Speaking to members of NERC’s Reliability and Security Technical Committee, ERO Director of Reliability Assessments John Moura said the organization will continue to follow priorities developed over its previous three-year plan, which expired at the end of 2025.
Moura joined the RSTC’s annual work plan summit, hosted at the headquarters of Oglethorpe Power on Jan. 20, to share the ERO’s work plan priorities for 2026. NERC CEO Jim Robb said in 2025 that the ERO planned to approach 2026 as a “bridge year” between three-year plans in light of uncertainty around multiple issues including large loads, gas-electric coordination and trade policy that made long-term planning “a fool’s mission” at the time. (See 2026 to be ‘Bridge Year’ for NERC Budget.)
NERC is “already working on [the] next revision of a long-term strategy,” Moura said, but in the meantime is following the priorities of the previous plan. Those priorities are grouped into four categories: energy, security, engagement, and agility and sustainability.
The energy category involves “deepening and broadening” stakeholders’ understanding of reliability risks by improving the ERO’s reliability assessments. Interconnection-wide energy assessments will be a part of this effort beginning next year after a pilot program launched in 2025 to establish common platforms and standardized assumptions for the Eastern, Western and Texas interconnections, Moura said.
Another aspect of the energy category is addressing the reliability risks posed by data centers and other large loads by completing reliability guidelines that are already under development and developing new reliability standards if necessary. NERC may also conduct industry outreach and education on mitigation measures.
The next category, security, involves the rapidly developing landscape of threats against the grid’s cyber and physical assets. NERC aims to advance the grid’s resilience through multiple initiatives, including threat analysis through the Electricity Information Sharing and Analysis Center, the GridSecCon security conference and other mechanisms. NERC will also keep industry and policy makers informed of security threats and other priorities as part of the third category, engagement.
The final priority, agility and sustainability, involves updating the ERO’s internal process. A major area of focus here is the ERO’s efforts to modernize its standards development process. Moura also included NERC’s work on improving data access and efficiency by enhancing its software tools and leveraging artificial intelligence tools where appropriate.
Asked by RSTC Chair Rich Hydzik what issues NERC sees as most pressing in terms of impacts on grid reliability, Moura named the growth of demand outstripping the pace of construction, along with shifts in demand that challenge grid planners’ assumptions.
“I think the biggest trend we’ve seen … is this shift from summer risk, where you traditionally were peaking … and that’s slowly changing, where we’re actually seeing a lot of risk during the winter,” Moura said. “Not a lot of solutions that we’re building are for winter. We’re building a lot of storage, a lot of solar, [and that’s] not very good for winter.”
NERC Chief Engineer Mark Lauby added that the grid’s dynamic performance is another growing source of concern for the ERO, suggesting that building the tools to understand the system must be a priority for grid planners.
“How do we design the system so that it [has] the stiffness it needs [and] the ability to sustain events on the system? We need to have good dynamic models to do that,” Lauby said. “I worry that, right now, I don’t think we have a real good perspective of what’s happening on the interconnection and what’s happening on your neighbor’s system, and how that’s going to impact your system. So I think those are the things that keep me up at night.”
Setting up cost floors and caps for transmission lines can help get major transmission connections between markets built, said experts in a webinar hosted by the American Council on Renewable Energy (ACORE) on Jan. 20.
The U.K. has used that method to finance major new interconnectors with different markets on the European mainland and Ireland, and advocates said it could help get interregional lines financed and built in the United States.
Using floors and caps for major transmission lines combines the investment certainty from regulated rates and merchant exposure that optimizes asset use, said Regulatory Assistance Project Principal Jennifer Chen.
“Regulated interregional transmission is challenging because balkanized planning and disagreements between neighboring authorities on shared costs borne by their respective captive ratepayers can present issues,” Chen said. “On the other hand, purely merchant financing faces challenges with upfront investment and certainty, amongst other issues.”
