Search
December 21, 2025

Posted on

Load Growth Putting Pressure on Capacity Markets in the Northeast

BOSTON — Capacity markets have brought significant cost savings for customers in the Northeast over the past two decades but now face the critical need to evolve amid rapid load growth and a changing resource mix, according to a group of experts.

“We’re in a moment that requires a significant amount of evolution,” said Liz Delaney, vice president at New Leaf Energy, speaking at the Energy Bar Association’s annual Northeast Chapter meeting on June 18.

All three of the Northeastern RTOs have pursued significant capacity market reforms in recent years; ISO-NE and NYISO are in the midst of significant capacity market overhauls — the Capacity Market Structure Review project for NYISO and the Capacity Auction Reform project for ISO-NE — while FERC approved major resource accreditation changes for PJM in 2024. (See FERC Approves 1st PJM Proposal out of CIFP.)

Since the inception of capacity markets, grid operators frequently have made design changes to reduce volatility and improve price formation and resource accreditation, said Marc Montalvo, CEO of Daymark Energy Advisors.

“I think all of these things are evolutionary and are important, and are a sign of a dynamic learning environment, as opposed to a sign of weakness,” Montalvo said.

However, with every significant change, “there are dollars at play,” Montalvo added. “Politics is just played differently than either engineering or economics, and that’s where we find ourselves now.”

In PJM and MISO, resource retirements and new large loads — including AI data centers — have contributed to major spikes in capacity prices. (See MISO Summer Capacity Prices Shoot to $666.50 in 2025/26 Auction and PJM Capacity Prices Spike 10-fold in 2025/26 Auction.)

While New York and New England have not experienced the same level of large loads seeking to come online, both have ambitious transportation and building electrification goals, which, if successful, would drive significant load growth. The region also could see the addition of smaller-scale data centers. (See Limited Demand for Large-scale Data Centers in New England.)

Data center growth “really puts pressure on every corner of the industry,” said Samuel Newell, principal at the Brattle Group, noting that the recent spike in load growth projections appears to be “much more than our development pipeline, supply chains and transmission planning were ready for.”

There’s immense uncertainty around data center load growth, and it can be difficult to know if proposed load sources are real or speculative, Newell said.

“There’s so many uncertainties with regard to what demand will be, what computational efficiencies will be,” Newell said. “I don’t think it’s realistic to forecast it well.”

While rising capacity prices should increase the incentives for new resources, high costs also can cause political blowback for RTOs, a circumstance experienced recently in PJM.

“That’s real money in residential, commercial and industrial customers’ pockets … and it’s turning out to be a real political problem and flashpoint,” said Walter Graf, chief economist for PJM.

In New England, the capacity market has successfully signaled whether to build new resources and has helped shield customers from risks associated with generation development, said Bruce Anderson, senior vice president at the New England Power Generators Association (NEPGA).

In recent years, the region has seen “historically low clearing prices, reflective of the system at large,” Anderson said. Although ISO-NE anticipates load growth to accelerate over the next 10 years, peak loads in the region have been relatively static over the past decade, in part due to energy efficiency gains and the deployment of rooftop solar.

Anderson said he’s “very hopeful” about the capacity reforms underway at ISO-NE and is particularly interested in the capacity accreditation changes, which should allow for increased “substitutability” between different resource types in the market.

He added that ISO-NE’s proposal to cut the time between capacity auctions and the capacity commitment period (CCP), and split CCPs into summer and winter periods, should help the region cope with increasing winter reliability risks and enable better-informed investment decisions.

While ISO-NE’s CAR project creates short-term market uncertainty, Anderson said he hopes the capacity market that emerges will be able to provide a “period of stability” once finally implemented in the 2028/29 CCP.

“Getting some stability in the market, that really helps in investor confidence and investor decisions,” Anderson said.

He also said NEPGA members have discussed the potential to bring back some version of a price lock for new resources, which may help serve as an alternative to strict reliance on state contracts to bring more resources into the market.

In 2020, FERC ordered ISO-NE to eliminate its allowance of a seven-year price lock for new entrants, a move that was supported at the time by NEPGA. (See FERC Orders End to ISO-NE Capacity Price Locks.)

Other speakers spoke favorably about a seasonal market construct but expressed some skepticism about ISO-NE’s “prompt market” proposal, questioning whether the market will provide enough certainty to attract investment in new resources.

“I’m personally a bit skeptical of the benefits of New England moving from a forward to a prompt structure,” said Montalvo.

Delaney of New Leaf emphasized the importance of providing enough transparency to allow participants to model market outcomes multiple years into the future. She added that creating avenues for bilateral contracting is essential to helping new resources come online.

“We need some level of certainty over a significant portion of the revenues to make the math work,” Delaney said.

Posted on

N.J. Launches Ambitious Energy Storage Incentive Program

The New Jersey Board of Public Utilities has launched a storage incentive program, aiming to develop 1,000 MW of capacity to mitigate the state’s energy shortfall. 

The first phase of the Garden State Energy Storage Program has a goal of developing 350 to 750 MW in transmission scale capacity by October. The agency aims to award the remainder of the first phase capacity by next May. 

The program will have a competitive solicitation, according to the June 18 board order explaining the plan. Financial support in the form of fixed incentives will be paid over 15 years. The program will be open to stand-alone energy storage projects as well as solar-plus-storage projects. The pre-qualification process will start June 25, and the final bid submission deadline is Aug. 20. 

“These projects are essential for mitigating the electric capacity supply crunch that is driving dramatic rate increases for New Jersey customers,” according to the order. It adds that “quantitative analysis” by the BPU staff indicates the project will “provide net savings to ratepayers within the first few years of its operation.” 

Boosting Supply

New Jersey, like other states, faces a potential energy shortfall, which PJM attributes in part to the closure of fossil fuel generators faster than new — mostly clean energy — facilities come online. Surging demand from data centers and electric vehicles exacerbates the problem. 

A BPU release said the storage project “directly addresses demand growth and limited supply.” 

