Seattle City Light presented its proposal for the Bonneville Power Administration’s overhaul of the agency’s transmission planning process, saying BPA should offer interim conditional firm service (CFS) to most developers in the 61-GW transmission service queue.
During a Jan. 15 customer-led meeting, SCL’s Michael Watkins said the municipal utility supports many of the proposed alternatives under BPA’s Grid Access Transformation (GAT) project, including moving toward proactive transmission planning, “so that you’re planning ahead of customer needs, not responding to customer requests.”
BPA has a goal of reducing the time from transmission request to service to five to six years.
Watkins said SCL supports that goal and “Bonneville acquiring the resources to be able to do that.”
“We believe that future makes sense if customers can access conditional firm service/non-firm service, in the very near to short time, so that customers can react nimbly to a very changing landscape with some conditional firm service to get transmission service to meet those needs,” Watkins said.
BPA launched the GAT initiative to consider changes to its planning processes following a surge of transmission service requests (TSRs). The most recent transmission study includes 61 GW of new generation, compared with 5.9 GW in 2021, according to the agency. (See BPA Tx Planning Overhaul Prompts Concern for Northwest Clean Energy Compliance.)
BPA’s proposal to tackle the queue involves a two-part approach: a transitional phase to get off the pause and a longer-term “future state” that will include more substantial reforms to BPA’s existing transmission processes, such as shifting toward proactive transmission planning or stricter evaluation criteria of TSRs to reduce the queue.
But even with the “myriad” of options BPA has presented, the queue will remain around 31 GW, which will take about five to seven years to study, according to SCL’s presentation slides.
“We just don’t see that as a real solution for the region,” Watkins said.
BPA staff noted during the meeting that the agency does not have a proposal, only alternatives for stakeholders to consider, saying “it’s entirely possible … under the strictest application of new evaluation criteria, that the queue would be significantly smaller than the 31 GW that’s on the slide.”
“So, again, not a proposal, but just there are some options that would get us to a significantly smaller queue,” BPA staff said.
‘Daring and Bold’
Still, BPA should offer interim CFS with few exceptions to address the queue, Watkins argued. CFS is a form of long-term firm transmission service that allows BPA to curtail the reservation under certain circumstances, according to BPA documents.
“I believe where we’re at as a region has led us to a place where our best option is to now operate by curtailment,” Watkins said. “And in 99.9% of the time of the hours of the Northwest, there is never curtailment, even though there’s almost unlimited non-firm every one of those hours. I believe in the short term … we could live with … curtailment, with almost unlimited conditional firm service on our system, with the caveat that when we’re in extreme weather events it’s not going to work.”
To secure CFS, customers would, for example, sign contracts with additional requirements, such as length of contract, securitizing future and unknown projects, and securitizing five years of service rates.
“We think if we go down that route, that most of the queue will self-select to get out of the queue,” Watkins said. “Therefore, you don’t need a lot of large policy levers pulled to filter out the queue with. And that lends itself to queue management.”
BPA staff called the idea “daring and bold,” noting that the proposal has been up for discussion in the past.
Staff appeared to acknowledge the potential of offering CFS as a way to clear the queue by requiring financial commitments. Still, they warned that if more customers than expected accept the offer, it could put the agency and the region in a tricky spot.
“If we are surprised by the number that accept the offers, the amount of work in front of us to catch up on the sub grid might be more than we could handle, and so we may have gotten ourselves then into a reliability issue that we can’t build our way fast enough out of,” staff said. “And so it’s just hard to say exactly how much risk we would be exposed to collectively. That’s not Bonneville’s risk. That would be all of our risk.”
The principal driver for all this is that in the most recent capacity auction, for the delivery year 2027/28, PJM cleared 145,777 MW, which was 6,517 MW less than the “reliability requirement” of 152,294 MW. This comes at a time of high capacity prices. The combination of cleared capacity shortfall and high capacity prices is seen as a crisis requiring extraordinary measures. (See PJM Capacity Auction Clears at Max Price, Falls Short of Reliability Requirement.)
There is no crisis. Industry expert Matt Estes explains in plain language what the shortfall really entails:
“First of all, people who live in the PJM region don’t need to rush out to buy home generators. Although PJM was unable to acquire all of the capacity that it said it needed to ensure reliability, this does not mean PJM will inevitably be subjected to blackouts. PJM was able to acquire significantly more capacity than it anticipates will be necessary to serve its maximum demand for the year. Instead, the shortfall affects PJM’s reserve margin, which is the amount of capacity PJM acquires above its projected peak demand. The reserve margin allows PJM to supply the peak demand even if some capacity is unavailable due to problems with equipment or for needed maintenance, and/or if demand is higher than expected.
“PJM wanted to acquire enough capacity to achieve a 20% reserve margin. Although this did not happen, PJM still acquired enough capacity to have a 14.8% reserve margin. This is a healthy margin, and close to PJM’s target reserve margin in many previous auctions. I know in the past PJM has been criticized as using overly conservative assumptions for determining its needed reserve margin. And even if a 20% margin is needed to meet its one-event-in-10 year reliability standard, there is only a 10% chance that once in 10 years circumstances will occur in the year in which PJM failed to acquire enough capacity to achieve a 20% reserve margin.”
Steve Huntoon
And even if a shortage event did happen, it could be managed by rolling blackouts of short duration for a small percentage of retail customers in PJM. (This is, however, a useful reminder to utilities that they need to make sure their outage management tools, such as customer communications, are up to snuff.)
The PJM board has identified an additional option of requiring “certain large loads, including data centers, to move to their backup generators, or curtail their demand, for a limited number of hours during the year to prevent a larger scale outage for residential and other consumers.” There was 13,000 MW of projected data center demand in the load forecast for the 2027/28 auction (along with 4,000 MW of existing data center demand).
