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January 25, 2026

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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.

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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.

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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 at around -20° F and Detroit at -5°, while northernmost points of North Dakota and Manitoba saw -30°.

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, Great River Energy’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.)

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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.

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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.

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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.

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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.

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Questions Abound over MISO Idea for Zero-injection Agreements

Stakeholders have several lingering questions as MISO continues to draw up a “zero-injection” avenue for large loads with planned on-site generation.

Marc Keyser, with MISO’s external affairs team, said the RTO is looking to define and standardize the process, though it already maintains a few signed generator interconnection agreements with no electricity injection specified.

The RTO said in late 2025 that it would create interconnection agreements where generation dedicated to large load facilities is barred from injecting into its system. Those generation projects would be able to bypass the generator interconnection queue and interconnect in a matter of months, not years. (See MISO Floats ‘Zero Injection’ Agreements to Bring Co-located Gen Online.)

“We would like to make a filing soon. The first quarter is a great goal to have,” Keyser said at a Planning Advisory Committee meeting Jan. 21.

MISO Director of Expansion Planning Jeanna Furnish added that the RTO would also continue to vet the proposal through its stakeholder process over spring.

“We understand that there are a lot of questions we have to work through,” Furnish said.

Keyser said a zero-injection agreement would restrict local generation to providing for its co-located load. He said the generation would be prohibited from running if the load isn’t operating to accept it.

“It’s potentially reducing network upgrades to interconnect,” Keyser said of the arrangement that would get new generation on — and simultaneously keep it off — the system.

MISO’s plan specifies that load can extract generation from the larger network if the generation isn’t on, but its designated generation can never inject into the system from its point of interconnection.

But stakeholders still had questions about how MISO would prevent the netting of behind-the-meter generation with load, a practice FERC prohibits.

Keyser said MISO would require separate metering and telemetry data of the load and generation. “This is not an opportunity to net load and generation behind the meter,” he said.

MISO Director of Resource Utilization Andy Witmeier said the process won’t allow netting because the RTO will have full visibility into both the generation and load from a planning and operations perspective.

For studies, MISO said a zero-injection resource would be modeled the same as any other resource. It plans to study NERC contingencies and conduct reliability analysis, accounting for steady-state, voltage stability and dynamic stability.

“Broadly, our studies are designed to capture contingencies,” Keyser said. However, MISO said reliability studies will always include scenarios where zero-injection resources are offline.

MISO said network upgrades wouldn’t be needed for zero-injection resources even when the most severe contingency occurs and generation trips offline. Keyser said the studies would be designed to “quickly reflect” that load has sought its own generation.

Staff said MISO has struck zero-injection agreements for three unnamed customers so far, including chemical processing plants in MISO South.

“I wouldn’t say this is readily available,” Witmeier said of the arrangements. He said the process isn’t documented in MISO’s tariff or Business Practices Manuals.

Mississippi Public Service Commission consultant Bill Booth asked if the prohibition on generation injections would be voluntary or if MISO would require physical elements to prevent injection. “How can you rely on voluntary participation if you’re not scanning the system for injections?” he asked.

Keyser said that of MISO’s existing zero-injection agreements, some have equipment to bar injections while others have committed to not injecting.

Booth said barring an electric interlock, the RTO should deliberate on the difference between a voluntary promise not to inject and a guarantee to not inject.

The Sustainable FERC Project’s Natalie McIntire asks what would happen if a large load supported by a dedicated generator tripped offline suddenly and the affiliated generator could not turn off output “really quickly.”

“We know that we owe it to stakeholders to be more specific about what it means to be zero,” Keyser said. “It’s an important question. We do plan on addressing it.”

He said MISO is holding conversations about operational reliability and is discussing elements such as how long it’s appropriate for a 150-MW generator, for example, to churn out 151 MW.

“I just don’t want MISO to gloss over all of these really technical questions as you’re trying to develop this really quickly,” McIntire said.