Cap-and-floor is a financing model that combines approaches from both with the floor offering certainty and the cap allowing trading potential to be maximized. Customers get paid back if revenue exceeds the cap over a set period, and the floor requires ratebase customers to pay to meet it when market revenues fall short.
“Projects can create more value than in a purely regulated setting. That value can be shared with customers,” Chen said. “The costs of the projects are allocated to the markets, to those procuring transmission services, instead of defaulting to captive ratepayers.”
Since being implemented in 2014, the method has led to several major transmission links between Great Britain and other countries. Great Britain is regulated by the Office of Gas and Electricity Markets (Ofgem), while National Grid runs the transmission system for England and Wales.
Regulators have issued several solicitation windows since 2014 and picked projects that produced net benefits and filled a need on Great Britain’s grid.
“The first interconnectors in Great Britain were developed under a merchant model where revenues were fully exposed to market risks and developers would seek exemptions from certain regulatory requirements,” said Ofgem’s Megan Jones.
Then, in 2007, the European Commission put a cap on revenue for an interconnector between Great Britain and the Netherlands called “BritNed.”
“Because of this decision to impose this additional condition, there was a risk that the merchant model, and therefore interconnected development more broadly, could become less attractive to investors and developers,” Jones said.
Working with regulators in Belgium, Ofgem introduced the cap-and-floor model in 2014 to make merchant interconnectors viable again.
“Developers are incentivized to invest in a project where the potential market value of an interconnector and the consequent revenues are greatest compared with their costs,” Jones said. This means that there is also an incentive for developers to keep delivery and operation costs down.”
Those incentives minimize the risk that consumers will have to pay anything to ensure interconnectors’ revenue meets the floor price, she added.
Ofgem has open three solicitation windows so far in 2014, 2016 and 2022. Before then, Great Britain had four connections with neighboring countries, and since then, four more have been completed, one is under construction, and seven more have won regulatory approval, Jones said. They have created 5.3 GW of transfer capacity and see flows go both ways, though for now, Great Britain is a net importer.
“Various projects have returned revenues above the cap to consumers, and at the moment, that currently amounts to roughly 300 million pounds having been returned,” Jones said.
National Grid has participated in those solicitations through its subsidiary National Grid Ventures, said the latter’s Mark Tunney. It’s still possible to build interconnectors without the cap-and-floor model, but those projects are much rarer.
“We submit all of our various parameters into Ofgem in order to assess the cap and the floor,” Tunney said. “So, what is the capital cost we spent? What are the ‘OPEX’ costs that we anticipate? Our tax, the allowed return, is calculated by Ofgem, etc. And they form the cap and the floor.”
The revenues are measured against the cap and the floor every five years for the lines National Grid has constructed, but Tunney said that could be cut down to one year to work better with different business models.
After the lines get built, Ofgem does an audit of the construction process and its costs, and Tunney said National Grid Ventures has gotten somewhere between 97 and 99% of its project costs approved for the floor under that process. Ofgem also allows changes in the floor-and-cap parameters over the project’s life if rules and regulations change that require more spending, he added.
Grid United develops interregional transmission lines in the United States, which operate like the interconnectors across the Atlantic, and has been interested in using the cap-and-floor model since learning about it several years ago, said CEO Michael Skelly.
“We have talked to a number of policymakers here in the U.S. about this idea, and I think there’s some real interest out there,” Skelly said. “We would need to build momentum and so on. But the reasons that we’re enthusiastic overall because it may help us cut through the Gordian knot that we have here in the U.S. — how are we going to pay for new transmission?”
Grid United has done some calculations on different projects and found that the cap-and-floor method could lower revenue requirements for major transmissions by 30 to 40%, he added.
But getting the method in place will require some outreach to regulators so they understand how it works and, given the political climate here, the concept could use a rebrand.
“We’ll have to come up with a new name here in the U.S. because people might think this is some carbon thing, which we may have a hard time to sell,” Skelly said. “But there’s lots of clever people out there that can figure out how to sell it.”