“By strategically investing in energy storage now, we’re building a resilient system that can better withstand both man-made and weather-related disruptions,” BPU President Christine Guhl-Sadovy said in a release. She added that storage also can “support the critical integration of more clean energy, which is vital for New Jersey’s sustainable future and peace of mind.” 

Democratic legislators and BPU officials argue that solar and storage projects are the quickest and cheapest way to add new electricity generation. Storage can provide power overnight or when the sun is not out, and help meet spikes in demand. The BPU says storage can boost the supply of electricity, thus reducing prices.   

Guhl-Sadovy called the launch of the program a “pivotal moment for New Jersey’s energy landscape,” 

“This isn’t just about meeting our climate goals, it’s about making sure every family can afford to keep their lights on and their home comfortable,” she said. 

New Jersey’s Clean Energy Act of 2018 requires the state to deploy 2,000 MW of energy storage. The state already has missed a state target of having 600 MW of storage in place by 2021. The BPU said last year the state had just 560 MW of installed storage. 

Future Phases

The BPU in 2015 established the Renewable Electric Storage Incentive Program and also offered incentives to solar projects coupled with storage under the agency’s Successor Solar Incentive (SuSI) program, neither of which covered the large scale and sweep of the latest program.  

The BPU’s first version of the Storage Incentive Program (SIP), released in 2022, focused on how to stimulate storage. It since has been modified into the current version through a series of public hearings. (See Impact of NJ’s Storage Plan on Overburdened Communities Questioned.)  

The second phase of the new program is intended to be launched in 2026 but was not approved in the June 18 order. It would “focus on incentives for smaller energy storage systems connected to local distribution grids, including both “in front of the meter” (grid-connected) and “behind the meter” (residential or commercial) systems, according to the BPU release. 

A third phase that would offer transmission performance incentives also is under consideration, but the phase is “currently deferred” according to the order. 

Fred DeSanti, executive director of the New Jersey Solar Energy Coalition, said in an email to RTO Insider that he understands “the potential good that can come of transmission level storage in terms of helping with the capacity shortfall.” But he expressed concern that the funding would come from the Regional Greenhouse Gas Initiative (RGGI). 

DeSanti said the state, an energy importer, has reaped most of the benefits it can from participating in the RGGI program. He added that by deferring the behind-the-meter proposal to the second phase of the storage program, the state “misses an opportunity to help this important market” just as it faces the loss of crucial tax credits in the federal budget being shaped by Congress. 

Mitigating Ratepayer Pain

The BPU emphasized the way extensive storage capacity could help bring down electricity prices in the state, as the agency also backed a series of initiatives designed to mitigate the impact of the recent 20% hike on the average ratepayer bill. 

The board approved changes in the state universal service fund (USF), which provides credits to low- and moderate-income ratepayers struggling to pay gas and electricity bills. The board increased the minimum USF benefit from $5 to $20 and the maximum benefit from $180 to $200. 

The board order also requires utilities to increase ratepayer enrollment in the program to ensure that more eligible ratepayers benefit. The state’s four utilities are required to increase by 5% their enrollment in the program during the year from October 2024 to September 2025. They should increase enrollment by 3% in the second year and by 2% in the third year, according to the plan. 

The changes are expected to affect 136,000 existing customers who receive the minimum benefit and an additional 8,000 who receive the maximum benefit, according to the BPU. The utility enrollment efforts are aimed at the 80% of eligible household that are not signed up for the benefit. 

The changes will cost about $28.5 million, which will be paid with existing funds, the board said. 

Posted on

DOE’s Wright Fields Senate Questions About Funded Project Reviews

Senators had a chance to ask Energy Secretary Chris Wright about project spending his department has put under review — or already cut — when he testified at the Senate Energy and Natural Resources Committee about the Trump administration’s 2026 budget request.

“It is deeply concerning how many billions of dollars were rushed out the door without proper due diligence in the final days of the Biden administration,” Wright said during his June 18 testimony. “DOE is undertaking a thorough review of financial assistance that identifies waste of taxpayer dollars, protects America’s national security and advances President Trump’s commitment to unleash American energy dominance.”

He said that led DOE to terminate 24 projects totaling $3.7 billion in spending that failed to meet the economic, national security or energy security standards needed to sustain the agency’s investment.

Ranking Member Martin Heinrich (D-N.M.) said those deals were canceled without notice or justification and that DOE crossed into “impoundment territory,” which is when the executive branch cancels congressionally approved funds, an act only legal in narrow circumstances.

“Actions like these will severely damage our country’s ability to lead in developing and commercializing next generation technologies while ceding ground to our competitors,” Heinreich said.

Sen. Steve Daines (R-Mont.) asked about the North Plains Connector transmission project, which would run through his state and connect the Eastern and Western interconnections. Last summer it was awarded funds under the Grid Resilience and Innovation Partnership (GRIP). (See DOE Announces $2.2B in Grid Resilience, Innovation Awards.)

The project would open new markets to the Colstrip power plant, which currently is linked to utilities in Oregon and Washington, Daines said.

“This project would have the potential to diversify Montana’s generation assets, unlocking billions in private investment and enhance our nation’s energy security by connecting the Eastern and Western Electric grids,” he said.

Wright said he has met with the North Plains Connector’s developer previously and called the project — and the general idea of increasing transfer capability across the two interconnectors, a good idea.

“We are committed to following this project review process where a crew of people evaluate — not political, not biased for this or that,” Wright said. “Just look at the math, look at the numbers, and is this thing viable and beneficial for America. You know, yes, no or adjustable — it’s modifiable. So, we haven’t finished that on that project yet, but I think you make a strong case for the project.”

‘Demand and Pressure’

Sen. Angus King (I-Maine) noted that GRIP funding was approved under the bipartisan Infrastructure Investment and Jobs Act, and not the Inflation Reduction Act, which is much more unpopular with Republicans. He asked whether the DOE’s review of projects will be fair.