Arkansas Electric Cooperative Corp.’s David McRae said interrupting inertial generators can harm the generation. He asked how the RTO envisions dedicated generation ramping down over multiple cycles, if needed.

Keyser acknowledged that MISO has more work to do on those details as well.

At a Dec. 18 Organization of MISO States meeting, OMS counsel Brad Pope said the RTO’s zero-injection plan could harbor some “real reliability concerns” if it isn’t carefully thought out. OMS has scheduled a Jan. 23 meeting to discuss the proposal with RTO officials.

WEC Energy Group’s Chris Plante said the no-netting rule should apply universally across all markets, including the capacity market. He asked how MISO would accredit generation dedicated solely to a single customer.

“I would encourage MISO not to design this behind closed doors and include stakeholders on the design,” Plante said.

Booth said the RTO must figure out where the co-located load fits into a load-serving entity’s obligation to serve. “We can’t ignore it.”

Anthony Alvarez, of the Iowa Office of Consumer Advocate, asked if the co-located load could become demand response or load-modifying resources.

Keyser said MISO will have to explore that more, but the large loads would be firm, full-rights load and other loads are entitled to become LMRs.

However, Keyser also said MISO would have to work out “what does demand response and market participation look like.”

Wolverine Power Cooperative’s Sawyer McClure said he didn’t see why would-be zero-injection generation wouldn’t just pursue retail behind-the-meter generation status to serve the large loads.

But Keyser said behind-the-meter status is meant for only generation connected at the distribution level.

“If the required connection is at the transmission level, that wouldn’t work,” Keyser said.

MISO said it would provide more details on its proposal at the PAC’s meeting Feb. 25.

“This is not the extent of large load integration or ‘helps’ to incorporate large load,” Keyser said of MISO’s proposal.

Additionally, MISO will hold a workshop on how it plans to handle future large loads Jan. 30.

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Wright Ready to Use Emergency Powers to Dispatch Backup Generation During Winter Storm

U.S. Energy Secretary Chris Wright on Jan. 22 sent a letter to reliability coordinators and balancing authorities saying the department is ready to use its authority under Section 202(c) of the Federal Power Act to dispatch backup generation from large customers if needed ahead of a major winter storm over the following days.

The Department of Energy estimates about 35 GW of backup generation are available around the country, and using them during emergency conditions could mitigate blackouts and cut costs during the winter storm expected to impact much of the Eastern Interconnection.

“The Trump administration will not stand by and allow the previous administration’s reckless energy subtraction policies and bureaucratic red tape put American lives at risk,” Wright said. “We have identified more than 35 GW of unused backup generation that exists across the country and are taking action to ensure that if the nation needs it, the generation will be made available. Rest assured, President Trump and the Energy Department remain committed to doing everything in our power to mitigate blackouts and lower energy costs for the American people.”

The National Weather Service said a major storm was moving across the country, from the southern Great Plains and lower Mississippi Valley on Jan. 23 and then toward the Ohio Valley, Mid-Atlantic and New England over the weekend. Heavy snowfall is expected across the northern part of the system, with mixed precipitation across the South.

Wright and others at DOE have talked about using backup generation in public comments, but the letter offers new details on the idea — such as the use of FPA Section 202(c), which the department has used to stop central-station generators from retiring over the past year.

“Across the country there are gigawatts of readily available backup generation that have remained largely untapped until now,” Wright said in the letter. “This backup generation can and should be used to save American lives and avoid billions of dollars in economic devastation, as energy subtraction policies of the previous administration cause acute scarcity events.”

Wright said he has directed the department to prepare 202(c) orders, which would ensure backup generation that would otherwise be idle is available during emergency conditions.

If RCs or BAs contact DOE during the storm, even with a phone call, and say that they are facing an emergency that warrants a 202(c) order, Wright wrote that he would review the facts and issue one as needed. The backup generation would run “as a last resort before” rolling blackouts.

“There are certain facilities whose operations are of such criticality that it would be inappropriate to require their backup generation to run early in an emergency (like military installations and hospitals),” Wright wrote. “I expect the reliability coordinators and balancing authorities to work closely with the facilities within their service territories to deliberately prioritize the dispatch order of backup generation to achieve the greatest benefit to the bulk power system while balancing mission-essential functions.”