Now let’s look at why the shortfall occurred. According to PJM there was a 5,249.9-MW increase in forecasted load, mostly due to additional large loads (i.e., data centers).
It now appears the forecasted demand increase was overstated. PJM’s most recent load forecast shows a 3,735-MW reduction in the forecast for the 2027/28 delivery year “due to updates to the electric vehicle and economic forecasts as well as improved vetting of requested adjustments for data centers and large loads.”
In other implications for the future, there is a large amount of new generation in various stages of development, some portion of which will go into service and offer in future auctions. The current state of resource planning is described here.
Newly available generation can be procured for the 2027/28 delivery year in the incremental auction to be held in February 2027.
In summary, the shortfall did not portend an emergency, the shortfall was overstated, and there is an abundance of potential new supply.
With this knowledge, let’s consider the Trump-Governors proposal for a “Reliability Backstop Auction to procure new capacity resources commencing no later than September 2026.” Where is this new capacity coming from so quickly? In the last auction there was only 810 MW of eligible supply available that did not clear, due to the temporary price cap.
And, in complete contradiction to acquiring even this small amount of new capacity, the proposal also calls for extending the temporary price cap.
And how would this backstop auction differ from the next regular auction coming up in July? Would the price cap not apply to the backstop auction? My head hurts.
And what about all the new generating plants in various stages of development? Will they be able to offer into the backstop auction when they otherwise would offer into the regular auctions? If so, the available future supply for existing PJM customers would be reduced, creating upward price pressure in the regular auctions. And if not, where will supply for the backstop auction come from? Brand new generating projects taking years to go from conception to in-service? My head hurts.
And who are the buyer(s) of the reported $15 billion in generation? Some reports suggest it’s the data centers themselves, while others suggest it’s PJM, which would pass the costs through to load-serving entities with the states directing how the LSEs allocate the costs. My head hurts.
OK, I’ll stop here.
P.S. Except to flag this repeated claim in the Trump administration’s so-called “fact sheet”: “PJM forced nearly 17 GW of reliable baseload power generation offline during the Biden years.” This is completely false.
As everyone connected with PJM knows, PJM hasn’t forced a single gigawatt of baseload generation offline. PJM doesn’t have the power to do that, even if it wanted to. And it’s exhibited no want to do so. Instead, PJM for years has expressed reliability concerns about the retirement of baseload power plants, such as here and here.
OK, this time I’ll really stop.
Columnist Steve Huntoon, a former president of the Energy Bar Association, practiced energy law for more than 30 years.
SPP stakeholders have overwhelmingly endorsed a conditional interconnection process for large loads that will be paired with two other FERC-approved processes as part of the grid operator’s effort to approve large loads.
The conditional high-impact large load service (CHILLS) tariff revision request (RR720) gives load two paths for conditional connection: CHILLS with sufficient designated resources but contingent on transmission upgrades, and a large-load generation assessment that requires accredited, equivalent support generation for CHILL.
“Ultimately, we have what I would consider a policy that has a narrower scope than initially proposed before,” Yasser Bahbaz, senior director of operations told the Markets and Operations Policy Committee during its Jan. 13-14 meeting. “It’s that way because it does address, and is designed to address, concerns with respect to impact to the system, from a market impact and market-energy pricing standpoint, and also from a reliability standpoint.”
The CHILLS proposal was split in September from the policy package that included a high-impact large load (HILL) study and high-impact large-load generation assessment (HILLGA) to give stakeholder groups more time to refine and address concerns expressed with the CHILL policy. FERC approved the HILL and HILLGA policies Jan. 15. (See FERC Approves SPP Large Load Interconnection Process.)
The HILL/HILLGA proposal accelerated studies and access to interconnection information, but market participants without generation cannot establish a delivery point for the HILL study. CHILLS expands on that policy to enable speed to power, not just speed to information, Bahbaz said.
“[HILL] information was basically saying, ‘This is what it takes, this is what it costs, and these are upgrades that are needed for these large loads to interconnect,” he said. “So, we are taking it from just a speed to information to speed to power.”
SPP’s Market Monitoring Unit said that with recent revisions to the proposal, it now supports the CHILLS policy. However, it called for the RTO to document that it will commit reliability status resources or make local reliability commitments only to supply firm load and ensure consideration in determining whether a participant has sufficient capacity to “cover” a CHILL with associated generation.
MMU lead Carrie Bivens noted that load-responsible entities (LREs) can use the same megawatts for both the planning reserve margin and to cover a CHILL.
The CHILLS load-interconnection process | SPP
“It’s the exact same megawatts of capacity that are pointed at two different purposes,” she said. “It does make the region reliant on essentially perfect responses from resources and CHILLS in order to mitigate reliability risks.”
MOPC members endorsed the proposal with 99.3% approval, although there were 43 abstentions. There were only five no votes.
Peak Demand Assessment Delayed
MOPC members voted to direct staff to modify revision request RR703 by altering the proposed peak demand assessment (PDA) to focus only on the forecast effects of load-modifying demand response resources (LMRs). The revised tariff change is to be brought back to working groups before the April MOPC meeting.
The endorsed motion was crafted as a compromise after a previous motion amending a Supply Adequacy Working Group recommendation to include a cap on LMRs based on 2025 actuals or workbook submittals failed. Members cited concerns over the load forecast’s evaluation while expressing support for the RR’s demand-response portion.
