Search
January 26, 2026

Posted on

Where are Utilities Best Serving Customers?

PJM had a big day Jan. 16.

The governors of states in the RTO’s territory met at the White House to discuss the flailing market; the administration’s Energy Dominance Council released a fact sheet on bringing big power plants back to solve PJM’s generation problems and a statement of principles urging it to make tariff revisions to right the ship; and the RTO’s Board of Managers released a letter directing its staff to make operational and market modifications, including revising its methods of load forecasting, instituting a reliability auction and forming a Bring Your Own New Generation (BYONG) plan for large load customers.

Alison Williams | Power for Tomorrow

The series of overlapping and likely coordinated actions has been received well by the energy community. And yet, what are being proposed are merely ideas. As Commissioner David LaCerte commented at FERC’s open meeting Jan 22: “These issues raised in these announcements will make their way to FERC soon.” Translation: We’re still talking about solving problems, not actually solving them.

So if we’re still in the planning phase, policymakers would be wise to look beyond PJM to find successful examples of the mutually beneficial outcomes everyone wants: American energy dominance, industrial competitiveness and customer protection.

Vertically integrated utilities have been doing this successfully for more than a century. In regions like the Southeast, this electric industry structure — where utilities own generation, transmission and distribution — is shielding customers from price spikes while supporting economic growth.

The data overwhelmingly support the vertically integrated model. On average, based on 2024 prices, residential customers in “deregulated” states paid 42% more for electricity than residential customers in states with vertically integrated utilities. Excluding Alaska and Hawaii — outlier states with unique geographic considerations — eight of the 10 most expensive states for electricity have a “competitive” structure.

Competition’s promise was lower prices, right? The hard data show that this promise has failed, costing residential customers billions. For example, in Illinois, a national consumer group has found that electric customers have paid $2 billion more for electric “choice” than they would have with the default utility.

The success of the vertically integrated utility isn’t by chance. And it isn’t monopoly power run amok. Rather, the vertically integrated utility model exists to serve the public interest and place the customer front and center. When Congress passed the Federal Power Act, it chose this approach because electricity requires massive infrastructure investment and therefore demands a different framework. We don’t need to imagine what thousands of wires individually bringing power to homes would look like because we see that in some parts of the world, and that is the way power was delivered in New York City in the late 19th century.

The primary operating principle of the vertically integrated utility is an obligation to serve all customers. These utilities are required to conduct extensive long-term planning where supply and demand must be balanced over decades and the procurement of resources must be the best combination of least cost and least risk. None of these actions or plans can move forward without oversight and approval by state regulators, who hold the dual objectives of supporting state-based growth and ensuring electric rates are fair, reflect actual costs and are allocated fairly across all customers. This relationship between utilities and their regulators is the original public-private partnership — and it doesn’t just work for electricity; it’s also a successful model for water, sewer and gas heating.

Yet, despite a century of success and recent data affirming that customers win under the vertically integrated model, some believers in “competition” continue to make the case for expanding it throughout the electric sector, including pushing for open solicitations for transmission projects. But the data are clear there too, and the pattern repeats: “Competitive” transmission delivers the same disappointing results as “competitive” electricity markets.

Consider what “competitive transmission” actually means. Planning entities determine which transmission projects are needed before any competition begins. Developers (the ones supposedly competing) merely bid to see who builds projects, not on identifying needs or providing ongoing competitive service. Indeed, competitive transmission operators have been fighting for years to be treated like regulated utilities when it comes to prices. Moreover, their so-called competitive bids routinely fail to translate into actual customer savings, proving the theory wrong.

A revealing example comes from New York in 2022, where a “competitive” bid came in 22% lower than the local utility’s proposal. Advocates of competitive transmission celebrated this as proof that competition in transmission can work. But the developer encountered cost overruns of about $74 million above its cost cap because of regulatory delays, transmission line rerouting, tree clearing and wetland mitigation. Tellingly, the original bid failed to account for these costs — whether through strategic omission to win the contract or unfamiliarity with local terrain and regulatory requirements. Ultimately, this project’s cost reached $249 million, up 38% from the winning bid and exceeding what the experienced local utility would have charged.

These stark examples of “competition” failures are particularly important now, as many state legislative sessions resumed at the start of the year and legislators are feeling pressure to find solutions to rising energy costs. Perennial bill proposals on energy often include doubling down on market structures, deregulation and pushes for retail or industrial “choice.” But these options can be best described as “competition for competition’s sake.”

Today’s policymakers should ask a simpler question for finding energy solutions: “What approach best serves customers?” The answer is clear: Well-regulated, vertically integrated utilities have a proven track record of protecting customers.