“We’re evaluating the engineering, the science, the finance and just the viability of the projects,” Wright said. “It is just a business review. Unfortunately, it wasn’t done before when grants were given. But I would say, in the GRIP program, there’s a lot of very good projects there.”

King then asked about a major energy storage project being built north of Bangor, Maine, by Form Energy, which is under review by DOE currently. (See: Form Energy to Develop First Multiday Storage Project in New England.)

“We stood up this process a few weeks ago,” Wright said, adding that the agency expects to do at least 20 reviews a week and telling King that he’s “very interested” in storage as well. “My chief of staff here is here with me, and we’ll make sure that in the next few weeks at most, we will get on to that project.”

King additionally said he didn’t understand why the Grid Deployment Office is facing a 75% cut in funding under DOE’s budget request, given the “demand and pressure” on the grid.

Wright said he thinks DOE’s most important grid-related offices are the Office of Electricity and the Office of Cybersecurity, Energy Security and Emergency Response. The budget cuts to GDO are part of a reorganization that will refocus its work in the Office of Electricity.

King said he hoped the funds earmarked to strengthen the grid are not slashed in the face of rising demand and more expensive power bills for consumers.

“One of the things I’ve noticed just in my career in energy is it used to be that the principal part of your electric bill was the cost of energy,” King said. “Now, in many places, transmission and distribution is 50% or more, and that’s only going to increase, unless we start to think about new technologies, what are called GETs, which I’m sure you’re familiar with — grid enhancing technology, so that we’re not simply rebuilding massive facilities that could be obviated by new technologies.”

Posted on

Georgia Power Calls Largest-ever 50-50 Hydrogen Test a Success

A natural gas-fired plant outside Atlanta has completed what is described as the largest 50% hydrogen-gas blending test of its kind in the world. 

The trial was the latest in a series by Georgia Power and Mitsubishi Power at Plant McDonough-Atkinson in Smyrna, Ga., a former coal facility that was converted to natural gas in 2012. 

In 2022, the two companies and the Electric Power Research Institute carried out a similar test that also was the world’s largest up to that point, producing 265 MW at full load from an M501G advanced gas turbine with fuel that was 20% hydrogen by volume. 

In May and June, a series of tests at full and partial load culminated in 283 MW output with 50% hydrogen from an M501GAC turbine that had been converted from steam-cooled to air-cooled. 

The 20% hydrogen test achieved a 7% reduction in carbon emissions compared to 100% natural gas; the 50% hydrogen test achieved a 22% reduction. 

Georgia Power said in a June 16 news release that it entered the collaboration with Mitsubishi as part of its research and development efforts toward affordability, reliability and carbon reduction. 

But it did not specify what it would do with the results. A spokesperson told NetZero Insider that the utility and its partners would study the results of the trials to better assess the future potential of hydrogen. 

What to do with hydrogen is a common question these days. 

Clean hydrogen was a priority of the Biden administration as a clean, or less dirty, alternative to fossil fuels, but the rollout was delayed amid extensive debate over how to define “clean hydrogen” and how to subsidize its development. Many of the potential investments in hydrogen industrialization contemplated by the private sector were held back until these critical details were finalized. 

Final rules for the key 45V Clean Hydrogen Production Tax Credit were not issued until January 2025 — more than two years after the credit was authorized and less than three weeks before the arrival of President Donald Trump and his sharply different energy agenda. 

The latest word on congressional budget negotiations is that 45V is in line to be slashed or scrapped, the biggest loser among all the Biden-era green initiatives. 

Without the federal government’s carrot or stick urging wider adoption of hydrogen, an already-challenging proposition is losing some of its appeal. But some had never been sold on widespread use of hydrogen in the first place. 

The Institute for Energy Economics and Financial Analysis, for example, criticized the concept of hydrogen-fueled gas turbines in an August 2024 report, laying out all the challenges that face such an attempt and pitching existing options as better alternatives. 

If nothing else, hydrogen is not a one-to-one substitute for natural gas: It is much less energy-dense, meaning a greater volume is needed to generate the same amount of electricity. A 50-50 mix by volume, as at McDonough-Atkinson, does not produce anywhere near a 50% reduction in emissions because much more methane than hydrogen is being burned. 

Further, the process of producing hydrogen can be expensive, create emissions of its own or result in a net loss of energy potential — or some combination of the three. 

Natural gas remains the largest U.S. power source. The 2,084 utility-scale gas-fired power plants tallied by the U.S. Energy Information Administration in 2023 produced 43% of the nation’s electricity. 

But in 2024, EIA counted fewer than a dozen of those plants flirting with hydrogen: four facilities besides McDonough-Atkinson where hydrogen co-firing had been tested, three new plants that were hydrogen-capable and two plants where planned upgrades would add hydrogen capabilities. 

Georgia Power expects to be burning natural gas for many years to come. Its 2025 integrated resource plan proposed nuclear uprates, natural gas expansion, and delayed coal and gas retirements to meet anticipated demand growth. (See Georgia Power Proposes Nuclear Uprate, Delay in Fossil Retirement.) 

In its June 16 news release, Southern Co.’s largest electric subsidiary said natural gas remains a central part of its strategy. 

“Natural gas serves a critical role in our generation mix, providing flexibility, baseload power and quick response to customer demand, and will continue to be an important fuel as we plan to meet the energy needs of a growing Georgia through a diverse portfolio of generation resources,” Senior Production Officer Rick Anderson said. 

But hydrogen is one of the future avenues the utility is considering, and the McDonough-Atkinson trials are part of that, he added. “Innovative testing such as this is just one way we help ensure we can deliver reliable and affordable energy for customers for decades into the future and reduce our overall emissions.” 

Posted on

Industry Sees Challenges as BPA Considers ‘Radical’ Updates to Transmission Planning

The Bonneville Power Administration faces monumental challenges in implementing actions to meet the Pacific Northwest’s needs once it lifts its pause on transmission planning, multiple stakeholders told RTO Insider.

