Search
December 16, 2025

Posted on

N.J. Gubernatorial Race Spotlights Clean Energy Policy

Clean energy policies and their impact on rising utility rates are under scrutiny in New Jersey’s most competitive gubernatorial race in years as voters decide on a replacement for Democratic Gov. Phil Murphy, a champion of green energy. 

Six Democrats and five Republicans have filed to seek the governor’s office, which Murphy used to aggressively promote offshore wind (OSW) projects, electric vehicle (EV) adoption and building electrification strategies. Murphy called on the state to have 100% carbon-free electricity by 2035. 

With the primary scheduled for June 10 and the general election Nov. 4, candidates have been bombarding voters with campaign ads for weeks. 

Yet the terrain faced by the candidates is vastly different — and less friendly to clean energy — from the one Murphy enjoyed in his two terms in office. The state’s major gamble on OSW largely has stalled amid logistical and cost challenges, flagging public support and opposition to wind power from President Trump. 

And the state could experience energy shortfalls because too few new generating sources are coming online as fast as old fossil-fueled plants shut down. That has helped cause a dramatic hike in electricity prices that has led to consumer outrage. (See NJ Lawmakers Sound Energy Supply Alarm.) 

Ratepayers will see the average bill rise by about 20% on June 1, a hike that has triggered a vigorous inquiry from legislators on what happened and how the state can boost its supply. Observers say electricity generation likely will emerge as a campaign issue with an intensity rare in electoral and public policy debates. 

“I don’t think it’s hyperbole to say that this is probably the most important gubernatorial primary in recent memory for both sides of the aisle, for the directions of both parties, and certainly for policies for environment and energy,” said a leading environmental advocate. 

Future Power Shortage

The rate hike comes as the public already clearly is concerned about energy costs, according to a poll by the William J. Hughes Center for Public Policy at Stockton University. It found that 67% of registered voters said utility costs were getting worse, compared with 27% who said they remained the same. 

New Jersey officials say the rate hike was created by the PJM capacity auction in July 2024, which resulted in a price increase that was 10 times larger than in previous years. PJM says the auction outcome was shaped in part by a surge in demand from EV use and a predicted influx of energy-intense data centers. New Jersey officials blame PJM’s inaccurate forecasting, saying it predicted more future demand than is realistic, which pushed up auction bid values. 

Micah Rasmussen, director of the Rebovich Institute for New Jersey Politics, said energy likely will be a more central issue in the general election than in the primaries. 

“The Republican candidates all point to Gov. Murphy’s clean energy policies as being responsible for the high cost of energy in the state, as well as present and future supply constraints,” he said. “We should expect to see some (GOP) scapegoating of New Jersey’s clean energy investments as being responsible for this year’s sticker shock in the cost of residential electric, even though that’s directly attributable to the annual PJM auction.” 

Moreover, “Democratic candidates will not be jumping to the outgoing governor’s defense,” he added. “So there’s not a tremendous amount of intra-party contrast.” 

The Trump Effect

New Jersey traditionally leans Democratic — both U.S. Senators are Democrats, and no Republican has won a U.S. Senate seat since the mid-1970s. The Democrats control both state legislative houses. But Republicans have succeeded in gubernatorial races — with Chris Christie and Christine Todd-Whitman each winning twice in the past 30 years.  

To add to the uncertainty, Murphy’s second electoral victory, in 2021, was much closer than his 2017 election, which some analysts attributed to public concern over his clean energy push. Others felt it was a reaction to the impact of the pandemic. 

Throw in Trump’s dominance of the Republican party, and his recent ability to attract swing voters, and the gubernatorial outcome is far from predictable. Vice President Kamala Harris in the 2024 election won by only 5 points. 

That has unnerved some environmental groups, which hope a Democratic victory would enable the state to continue many of Murphy’s policies even in the face of Trump’s crackdown. They argue that clean energy is the solution to the state’s pending energy shortfall. 

“The political environment, the protection of our natural resources, is more important than ever,” said Ed Potosnak, executive director of the New Jersey League of Conservation Voters. “I think right now, affordability is front of mind. I just can’t say it enough: Clean energy is the cheapest energy, and it’s also going to save money in the long run.” 

