • CAISO must provide testimony and receive feedback from the state Senate and Assembly energy committees before adopting the resolution.
    • CAISO must conduct a jobs study.

Praise, Concerns, Fear

In calling the amendments “substantial,” Becker also said some opponents “are falsely evoking public fear” that the market initiative exposes California to “federal meddling.”

“If FERC wants to interfere with our markets today or our climate policies via our energy markets, they can do that today. Just to be extremely clear,” Becker said.

Speaking in support of the bill, Marc Joseph, an attorney representing the International Brotherhood of Electrical Workers (IBEW), also noted that Trump already poses a threat to energy markets in the West.

“This bill does not give FERC any more jurisdiction over our policies than it has today,” Joseph said. “In any case, as Sen. Becker said, the decision to participate won’t come before 2028, so we have plenty of time to evaluate whether this remains a good idea. If it’s not, we just don’t do it.”

Still, former California Public Utilities Commission President Loretta Lynch, an outspoken opponent of SB 540, argued that federal challenges likely will ensue should the bill become law. (See Calif. Senate Committee Backs Pathways Initiative Bill.)

“Two major legal concerns that arise from this bill, according to the committee analysis, are based on the federal preemption doctrine and the Dormant Commerce Clause,” Lynch said.

“While the proposed amendments attempt to close the legal deficiencies that make California vulnerable, and I applaud the author for considering proposed amendments, they do not go far enough to protect California,” Lynch said. “And most importantly, they change the law now, today, and provide too much of California’s current legal authority, giving it over to the FERC and to the new RO.”

In an email to RTO Insider, Matthew Freedman, staff attorney for TURN, wrote: “TURN appreciates the amendments taken today in the Judiciary committee to address many of the concerns outlined in our letter. We are continuing to evaluate the bill and are working with Sen. Becker to minimize the risks to California’s consumers, environmental protections and clean energy leadership.”

Advanced Energy United has supported the bill. In an email, the organization’s managing director, Leah Rubin Shen, said, “We are encouraged to see lawmakers engaging constructively and balancing the priorities of a wide range of stakeholder interests.”

“This bill will strengthen California and the West’s position by building a broader market that protects state interests and fosters regional collaboration,” Shen added.

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NRECA Legislative Fly-in Focuses on Permitting, Meeting Demand

The National Rural Electric Cooperative Association (NRECA) has flown 2,000 member representatives to D.C. to lobby congressional leaders on key issues for the nation’s co-ops, which this year include passage of permitting legislation and meeting rising energy demand.  

“Our desire, as electric co-ops, is to make sure we have smart energy policies that help us meet this challenge, because it’s a good challenge to me,” NRECA CEO Jim Matheson said on a call with reporters kicking off the April 28-30 Legislative Conference. “I mean, growing electric demand is good news for our country. It shows our economy is growing, and that’s what we want.” 

One of NRECA’s key priorities is to get some changes to federal permitting passed, after a bipartisan effort to do so fell short in the last Congress. (See Lame Duck Permitting Push Fails; Manchin Blames House GOP Leaders.) 

“I think there continues to be an understanding across a large segment of Congress, in a bipartisan way, that our permitting process is not functioning in the most efficient way, and so that’s good,” Matheson said. “On the other hand, we all know that [there’s a] small margin in Congress and getting any type of legislation through can be a challenge.” 

One way the Republican majority is considering to get around the narrow margin is “reconciliation,” since it avoids the Senate filibuster, but it can be used only to pass laws related to funding the government (Democrats used it to pass the Inflation Reduction Act in 2022).  

With so many laws implicated in federal permitting, Matheson said the issue ultimately will require a “multifactor effort from a legislative standpoint” to enact all the needed changes. 

NRECA supports some of President Donald Trump’s regulatory rollbacks at EPA because they will keep needed power plants running in a time of demand growth. But the administration’s trade policies are presenting problems for that effort. 

“The supply chain that serves the electricity sector in this country is a global supply chain. That’s a fact,” Matheson said. “And, so, the answer is, to the extent that the supply chain is disrupted or has additional costs associated with it based on tariffs, yes, that is going to have an impact on the electric sector in general, and on electric co-ops in particular.” 