“I was hoping that this wouldn’t happen,” Evergy’s Jim Flucke, chair of the Market Working Group, said in offering the compromise motion. “It would allow for another three months to allow us to work through some of the concerns in the PDA. The big difference that we’re proposing is that we focus PDA strictly on the demand response.”
Flucke said the demand response piece would remain as “previously envisioned.” He said the key hurdle is working through demand response’s deployment and how “that’s going to fit into this approach of being able to evaluate your demand response portion and how well it is meeting what your expectation was in your workbook.”
SPP staff said they can work with the three-month delay in adding “increasingly critical” demand response as the RTO addresses rapid load growth, evolving resource mixes and tighter energy conditions. Natasha Henderson, senior director of grid asset utilization, said the grid operator will be reliant on FERC approval if it is to implement a revised PDA forecast in 2028 and with risk mitigation for 2027 “that isn’t full implementation.”
“I think this is doable … while I ask for 60 days [for FERC action], I suspect it’s going to be more like 180 days, given the contentious nature of this policy,” Henderson said.
RR703 is intended to increase the visibility and ability to deploy demand response by creating a participation model and accreditation framework for non-price-sensitive DR. SPP wants to incent LREs to manage peak loads by qualifying non-registered or load-modifying demand response capable of performing when their peak loads exceed their qualified resources. (See REAL Team Endorses DR Policy, CONE Value.)
In other actions, MOPC:
Approved base planning reserve margins for the RTO Expansion members of 19 and 40% for the summer and winter seasons, respectively. The PRMs are effective in 2027 to give the RTOE members time to adjust to integration into SPP. They were based on a loss-of-load expectation study and other analysis directed by an RTOE ad hoc study group and other stakeholders. The RTOE is one-tenth the size of SPP, with a little more than 5 GW of accredited capacity.
Endorsed a proposed tariff revision (RR534) that limits long-term firm services up to the interconnection limit at the point of interconnection for modeling and controlling energy storage resources hybrid configurations.
Wyoming Transmission Outage
A November grid disturbance resulted in a significant “uncontrolled” loss of generation (4 GW) and load (1 GW) across Wyoming and into western South Dakota, staff told MOPC.
The Nov. 13 event in the Western Interconnection began with the planned removal of a 500-kV transmission line in the PacifiCorp balancing authority area. That led to the immediate loss of another 500-kV line that triggered cascading outages around 12:34 p.m. (MST).
SPP’s Derek Hawkins, director of system operations, said the RTO’s reliability coordinator operators immediately responded to address severely loaded transmission constraints, working across internal and external transmission operators and the neighboring RC to return the system to a “secure operating state.”
“We did that very quickly … to get the system in a spot where we could start the restoration,” he said, noting the restoration was completed in the evening of Nov. 13.
NERC and WECC have launched a coordinated investigation into the event. Hawkins said they are likely to file a detailed report that covers the root causes, contributing factors and lessons learned from the event.
Hawkins also said high winds in December resulted in several new marks for wind generation, eventually topping out at 26.3 GW on Dec. 19. SPP’s previous high came in August 2025 at 24.3 GW.
Dueling CSP Studies
SPP staff told members that its joint operating agreement with MISO requires another joint study in 2026, even as the grid operators are completing their 2024 study.
The two RTOs have conducted preliminary screening analyses of 31 projects, using both original coordinated system plan (CSP) models and those that incorporate approved transmission projects from 2025. Staff will focus next on 14 projects, primarily along the southern seam in Arkansas, Louisiana, Oklahoma and Texas, in evaluating their reliability, economic and transfer benefits.
“We will begin to build a business case for any projects out of those 14 that make it through, that we want to even consider a little more in terms of benefits calculation,” Clint Savoy, SPP’s manager of interregional strategy and engagement, told MOPC. “We will start having conversations about cost allocation … and we expect those conversations to continue through this year.”
The grid operators plan to draft a report on the 2024/25 study’s results by March 9 and then develop a business case and allocate costs. They have yet to agree on a single joint project during the more than 10 years of the FERC Order 1000-compliant CSP process, usually disagreeing over the cost-benefit analysis.
Stakeholders have until Feb. 6 to submit transmission issues for 2026 that could be system needs to either MISO or SPP. The RTOs’ staffs will review the issues 2026 during a March 6 meeting.
MOPC also approved 19 tariff revision requests — several related to the RTOE —that, if approved by the board, will:
RR694: Align the analysis and changes during the annual flowgate assessment to the flowgate list with real-time operations.
RR704: Set standard, baseline assumptions for the annual loss-of-load expectation study and the process for studying sensitivity or assumption changes and their impact on the PRM.
RR714: Improve Business Practice 7060’s (Notification to Construct and Project Cost Estimating Processes) language for consistency, readability and procedural clarity.
RR718: Develop inverter-based resource requirements based on reliability needs for SPP governing documents.
RR723: Update the business practices for transmission service and related tagging practices when RTOE begins operations April 1.
RR724: Revise Attachment AQ’s study scope to include Integrated Transmission Planning project-selection criteria for network upgrades and consider zonal reliability upgrades.
RR725: Modify existing language requiring SPP to follow up with a phone call when a market participant does not confirm a commitment by making the calls optional, rather than mandatory, to reduce unnecessary manual interventions by operators.
RR726: Update applicable governing documents to support the integration of RTOE participants into SPP’s existing modeling and transmission planning processes, clarifying terminology and update references and incorporating modeling considerations specific to the Western Interconnection.
RR727: Update the revision request process document to include a new governing document (the CPP manual) required for the new regional planning and generation-interconnection study process.
RR729 Update the cost of new entry value based on SPP staff’s annual review for implementation in the 2026 summer season.