BPA issued the pause in February to consider new “reforms” in light of “exponential growth” of transmission service requests. The agency’s 2025 transmission cluster study includes over 65 GW of requests, compared with 5.9 GW in 2021. The requests exceed the total regional load projected for the Pacific Northwest in 2034, according to the agency. (See BPA Halts Some Tx Planning Processes Amid Surge of Service Requests.)

To deal with the demand, BPA Administrator John Hairston has set ambitious goals for the agency. In a recent keynote address at the Western Conference of Public Service Commissioners’ annual meeting, Hairston noted that much of the challenge stems from planning “around prospective data centers or generators that may never come to fruition.”

Hairston said the agency sees the need for a “new planning paradigm.” It is “rethinking” its transmission planning processes and working with its utility customers to identify new approaches by the end of the year. (See Industry Needs ‘New Planning Paradigm,’ BPA Chief Tells Regulators.) Ultimately, Hairston wants to reduce the time from transmission request to service to five to six years.

In an email to RTO Insider, BPA spokesperson Nick Quinata said the agency “has committed to considering radical new methods to reduce the time it takes to enhance infrastructure to accommodate its customers’ needs.”

BPA will provide more information on its timeline and proposed solutions at a workshop in July.

A New Approach

But analyzing 65 GW is “impossible,” Randy Hardy, the agency’s administrator from 1991 to 1997, told RTO Insider.

“They’ve got to somehow define a set of rules that will give them a more realistic ability to analyze whatever subset of the 65 GW they deem appropriate,” Hardy said.

Much of the issue stems from aggressive clean energy legislation passed in Washington and Oregon in 2019 and 2021, respectively. The laws set strict standards for greenhouse gas emissions and ushered the region into a “gold rush” among developers, eventually leading to today’s situation, according to Hardy. (See Clean Energy, Equity Goals to Reshape Oregon IRP Process and Washington Agencies Adopt New Rules to Implement CETA.)

Even though not every project will be completed, BPA must assume the opposite when analyzing them, Hardy said.

“The cumulative costs associated with building all that transmission means that the expenses of any particular transmission service request are enormous,” he added.

He noted the 2023 cluster study included approximately 17 GW. The challenges with 65 GW are greater, and “even if you could analyze it, the cost would be so ridiculously high that nobody would sign up for anything.”

BPA must depart from the principle of first come, first serve when taking on requests, Hardy said.

The agency is “not regulated technically by FERC … but they’ve made a policy commitment to align themselves as closely as they can to the FERC pro forma tariff,” Hardy said. “They’re probably going to have to loosen that to some extent, because first come, first serve is not going to allow them to resolve this. They’ve got to be able to exercise some engineering judgment of the transmission service requests that are filed as to which ones look the most promising.”

Because FERC does not regulate BPA, the agency can and should take “bold steps” to clear up the transmission queue, Nicole Hughes, executive director at Renewable Northwest, told RTO Insider.

BPA should use its power to “wean out” speculative projects that are unlikely to get built. The challenge is to clear the queue equitably, Hughes said.

“We want to make sure that generation and load are being treated equitably and that load doesn’t take a higher priority here,” according to Hughes. “We want to make sure that the point-to-point customers are being treated equitably and the network customers aren’t being prioritized here.”

BPA has allowed other issues to take priority, like long-term contracts and its day-ahead market process, and the agency is now in “panic mode,” Hughes said. (See BPA Flooded with Comments on Draft Day-ahead Market Decision.)

Proactivity

Renewable Northwest has been a supporter of BPA taking a more proactive approach to transmission planning, Hughes said. She pointed to the Western Transmission Expansion Coalition (WestTEC), which is jointly facilitated by the Western Power Pool and WECC, as an example. (See WestTEC Tx Study on Track Despite Delays.)

WestTEC’s goal is to produce an actionable study to inform Western grid planning over 10- and 20-year planning horizons. Hughes said it’s unclear what BPA will do with the information coming out of the WestTEC process, saying “that’s still to be decided.”

Henry Tilghman, a consultant whose clients include Renewable Northwest and the Northwest & Intermountain Power Producers Coalition (NIPPC), said there is a disconnect between the development time frames for different types of facilities that need to be addressed. (Tilghman spoke with RTO Insider on his own behalf, not that of his clients.)

“You can bring a new gas plant or renewable generator online in 18 months once you have all of your permits and the financing in place,” Tilghman said. “The construction time can be a year and a half. Same for a data center. But if you’re looking at a new transmission expansion with all of the siting and permitting and everything, that … takes at least 10 years to do. …

“I think a lot of the problems that the region is facing that Bonneville is attempting to solve stem from really just sort of an inadequate regional planning process,” Tilghman added. “Even if we get it fixed … through Order 1920 compliance, we’re still catching up on all that planning work that could have been done and hasn’t been done.”

According to Lauren Tenney Denison, director of market policy and grid strategy at the Public Power Council (PPC), BPA is considering moving toward proactive planning as a possible solution.

“The cost and risk discussion is going to be a really important one throughout this process,” Denison said. “Building ahead of time, doing this proactive building that BPA is talking about, it has the ability to get us ready for future needs. But there is a cost to that, and so it’s just a challenging issue that we will need to address with the region as we work through this.”

Other challenges include the time it takes to build new transmission, a scarce labor pool and an arduous permitting process, PPC CEO Scott Simms said. For example, crossing state lines and different jurisdictions and federal agencies bring a host of bureaucratic headaches for developers, he said.

“We’ve seen proposals where segments of a line are approved and then they have a window, but there’s approval pending somewhere else, and then the original approval expires while the new ones being granted,” Simms said. “That’s just paperwork that can be easily revamped and removed.”

With a Little Help from Customers

There are opportunities for BPA customers to assist in developing transmission infrastructure, something Simms hopes will get fast tracked as the agency considers planning changes.

He said BPA appears willing to “engage or explore some disruptive elements that we haven’t done before.”