Democratic Nuance

The six Democrats seeking the governor’s office include Steve Sweeney, a longtime legislator and the former state senate president, and Steve Fulop, a former Marine and an Iraq war veteran who is mayor of Jersey City, the state’s second-largest city. 

Two members of the U.S. House of Representatives are running: Mikie Sherrill, a former Navy helicopter pilot and federal prosecutor, and Josh Gottheimer, who worked at the U.S. Commission on Civil Rights under Presidents Obama and Clinton. Also running are Ras Baraka, the mayor of Newark, New Jersey’s largest city, and Sean Spiller, a former high school science teacher and mayor of Montclair, who also is president of the New Jersey Education Association, the state’s powerful teachers’ union. 

In general, the candidates support a commitment to clean energy, with some nuanced divergences from Murphy’s path. Gottheimer, for example, who is more of a centrist Democrat, touts an “all-of-the-above” energy strategy on his campaign website, setting a distance from Murphy’s single-minded focus on electrification. 

Sherrill’s commitment to “invest in clean energy like solar” suggests a far more vague clean energy focus than the current governor’s vision. 

Fulop backs Murphy’s OSW commitments, one of the governor’s most controversial moves. Polls have shown a drop in support for offshore wind, from 82% in favor in 2008 to 54% in 2023. Republicans and Jersey Shore residents in the past 18 months have waged an aggressive campaign to head off the projects, in part by expressing concern — somewhat improbably — for the impact on the area whale population.  

Baraka embraces Murphy’s stance of fossil-free electricity generation by 2035. 

Sweeney largely avoids energy issues on his campaign website, but suggested to Fox News that he would halt the state’s adherence to Murphy’s earlier commitment to be 100% clean energy by 2050.  

Potosnak, of the League of Conservation Voters, said his organization endorsed Sherrill, in part because she is “not the same as Murphy” and has a “fresh perspective.”   

She outlined a more “robust and innovative” solar program than Murphy’s, “putting solar on as many as is practical government buildings and parking lots, which is great, because that saves us from cutting down forests,” he said.  

“I don’t think the environment is a left or right issue. It’s an issue of critical importance to our future, for our families, for our businesses,” Potosnak said. But he added that while Republican candidates for a variety of offices have in the past courted the League’s support, none did in this gubernatorial race. 

“We reached out to them,” he said. “Unfortunately, none applied for the endorsement.” 

GOP OSW Ban

That disinterest in the League’s outreach likely stems in part from the GOP’s tight embrace of Trump, who has frozen the nation’s offshore wind projects and is believed to be considering cuts to subsidies for clean energy, such as the federal tax credits for solar and EVs. 

A poll released April 25 by the Eagleton Institute of Politics, a unit of Rutgers University, found that the Democratic race is close, with Sherrill leading the pack with 17%, followed by Fulop at 12% and Spiller, Baraka and Gottheimer all at 9 or 10%. 

The poll found the Republican race much less open, with 42% of New Jersey registered Republicans and Republican-leaning independents surveyed saying they prefer Jack Ciattarelli. A former assemblyman, Ciattarelli ran against Murphy in 2021 and came within three points of beating him. The second-place candidate in the poll, former radio host Bill Spadea, drew 12%. 

Ciattarelli, Spadea, Barbera and Kranjac are all strong Trump supporters. 

Bramnick has criticized Trump, and he argues that he’s the Republican most in tune with New Jersey’s centrist voters and so is most electable in the general election.  

Spadea, in a recent post on X, rebuffed Democratic criticism that PJM carries the blame for state’s future energy shortfall. He blamed the Democrats’ “radical climate change agenda” for plant closures. He said he would scrap Murphy’s Energy Master Plan, cut subsidies for wind and solar, and increase nuclear and natural gas electricity generation. 

Bramnick has called for the state to pursue natural gas and nuclear solutions until clean energy technologies become “more affordable and reliable.”  

Ciattarelli says that if elected, he would draft a state Energy Master Plan based on an all-of-the-above energy policy. He wants to ban offshore wind farms and withdraw New Jersey from the Regional Greenhouse Gas Initiative (RGGI). He also would “repeal unrealistic and unaffordable state mandates and timelines regarding electric vehicle sales, household appliances, home renovation and home construction — which would make New Jersey even more expensive,” his website says. 