RR730: Clean up inaccuracies in the list of Western Area Power Administration-Colorado River Storage Project (WAPA-CRSP) resources to be included in its federal service exemption (FSE) resource hub.
RR733: Update tariff and protocol language to clarify how disputes between the MMU and a market participant (MP) will be handled and clarify that they can dispute the MMU’s ex-post verification of actual costs.
RR734: Clarify that SPP and MPs can use FSE transfer points and the WAPA-CRSP resource hub to obtain candidates and nominate auction revenue rights and long-term congestion rights consistent with the tariff’s FSE provisions.
RR735: Align tariff and protocol language with current congestion-management practices by replacing outdated market-flow submission requirements with the parallel flow visualization process.
RR736: Improve the regulation selection process’ efficiency by automatically selecting resources when their regulation capacity limits and ramp rates are equal to their energy capacity limits and ramp rates. The selection for regulation of eligible resources that cleared in the day-ahead market will be done as reliability unit commitments instead of the real-time balancing market.
RR737: Add administrative language to the SPP market protocols to effectuate and align with the approved RTOE tariff language. Settlement calculations will be relocated to a settlement-calculation reference manual.
RR738: Revised Business Practice 10000 (Reliability Coordinator Outage Coordination Methodology) to accommodate RTOE members.
RR740: Clarify current reliability coordinator (RC) function practices for identifying and addressing emergency conditions in the SPP RC area by adding a new section in SPP’s operating criteria.
RR741: Add an addendum to the tariff formalizing interregional-transmission planning coordination for the Western Interconnection to meet Order 1000 requirements and allow SPP to coordinate RTOE planning activities with adjacent Western planning regions.
Two new studies released by advocates on opposite sides of the clean energy debate reach opposite conclusions about the economic benefits of renewables.
A coalition of free market think tanks on Jan. 13 trumpeted a new report by Always On Energy Research (AOER) concluding that if state renewable energy mandates in New England were abandoned in favor of new nuclear and natural gas generation, ratepayers would save hundreds of billions of dollars over the next 25 years.
The Coalition for Community Solar Access (CCSA) on Jan. 14 hailed a new report it commissioned from Synapse Energy Economics that found expanding New York’s distributed solar portfolio to 20 GW and increasing the state’s energy storage capacity could lead to $1 billion in annual energy cost savings for ratepayers by 2035.
The AOER report was quickly criticized in a rebuttal by a group of decarbonization advocates who called its data selective, its analyses flawed and its proposed scenarios highly unrealistic.
The CCSA report, on the other hand, is itself a rebuttal or rebuke of New York state’s recent step back from some of its clean energy goals and its governor’s interest in an all-of-the-above energy solution to ensure affordability.
Although the conclusions and suggested solutions vary widely, the underlying issue — expensive electricity — is not debatable.
In its most recent monthly price report, the U.S. Energy Information Administration calculated the average U.S. electricity price across all customer sectors nationwide at 13.63 cents/kWh in October 2025. New York was 57% higher at 21.34 cents and New England was 75% higher at 23.8 cents.
For all of 2024, those seven states ranged from 42 to 88% higher than the national average. Only California and Hawaii were higher.
New England
The AOER report was released by the Maine Policy Institute, Fiscal Alliance Foundation, Josiah Bartlett Center for Public Policy, Rhode Island Center for Freedom & Prosperity, Yankee Institute and Americans for Prosperity Foundation.
It is a continuation of previous AOER state-level analyses, including a 2024 study that modeled the economic and reliability impacts of energy policies in the six New England states; all but New Hampshire have established aggressive decarbonization requirements.
While AOER does not explicitly identify itself as pro-fossil fuel, it repeatedly describes itself with common pro-fossil keywords such as affordable, abundant and reliable, and its work frequently faults green policies.
The 2026 report — “Alternatives to New England’s Energy Affordability Crisis” — looked at four ways to meet a total peak demand of 52.5 GW on the ISO-NE grid in 2050:
The renewables scenario would combine 19.2 GW of onshore wind, 43 GW of four-hour storage, 66 GW of offshore wind and 68.4 GW of solar at a cost of $815 billion.
The nuclear scenario gradually replaces all carbon dioxide-emitting generation with 20.4 GW of large nuclear plants and 14.7 GW of small modular reactors, plus 13.7 GW of natural gas generation in a bridge and/or peaker role at a total cost of $415 billion.
The natural gas scenario entails all types of existing generation assets being used until they reach the end of their useful lives, then being replaced with new combined cycle gas-fired plants plus new gas combustion turbine peakers. This would cost $107 billion.
The “happy medium” scenario would add 10.8 GW of new nuclear and 24.3 GW of new gas capacity to existing generation at a cost of $196 billion.
The authors note that each scenario faces significant obstacles: the sheer scale of a wind-solar-storage buildout, anti-offshore wind policies, insufficient gas pipeline capacity and the very concept of building so many nuclear reactors. They also said they did not attempt to factor in the cost of things such as building electrification or quantify the fuel cost savings such steps would offer.
The think tanks that released the AOER report focused on the dollar figures and urged New England policymakers to turn away from renewables.
“New Englanders are being asked to bankroll an energy experiment that is dramatically more expensive and far less reliable than proven alternatives. This study puts hard numbers behind what families and businesses already feel every month. State-mandated wind and solar are driving up costs while increasing the risk of blackouts. Replacing these mandates with nuclear and natural gas would save hundreds of billions of dollars, strengthen grid reliability and deliver real emissions reductions without sacrificing affordability or economic competitiveness,” Fiscal Alliance Foundation Executive Director Paul Diego Craney said in a news release.