Electric utilities overseen by smart regulators provide the actual benefits that “competition” is supposed to deliver — downward pressure on prices, accountability for performance and incentives for efficiency — but with additional protections that markets cannot provide, including mandatory service obligations, reliability requirements, and protection from price volatility and market manipulation.

Regulators disallow cost recovery for imprudent investments, enforce lowest reasonable cost standards, and ensure balanced consideration of customer and shareholder interests. These are not theoretical benefits; they are demonstrated outcomes from a century of sound regulatory practice. We have examples of success popping up across the country, where vertically integrated utilities are recruiting data centers and advanced manufacturing with fair electricity rates that don’t harm small customers and average citizens.

The choice facing policymakers is straightforward: proven regulatory approaches that prioritize customers, or continued experimentation with “competitive models” that have repeatedly failed to deliver on their promises. After a century of evidence and recent high-profile market failures, the answer should be clear.

Alison Williams is senior vice president of Power for Tomorrow, a nonprofit that provides practical research, commentary and information regarding how the regulated electric utility model protects consumers and promotes consumer benefits.

Posted on

EVs Outrank Data Centers in California Electricity Demand Forecast

The California Energy Commission has signed off on a forecast showing the state’s electricity consumption could surge by as much as 61% over the next 20 years, but it pegs the biggest driver as increased electric vehicle use, with new data centers coming in second.

The CEC on Jan. 21 voted to approve a resolution adopting the forecast and including it in the agency’s 2025 Integrated Energy Policy Report (IEPR), which informs the state’s resource adequacy requirements, integrated resource plans, reliability assessments, and transmission and distribution planning.

CAISO’s peak load is predicted to increase to about 66 GW in 2045, up from 46.5 GW in 2025. The 2024 IEPR forecast estimated 2045 peak load of about 66.8 GW. (See Data Centers to Drive Calif. Power Demand, Sales.)

The adoption of electric vehicles is the biggest driver of peak load growth at 8,234 MW, followed by new data centers (4,721 MW), fuel substitution from electrification (4,464 MW) and climate change impacts (1,811 MW), according to CEC lead forecaster Nick Fugate. New consumption outside those categories accounts for 6,011 MW of peak load growth.

Fugate noted that the 2025 forecast is the first for which the CEC has considered using “known load” data in its forecasts, which include “energization requests at the distribution system level” and “project-level data” from investor-owned utilities — many of which are proposed data centers.

Still, the CEC decided not to include known load data in this round of planning forecasts because it lacked historical records to examine “when evaluating key assumptions made in our analysis,” Fugate said. The agency did provide alternative forecasts that reflect those data, and Fugate said the agency will continue to monitor known loads in 2026 and 2027 for possible inclusion in future planning forecasts.

“The approach we’ve taken to determine incrementality to our forecast allows for substantial room for double counting,” Fugate said. “It’s meant to give a bookend estimate to cover the very high-end risk, rather than to project a most likely outcome at the system level. So, while we are working with the IOUs to sort through the energization timelines to better understand this data, to validate our key assumptions and to refine our analytical approach, there is still this question of how to mitigate potential risk applied by known loads data.”

The forecast’s “high case” shows that California’s annual electricity consumption could rise to 450 TWh in 2045, compared with about 280 TWh in 2025. By comparison, the state’s consumption was 270 TWh in 2005. (See Calif. Electricity Consumption Headed off the Charts, CEC Forecast Shows.)

The high case shows a compound annual grow rate (CAGR) of 4.2% from 2024 to 2030 and 1.5% from 2030 to 2045, translating to 2.3% over 2024-2045.

For the “mid case,” the CAGR figures are 2.3%, 1.7% and 1.9%, respectively, with 2045 consumption estimated at just above 400 TWh.

“This is one of the most important aspects of the commission’s role and job, and one that I’ve always been very, very fascinated with and interested in,” Commissioner Nancy Skinner said ahead of the vote during the CEC’s monthly business meeting Jan. 21.

But speaking on behalf of the California Coalition of Large Energy Users during the meeting, Meredith Alexander said the group was troubled by the CEC’s decision to exclude known loads from its planning and local forecasts.

“At this point, we’re concerned that there could be real effects on reliability and costs in the next few years, if the forecast is artificially low,” she said. “Load-serving entities could under-procure capacity, meaning that our load-serving entities are not sufficiently resourced to serve our new loads.”

Speaking ahead of the vote, Commissioner Andrew McAllister said he was “comfortable with” adopting the forecast while acknowledging the concerns, which he said reflected the “increased uncertainty” around growing loads.

“I do want to note there are so many moving parts and so many new electric technologies being introduced to the market — really, at rates we’ve never seen before — that close dialogue with stakeholders and continued engagement throughout the years is more important than ever, so that we get as close to being right as we possibly can,” CEC Chair David Hochschild said.