He doesn’t name the mandates, but that likely would include Murphy’s 2021 commitment to New Jersey to California’s Advanced Clean Truck (ACT) regulations, which require truck manufacturers to meet increasing electric vehicle sales targets, and his 2023 adoption of the Advanced Clean Cars II, which will require all new light-duty vehicles sold in the state to be zero emission by 2035. 

Murphy’s administration also has vigorously promoted building electrification — the use of electric heating and hot water systems — but has not mandated their use and says he would rather use incentives to get the job done. 

Posted on

FERC-NARUC Collaborative Examines Ongoing Issues with Gas-electric Coordination

It’s been more than a decade since participants in the natural gas and power sectors identified the lack of gas-electric coordination as a key risk for the operations of both industries. 

And while there’s been progress since then, the steady growth of gas-fired generation and continued disconnect between the sectors’ business models gave the Federal-State Current Issues Collaborative plenty to discuss on the subject during an April 30 meeting at FERC headquarters. 

“I think I saw a number that 47% of all power gen in America now is gas,” FERC Chair Mark Christie said at the meeting, which brought together representatives of FERC and the National Association of Regulatory Utility Commissioners (NARUC). “So, gas has become just absolutely critical to our to our electric system’s reliability.” 

But gas also is important to manufacturers, as well as residential and other end-use customers who rely on the fuel to stay warm in winter, he added. 

Gas generation is important to the grid not only for the huge volume of power it produces, but also because its operational characteristics enable it to balance intermittent resources, which have been growing rapidly, NERC CEO Jim Robb said. 

“I’ve also been a very outspoken critic of the state of natural gas-electric industry coordination since my time as the CEO of WECC in the Western Interconnection and over the past seven years in my time as the CEO of NERC. I’ve described these challenges as the most admired problem in the energy sector, and it’s time to stop admiring them,” Robb said. 

The electricity industry has experienced five well-publicized winter reliability events over the past 14 years that implicated gas-electric coordination, though changes made in response to those events bore fruit this past winter as industry participants made it through several weeks of arctic cold without incident, he added. (See FERC, NERC Say Grid Winter Recommendations Working.)  

But more work is needed, as highlighted by the massive April 28 blackouts on the Iberian Peninsula. It will take some time for the industry in Spain and Portugal to determine the cause of the outages, and it could be weeks before the true causes are known, Robb said. 

“There are, however, a couple of observations that do seem clear,” he said. “By all open-source reports, there was very little traditional generation in operation at the time of the cascade. While other factors may play a role, the lack of spinning generation and the inherent inertia it creates undoubtedly allowed the situation to spiral out of control more quickly than had those plants been operating.” 

Lack of Inertia

Inverter-based resources such as wind and solar do not offer the grid the same levels of inertia that a large spinning mass provides, which means when grid frequency deviates from a stable level, there are fewer resources capable of absorbing that change, allowing outages to cascade more broadly, Robb said. Some new inverters could address that issue, but the technology has not been proven, he said. 

Largely islanded systems, like those in ERCOT and the U.K., already are running into inertia issues today, said ISO-NE CEO Gordon van Welie. But those problems are not expected to be felt in the Eastern Interconnection for another decade or so, he said. 

Van Welie contended that gas-electric coordination issues are still relevant today because the gas system and electric grid are really one system aimed at delivering energy. ISO-NE’s position at the end of the gas pipeline network, without any local supplies of the fuel, makes those issues more acute for New England. 

“Fundamental differences between the gas and electric markets require acknowledgment and specific actions to mitigate and/or account for those differences,” van Welie said. “The electric system is planned and built on forecast mode, while the gas system relies on ad hoc, long-term customer contracts. This makes it difficult for the gas and electric systems to function efficiently as interdependent systems.” 

He pointed out that gas pipelines are built based on firm contracts signed with demand, and that there is no central planning to meet peak demand plus a reserve margin like on the power grid. 

Ohio Public Utilities Commissioner Dennis Deters asked what can be done with large data centers that are “bringing their own generation” to get to market quickly and what impact that could have on the gas system. 

That development illustrates the possibility that the gas industry is not planning for new demand, van Welie said. 

‘Intense’ Planning

But natural gas utilities do have to plan to meet demand on the coldest day of the year, when the gas system delivers three times as much energy as the grid does on the hottest day, American Gas Association CEO Karen Harbert said. 