The 501(c)(3) working to reduce carbon emissions in the Northeast laid out a point-by-point rebuttal of the report three days after AOER released it, saying its analysis “grossly inflates the cost of clean energy, selectively ignores fuel savings and proposes highly unrealistic alternative scenarios.”
It also ignores the societal cost of carbon emissions, understates the cost of nuclear, overstates the installed capacity needed and does not consider the prospect of emerging clean-energy technologies, Acadia said.
Acadia similarly attacked AOER’s 2024 report, “The Staggering Costs of New England’s Green Energy Policies.”
New York’s Shift
The Empire State through rhetoric and policy has long been one of the most aggressively green states in the nation.
But energy development comes at a high cost and slow pace in New York, and renewables are lagging far behind the goals the state mandated in its landmark 2019 climate law.
With utility costs high and rising further, with existing generation assets aging and with the Trump administration actively opposing renewables, New York Gov. Kathy Hochul (D) recently has taken a more pragmatic stance, continuing to embrace the state’s green goals but hesitant about the cost of reaching them.
Among other things:
The New York Power Authority is taking a measured approach to its new role as renewable energy developer, initially targeting fewer and smaller projects than advocates would like and expecting a high attrition rate for them.
The newly updated State Energy Plan predicts a longer reliance on fossil fuels, possibly including what until recently was unthinkable — new-build fossil generation.
The state allowed a controversial gas pipeline expansion plan to go forward after previously rejecting it.
Hochul has held off on implementing a planned cap-and-invest system.
The state appears poised to continue its subsidies for existing nuclear power plants, which cost ratepayers about $500 million/year.
Hochul in mid-2025 ordered development of 1 GW of new nuclear capacity, then kicked that up to 5 GW in her 2026 State of the State Address.
Distributed solar generation is one of the bright spots in New York’s clean energy landscape — deployment has surpassed goals and by some measures has led the nation.
A large group of mostly Democratic Assembly members and senators are sponsoring the Accelerate Solar for Affordable Power (ASAP) Act (A8758/S6570), which would boost the state’s goal from 10 GW of distributed solar by 2030 to 20 GW by 2035.
The seasonal contribution of solar and storage are shown by hour and month. The boldface outlines indicate the hours most likely to see NYISO reliability events. | Synapse Energy Economics
Installed capacity presently stands at 7.3 GW with 2.8 GW more in the development pipeline, advocates say.
The study Synapse Energy Economics conducted for CCSA concluded that with 20 GW of distributed solar and 3.7 GW of distributed storage in place by 2035, an estimated $1 billion/year in ratepayer energy costs would be avoided. The savings would accrue to all ratepayers, though not equally across regions.
This much capacity would avoid the use of 56 Bcf of gas for energy generation, or about 11% of New York’s total in 2024. That reduction would yield a savings of $947 million in societal cost of greenhouse gas emissions.
The authors say other benefits such as public health improvement and the ability to defer grid upgrades would be notable but were not quantified for the report.
Synapse lists multiple environmental advocacy organizations among its clients. The scope of its work includes a significant focus on green energy and decarbonization but extends to other aspects of the power grid.
“This study shows that smart policy choices can unlock real savings for all customers, not just those who install solar on their rooftops,” CCSA Northeast Director Kate Daniel said in a news release. “The ASAP Act is an opportunity to build on New York’s leadership and scale solutions that are already working.”
ASAP’s sponsors embraced that conclusion.
“In these uncertain times and with headwinds from the federal government, it’s more important than ever for New York state to lean into and expand on our successes,” said Assemblymember Didi Barrett (D), sponsor of the ASAP Act in the Assembly and chair of its Energy Committee.
“Solar energy is the cheapest form of energy to produce and a linchpin for affordability,” said State Sen. Pete Harckham (D), sponsor of ASAP in the Senate and chair of its Committee on Environmental Conservation. “This new study re-emphasizes the long-term, abiding value of renewable energy and storage systems in this regard. At this point, we should be exponentially increasing our clean energy efforts and gigawatt goals with distributed solar projects to create thousands of green jobs and save ratepayers millions of dollars.”
Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee and Members Committee meetings Jan. 22. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will cover the discussions and votes. See next week’s newsletter for a full report.
Markets and Reliability Committee
Consent Agenda (9:05-9:10)
Endorse proposed revisions to the Regional Transmission and Energy Scheduling Practices document to codify the NAESB version 4.0 Business Scheduling Practice Standards.
Endorse proposed revisions to Manual 2: Transmission Service Request drafted through its periodic review.
Endorse proposed revisions to Manual 21B: PJM Rules and Procedures for Determination of Generation Capability to expand the definition of dual-fuel gas generation to include configurations where the secondary fuel is stored off-site but directly connected to the resource with a dedicated pipeline. (See “Stakeholders Endorse Expanded Dual Fuel Manual Definition,” PJM PC/TEAC Briefs: Jan. 6, 2026.)
Endorse proposed revisions to Manual 28: Operating Agreement Accounting drafted through the document’s periodic review. The changes seek to clarify the opportunity cost calculation for hydro units, how day-ahead load response bids are included in the day-ahead operating reserve charges and the calculation of capped real-time synchronized reserve assignments for demand response.
Endorse proposed revisions to Manual 38: Operations Planning proposed as part of its periodic review. The language details the long-term study process included in the Regional Transmission Expansion Plan and adds MISO solar generation to planning studies.
Endorsements (9:10-9:35)
2026/2027 3rd Incremental Auction (IA) Installed Reserve Margin (IRM) and Forecast Pool Requirement (FPR) (9:10-9:35)
PJM’s Josh Bruno will present the recommended IRM and FPR values for the 2026/27 Third IA, which is scheduled to be conducted on Feb. 24. The parameters were calculated with the 2026 load forecast, which scaled back PJM’s estimates of the load growth anticipated for the delivery year. This resulted in staff recommending an IRM of 18.6%, 0.5% lower than the margin used in the base residual auction, and a 0.9291 FPR, 0.0121 higher than the BRA.