Posted on

Cleantech Manufacturing Investments Drop, Cancellations Rise

In late 2025, U.S. cleantech manufacturing investment cancellations reached their highest level of any quarter in the eight years a database has been tracking such announcements.

Also in the fourth quarter of 2025, new investment announcements dipped to their lowest level in five years.

The Clean Investment Monitor (CIM), maintained by Rhodium Group and MIT’s Center for Energy and Environmental Policy Research, tallied $3.4 billion in quarterly investment announcements and $8.4 billion in cancellation announcements.

For all of 2025, amid President Donald Trump’s opposition to many clean energy technologies, the CIM tallied $24.1 billion in manufacturing investment announcements and $22.6 billion in cancellations. By comparison, 2024 saw announcements worth $32.5 billion and cancellations worth $4.4 billion.

Investment cancellations by technology | Rhodium Group

The ratio was even more lopsided in 2023 — $65.5 billion announced and $1.6 billion canceled.

The decrease in actual investment activity — the dollars actually being spent — was not as marked. Many previously announced investments were still being carried out in the fourth quarter. The CIM placed total actual investments at roughly $9.3 billion — down 29% from a peak of about $13.1 billion in the third quarter of 2024.

The majority of the $3.4 billion in new manufacturing announcements for the quarter was related to batteries — $2.5 billion, including Ford Motor Co.’s $2 billion decision to convert an EV battery factory in Kentucky to battery energy storage system production.

There were just five announced cancellations in the CIM for the fourth quarter, but they all were huge, and all were connected in some way to EVs. Ford’s planned electric pickup truck and commercial van factories in Tennessee and Ohio were valued at a combined $4.71 billion; Gotion’s EV battery factory in Michigan at $2.44 billion; Westwin Elements’ nickel refinery in Oklahoma at $748 million; and ICL Group’s battery materials factory in Missouri at $546 million.

The combined $8.44 billion in cancellations was the most of any quarter in the CIM database since its start in 2018.

U.S. cleantech manufacturing investment announcements tallied by the CIM peaked in 2022 as the landmark Inflation Reduction Act worked its way through Congress and was signed into law by President Joe Biden: $91.4 billion for the year, capped by $32.2 billion in the fourth quarter alone.

By contrast, the CIM tallied just $24.1 billion in 2025 announcements, capped with the $3.4 billion in the fourth quarter — the least of any quarter since the final months of Trump’s first term.

The CIM also tracks cleantech investments in the U.S. energy industry and retail sectors, neither of which has tapered off the way the manufacturing sector has.

Combined investments in all sectors hit a record-high $75.4 billion in the third quarter, mostly from consumers rushing to buy EVs before federal tax credits expired.

Posted on

FERC Dismisses Rehearing Ask for SPP’s ERAS Process

FERC has rejected a rehearing request of its order approving SPP’s proposed one-time accelerated study of shovel-ready interconnection requests, sustaining its original 2025 decision (ER25-2296).

Clean energy groups and public interest organizations — including the Advanced Power Alliance, American Clean Power Association, Natural Resources Defense Council and Sierra Club — opposed the Expedited Resource Adequacy Study (ERAS) during the stakeholder process, arguing that it amounts to queue jumping, bypasses open access to the RTO and violates FERC’s principle of nondiscriminatory access to the grid.

The organizations filed for rehearing in August, one month after FERC’s order. They contended the commission’s decision was arbitrary and capricious because it was based on unexplained assumptions that little to none of the capacity being studied in SPP’s current interconnection process will be available to serve near-term resource adequacy needs.

The groups called the assumptions “implausible,” noting that the RTO assumed none of the 4,500 MW of summer-accredited capacity in a 2022 study cluster will be available to meet 2030 needs; only 418 MW of over 31,000 MW of energy storage in the queue will meet 2030 resource adequacy needs; and no capacity from the 2024 study cluster will be available in 2030.

They said the grid operator has projected in other forums that 40% of the generation in the queue will come online, “inconsistent with SPP’s assumptions,” and that it did not discount future load growth to reflect historical rates.

FERC disagreed. In an order issued at its monthly open meeting Jan. 22, said SPP had met its burden to show that the ERAS process is just and reasonable and supports near-term resource adequacy needs.

“A number of well documented factors are contributing to what SPP has characterized as a looming resource adequacy crisis,” the commission said. It noted SPP “expects” available capacity to drop below reserve margins by 2027 and for the region to have insufficient capacity to meet peak demand in 2030.