The tariffs have proved to be moving targets, with President Trump often lowering or delaying them, but any disruptions or higher costs for needed equipment ultimately is going to impact the rural consumers NRECA members serve, he added. 

The industry still is dealing with supply chain disruptions from the COVID-19 pandemic, and now any policy uncertainty is exacerbating the issue, said Keith Brooks, general manager of Douglas Electric Cooperative in Roseburg, Ore. 

“We adjusted our inventory practices during COVID,” Brooks said on the press call. “We’re probably carrying twice as much inventory as we had in the past, just to ride out some of these supply chain ups and downs. But, you know, anything that makes the situation worse is a little scary for us.” 

The tariffs have not been in place long enough to have had a major impact on the power industry’s supply chains yet, he added. 

“We continue to be in a wait-and-see mode for any actual dollar impact to our members that will be the result of any tariffs that come through,” said Annalisa Bloodworth, CEO of Oglethorpe Power, a 38-member co-op in Georgia. “We are starting to receive, from vendors across our supply chain, notices and alerts that their expectations are of increased costs and potential disruption.” 

That comes on top of a supply chain that is under much pressure, not only from the supply side, but from the growing demand for power in the U.S. and around the world, Bloodworth added. 

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Growth of BTM Solar Drives Record-low Demand in ISO-NE

ISO-NE experienced record-low demand on Easter Sunday because of mild temperatures and high behind-the-meter solar output, making 2025 the fourth consecutive year the RTO has set a low-load record.

The 5,318-MW minimum load April 20 was a significant drop from the previous record low of 6,596 MW, set in April 2024. ISO-NE estimates that BTM solar production reduced systemwide demand by about 6,600 MW.

Steven Gould, director of operations at ISO-NE, said the RTO anticipated the low-load conditions days in advance and was able to forecast the minimum load with great accuracy.

“It was a very quiet day because we prepared and we communicated,” Gould said. He added that the impact of declining minimum loads is “something that we are continuously looking at. We’re fine now, but we want to be proactive, and that’s what we’re doing.”

The region’s solar boom has led to an increasing amount of duck curve days, which are defined as days when daytime demand drops below nighttime demand. In 2024, New England experienced 100 duck curve days for the first time in its history.

Steven Gould, ISO-NE | ISO-NE

Largely driven by state policy, the region recently has added about 700 MW of BTM solar capacity per year, Gould said. Solar growth has been strongest in Massachusetts and Connecticut, which are home to about two-thirds of the BTM solar generation in the region.

Gould said the “biggest concern at light loads” is the creation of high-voltage conditions on the transmission system. He said ISO-NE coordinates with the region’s transmission owners ahead of forecasted light-load periods to ensure the system has resources available to reduce the voltage on the system.

Light-load conditions also create the need for significant ramping capabilities as solar production wanes in the evening. On April 20, natural gas generation dropped from over 4,700 MW in the early morning to about 1,800 MW between 10 a.m. and 3 p.m., before increasing in the evening to over 5,000 MW as the systemwide peak grew to about 11,800 MW.

“We have the resources to [ramp back up] at this point in time, and we’re able to do it quite easily,” Gould said.

Power system emissions, which largely are driven by natural gas generation, especially during warmer months, were cut roughly in half during this midday period, before increasing again in the evening.

Nuclear generation, which lacks the ability to quickly increase or decrease production, remained steady at 2,115 MW throughout the day. In the future, Gould said he does not expect low loads to create operational issues for nuclear resources because the region can export power to neighboring regions during extreme low-load conditions.

On April 20, ISO-NE went from importing about 1,500 MW in the morning to exporting power midday to NYISO as New England’s real-time hub LMP dropped to as low as ‑$31.7/MWh. Imports climbed back to about 1,000 MW in the evening.

Looking forward, Gould said he expects the growth of transportation electrification and electric storage to eventually drive up midday demand, helping to mitigate potential low-load concerns.

“We think battery storage and electric transportation and heat pumps will be able to curb the light load, because that will be the lowest energy price for those resources to charge their systems,” Gould said. “If you look at Texas and California, they’re very much ahead of us for battery storage, but that’s what they’re doing.”