Debates about affordability continue to dominate state-level energy policy debates throughout New England, shifting the focus away from decarbonization, a panel of experienced lobbyists said at a webinar held by the Northeast Energy and Commerce Association on Jan. 16.
All six New England states face gubernatorial elections in 2026, while U.S. Senate races in Maine, Massachusetts and New Hampshire are drawing significant attention. As federal and local political races heat up, energy affordability is poised to be a key issue, several speakers said.
Christopher Boyle, a lobbyist and former Rhode Island House majority whip, said he has seen “a sea change in how we’re looking at energy in the General Assembly and the governor’s office.”
He noted that Rhode Island Gov. Dan McKee (D) did not mention climate change during his Jan. 13 State of the State address, and has proposed pushing the state’s target for achieving 100% clean energy from 2033 to 2050. McKee also has proposed a cap on energy efficiency spending.
In Massachusetts, Republican challengers have frequently criticized Gov. Maura Healey on the topic of energy affordability, said Jen Gorke of TSK Associates. She noted that the spike in energy prices in the past winter “led to affordability being on the agenda in a way that I have never seen it in Massachusetts.”
But while there is broad agreement that energy affordability is a problem that must be addressed, there is significant disagreement about its root cause, Gorke said, noting that “if you don’t agree on the cause, you can’t agree on the solution.”
“There’s kind of two camps, and a lot of people in the middle,” she added. “Some see our leadership on clean energy and climate as the driver of high cost, while others see those exact same things as the path to lower cost and greater stability and reliability in the future.”
A pair of energy bills introduced in Massachusetts in 2025 exemplified some of the divergence in approaches to addressing energy affordability.
In May, the Healey administration proposed a wide-ranging bill that would tighten regulations around residential competitive electricity supply; allow utilities to issue bonds to help cover costs of the clean energy transition; expand the state Department of Energy Resources’ (DOER’s) procurement authority; and reduce net metering rates for new large solar resources. (See Mass. Gov. Healey Introduces Energy Affordability Bill.)
In contrast, the House members of the legislature’s Joint Committee on Telecommunications, Utilities and Energy (TUE) advanced a bill in November that drew significant public pushback from environmental advocates. While the bill included similar competitive supply regulations and expanded procurement authority for the DOER, it also would cut energy efficiency spending, reduce the annual requirements of the state’s Renewable Portfolio Standard and undermine several key components of the state’s heating electrification strategy. (See Top Mass. House Members Seeking Major Rollback of Climate Laws.)
These debates may heat up in 2026; House lawmakers seek to advance a version of the TUE bill out of the House Ways and Means Committee, while the Senate likely will produce its own version of an energy bill. Historically, the Senate has tended to side with climate advocates on energy policy debates and recently has looked to cut energy costs by reining in spending on the gas system.
Gorke added the Trump administration continues to have a major effect on all aspects of state government, including energy policy, with particularly large impacts on the state’s offshore wind industry.
“Offshore wind was the key tool for Massachusetts and was really expected to carry a big share of the clean energy transition,” she said. “People are trying to be very creative about how we can plug these holes and keep the momentum, but it has a big impact.”
She added there’s significant concern the Trump administration’s antagonism toward offshore wind will have a long-term chilling effect on investment in future projects even if the current crop of under-construction projects overcomes the administration’s obstacles.
“For Rhode Island, offshore wind is the holy grail of our policy,” said Boyle. He added that, while Revolution Wind may be able to finish construction, the future of SouthCoast Wind is far murkier. “I think the SouthCoast project is the one that is going to really have a material, substantial effect … it’s obviously both an energy issue and a jobs issue having an impact from Washington.”
As offshore wind struggles, Maine’s ongoing solicitation of 1,200 MW of onshore wind in the northern part of the state appears to be increasingly important for the clean energy goals of the southern New England states, said Jeremy Payne, a Maine-based lobbyist for Cornerstone Government Affairs. (See Maine PUC Issues Multistate Transmission, Generation Procurement.)