“We do have intense resource planning, and we do have long-term contracts so that the people that have contracted for the gas get the gas — full stop,” Harbert said.  

She said data center operators used to start their development process at offices of state governors, seeking to get the best tax treatment possible.   

“And then the last place they would go would be the utility. Where’s the first place they are going now? It’s the utility,” she said. 

That allows the utilities to explain how much headroom is available on their system and how long it could take to connect major new demand, she added. Those questions increasingly are driving where data centers go, and Harbert said it’s important to keep those facilities in the U.S. 

Harbert expressed agreement with many in the electric sector that new pipelines and other infrastructure — especially storage — will be needed to ensure reliability for both systems. The politics of expanding pipelines in New England have for years been fraught, but van Welie said an increased focus on affordability in the region could start to change that.  

“I think the real gap, though, is that there was an unintended consequence when we restructured the industries, particularly the electric industry, 25 years ago,” van Welie said. “So, in a place like [Dominion Energy’s Virginia territory] or in Florida, when you build a new gas power station today … you bring the package along to the state regulator and you get approval for the whole thing — the power plant, plus the firm gas transportation contracts, which then results in infrastructure. So, when we unbundled the industry 25 years ago, we broke those linkages.” 

Contributing to the problem is the fact that local gas delivery companies must plan around firm load for their direct customers, but not for electric generators. Resolving that issue is important to both industries because extreme cold can cause issues on either the gas or electric system that then degrade the reliability of the other, as seen in Texas in February 2021 during Winter Storm Uri, van Welie said. (See Texas Supremes Hear Arguments in Last Uri Case.) 

“It’s not a criticism, it’s a reality,” van Welie said. “We’re not planning it to meet the full demand that’s being placed on that system, both the average demand that we placed on it over time as well as the instantaneous demand that is placed on it for purposes of balancing the electric system.” 

Expansion of gas storage represents one way to deal with the issue. On that front, the gas industry has increased the amount of LNG storage in the Northeast in recent years, since the region lacks the right geology for natural storage caverns, said Harbert.  

But while that helps her members, the disconnect in the business models means the issues van Welie highlighted are still there. 

Dominion Energy Virginia has faced nothing like the issues New England confronts around gas-electric coordination, but the fuel has become the backbone of its system in recent years, said Edward Baine, the company’s president of utility operations. The utility won approval in February for its Brunswick-Greensville LNG storage facility to serve two of its gas plants that lacked alternative supplies. 

“Between 2019 and 2023, these two power stations contributed more than 25% of the company’s energy production and achieved a combined capacity factor of approximately 75%,” Baine said. “Importantly, Brunswick and Greensville are two power stations in our fleet that do not presently have on-site backup fuel or access to multiple gas facilities.” 

Posted on

IESO Tweaks Modeling for Outage Management

IESO is incorporating a wider range of risks in its Reliability Outlook (RO), an 18-month forecast used to manage generator and transmission outages, a move it says will make it slightly easier to schedule summer outages.

The new probabilistic approach departs from the outlook’s deterministic focus on “normal” and “extreme” weather scenarios. The new methodology also changes how the ISO projects hydro and wind output and how it accounts for imports and planned loads.

The changes will bring the RO in line with best-practice forecasting methodologies and is a better fit for the evolving supply mix, with increased solar, storage and other distributed energy resources, IESO officials said during a recent briefing.

The ISO uses the RO to comply with NERC and Northeast Power Coordinating Council reliability standards. Bonnie Chan, manager of planning assessments, said the ISO completed its shift with the publication of its RO methodology in late March.

The changes “will make sure that resource planning decisions are based on the most accurate, data-driven insights possible, helping us better align planning efforts with what’s happening in the market,” said Fatema Khatun, a stakeholder engagement adviser.

The new approach is a response to stakeholder feedback and a recommendation from the Market Surveillance Panel that the ISO improve the RO’s alignment with two other forecasts: the Adequacy Report, which focuses on Ontario’s electricity requirements for the next 34 days, and its Annual Planning Outlook, a 20-plus-year look used for evaluating long-term investment decisions and resource acquisitions.

IESO’s metric for determining resource adequacy is called the Reserve Above Requirement (RAR). The ISO begins its evaluation by derating its installed resources and imports based on factors such as effective forced outage rates. The resulting “available” resources are measured against the projected demand forecast and required reserves. If there is excess capacity, the ISO has a positive RAR.