Stakeholders will be asked to endorse the parameters upon first read and same-day endorsement will be sought at the Members Committee meeting.
Members Committee
Endorsements (11:00-11:30)
Minimum Capitalization (11:00-11:15)
PJM’s Ryan Jones will present a proposal to increase the minimum capitalization requirements to participate in its markets. It would double the tangible net worth requirement for market participants and add a 3% annual escalator. (See PJM Presents 1st Read on Minimum Capitalization Requirement Proposal.)
Facing surging electricity demand from data centers and artificial intelligence, NV Energy might soon be struggling to meet Nevada’s renewable portfolio standard.
That’s according to Janet Wells, NV Energy’s vice president of resource planning, who led a Jan. 14 stakeholder meeting on the company’s 2026 integrated resource plan.
Wells said the company expects to face challenges in meeting the RPS “for several years.”
“Federal policy has reduced the deliverability of new renewable resources while also increasing energy needs to support the [federal] AI action plan,” Wells said. “That combination will create challenges in meeting the RPS compliance.”
Among those challenges are soon-expiring federal tax credits for solar and wind projects, federal policy shifts on solar and wind, and potential tariff impact on imports, Wells said previously.
If the company misses the RPS target, it will ask regulators for a compliance waiver, Wells said.
NV Energy thus far has been meeting the state’s RPS, which requires a certain percentage of electricity sales to come from renewable resources. The RPS increased from 29% in 2022-23 to 34% in 2024-2026, 42% in 2027-2029, and 50% in 2030 and beyond. In 2024, the company exceeded the standard with 46.8% renewables.
At the January meeting, Wells provided more detail on the load forecast on which the new IRP will be based.
A load forecast for the company’s 2024 IRP predicted system growth of 31,000 GWh over 20 years, or a compound annual growth rate of 3.2%.
In the new forecast, electricity sales from 2026-2046 are expected to reach 43,400 GWh, a 40% increase from the previous forecast, with a compound annual growth rate of 5.3%. Much of the growth will be concentrated in the northern part of the state.
“The main reason for the difference is a continued increase in the large customer requests, specifically data centers and AI-driven load,” Wells said.
As for the RPS, existing and approved renewable resources will be enough to meet the standard in 2027, NV Energy’s projections show. But more renewables will be needed starting in 2028 for RPS compliance.
To help meet its surging demand, NV Energy issued a request for proposals in 2024. The RFP drew 198 bids — a company record.
From there, the company developed a shortlist of 15 projects totaling 8 GW of capacity. About 3,800 MW is new generation and about 4,200 MW is storage, Wells said. NV Energy has already requested regulatory approval for one project: a 150-MW power purchase agreement for the Dodge Flat battery storage system in northern Nevada.
Approval for other projects will be sought through the 2026 IRP. Wells said the expected ratio of renewables and storage to thermal resources is roughly 3:1. She noted that the earliest new gas combustion turbines could be in operation would be 2029 or 2030.
Allocating Costs
NV Energy’s base load forecast for its 2026 IRP includes “mitigation” for large loads — meaning requested loads are reduced by half if a line-extension contract has been signed or by 85% if there’s no contract, Wells said during the December meeting.
In addition, the company developed a “base minus” forecast that excludes growth from data centers and AI. Wells said resource costs to meet the two forecasts would be compared, and the extra costs seen in the base forecast could then be allocated to large load customers.
A third forecast called “base plus” assumes that all load will materialize from large customer projects with signed contracts.
In another consequence of surging demand, NV Energy is delaying plans to close its open position, which refers to resource needs that are met through short-term market purchases rather than by the utility’s own resources or long-term contracts.
Wells said the goal now is to gradually reduce the company’s open position from around 2,000 MW in 2027 to 500 MW by 2031.
NV Energy is required to file an IRP at least every three years. Legislation passed in 2023 authorized the company to file an IRP more often “if necessary.” The 2026 IRP is coming only two years after the company’s 2024 plan.
NV Energy plans to host a third stakeholder session on the 2026 IRP in February, with a focus on the company’s distributed resource plan, the transportation electrification plan and the demand-side management plan.
The NYISO Operating Committee has approved the ISO’s locational capacity requirements (LCRs) despite multiple stakeholders abstaining from the vote in protest of the process.
“On behalf of Multiple Intervenors and the city [of New York], we just want to express that we are deeply concerned with the process NYISO went through,” said Kevin Lang, a lawyer from Couch White who represents large industrial customers and NYC. “The NYISO can’t surprise, and should not be surprising, market participants with last-minute changes in its methodology.”
In addition to the Multiple Intervenors group and NYC, PSEG Long Island and Energy Spectrum abstained from the Jan. 15 vote. All other members voted in favor of the LCRs.
Lang was referring to a presentation given to the New York State Reliability Council’s Executive Committee (NYSRC EC), in which changes to the 2026/27 installed reserve margin (IRM) study were discussed and voted on. According to the published LCR Study, the IRM report implemented changes to include modeling of the Champlain Hudson Power Express and winter fuel constraints. These changes included modeling of voluntary curtailments and distributed area resources. Transmission security floor values, which are used in the calculation of the LCRs, also were updated.
“The NYSRC EC is concerned with the timing and lack of notice in the NYISO TSL [transmission security limit] methodology and the apparent reversal of previous TSL positions without stakeholder or NYSRC input,” NYSRC EC chair Mark Domino was recorded saying in the meeting minutes. Domino said the NYSRC would reactivate the Reliability Resource Evaluation Working Group to consider a new reliability rule to address this issue.