“SPP further [predicts] that, within the next two to five years, [load-responsible entities] will be unable to meet their state-mandated obligation to serve load” and the tariff’s resource adequacy requirements, FERC said, pointing to the RTO’s projections that an additional 16.7 GW of accredited capacity will be needed by 2030.

The RTO has 552 active interconnection requests in its queue for more than 130 GW of capacity. It told FERC that given proposed commercial operation dates, historical withdrawal rates and capacity accreditation rates, “actual capacity to meet SPP’s near-term resource adequacy needs was likely to be far more limited” and that its current interconnection process could not meet expected needs.

The commission also rejected open-access arguments, saying ERAS interconnection requests are “necessarily subject” to SPP’s more stringent criteria for eligibility.

“ERAS interconnection customers are differently situated than interconnection customers that do not meet these criteria,” FERC said, “in their expected ability to achieve commercial operation more quickly to participate in this one-time process to respond to the near-term needs of particular LREs that SPP has determined are expected to face a capacity deficiency.”

In approving the ERAS process in July 2025, FERC found that SPP had “existing authority” under its tariff to evaluate and maintain resource adequacy and to manage its interconnection queue in providing sufficient generation to meet RA requirements. (See FERC Approves SPP’s ERAS Process, Accreditation.)

Order 2023 Compliance Accepted

In a separate order issued during the meeting, FERC accepted SPP’s second compliance filing with the requirements of Orders 2023 and 2023-A (ER24-2026).

In partly accepting SPP’s first compliance filing in June 2025, the commission found that its proposed tariff revisions amending FERC’s pro forma large generator interconnection procedures (LGIP) and generator interconnection agreements partly complied with the order. (See FERC Partly Accepts SPP’s Order 2023 Compliance.)

It found SPP followed its subsequent directives by proposing to adopt, without modification, the pro forma LGIP requirement that an affected system restudy be completed within 60 calendar days from the restudy need’s date. The commission also said the grid operator complied by removing language from the pro forma LGIP requiring interconnection customers to submit a deposit with each request, even when more than one request is submitted for a single site.

FERC issued Order 2023 in July 2023 in an effort to clear backlogged interconnection queues by implementing a first-ready, first-served cluster study process; increasing interconnection customers’ financial obligations; and penalizing grid operators for missing study deadlines. (See FERC Updates Interconnection Queue Process with Order 2023.)

In 2024, the commission rejected challenges to the interconnection rules under Order 2023 and made several clarifications, minor modifications and an extended compliance deadline with Order 2023-A. (See FERC Upholds, Clarifies Generator Interconnection Rule.)

FERC Releases Letter Orders

In a Jan. 20 letter order, FERC accepted SPP’s proposed tariff revisions modifying language related to the local market power test for resources in frequently constrained areas (FCAs) (ER25-3331).

The revision, with an effective date of Jan. 26, prohibits market participants from nominating and acquiring — and portfolios from containing — certain auction revenue rights and transmission congestion rights (TCRs) that source and sink in electrically equivalent settlement location groups.

SPP’s Market Monitoring Unit supported SPP’s proposal, saying it “more clearly define[s] the full scope of trades that are not permissible in SPP’s TCR market.”

The commission directed SPP to submit a compliance filing within 30 days of the order’s date.

In another Jan. 20 letter order, FERC approved the RTO’s proposal to modify language setting the conditions under which a resource is determined to have local market power (ER26-562).

The commission found it reasonable for resources within an FCA to undergo the same level of scrutiny as resources outside the area when testing for local market power with respect to constraints outside the FCA. It said SPP’s proposal applies the existing resource-to-load distribution factor and binding reserve zone conditions for all resources while retaining other conditions for resources in an FCA.

Posted on

FERC Approves License for Goldendale Hydro Project in Wash. State

FERC has approved a 40-year license for a proposed 1.2-GW pumped hydroelectric storage facility near the city of Goldendale in Klickitat County, Wash. (P-14861-002).

According to the commission’s order, approved at its monthly opening meeting Jan. 22, Rye Development will build and operate the closed-loop, 12-hour Goldendale Energy Storage Project along the cliffs of the Columbia River Gorge and near the John Day Dam. It will include two reservoirs, one at the bottom of the cliffs and another about 2,300 feet higher.

A powerhouse built in an underground cavern will contain three, 400-MW pump-turbine units. A 500-kV transmission line will connect the project to the Bonneville Power Administration’s system through the existing John Day substation. The project is expected to generate power eight hours on a typical day and up to 12 hours a day if needed.

“The energy produced will be delivered to the wholesale market to be purchased by utilities in the Pacific Northwest and California to help satisfy periods of peak demand and provide grid flexibility,” FERC said in its order.

According to the project’s website, it has a price tag of more than $2 billion. The expected commercial operation date is 2032.