Four other New England states are collaborating with Maine on the procurement, while ISO-NE’s complementary Longer-term Transmission Planning procurement has the backing of all six New England states. Payne speculated Maine may look to procure some of the energy from the Millstone Nuclear Power Plant in Connecticut in exchange for Connecticut’s procurement of onshore wind in the Northern Maine RFP.
Millstone is under contract with Connecticut electric utilities through 2029, with the utilities required to purchase about half of the plant’s power and all its environmental attributes over the period. The state repeatedly has expressed interest in including other states in subsequent contracts.
“Connecticut has long been interested in nuclear — has long seen its value — but does believe that it has to be a regional resource, because currently the burden is on Connecticut electricity ratepayers,” said Nicole Tomassetti, partner at Capitol Strategies Group.
There’s broad interest across states in exploring the potential of small modular nuclear reactors (SMRs). While it’s difficult to forecast future costs for the early-stage technology, a 2024 study by ISO-NE estimated that adding about 15 GW of SMRs by 2050 could enable the region to meet state decarbonization goals at 33% less capital cost than the renewable-dominated base scenario.
“We have a pretty big political divide here, and obviously we’re in a campaign year, so that makes it even more pronounced, but I think nuclear is one of the few topics where the Democrats and the Republicans can agree that there’s some potential,” said Heidi Kroll, a New Hampshire-based lobbyist for J. Grimbilas Strategic Solutions.
New England has a long history with nuclear power; it was home to a boom in both nuclear development and anti-nuclear activism in the latter half of the 20th century. After a series of major plant retirements over a period of about 25 years starting in the mid-1990s, only Millstone in Connecticut and Seabrook Station in New Hampshire remain.
In Rhode Island, the mere mention of nuclear power in legislative hearings used to elicit “groans and moans and screams and eye rolling,” Boyle said. “The fact that it has become part of an accepted methodology to solve this problem, I find historically very interesting.”
ERCOT is absorbing a wave of large, price‑sensitive load, especially data centers, faster than the market rules were built to “productize.”
ERCOT planning materials show about 226 GW of large loads seeking interconnection as of Nov. 18, 2025 (up from 63 GW in December 2024), with about 225 new large‑load requests submitted in 2025 and about 73% of the queue attributed to data centers. If the finance path for renewable‑firmed supply is uncertain, the default “under-writeable” answer becomes on‑site gas.
What Generation Netting Really is
Generation netting for ERCOT‑polled settlement (EPS) meters (Protocol 10.3.2.3) is a settlement boundary rule: Under specific electrical configurations and metering constraints, ERCOT may settle a paired generator and load on a net basis. The protocol is intentionally restrictive (“generation netting is not allowed except under” defined conditions) and depends on site topology (e.g., common switchyard concepts, EPS metering points and limits on alternate grid connections). Netting can reduce settled energy volume. It does not convert a complex behind‑the‑meter campus into a financeable product. (See Aurora Research Report.)
Why it Fails the ‘Investment‑grade’ Test
Credit committees don’t finance “net MWh.” They finance the residual risk stack, especially correlated tail risk. Even with netting, a renewable‑firmed data center typically retains:
Scarcity price tail on backup imports. ERCOT’s systemwide offer cap (HCAP/SWOC) remains $5,000/MWh (with a low cap framework that can apply under certain conditions).
Congestion/basis risk (nodal price separation between where supply is produced and where load settles).
Operational/curtailment risk: the usable “firming” value of renewables plus storage can degrade precisely when the grid is stressed (telemetry/dispatch constraints, emergency operating modes or required load shedding).
Administrative/process risk: eligibility, metering design and true‑ups can become bespoke legal/settlement work, hard to replicate across multiple campuses.