The final LCRs were first presented Jan. 6 at an Installed Capacity Working Group (ICAP) meeting. (See NYISO Presents Final LCRs for 2026/27.) At that meeting, little discussion of the final LCRs occurred.
The LCRs, expressed as a percentage of peak load forecast, represent the minimum capacity that generators and load-serving entities must maintain within the downstate zones. These zones have substantial transmission constraints.
“We are going to work with the Reliability Council to address the minimum timing issue,” said Yvonne Huang, senior manager of ICAP market operations. “We will try to improve the process going forward.”
Huang asked NYISO to “never do that again” and requested clarification as to why the ISO waited until the last minute to introduce methodology changes to stakeholders. She said the ISO made the changes because of the reliability need that was discovered in 2025. (See NYISO Again Identifies Reliability Need for NYC.)
“I agree we should work better to improve and bring the changes early,” said Huang, who added that the changes were first brought up in a Nov. 20 Electric System Planning Working Group meeting. “We were working as fast as we could.”
Jason Ragona, representing Con Edison, issued a statement saying that while the company would vote to support the LCR motion, it wanted on the record that it shared Lang’s concerns about rapid changes to TSL and LCR calculations. Ragona encouraged the NYSRC to adopt procedural changes to “minimize” future occurrences.
The representative from PSEG Long Island issued a similar statement to Ragona’s, calling for more time to perform complete reviews and comments about any changes.
Other Business
The OC also heard the Operations Report for the New York Control Area for December 2025. The peak load for the month was 23,448 MW on Dec. 15 around 5 p.m. That set the winter load record for the year. Wind generation peaked at 2,338 MW on Dec. 18 at 10 p.m. Solar peaked at 2,767 MW on Dec. 22 at 11 a.m. No major emergencies occurred, but seven alert states were issued during the month.
The committee also heard and approved revisions to the System Restoration Manual and approved a system impact study scope for a data center development on the former site of the Remington Arms Factory in Ilion. The Associated Pressreported on the factory’s closure in 2024.
After nine years, MISO will close out its multiphase market platform replacement project, leaving a bulk of unfinished work on its real-time market.
MISO said it’s “adjusting the remaining scope to conclude the program in 2026,” and will cut its work to build a new unit dispatch system from the multiyear effort. That undertaking will become a standalone project.
MISO’s unit dispatch system balances generation and load in five-minute intervals to clear the real-time market, selecting generators’ offered megawatts and prices while managing transmission congestion and meeting reserve requirements. The system sends five-minute dispatch and price signals to generators based on bids and system need.
MISO’s removal of a new unit dispatch system from the market platform project means that the RTO will spend an estimated $154 million on the market platform swap-out, not including the unit dispatch system. MISO began the platform project with a $130 million budget plus a 25% contingency, bringing the total spending limit to $162.5 million.
MISO said even though it’s cutting out the capstone task of the platform replacement project, the work thus far on the project would deliver about $425 million in benefits.
“Obviously, we’ve spent more than we anticipated,” MISO’s Scott Daugherty said during a Jan. 15 meeting of the Market Subcommittee. Daugherty added the expense is part of MISO being on the “cutting edge” of incorporating the newest technologies.
MISO planned to build the unit dispatch system over 2026, test and deliver it sometime in 2027 and formally launch it in 2028. It’s unclear what a new budget and timeline might be. In the meantime, MISO will make do with its existing system.
MISO principal adviser Kevin Larson said re-platforming MISO’s market has been a complex endeavor.
Daugherty said isolating the unit dispatch system overhaul as its own project will allow MISO to work more automation into the finished product.
“Eventually we’ll get the UDS to the current re-platformed engines,” he said.
“The core objective we were going after is performance and security,” Larson added.
In response to stakeholders’ questions, Larson said the new market platform won’t be embedded with AI-based technology. Larson said AI would show up in the market’s “secondary capabilities,” like MISO’s uncertainty management tool, which helps guide dispatch.
Some stakeholders said they were disappointed with MISO’s decision to strike the dispatch system rebuild.
“I’m trying to be calm; I am frustrated with this, but I understand this is difficult to do,” Fresh Energy’s Mike Schowalter said.
Schowalter said MISO has told stakeholders repeatedly the market platform replacement would allow MISO to make more complex market changes. He asked to what extent “carving out” the unit dispatch system would impede what’s possible.
Schowalter said the new market platform always has seemed like “black box that’s going to do all these magic things” that stakeholders might not understand. He asked for a more detailed explanation of what new capabilities the market platform would enable.
“What are those things that are going to have to wait another two years?” Schowalter asked. He added there’s “a lack of understanding on what’s waiting for what.”
Daugherty said the purpose of the market platform replacement is to “not do much that’s new but re-platform the existing capabilities” and position the markets to be more adaptable to new technologies and increasingly complex market products.
Kevin Larson (left) and Scott Daugherty, MISO | MISO
“We’ve had this big chunk of market enhancements we haven’t been able to go after,” Daugherty said.
Clean Grid Alliance’s David Sapper asked where MISO’s work to bring aggregated distributed energy resources into the market under FERC Order 2222 stood.
MISO staff took down the question to address later.
Michigan Public Power Agency’s Tom Weeks said the market platform replacement was sold by MISO as: “OK, all the things we can’t do in terms of improving the markets, we can do” once the new platform is in place. Weeks made the comment while asking MISO to create a commitment process especially for jointly owned generation resources.