Over the next decade, ISO-NE anticipates BTM solar production to nearly double, growing at a rate of about 570 GWh per year. ISO-NE expects this growth to push the system peak load later in the day but does not expect it to have a major impact on peak loads levels. By 2034, ISO-NE expects BTM solar growth to reduce the summer peak by an additional 140 MW and the winter peak by about 400 MW.

However, Gould emphasized the difficulty of forecasting system conditions years in advance, “especially when you go from one [federal] administration to a new administration,” pointing to the struggles and uncertainties surrounding offshore wind development.

“Things are dynamically changing,” Gould said. “We’re doing lots of studies. … We’re taking about light loads; we’re looking at ramping; we’re looking at intermittent resources; we’re looking at forecasting irradiance; we’re looking at forecasting wind and forecasting demographic behavior, and putting it all together to make sure we have adequate resources in our market on a daily basis.”

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ISO-NE’s Final 10-year Demand Forecast Tapers Expectations

ISO-NE has significantly lowered the peak load and net energy estimates in its final 2025 10-year load forecast but still predicts the region’s peak demand will grow by over 2 GW by 2034, the RTO told its Planning Advisory Committee on April 29.  

The reduced demand growth expectations are driven largely by reductions in ISO-NE’s adoption forecasts for heating and transportation electrification. The RTO cut its electrification forecasts in response to data indicating its previous forecasts significantly overestimated the adoption of electric vehicles and heat pumps. (See ISO-NE Scales Back Vehicle, Heating Electrification Forecasts.)  

The final forecast predicts the RTO’s summer peak for an average year will grow from 24,803 MW in 2025 to 26,897 MW in 2034. It expects the winter peak to grow more rapidly — from 20,056 MW in 2025 to 26,020 MW in 2034. Compared with the 2024 10-year forecast, ISO-NE reduced its 2033 summer peak projection by 2.1% and its winter peak projection by 7.1%. 

The RTO expects the winter peak to surpass the summer peak at some point in the 2030s due to heating electrification. The model predicts that average winter and summer peaks will be about equal by 2035, though the winter peak could pass the summer peak earlier under more severe winter weather conditions.  

The projections also reflect major changes to ISO-NE’s base modeling methodology, including the incorporation of hourly data, additional weather scenarios and climate change effects. (See ISO-NE Cuts Winter, Summer Peak Load Forecasts for 2033.)  

Hourly modeling allows ISO-NE to evaluate “a wider variety of system conditions, not just peak loads,” and capture peak loads that occur any time of day, not just in the evening, said Victoria Rojo, supervisor of load forecasting at ISO-NE. Rojo said ISO-NE expects morning winter peaks to become more common as load from heating electrification increases. 

Based on an evaluation using the updated hourly forecasting, Pradip Vijayan, manager of transmission planning at ISO-NE, said the RTO plans to simplify its transmission planning studies to focus on just two scenarios: a midday peak high renewable scenario and an evening peak scenario.  

“For transmission planning high net summer peak load analysis, the ISO proposes modeling 95% of the coincident gross peak load with 0% PV,” Vijayan said, noting that, as the net summer peak load moves to later in the evening in the coming years due to rooftop solar, “this load level should cover both the coincident net peak load conditions in New England and non-coincident net peak loads for most load zones.” 

For the winter, he said ISO-NE plans to continue modeling the peak as “100% of the gross New England winter peak with 0% PV,” noting the “significant variance in PV availability on high winter load days.” 

Updated Interface Limits

Also speaking at the PAC meeting, Alex Rost, ISO-NE’s director of transmission services, said the RTO will increase the Surowiec-South and the Maine-New Hampshire interface transfer limits to 2,200 MW because of network upgrades associated with the New England Clean Energy Connect (NECEC) transmission line. The Surowiec-South limit in Maine now is set at 1,800 MW, while the Maine-New Hampshire limit now is 2,000 MW.  

Rost said the increase of the Surowiec-South interface will allow for the increase in the capacity import capability of the New Brunswick-New England interface from 980 MW to 1,000 MW.  

The updated interface limits will be used in forward capacity market analyses, beginning with the overlapping interconnection impacts analysis for the 2025 interim reconfiguration auction qualification process, which will “determine whether there is sufficient capacity capability to qualify any proposed new capacity resources,” Rost said.