Erik Steimle, Rye’s chief development officer, called the approval “a landmark moment for the Pacific Northwest.”

“With electricity demand and energy costs on the rise, this license represents a huge step toward a more reliable grid and affordable energy prices for the region,” Steimle said in a statement.

The reservoirs initially will be filled with 7,640 acre-feet of Columbia River water bought from Klickitat Public Utility District. An additional 360 acre-feet will be purchased each year to make up for water loss from evaporation and seepage. The initial fill will take place over seven months, from September through March, to avoid Columbia River flow reductions that could delay salmon smolt migration.

The project area is within Klickitat County’s Energy Overlay Zone, which is intended to streamline energy development. The upper reservoir site is within the Tuolumne wind farm.

The lower reservoir is planned at the former site of Columbia Gorge Aluminum smelter. The landowner and the former smelter operator are working with the state on cleanup efforts, and project owner Copenhagen Infrastructure Partners has pledged $10 million to help.

The state’s Department of Ecology issued a water quality certification for the Goldendale project in May 2023, which was upheld on appeal in January 2025.

The project faced opposition from members of the Yakama Nation, Umatilla Tribes, Confederated Tribes of the Warm Springs Reservation of Oregon and Nez Perce Tribe. It is on property that has historical significance and is used for sacred ceremonies. (See Wash. Approval of Pumped Storage Project Sparks Dissent.)

The FERC order noted that Rye proposed protecting cultural resources and mitigating unavoidable impacts to historic sites through a historic properties management plan. Other measures include consulting with tribes to provide post-construction access to the project area for cultural programs and to ensure construction doesn’t block access to traditional fishing areas.

Rye is a partnership between EDF power solutions and Climate Adaptive Infrastructure. It is also developing the 393-MW, eight-hour Swan Lake pumped storage project in Klamath County, Ore., and the 266-MW Lewis Ridge pumped storage project in Bell County, Ky.

Posted on

MISO Enters Max Gen Emergency in Arctic Blast

MISO declared a maximum generation emergency for its Midwest region just after midnight Jan. 24 as northern portions of its footprint rode out temperatures plunging into the negative double digits.

The grid operator said it was contending with forced generation outages and transfer limits along with the demand coming with subzero temperatures.

Minneapolis temperatures bottomed out around ‑20 degrees Fahrenheit and Detroit at ‑5 F, while northernmost points of North Dakota and Manitoba saw ‑30 F.

At the time of the emergency declaration, MISO said it curtailed scheduled exports and activated emergency maximum limits for resources in its markets. Around 6 a.m. ET, the RTO elevated its emergency pricing from its $600/MWh first-tier offer floor to its second-tier, $1,100/MWh floor.

MISO forecast a 96.4-GW peak demand for Jan. 24. It was accepting about 4.5 GW in imports around 9:30 a.m. ET while coal and gas units supplied about 74% of a 93-GW demand. Prices at that time appeared to exceed $500/MWh at Wisconsin and Minnesota pricing nodes.

However, MISO noted it was experiencing “system difficulties” with its real-time locational marginal prices and said it could not issue prices. The RTO’s website listed an unchanged, $211.22/MW marginal price.

According to Yes Energy data, Big Rivers Electric Corp.’s D.B. Wilson coal plant went offline unexpectedly Jan. 22.

MISO entered conservative operations Jan. 23. The grid operator didn’t appear to issue a maximum generation warning before it entered emergency procedures.

Ahead of winter, MISO predicted a 103-GW seasonal peak and said that level of demand should not require it to enter emergency procedures. (See MISO Predicts 103-GW Peak for Winter.)

MISO’s all-time winter peak of 109 GW occurred in January 2014, when Minneapolis registered a low of -23 F. MISO last entered a maximum generation emergency June 23, 2025. (See MISO Declares Max Gen Emergency in Heat Wave.)

Posted on

FERC Rebuffs Clean Energy Orgs’ Arguments Against MISO Fast Lane

FERC ruled that MISO is free to continue using its interconnection queue “fast lane,” shutting down rehearing requests from several clean energy organizations.

The commission on Jan. 22 concluded again that MISO’s temporary expedited queue process for generation projects deemed necessary by states is “appropriately tailored to address” near-term resource adequacy needs (ER25-2454).

The clean energy groups that requested rehearing included the Clean Grid Alliance, Sierra Club, Sustainable FERC Project, Natural Resources Defense Council, Southern Renewable Energy Association, Clean Wisconsin, Advanced Energy United, American Clean Power Association and Solar Energy Industries Association.

They argued MISO doesn’t confront the dire resource adequacy crisis it purports to be facing, saying the RTO and the Organization of MISO States’ 2025 Resource Adequacy Survey showed that by 2031, the footprint could have a surplus ranging from 1.4 to 6.1 GW.