“We think that category includes the element of how customers of BPA can help shoulder some of that burden in order to make the regional objectives get achieved more quickly,” he added.

The PPC has support for this idea from NIPPC Executive Director Spencer Gray, among others.

“Bonneville has had, and does have, a pretty restrictive approach to outsourcing some of the grid upgrade work to customers,” Gray said. “We’re hoping that that can change. That feels like really low-hanging fruit. I think the place that’s most relevant is for network upgrades for interconnection customers. Both generators and load.”

There is an opportunity to leave more of the building to customers in the pro forma Open Access Transmission Tariff, according to Gray.

“We really think there’s room to liberalize that self-build option in the Northwest on Bonneville’s grid,” Gray said. Allowing a customer to either build themselves or contract out some of the work “would alleviate a lot of the burden on Bonneville itself to pull off some of these upgrades” and let the agency focus on “transmission service-driven upgrades rather than interconnection.”

Aaron Tinjum, vice president of energy for the Data Center Coalition, told RTO Insider in a statement that data center companies “are leaning in as engaged partners across the country to ensure we meet this moment in a way that supports both data center development and an affordable, reliable electricity grid for all customers.”

The industry is “committed to paying the full cost of service for the energy it uses, including transmission costs,” he said.

Workforce Challenges

Other reforms are needed to meet Hairston’s five-to-six-year timeline. A crucial one is allowing BPA to competitively pay staff. There’s a big pay gap between BPA and consumer- and investor-owned utilities, Gray said.

“Any entity of comparable size to Bonneville in terms of asset, ownership, operating revenue, circuit miles of transmission … they just pay more,” Gray added. “And if we’re going to keep good staff, new talented ones, we really need to get [BPA] competitive pay authority so [BPA] can compete in the market for personnel.”

The bipartisan Reliability for Ratepayers Act, passed by the U.S. House of Representatives on Jan. 15, aims to address this issue. Still, stakeholders told RTO Insider recent federal staffing cuts and “deferred resignation” buyout offers from President Donald Trump’s unofficial Department of Government Efficiency have caused significant disruptions and risk shaking morale at BPA.

About 200 agency employees — or 6% of the workforce — accepted the buyout offer, while 90 job offers had been rescinded following a federal hiring freeze announced Jan. 20, according to BPA.

U.S. Energy Secretary Chris Wright has said BPA will not undergo more staffing cuts as part of Trump’s quest to slim down the federal government. BPA’s federal workforce now stands at around 3,150 employees, Hairston said during the agency’s quarterly business review May 15. (See BPA Exempted from Federal Staffing Cuts, Hairston Says.)

Whether BPA can meet the five-to-six-year goal hinges on a sufficient workforce and the lifting of the federal hiring freeze, former Administrator Hardy said. He put the odds of accomplishing the goal at 50/50.

“They’re stuck with being down 200 positions when they actually need more than the 200 positions to be able to have sufficient staff to get them to a 90% or 80% level of confidence that they can accomplish all this stuff,” according to Hardy. “So can it be done? Maybe, but it is a huge, huge challenge given the staffing restrictions that they’re now subject to under the Trump administration.”

Posted on

Oregon Governor Signs Bill to Create Data Center Rate Class

Oregon Gov. Tina Kotek on June 16 signed a bill designed to ensure that operators of large data centers pay for grid upgrades needed to supply them with electricity, avoiding shifting those costs to residential ratepayers as the facilities proliferate across the state. 

The Oregon Senate on June 3 voted 18-12 to approve an amended version of House Bill 3546, dubbed the POWER Act, followed two days later by the House of Representatives’ concurrence and passage 37-17. 

The bill directs the Oregon Public Utility Commission to create a new retail rate class for big electricity consumers such as hyperscale data centers and cryptocurrency miners in order to allocate grid upgrade costs “in a manner that is equal or proportional to the costs of serving the class.” (See Oregon House Passes Bill to Shift Energy Costs onto Data Centers.) 

Rep. Pam Marsh (D) sponsored the bill to insulate residential ratepayers from the infrastructure costs associated with serving the burgeoning number of high-consuming data centers in the state, saying the “explosion of huge technology facilities has upended” the traditional process for allocating energy-related costs proportionally among consumers. 

The new law, which applies only to the investor-owned utilities overseen by the PUC, stipulates that the new class “must be separate and distinct” from existing rate classes for other commercial or industrial retail electricity consumers and have its own tariff schedule. 

The law creates a new class of consumer — “large energy use facility” — to identify electricity customers who are equipped to use 20 MW or more of energy and provide computing services, data processing, web hosting or other related services. 

Under the law, the tariff schedule adopted by the PUC must require a large data center to foot the bill for a proportionate share of the grid upgrade costs a utility incurs to serve the facility. 

The data center operator would additionally be required to enter a service contract with its utility for a minimum of 10 years and be obligated “to pay a minimum amount or percentage, as determined by the [PUC], based on the retail electricity consumer’s projected electricity usage for the electricity services the electric company is contracted to provide for the duration of the contract.” 

The law does not restrict large data centers from using Oregon’s “direct access” program, which allows nonresidential consumers to purchase electricity from a PUC-certified electricity service supplier rather than a utility. 

‘The Whole Freaking Point’

The bill won the support of groups like the NW Energy Coalition, BlueGreen Alliance, Sierra Club and the Oregon Citizens’ Utility Board, along with utilities such as PacifiCorp. 

However, data center companies voiced their opposition, with the Data Center Coalition in March filing testimony saying that, while it supported the intent of HB 3546, it believed “no customer, industry or class should be singled out for differential or disparate rate treatment unless that approach is backed by verifiable cost-based reasoning.” 

Ellen Zuckerman, Google’s head of energy market development for North and South America, echoed that view during a June 3 panel discussion at the Western Conference of Public Service Commissioners’ annual meeting in Portland, Ore. 

“If you create a discriminatory rate class for data centers, what signal are you potentially sending to them? Are you telling them then to go off-system and invest in behind-the-meter resources?” Zuckerman said. “You’re losing that opportunity to invest their capital in your grid.” 