Weather Scenarios

The RO previously used a deterministic approach to calculating resource adequacy based on an “extreme” weather scenario and the assumption it would be able to rely on up to 2,000 MW of imports year-round.

The outlook used 31 years of weather history — dry bulb temperature, dew point, wind speed and cloud cover — from six weather stations between Windsor, Ottawa, Toronto and Thunder Bay to generate normal (50/50 probability) and extreme (maximum) demand forecasts. The approach was limited in its simplified output projections for embedded wind and solar.

Probalistic weather simulations (right) provide a greater range than deterministic \”normal\” and \”extreme\” projections (left). | IESO

IESO will continue to use 31 years of weather history but add a new data source for predicting production from its 2,000 MW of embedded solar capacity: Global Horizontal Irradiance (GHI), which measures the total solar radiation received on horizontal surfaces.

“Cloud cover is not necessarily the most accurate input for our solar models,” said Andrew Trachsell, senior demand forecaster. “Unlike the previous methodology, where you’re looking at cloud cover at [a weather station] that could be 50 km away [from a solar farm], this [GHI] data is at a very granular level — at 2 by 2 km — so it is a much more detailed or accurate input.”

Demand Scenarios

IESO also is changing how it accounts for new demand in the province, which increasingly has been targeted by large loads seeking low-carbon power.

It will use a “planned” scenario to account for loads that are less certain to reach commercial operation during the forecast period but large enough to warrant consideration because of their potential impact on grid operations. Its “firm” demand scenario will be limited to loads with a high probability of going into operation during the forecast horizon.

The former approach, which used a monthly normalization, resulted in higher demand peaks, particularly in the summer.

“The previous methodology attempted to put a monthly peak — which is a peak at a higher level with certainty, and less uncertainty above it — into the forecast, and then apportion that monthly peak across the week,” Trachsell said. “Now we’ve moved to just strictly the weeks, and that means that you’re going to get a lower peak with certainty, but much more … variability above it.”

Wind and Hydro

IESO also has begun using probabilistic distributions to model wind and hydro production instead of using a median value for each week. That allows it to capture a broader range of risks, including the tail ends of low and high hydro and wind conditions.

In the past, modelers used a monthly median of production plus scheduled operating reserves; 2012 was the proxy for the driest year, with 800 MW of hydro subtracted for the summer months.

“Before we looked at it more deterministically, we had the normal and extreme, and that was kind of like the bookends and we used the extreme weather scenario to do outage management and decision making,” said Emanuel Moldovan, senior planner. “There’s no more bookends. It’s just one scenario.”

IESO has begun modeling wind output using a Weibull distribution, which allows for a more accurate representation of low wind conditions. | IESO

Trachsell said the ISO’s previous method also “forced everything into a normal distribution, with an assessment of what the uncertainty around that normal was that had to be calculated. And once again, this was a fixed approach that was not necessarily as robust as it could be.”

The new methodology models wind on a Weibull distribution in all months, which the ISO says is more accurate in accounting for low wind periods. A Weibull distribution also is more flexible than the normal distribution and can be used to model a wider range of data shapes, including skewed and non-normal data.

LOLE Allocation

As the region’s Planning Coordinator, IESO is charged with ensuring the loss-of-load expectation (LOLE) averages no more than one day every 10 years, the limit set by NPCC.

Going forward — “pending ongoing monitoring of the situation,” Moldovan said — the ISO will allocate 30% of the LOLE risk to the summer (May to October) and 70% in the winter (November to April).

The new approach will reduce the RAR in the winter and increase it in the summer, making it slightly easier to approve outages in the summer. “Although the winter RAR is decreasing, current system conditions do not indicate a need to reschedule outages due to resource adequacy concerns in the winter months,” IESO said.

Imports

Assumed imports will be reduced from 2,000 MW to 1,000 MW in winter in both the RO and the Adequacy Report to account for IESO’s capacity agreement with Hydro-Quebec, which needs firm capacity from Ontario during those months.

Overall, while the new methodology considers a wider range of risks, “the results are similar to the previous approach and should result in minimal changes for outage management,” IESO said.

Posted on

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.” 

Posted on

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.

Posted on

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.” 

Posted on

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%. 

Posted on

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.

Posted on

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.” 

Posted on

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.