The groups also said that MISO could have looked to its regular interconnection queue to find helpful generation and argued the fast lane would drain the RTO’s manpower at the expense of the regular process.

FERC said that contrary to the organizations’ claims, MISO has “sufficiently documented that its region is likely to face near-term resource adequacy needs” that will not be satisfied by existing projects in the regular interconnection queue.

The commission also said that regulators are under no obligation to comb through the existing queue to find a project to meet a resource adequacy need, adding that MISO’s queue process falls outside of state regulators’ jurisdiction.

Furthermore, FERC said once it found the fast track was a reasonable means of addressing resource adequacy risks, “we need not — and cannot under the standard applicable here — consider whether an alternative proposal that imposed this ‘search for a better project’ requirement might be preferable.”

‘Permissible Departure’

MISO created the temporary queue express lane to more quicky get necessary generation online. Throughout 2026, the grid operator will accept four 15-project cycles into the fast track.

The first two cycles, accepted in 2025, overwhelmingly comprise gas generation. MISO expects the 11 GW of new natural gas generation from this phase to begin coming online in 2028. (See MISO Accepts 6 GW of Mostly Gas Gen in 2nd Queue Fast Lane Class.)

FERC disagreed that it stepped outside of its precedent prohibiting discrimination in generator interconnection to approve the express lane and said its decision “arises in the particular context of a potential resource adequacy shortfall in MISO and, therefore, reflects a permissible departure from the standardized generator interconnection procedure.” It found the RTO’s design “contains sufficient guardrails to address the concerns relating to undue discrimination.”

The commission determined that interconnection customers in the fast lane are “differently situated” than MISO’s other interconnection customers and can be allowed shorter wait times, slightly different studies and ultimately pay less for interconnection service.

“To the extent [expedited] interconnection customers receive favorable terms of interconnection as part of this one-time process, we find that this treatment flows from reasonable choices in the design” of the expedited queue, FERC said in its order.

FERC added that regular interconnection customers could benefit from the network upgrades built by expedited interconnection customers.

The commission decided once more that the expedited queue can help sustain resource adequacy and said that even with the three-year grace period for expedited projects to come online, the last cycle of studied projects would be operational in August 2033 at the latest, within the timeline to address MISO’s pressing resource adequacy problems.

FERC pointed out that objective regulatory agencies must verify the project need and said regulators are “uniquely positioned to see the need and review the project that is being proposed.”

It also noted that expedited interconnection requests are subject to stricter requirements than those in the standard interconnection queue, including higher fees per megawatt, a $100,000 nonrefundable deposit, definitive proof of land use and a requirement to pay for all network upgrades. It said those requirements encourage only shovel-ready projects to apply.

The commission reiterated that MISO’s creation of a limited, temporary process strikes a balance between ensuring resource adequacy while limiting the fast track to a manageable number of interconnection requests that can be studied quickly. The commission said despite the clean energy organizations’ arguments, the process is a one-time exercise conducted over a specific time frame. It said the quarterly nature of the studies doesn’t suggest that MISO plans to exceed the 68-project cap or repeat the process.

“This approach falls well within the flexibility we afford to RTOs/ISOs to design appropriate solutions to their interconnection challenges and well within a reasonable view of what constitutes a ‘one-time’ process,” FERC wrote.

Altogether, MISO’s temporary process would accommodate 68 projects, with 10 set aside for independent power producers and eight reserved for entities serving retail choice load in downstate Illinois and part of Michigan.

Posted on

DOE to Restructure or Eliminate $83 Billion in Biden-era Loans

The U.S. Department of Energy said it is restructuring, revising or eliminating more than $83 billion in loans and conditional commitments issued under the Biden administration.

The Loan Programs Office offered a total of $104 billion under President Joe Biden, much of which came from the Inflation Reduction Act, the 2022 law that was passed using reconciliation to get around Republican filibusters in the Senate. President Donald Trump’s DOE lambasted the loans as part of the “Green New Scam” and has transformed the loans office into the “Office of Energy Dominance Financing.”

“Over the past year, the Energy Department individually reviewed our entire loan portfolio to ensure the responsible investment of taxpayer dollars,” Secretary Chris Wright said in a Jan. 22 statement announcing the move. “We found more dollars were rushed out the door of the Loan Programs Office in the final months of the Biden administration than had been disbursed in over 15 years. President Trump promised to protect taxpayer dollars and expand America’s supply of affordable, reliable and secure energy.”

DOE has eliminated $9.5 billion in funding that was going to wind and solar, replacing it with investments in natural gas and uprates at nuclear power plants.