Residual risk stack after Generation Netting | Alexandre Alonso Carpintero
SB 6 Adds Layer of Uncertainty
Texas SB 6 (effective June 20, 2025) added PURA §39.169, requiring system‑impact review of certain net‑metering arrangements involving new large loads and stand‑alone generation. ERCOT’s market notice M‑B090225‑01 implements interim procedures, publishes a list of stand‑alone generation resources (as of Sept. 1, 2025), and states the process may change or be pre-empted by forthcoming Public Utility Commission of Texas rules.
ERCOT’s large‑load interconnection Q&A further notes that some arrangements involving existing “stand‑alone” resources require approval through the net metering review process before the load can be energized. “Interim and subject to change” is not bankable language when you’re trying to finance repeatable, gigawatt‑scale campuses.
A Simplified 300-MW Hybrid Example (Wind + Solar + BESS)
Assume a 300-MW flat-load campus behind EPS metering with 300 MW of wind plus 300 MW of solar plus a 100-MW, 400-MWh (four‑hour) battery. Netting can reduce settled imports across many hours. The financing problem is the tail.
Illustrative stress case: 20 scarcity hours per year when renewables are low and the battery is depleted or held for contingency. If the campus must import 100 MW during those hours and real‑time prices clear at $5,000/MWh, the annual cost is: 20 h × 100 MW × $5,000/MWh = $10 million.
That volatility is correlated with grid stress and uptime risk. The easiest way to cap both is a 300-MW on‑site gas plant, hence gas becoming the “insurance policy” for load growth.
What ‘Netting Plus’ Should Standardize
ERCOT does not need to copy another RTO. It needs standardized pathways that turn behind‑the‑meter engineering into predictable settlement plus performance rules:
Campus netting: standardized netting across a defined private network footprint (multiple meters/feeders under common control) with clear telemetry and true‑up rules.
Measurable firmness: a standardized add‑on (e.g., a performance obligation or ancillary‑service bundle) that lets large load pair renewables with qualifying firming (storage, fast response, contracted curtailment) and get settleable credit.
Clear hybrid “serve‑load‑first” rules: reduce ambiguity for storage charging/discharging, exports and when the site is acting as load vs generation.
Transparent backup settlement: make residual grid exposure bounded and hedge-able rather than a surprise.
Protocol 10.3.2.3 is a starting point. “Netting plus” is what makes renewable‑firmed data centers financeable at scale.
Alexandre Alonso Carpintero works on market design and commercial structures for large loads, including data centers.
Colorado Springs Utilities has enacted a new program that will charge customers different rates for energy used at different times of the day.
The utility will charge a higher rate for energy used during the peak hours of 5-9 p.m. during the winter and summer seasons. The winter peak charge will increase from 7 cents to 14 cents, while summer peak hours will jump from 7 cents to 29 cents.
Bill to Remove Eminent Domain Option for Carbon Pipelines, Projects Introduced
Rep. Tim Yocum (R-Clinton) has introduced legislation that would remove the use of eminent domain for private carbon capture, carbon pipelines and other underground carbon storage projects.
The bill was referred to the House Utilities, Energy and Telecommunications Committee. If the bill passes out of committee, it will move to the full House of Representatives for further consideration.
House Introduces Bill to Ban CO2 Pipelines from Using Eminent Domain
A House subcommittee advanced a bill that would prohibit carbon dioxide pipeline operators from exercising eminent domain for the purpose of building a pipeline.
Rep. Steven Holt (R-Denison) said the bill would not stop the pipeline from being built but would protect residents’ private property rights. Opponents of the bill argued it would stall economic growth by blocking construction of the Summit Carbon Solutions pipeline.
Holt advanced the bill to the House Judiciary Committee.
SCOTUS Denies Counties’ Request for Rehearing in Summit Pipeline Case
The U.S. Supreme Court denied a request Jan. 12 from Story and Shelby counties for a review of a lower court’s ruling that county ordinances pertaining to a carbon sequestration pipeline were preempted by federal pipeline regulations.