Zuckerman asked whether that could create “a system of balkanized planning” and “a paradigm where certain large customers can say ‘these resources are only for us’” and not offer them to the broader grid when other generating resources are set to retire.  

“These questions are really complicated; they warrant really deep stakeholder conversation,” she said. 

Speaking on the same panel, CUB Executive Director Bob Jenks said the data center operators are right to call the new rate class “discriminatory.” But “that’s the whole freaking point of a rate class: discrimination. You’re discriminating based on attributes and costs that are being put on the system and allocating them,” Jenks said. 

“We have a residential rate class because residential customers require a larger distribution network. We have an irrigator rate class because irrigators put unique costs on the system because of their summer usage pattern,” he said. “Because of their size, [and] the speed at which they can be built, their growth rate and their inflexibility, data centers have their own attributes that deserve their own rate class.” 

Posted on

NERC Responds to MISO IMM’s LTRA Criticism

In a statement, NERC blamed “mismatched data” submitted by MISO for a calculation in its 2024 Long-Term Reliability Assessment that resulted in the ERO warning that the region could face energy shortfalls in 2025, while acknowledging its own responsibility for the mistake. 

MISO’s Independent Market Monitor David Patton called out the ERO for what he called a “completely inaccurate” perception at a June 10 Markets Committee meeting of the ISO’s Board of Directors in Minneapolis. (See MISO IMM Blasts NERC Long-term Assessment, Says RTO in Good RA Spot.)  

MISO was the only area of the continent labeled as “high risk” in the LTRA, published Dec. 17, 2024. The designation means that energy shortfalls are likely to occur under normal peak summer or winter conditions in the next five years. NERC said at the time that resource additions had not kept pace with retirements of coal-fired generation since 2023, causing “a sharp [projected] decline in anticipated resources” beginning in summer 2025. (See NERC Warns Challenges ‘Mounting’ in Coming Decade.) 

However, Patton asserted that NERC had incorrectly used MISO’s unforced capacity values instead of its installed capacity, then compared the resulting numbers to an installed capacity requirement. This error, which Patton called “an apples and oranges assessment,” reduced the region’s capacity by more than 10 GW in the LTRA. 

NERC’s statement said the ERO conducted an “in-depth review” and found MISO’s submitted data “overstated the near-term energy shortfall risk.” When the analysis was rerun with corrected data, NERC found MISO should be reclassified as “elevated risk” for the 2025-to-2027 time frame, meaning resources are sufficient for normal conditions but shortfalls could occur under extreme weather conditions.  

“While this data mismatch went unnoticed by MISO and the Midwest Reliability Organization (MRO) that initially collects and vets the data, NERC is ultimately responsible for ensuring the accuracy of its independent reliability assessments,” NERC said. “Going forward, NERC, MRO and MISO are all committed to improving the data validation process to ensure accuracy.”  

NERC said it regrets the discrepancy and plans to post a corrected version of the LTRA “soon,” but it did not specify a time frame. 

MISO’s risk level still could rise to high by 2028, NERC said, “depending on new resource additions [and] retirements.” The new data did not require MISO’s standing in the 2025 Summer Reliability Assessment to be changed, according to the ERO, because that report uses different data. The SRA found that MISO was at elevated risk of shortfalls, along with MRO-SaskPower, MRO-SPP, ERCOT, NPCC and WECC-Mexico in Baja California. (See NERC Warns Summer Shortfalls Possible in Multiple Regions.) 

At the MISO board meeting, Patton said the misleading LTRA already has influenced national policy, as shown by the Department of Energy’s directive to keep a 1.4-GW coal plant in Michigan operating over the summer. (See Consumers Energy Seeking Compensation for Keeping Campbell Open.) He warned the confusion could “lead to FERC ordering market changes that are unnecessary.” 

Posted on

MISO’s Queue Fast Lane, Take 2, Nets Déjà vu Arguments

MISO’s repackaged proposal to establish a temporary fast track in its interconnection queue resulted in a familiar division among MISO stakeholders, with vertically integrated utilities campaigning for the proposal and clean energy organizations protesting.  

MISO in early June refiled the fast-track proposal, this time with a 68-project limit that includes special reservations for retail choice states and independent power producers. The grid operator managed to refile nearly 1,000 pages of tariff changes, explanation and testimony within three weeks (ER25-2454). (See MISO Reapplies for Generator Interconnection Fast Lane with FERC.)  

MISO committed to processing 10 fast-track applications per quarter for five quarters. Additionally, it added placeholders for 10 projects from independent power producers who have power purchase agreements with non-utility entities and an additional eight projects that can be submitted only by retail states for resource adequacy deficiencies. MISO would sunset the expedited process no later than mid-2027, or until the project limit is reached.  

Clean energy groups aren’t fans of the revised proposal.  

A joint filing from Sierra Club, Sustainable FERC Project and Union of Concerned Scientists, among others, said the proposal still confers “preferential access to thermal resources at the expense of renewable resources.” They said MISO again failed to establish why the fast track was mission-critical for resource adequacy.  

In a press release, Sierra Club said MISO submitted “a plan that will take place over many years and fails to justify the cap size it chose.” The nonprofit said MISO finalized the new plan “after a single stakeholder meeting that only allowed one round of Q&A and an informal exchange of ideas on how to improve the first discriminatory plan.” It also noted that the proposal’s 10-day comment period included two weekends, “giving all stakeholders only six working days to evaluate” and form responses to the new proposal.  

Advanced Energy United, the American Clean Power Association, the Solar Energy Industries Association, the Southern Renewable Energy Association and Clean Grid Alliance said MISO’s filing “retains many of the shortcomings” of the first while introducing new legal concerns. It said MISO should clarify that its guarantee of spots for independent power producers with non-load serving entity off-takers should not preclude them from competing for the 50 original spots.   