Of the $104 billion in Biden administration loan obligations, DOE has withdrawn or is in the process of de-obligating nearly $30 billion, with an additional $53 billion in revision.

The new Office of Energy Dominance Financing has more than $289 billion in available loan authority, which is accessible to more types of projects after the One Big Beautiful Bill Act. The funding level makes it the biggest energy lender in the world, DOE said.

The office is targeting six sectors: nuclear, fossil fuels, critical minerals, geothermal, the electric grid, and manufacturing and transportation, according to a blog post by its senior adviser, Gregory Beard.

The office closed three loans toward the end of 2025 totaling $4.1 billion, including a loan to Constellation Energy to restart the Three Mile Island nuclear plant; one to an American Electric Power subsidiary to strengthen its transmission system; and another to Wabash Valley Resources to use a coal plant to produce fertilizer.

This year the office will prioritize projects that contribute to energy security, grid reliability and affordability, Beard wrote.

Posted on

N.Y. Extends ZEC Nuclear Subsidies to 2049

New York is extending its nuclear power subsidies as far as 2049 at a cost to ratepayers as high as $33.4 billion.

The four reactors and their 3.36 GW of output constitute an indispensable part of New York’s power portfolio and decarbonization strategy, NYISO and various stakeholders have said.

They are expensive to operate, however, and not economical at market power prices.

The state in 2016 created the nation’s first Zero-Emissions Credit (ZEC) program in recognition of these factors, and on Jan. 22, the Public Service Commission (PSC) extended the program’s expiration date from 2029 to 2049 (case 15-E-0302).

Constellation Energy, which operates all four reactors, has sought financial certainty as it plans the future of the two oldest operating reactors in the nation. They are licensed to operate only into 2029, and the deadlines to apply for their relicensing are March and June 2026.

“Failing to extend the ZEC program creates a risk of these plants closing, which could have significant impacts on reliability, resource adequacy and achievement of statewide clean-energy goals,” PSC Chair Rory Christian said in a news release.

Later Jan. 22, Constellation said it was still reviewing the order and deferred comment.

The PSC had long been moving toward extension, and in a July 2025 white paper, its staff at the Department of Public Service laid out the justification for what is being called ZEC 2.0.

A broad range of commenters offered opinions in support or opposition for a broad range of reasons.

Many clean energy advocates in the state are particularly unhappy that the state is embracing nuclear rather than doubling down on renewable energy.

New York is a national leader in small-scale solar, but deployment of wind, large-scale solar and storage so far has not matched grand ambitions, and it is unlikely to get easier under President Donald Trump.

The four reactors are a combined 202 years old. But unlike the planned wind and solar farms, they are online now and they produce a lot of power — 21% of in-state generation and more than 40% of the state’s emissions-free power.

NYISO reports that the reactors, with a combined nameplate capacity of 3.36 GW, generated 27,073 GWh in 2024.

The four reactors typically post annual capacity factors in the low- to mid-90% range and are steady except for refueling outages.

The output of New York’s wind and solar installations varies noticeably by region and greatly by time of day or time of year. NYISO assigned a capacity accreditation factor of 10.5 to 12.24% to solar panels for the 2025/26 capability year and 16.61 to 18.2% for land-based wind, with exact amount depending on location.

Mixed Reactions

Meanwhile, the state’s existing fossil generation is aging, the Trump administration is blocking offshore wind development, land-based renewables are slow and increasingly expensive to deploy, the governor’s vision of new nuclear development may not become reality for a decade, and the dispatchable emissions-free resources state energy planners are counting on to backstop a carbon-free grid do not exist in scalable or economical form.

The existing nuclear reactors, therefore, are viewed as indispensable and, for now, irreplaceable.

In Oct. 20 comments submitted on the ZEC proceeding, NYISO wrote: “The existing fleet of four nuclear generation resources must remain operational to avoid resource adequacy shortfalls and other electric system reliability issues.”

ZEC 1.0 cost $468.4 million to $600.5 million per year and $3.73 billion total in its first seven years.

ZEC 2.0 is capped at $33.4 billion, or about $1.6 billion a year, but DPS staff said the actual cost to ratepayers is expected to be much less — perhaps more than 50% less — due to rising market revenue for the electricity they produce.

The costs to consumers resulting from retirement of the reactors would be greater, staff said.

ZEC 2.0 was modified to include contract performance requirements, a mechanism to reduce the payments if Constellation obtains other financial support, a four-year review process and other ratepayer safeguards.

The PSC vote was cheered by Carbon Free NY, a business-labor-environmental-community coalition that includes Constellation.