The lawsuit is between the counties and Summit Carbon Solutions, which is seeking to build a carbon sequestration pipeline across the state. In October 2022, county supervisors enacted local ordinances that established setback, permitting, emergency management and abandonment standards for hazardous materials pipelines within the counties. Summit sued the counties later that year, arguing the ordinances were preempted by federal pipeline safety standards.
The court did not offer an explanation for the denial.
Del. Lorig Charkoudian and Sen. Benjamin Brooks introduced the Affordable Solar Act on the opening day of the 2026 legislative session.
The bill would establish a target to connect 4 GW of solar capacity to the grid by 2035 and mandate that implementation result in no increases to utility bills for residents.
The legislation now moves to committees for hearings and fiscal analysis.
Healey Admin Pushes Back Clean Heat Standard to 2028
Environmental regulators are delaying implementation of the Clean Heat Standard until 2028, according to a note the Healey administration sent to stakeholders in late December.
The memo, sent to “stakeholders” on Dec. 23, 2025, said the administration is “working to ensure there is a robust market for affordable clean heat” and the state will be evaluating additional data around fuel and emissions trends and heat pump adoptions.
The standard is a key part of the state’s overall climate strategy and was expected to take effect in 2026. The Clean Energy and Climate Plan for 2025 and 2030, which was released in 2022, evaluated five different clean heat scenarios to identify “the most cost-effective way to meet statutory GHG emissions limits.”
NV Energy not Planning to Refund Full Amount to Overcharged Customers
NV Energy, which has overcharged customers as much as $65 million since 2002, says it doesn’t intend on making customers whole, according to a filing with the Public Utilities Commission.
The utility, which originally intended to pay back customers for six months of overpayment, is offering refunds back to June 2017, the last month for which it has records. PUC staff want customers made whole for all overcharges back to 2002, with interest, by estimating the overcharges preceding 2017. NV Energy claims the PUC would have to file a contested case, which “would significantly delay compensation to customers.”
A law passed by the Legislature in 2025 requires utilities pay back all overcharges with interest.
The Department of Environmental Quality approved a water protection permit for Mountain Valley Pipeline Southgate and its 31.3-mile natural gas pipeline.
The pipeline will transport natural gas from an interconnection point with the MVP Main Line project in Virginia to an interconnection point with the East Tennessee Natural Gas system in North Carolina.
The U.S. Senate voted 82-14 to pass an Energy and Water Development appropriations bill that will fund the Department of Energy, Army Corps of Engineers and Bureau of Reclamation for fiscal year 2026.
The bill appropriates just over $49 billion for DOE.
The House of Representatives passed the bill on Jan. 8, and it is expected that President Donald Trump will sign it into law prior to the funding deadline on Jan. 31.
2025 was the Earth’s second or third-hottest year on record, several U.S. and global climate science organizations said.
The National Oceanic and Atmospheric Administration, as well as the EU’s Copernicus and the U.K.’s Met Office, found that 2025 was the third-hottest year recorded. NASA found 2025 to be the second-hottest year, though the numbers were so close it was effectively tied with 2023.
The last three years are the three hottest the planet has ever faced, with 2024 being the warmest ever.
Toyota and Lightsource bp announced a 15-year virtual power purchase agreement.
Toyota will purchase energy from Lightsource’s 231-MW Jones City 2 solar project in Texas. Toyota Environmental Sustainability General Manager Tim Hilgeman said the agreement could cover more than 20% of the car maker’s purchased electricity needs in North America.
Google Taps Clearway for 1.2 GW of Carbon-free Power
Clearway Energy Group struck three deals with Google to supply the tech group with carbon-free power from 1.2 GW of capacity in Missouri, Texas and West Virginia.
The three power purchase agreements will support Google’s data centers in the SPP, ERCOT and PJM markets for up to 20 years.
All plants are slated to enter the construction phase in 2026, with the first ones expected to become operational in 2027 and 2028.
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 forecast load, mostly due to additional large loads (i.e., data centers).
It now appears the forecast 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 the 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.