MISO said the remaining sections of in-progress market platform work are positioned to be completed at the end of 2026. That includes the launch of its reliability assessment and commitment market tool, its look-ahead commitment tool and its one-stop repository for planning and operations data to create its models.
MISO unveiled its new day-ahead market clearing engine as part of the project in 2024.
Larson said MISO began the platform project in 2017 when it began having “on and off problems” with its day-ahead market clearing engine. At that time, it had a wish list of improvements the aging market platform wouldn’t be able to handle.
MISO needs pieces of the market platform replacement, specifically the new look-ahead commitment tool, to be able to comply with FERC’s Order 881, which requires real-time ambient-adjusted line ratings.
The look-ahead commitment tool works with the unit dispatch system to arrange near-term generator commitments.
Order 881 by 2028
MISO said it doesn’t expect full compliance with Order 881 until the end of 2028, due in part to the delay of the new look-ahead commitment clearing engine. (See MISO to Seek 3-Year Order 881 Delay for Vendor Holdups.)
At a Jan. 13 Reliability Subcommittee meeting, MISO also said its vendor might not be able to deliver the necessary software as scheduled in the second half of 2026 to ready its real-time system to incorporate the varied ratings. MISO added that its transmission owners are expected to prepare for the new rule into 2027.
“MISO’s systems being ready doesn’t mean that TO systems are ready,” MISO’s Paul Kasper said. He reminded stakeholders that TOs must conduct their own system testing and integration campaigns.
Kasper said MISO is taking “exceptional” steps to maintain its timeline on the project. “There’s only so much we can control with the vendor.”
FERC has approved SPP tariff additions that deploy novel study processes to quickly review requests for “high-impact” large loads seeking to interconnect to its system.
The new attachments to the tariff incorporate transmission, generation and load interconnection services into a single framework, effective Jan. 15. They establish a 90-day study-and-approval process for interconnecting large loads that will be paired with new generation or with current or planned generation (ER26-247).
In its Jan. 15 order, FERC said SPP showed that “unprecedented” growth in large loads in its footprint presented “significant and unique operational and planning challenges.” It found the grid operator’s addition of a high-impact large load (HILL) study and high-impact large load generation assessment (HILLGA) processes address those challenges “while maintaining the reliable operation of SPP’s transmission system.”
SPP CEO Lanny Nickell said in a statement that the grid operator is proud that it is “first in the nation” to blend transmission, generation and load interconnection services into a single framework.
“It’s essential to our nation’s competitive future that we can quickly, reliably and affordably meet vastly increasing energy demands,” he said. “We are now in a great position to enable this future.”
SPP defines HILLS as new commercial or industrial load, or an increase in the load, at a single site connected through one or more shared interconnection or delivery points, and where load is either 1) 10 MW or more if connected to the transmission system at a voltage level less than or equal to 69 kV; or 2) 50 MW or more if connected at a voltage level greater than 69 kV.
Customers registering their load as HILLs and with plans to acquire generation will get a 90-day study and provisional approval, with upgrades directly assigned until the customer acquires firm service for the new generation. They will not be required to have current generation or a generator interconnection agreement.
Under the HILLGA process, HILL customers bringing supporting generation will also receive a 90-day study and a limited interconnection agreement. Upgrades will be directly assigned to the generation customer.
Commissioner David Rosner filed a concurring opinion calling on other U.S. transmission providers to consider similar proposals to SPP’s “pragmatic steps” supporting economic growth in its footprint.
“Today’s order is a productive step toward facilitating the energy needed to win the AI race, bring back American manufacturing, and deliver the reliable and affordable energy on which families and small businesses depend,” he wrote.
FERC noted SPP’s filing contained several “ministerial errors” and directed the RTO to make a compliance filing within 30 days.
SPP developed the processes following a May directive from board Chair John Cupparo that staff deliver a timely, scalable and reliable approach to manage the exponential growth of load demand across the footprint. Staff’s first attempt was rejected by members in July before a revised version won endorsement from stakeholders and then the board in September. (See “Large Load Integration OK’d,” SPP Board Approves 765-kV Project’s Increased Cost.)
A third service, conditional high-impact large load service (CHILLS), was split out from the HILL/HILLGA policy package to give stakeholder groups sufficient time to refine and address concerns. Stakeholders have since approved the final framework and its two paths for load’s conditional connection.
SPP’s board will consider the CHILLS framework during its Feb. 3 meeting in Little Rock, Ark.
MISO is registering and accrediting resources to meet a roughly 2-GW uptick in load for the 2026/27 planning year.
The grid operator has so far recorded a preliminary 135.6 GW in total accredited capacity for the peak summer season, and it still has some resource registrations in progress.
The RTO reports it has nearly 175.6 GW of total installed capacity. For the 2025/26 planning year, the RTO had 139.4 GW in accredited capacity available to it in summer.
MISO has established an initial 137.5-GW initial planning reserve margin requirement to cover a 124.7-GW coincident peak forecast for summer. The RTO’s downward-sloping demand curve used in the auction will likely clear more capacity than the margin requirement. It entered the 2025/26 auction with a 135.2-GW margin requirement and ended with a nearly 137.6-GW requirement. Its 2025/26 coincident peak load forecast was 122.6 GW.
Speaking at a Jan. 14 Resource Adequacy Subcommittee meeting, MISO Manager of Resource Adequacy Andy Taylor said load forecasts have risen across the board for the upcoming planning year, according to load-serving entities. He said the increases aren’t large enough to cause panic.
The grid operator’s numbers, prepared for the upcoming spring capacity auction, are preliminary. MISO plans to post five more data updates through March 19.
MISO will open its capacity auction offer window will be open March 26-31 and post auction results April 28.