John Carlson of the Clean Air Task Force said: “The ZEC program supports more than 14,000 jobs across the state and prevents more than 16 million tons of carbon pollution each year, providing the foundation for a more affordable and cleaner grid for New Yorkers. We applaud the New York Public Service Commission for extending the ZEC program to preserve existing nuclear resources and bolster the program’s tangible economic public health benefits.”

Food & Water Watch decried what it called a massive corporate bailout — the largest single use of ratepayer dollars and the largest subsidy to a single company ever approved by the PSC.

“It’s outrageous that New Yorkers will once again be forced to bail out this toxic, money-burning industry with billions and billions more in the coming years. Despite decades of evidence that nuclear power is both inherently dangerous and cost-foolish, Governor [Kathy] Hochul insists on throwing good money after bad, with everyday families footing the bill,” said Food & Water Watch’s New York state director, Laura Shindell.

The most recent nuclear reactor retirements in New York — Indian Point units 2 and 3 in 2020 and 2021 — resulted in a substantial increase in reliance on natural gas-fired generation.

NYISO reports 51.4% of the electricity generated in New York was produced with fossil fuels in 2024, compared with 39% in 2019, the last year of full operation for Indian Point.

Posted on

NERC Modernization Task Force Leaders Present Final Recommendations

The task force developing recommendations for updating NERC’s standards development process is preparing to post its final recommendations for industry comments, the final opportunity for stakeholders to submit feedback before a formal presentation to the ERO’s Member Representatives Committee in February.

Leaders of the Modernization of Standards Processes and Procedures Task Force presented an overview of their recommendations at the MRC’s pre-meeting conference call Jan. 22. Task force Chair Greg Ford said the proposal would be posted on or before Jan. 26, with comments due by Feb. 5. The MRC will discuss the recommendations at its open meeting Feb. 12 in Savannah, Ga., with the Board of Trustees deciding what action to take, if any, at its open meeting the same day.

NERC leaders launched the MSPPTF in February 2025, saying the rapidly revolving risk environment has made it increasingly difficult for the ERO’s consensus-based standards development approach to keep up with new threats to grid reliability. (See NERC Leaders Highlight Canada-US Collaboration.) The challenge was put on display in late 2024, with the board invoking Section 321 of the ERO’s Rules of Procedure to shorten the normal process in order to meet a FERC deadline twice in less than six months. (See NERC Board Invokes Section 321 Authority for Cold Weather Standard.)

The task force’s final recommendations propose an overhaul of the standards drafting process, with changes across all stages of the development cycle and the addition of two new groups to help create new standards. Leaders presented the changes according to the phase of development to which they apply: standard initiation, standard drafting and balloting.

Per the proposal, the initiation process would now take the form of a review and prioritization process conducted by the Reliability and Security Technical Committee. Todd Lucas, the task force’s vice chair, said stakeholders would have the opportunity to submit standard initiation requests throughout the year. The RSTC would review requests twice a year and determine the appropriate action, which could mean creating a new standard or other steps like developing a nonbinding guideline or technical reference document.

If the RSTC determines that a new standard is needed, it would hand the proposal to a newly created subcommittee of the Reliability Issues Steering Committee. The subcommittee would consult with industry to determine a plan for development, and NERC staff would work with a newly created pool of on-staff subject matter experts to create a term sheet outlining the goals of the proposed standard, which would guide the standard development phase.

Lucas said the task force also envisioned a “fast track” process for urgent projects, such as a directive from FERC or the board. This process would bypass the general intake and review stages and begin with term sheet development. He emphasized that stakeholders would still have the opportunity to provide comments and influence development in the standard drafting phase.

Ford took over the presentation of the standard drafting updates, which are intended to eliminate the multiple comment and ballot periods that are part of the current process. Under the MSPPTF proposal, NERC staff and the SME pool would develop a “version zero” draft standard to be taken up and modified by the project team, rather than requiring the team to write a new standard itself.

The project team would conduct informal industry outreach to shape the standard, then post their draft for stakeholder comment and a straw poll. Further revision periods would be followed by a confirmation ballot.

The task force’s proposals for the balloting stage would introduce new rules for the registered ballot body, including the consolidation of large and small electricity end users (Segment 7 and 8, respectively) into a single segment, and doing the same for segments 5 (electric generators) and 6 (electricity brokers, aggregators and marketers). Segment 10, regional entities, would be removed from the RBB entirely, while other segments would see their weighting in the ballot body revisited.

Ford expressed optimism that the board will accept the MSPPTF’s recommendations and that NERC will be able to implement the proposal by the end of 2026.

“We’ve got to change the Rules of Procedure [and] Standard Processes Manual, [and] committee charters need to be worked on. … There’s a lot of opportunity for us, I’m sure, as we go through this process, but the focus is going to be on starting with [ROP] and then move forward on that as we go through the year,” Ford said.