“Accepting MISO’s unjust, unreasonable and unduly discriminatory and preferential proposal would undermine open access principles in the MISO region, derail the region’s existing generation queue, cast a pall of litigation risk over all stakeholders and ultimately jeopardize the long-term reliability and resource adequacy of the region,” the quintet wrote in a joint protest.  

The Michigan Public Service Commission argued that MISO’s refile “still gives rise to discrimination [and] lacks sufficient enforcement of shovel readiness and project completion.” It said MISO’s plan to cap the megawatt value of expedited projects at 150% of an identified need might shut out meaningful participation by renewable energy developers. The state commission also complained that MISO’s hurried refile and ensuing six-day comment period at FERC didn’t allow for stakeholder discussion or modifications based on suggestions. It asked FERC to reject the proposal and direct MISO to turn to its stakeholders to draft a more collaborative solution.   

Invenergy protested that MISO’s restyled proposal still vests regulators with “nearly unbounded discretion to select projects, without any objective criteria to judge whether such projects are capable of satisfying MISO’s resource adequacy needs.” It said MISO ignored FERC commissioners’ request that MISO retry with a narrowly tailored proposal.  

Competitive supplier Vistra Corp., which operates in Illinois, asked that FERC order an amendment to MISO’s proposal that gives independent producers until Dec. 1, 2025, instead of Sept. 1, to submit their projects for expedited treatment. It said MISO’s timelines are “too aggressive” for independents to contract with customers and meaningfully participate in the fast-track process “on a level playing field.”  

As they did the first time around, utilities chimed in to reaffirm their support.  

WEC Energy Group said the fast track is an “innovative solution” that would address an “urgent need for new generation resources.”  

Alliant Energy said MISO’s existing queue alone doesn’t provide a sufficient avenue for bringing critical generation online quickly. It also said MISO’s design doesn’t run afoul of FERC’s open access philosophy because it “does not restrict the type of generation facility that may apply or the entity which can submit.” Entergy and Cleco agreed in joint comments that MISO’s current framework “is not suited to address the need for immediate new resource additions.”  

Big Rivers Electric Corp. said the expedited treatment would ensure that load-serving entities “can meet their state-mandated obligations to reliably serve load.” It added that MISO’s resource adequacy challenges are “concrete and urgent.”  

Northern Indiana Public Service Co., Ottertail Power Co., DTE Electric, Ameren and Consumers Energy also registered support.

At a June 18 Louisiana Public Service Commission meeting, MISO’s Todd Hillman reviewed MISO’s additions of the project maximum, the limited number of cycles with a 2027 end date and allocation of projects for some independent power producers and MISO’s retail choice areas. He said the combination of those new elements should satisfy FERC’s initial concerns with the proposal and should “answer many if not all of their questions.”  

Commissioner Davante Lewis asked how MISO’s fast lane would avoid a “two-tier interconnection system that disadvantages” some projects and favors others.  

Hillman said MISO will work simultaneously over the next few years to get its normal queue down to a one-year process. He said the RTO is “confident” it can shorten time frames with the help of a new annual megawatt cap, AI-based software and some existing projects moving to the express lane.  

“They’re moving in parallel; they’re not really moving against each other,” Hillman said of the regular queue and the express lane.  

Posted on

NERC Details Performance Metrics in FERC Filing

Aiming to satisfy a FERC directive following the publication of the ERO’s five-year performance assessment, NERC has filed with the commission a set of new and existing metrics meant to “track the progress of the ERO in continuing to be an effective and efficient organization in furtherance of its regulatory responsibilities” (RR24-4). 

FERC approved NERC’s performance assessment in December 2024. (See FERC Approves NERC Assessment, Seeks Comment on IBR Standards.) The assessment covered NERC and the regional entities’ activities from 2019 to 2023 and argued that the organizations met the commission’s requirements to be recertified as the ERO. 

In a supplemental filing to the assessment, NERC said its plans for ongoing improvement include establishing “metrics around noncompliance processing … to ensure regional entities are realizing efficiency gains offered by a more streamlined minimal risk [compliance exception] process.”  

To help this process along, FERC directed NERC to submit a compliance filing within 180 days outlining metrics to track progress in the reliability standards development program, along with implementation and oversight of the compliance monitoring and enforcement program (CMEP). The commission specified that NERC’s metrics should track three areas: 

    • implementation and consistence of risk-based compliance monitoring practices; 
    • timeliness of violation processing; and 
    • reduction in subsequent serious risk violations stemming from similar issues as prior noncompliance. 

Four Categories of Metrics

  • NERC’s June 16 filing contained 11 metrics in four categories: reliability risk assessment, standards process, compliance monitoring and enforcement. The ERO said the metrics provide “a systematic approach to determining the efficacy of certain ERO programs from one performance assessment period to the next, with the next performance assessment to be filed with FERC in 2029.” 

The reliability risk assessment category contains only one metric, which tracks the time needed for NERC to address a risk identified in one of its publications, such as the Long-Term Reliability Assessment or the State of Reliability report. The time between risk identification and action is divided into three time frames: expedited action, completed within six months; efficient action, done between six and 12 months; and delayed action, taking longer than 12 months.  

Two metrics are included in the standards process category. The first tracks the percentage of ballots that achieve approval (measured as at least a two-thirds segment-weighted majority in favor) in NERC’s balloting process, along with how many ballots were needed for each standard to reach approval. Tracking these measures will help NERC “consider how quickly consensus was achieved, reflecting the success rate of the standards development process.” 

The second standards process metric records the percentage of affirmative votes for a standard gained in successive ballots. NERC said that in the 2029 performance assessment, it will look at factors that may have influenced stakeholders to change their votes. 

Tracking CMEP Success

In the next categories — compliance monitoring and enforcement — NERC said it recognized “the need for data-driven metrics to evaluate success as one of the core tenets of a risk-based CMEP.” These categories comprised the bulk of the metrics in the filing, with four each. 