Wright said he has directed DOE staff to coordinate with RCs or BAs ahead of the storm.

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FERC Directs ISO-NE to Cap Pay-for-Performance Balancing Ratio at 1.0

FERC on Jan. 22 partially granted a complaint by the New England Power Generators Association (NEPGA) about the design of ISO-NE’s Pay-for-Performance mechanism (EL25-106).

The commission directed ISO-NE to cap the PFP balancing ratio at 1.0 but rejected NEGPA’s complaint about the RTO’s method of allocating stopped losses.

ISO-NE’s PFP rules incentivize performance during capacity scarcity events. While all resources are eligible to earn credits, only resources with capacity supply obligations (CSOs) are subject to penalties for underperformance.

The complaint stems from a scarcity event on June 24, 2025, that coincided with ISO-NE’s highest peak load in more than a decade. PFP credits totaled about $114 million during the event.

In a complaint filed in late July, NEPGA contended that a pair of “flawed rules” caused capacity resources to accrue $51 million in “improper charges” during the three-hour scarcity event.

The balancing ratio, which is used to calculate resources’ performance responsibilities during scarcity events, averaged about 1.031 during the June 24 event, causing “$25 million in improper charges to capacity resources,” NEPGA wrote in its complaint. It argued for a cap on the balancing ratio, writing that capping the ratio at 1.0 would prevent resources from being required to supply more than their CSOs. (See NEPGA Seeks Relief for ‘Improper’ Pay-for-Performance Costs in ISO-NE.)

The association also called for changes to ISO-NE’s rules spreading the costs of under-collected PFP penalties across all capacity resources. Monthly stop-loss limits on the total penalties each resource can incur can cause under-collection of credits. Instead of charging these losses to all resources with CSOs, NEPGA proposed to deduct under-collected credits from the payment pool for overperforming resources.

The association noted that there was a $26 million under-collection of credits during the June 24 event. This deficit was charged to all capacity resources that did not hit their stop-loss limit during the event.

In response to NEPGA’s complaint, ISO-NE did not oppose capping the balancing ratio but opposed the proposed changes to the allocation of under-collected credits. The RTO argued it is fair to allocate stopped losses to capacity resources because the stop-loss rules benefit these resources by limiting their financial risks. (See ISO-NE Open to PFP Changes Following NEPGA Complaint.)

In its ruling, FERC agreed with NEPGA’s contention that the lack of a balancing ratio cap is not just and reasonable, noting that “in the absence of such a cap, resources with capacity supply obligations in ISO-NE may be subject to financial charges even when they are providing their maximum possible physical output during capacity scarcity conditions.”

The commission wrote that, under the current design of ISO-NE’s Forward Capacity Market, resources are frequently accredited near their maximum capability. Notably, this could change under the new rules proposed by the RTO in its Capacity Auction Reform project, which would accredit resources based on their expected reliability contributions during periods of shortfall and likely would reduce the overall accreditation value for many resources.

Capping the balancing ratio appears unlikely to hurt reliability, FERC wrote, reasoning that resources still would have received a significant performance incentive if the ratio had been capped on June 24. Capping the ratio at 1.0 would have lowered the effective performance rate from $9,337/MWh to $7,243/MWh during the event.

Regarding NEPGA’s complaint about the allocation of stopped losses, FERC agreed with ISO-NE’s argument that all capacity resources benefit from the stop-loss rules. It found the existing methodology to be “consistent with the beneficiary-pays principle.”

“The stop-loss mechanism provides each capacity resource with insurance against the possibility of suffering net financial losses in excess of the stop-loss limit,” FERC wrote. “Even a capacity resource that performs at its capacity supply obligation benefits from the stop-loss mechanism and should pay its share of the mechanism’s costs.”

FERC gave ISO-NE 180 days to file tariff changes capping the balancing ratio at 1.0.