The first measures the completion of risk-based tools, such as inherent risk assessments, prior to compliance monitoring engagements. These tools are used to assess a registered entity’s risk profile to identify appropriate compliance monitoring activities. NERC said the tracking will help the ERO “to understand whether any updated risks are considered in compliance monitoring activities.” 

Under the second metric, NERC will record how many newly registered entities have completed their inherent risk assessments and oversight planning, and how quickly they did so. NERC said these activities are necessary to understand any reliability risks faced by new entities; when combined with the previous metric, NERC will be able to determine whether new entities’ risk is incorporated into yearly compliance monitoring activities. 

The next metric “assesses the frequency in which the reliability standards requirements identified in the CMEP implementation plan are in the scope of CMEP engagements, such as audits and spot checks,” NERC said. Collecting these data will help NERC see which standards, and which requirements, are most often involved in each year’s compliance monitoring engagements. 

For the final compliance monitoring metric, NERC proposed to track whether REs performing engagements review an entity’s internal controls in addition to standards compliance. This will help the ERO evaluate the risk an entity poses and how it may perform in the future and is “essential to the successful implementation of risk-based CM.” 

Metrics in the first enforcement category are mainly concerned with the timeliness of the ERO’s enforcement processes. NERC observed that although the ERO has successfully disposed of more than 99.7% of minimal risk compliance exceptions (CEs) — which are used to address standards violations posing a minimal risk to grid reliability — submitted to FERC during the performance assessment period, the average processing time for these infractions was more than 16 months, which NERC said was disproportionate to the risk involved.  

The first of the metrics aimed at giving the ERO insight into disposal times compares the number of violations submitted to the number processed each year. This will help NERC determine whether the open inventory of instances of noncompliance is increasing or decreasing. 

NERC noted that the ERO “focused on reducing the volume of its oldest open inventory” in 2024 and made significant progress in doing so, processing more than 43% of its pre-2024 inventory by the end of the year. This resulted in the inclusion of another metric, which tracks the reduction of open inventory by reporting year. 

The last timeliness metric will track the number of CEs processed within 180 days of submission. This information “will not only help to determine the effectiveness of existing reliability standards, but may also support evaluation of whether a reliability standard should be modified or enhanced,” NERC said. 

NERC’s final enforcement metric would track processing of infringements posing serious risks with aggravating compliance history. This involves prior noncompliance of the same standard and requirement with serious enough underlying conduct that the RE aggravated the disposition method or monetary penalty. NERC said it will also track serious risk noncompliance caused by failed mitigation of prior violations. 

Posted on

Lazard: Solar and Wind Retain Lowest LCOEs

Lazard’s latest analysis of the levelized costs of energy concludes that wind and solar are the least expensive new-build power generation for the 10th year in a row.

The LCOE of new gas-fired generation, meanwhile, has hit a 10-year high, and shortages of equipment are expected to drive further steep increases. However, existing baseload generation is increasingly competitive with new renewables, which have seen recent increases in their own LCOEs.

Still other factors have dropped the 2025 levelized cost of battery energy storage systems to their 2020 level.

Lazard issued the 18th edition of its “Levelized Cost of Energy+” report June 16.

The financial advisory firm noted the report is a present-day snapshot based on the last 12 months in the U.S. power industry, rather than a prediction of future trends.

“Significant shifts expected” is what the report offers by way of predictions. Supply chain normalization and productivity enhancements could offset the rising LCOE of gas-fired generation over the longer term, for example, and expensive nuclear construction is poised to benefit from scale and development efficiencies.

Lazard also notes that other cost factors are shifting: Several grid operators are refining their capacity accreditation methodologies to incorporate the seasonal adjustments and diversity benefits of the increasing amount of renewable generation. This could significantly impact future firming costs, the report said.

There is no single cost offered for a given type of generation — the LCOEs sprawl across a wide range that grows even wider as variables are factored in.

Utility-scale photovoltaics, for example, run $38/MWh to $78/MWh. That falls to $20-$45/MWh if investment tax credits, production tax credits and economic community adders are factored in, and it jumps to $50-$131/MWh if storage is added and there are no tax credits — a scenario that may come to pass soon. (See Senate Finance Committee Looks to Eliminate Energy Tax Credits in 2028.)

New onshore wind without storage and without tax credits would have an LCOE estimated at $37-$86/MWh.

By comparison, a combined-cycle gas-burning plant runs $48-$107/MWh, or $41-$116/MWh factoring in 25% fuel price adjustments lower and higher. Adding a carbon price of $40-$60/ton, as some policymakers have proposed, would bump its LCOE to $63-$132/MWh.

Cost of capital is another key factor, and here again there is no single formula, because each type of generation has a different risk vs. return profile, and their costs rise or fall at different rates.

One unsurprising detail: Existing paid-for assets have a lower LCOE than newly built assets. The marginal cost of operation can drop as low as $24/MWh for a fully depreciated combined-cycle gas plant, for example, or just half the lowest calculated LCOE of a new gas plant.

The report calculates the most expensive type of generation would be a newly built peaker plant burning gas at a cost of $3.45/MMBtu. With a capacity factor of 10-15%, its LCOE would be in the range of $149-$251/MWh.

Lazard notes that renewables have grown into an established industry comprising 20% of the U.S. electrical system in the time it has been compiling its LCOE reports.

Data from its current and past reports show concurrent changes in LCOE: Utility-scale solar dropped from $359/MWh in the 2009 report to $58/MWh in 2025, while onshore wind dropped from $135/MWh to $61/MWh.

The data also show those 2025 LCOEs are significantly higher than in the 2021 report, when utility-scale solar and onshore wind bottomed out at just $36/MWh and $38/MWh, respectively.

Battery energy storage system prices are moving slightly in the opposite direction. Lazard places the 2025 levelized cost of storage for a 100-MW four-hour utility-scale standalone BESS at $115-$254/MWh, sharply lower than 2024 and slightly lower than 2020.

It attributes this to market factors, such as slower than expected electric vehicle demand and a resulting oversupply of cells, as well as to advances in technology like increased cell capacity and energy density.