El Paso Electric again is seeking regulatory approval for its New Mexico renewable energy plan after resolving tariff-related cost uncertainty of a solar-plus-storage procurement proposed in the plan.
The New Mexico Public Regulation Commission rejected the plan in October based on concerns about the cost of energy from the proposed 150-MW Santa Teresa solar project. EPE reported in August that developer DE Shaw Renewable Investments (DESRI) had told it the project had been “materially and adversely impacted by recent changes in law, in particular related to the imposition of tariffs by President Trump.”
The tariffs were expected to “result in millions of dollars worth of unplanned cost increases for construction of the generating facility,” the developer said. In an Oct. 16 order, the PRC said it could not approve EPE’s plan because the cost of the Dona Ana County-based project was unknown.
But since then, EPE has worked out a deal with DESRI calling for the utility to pay the same rate for energy from the project as in their previous agreement but with the contract terms extended to 25 years rather than 20.
The plan the commission is being asked to approve covers the first 20 years of the agreement; EPE would bear the risk of the five-year extension, PRC staff said in a filing.
The expected cost of the project’s energy assigned to New Mexico for 2026 is $45.67/MWh. That is below an inflation-adjusted renewable cost threshold of $74.14/MWh.
The PRC on Nov. 25 granted EPE’s motion for a rehearing, which could take place as soon as Dec. 11.
EPE and DESRI did not respond to RTO Insider’s request for more details on the tariff impacts.
RPS Challenges
New Mexico’s investor-owned utilities file a plan each year on how they will meet the state’s renewable portfolio standard in the following year.
The required percentage of zero-carbon resources supplied for retail electricity sales increased to 40% in 2025, after sitting at 20% since 2020. It will continue to rise through 2045, when it reaches 100%.
In 2023, EPE supplied about 16% of retail energy sales to New Mexico customers with renewable resources, a figure that grew to just over 20% in 2024.
EPE’s 2026 plan includes renewables and renewable energy certificates from an approved portfolio as well as the proposed Santa Teresa procurement.
Santa Teresa will be built at the former site of the Hecate solar project, which at one time was expected to be in service by 2022 but never was built. DESRI took ownership of the project. EPE’s power purchase agreement for Hecate was terminated in 2024, and the utility received $14.9 million in liquidated damages, according to the 2026 plan.
EPE, which serves customers in New Mexico and Texas, noted in its plan the challenges of providing electricity in jurisdictions with different renewable energy requirements. The utility previously received PRC permission to adjust the amount of renewable energy allocated to New Mexico, rather than Texas, to meet New Mexico’s RPS targets.
For the Santa Teresa project, EPE asked to buy all the solar energy generated in 2026 and allocate it to New Mexico, starting when the project comes online midyear. That allocation would be needed to meet the 40% RPS target in 2026, but it likely would be a short-term arrangement.
“EPE would not expect to propose allocation of the total annual energy output of the [Santa Teresa project] in 2027,” the company says in its proposed plan.
Of the project’s 150 MW of battery storage, EPE wants to purchase and include 50 MW in its RPS portfolio.
The California Department of Water Resources and other parties have asked CAISO to restart a transmission access charge initiative that was put on hold in 2018 due to the development of the ISO’s Extended Day-Ahead Market.
CDWR, along with the Bay Area Municipal Transmission Group and the State Water Contractors, want CAISO to bring back a drafted final proposal regarding the ISO’s Transmission Access Charge (TAC) rules in order to possibly reduce the amount of new transmission needed in the state.
CAISO’s current TAC rules measure transmission use with a “volumetric-only” approach, which “fails to reflect cost causation and utilization of the transmission system, resulting in inequitable allocation of costs,” the CDWR group said in Nov. 13 comments on CAISO’s draft 2026-2028 policy initiatives road map.
“Costs should reflect that transmission networks are built to handle peak demand when the grid is strained the most,” the group said.
CAISO instead should recover a larger portion of fixed electric transmission costs through a demand-based rate structure, and less from volumetric rates, the group said. Doing so would incentivize better load management practices and reduce the need for new transmission that is driven by peak demand requirements, they said.
Current TAC rules send inefficient price signals to behind-the-meter battery storage resources operators, the group said. If price signals were accounted for more specifically, CAISO might find it needs to plan for less new transmission infrastructure, the group said.
In February, CDWR proposed to restart the TAC initiative and bring back the 2018 proposal. However, CAISO dismissed CDWR’s request because the “levels of behind-the-meter solar have stabilized, rendering these changes unnecessary and overly complex in today’s market,” CAISO said, according to the CDWR group’s Nov. 13 comments.
CDWR is concerned about CAISO’s “misunderstanding of the substance and need” for the TAC proposal and are “frustrated by the process used to date,” they said.
“CAISO infrastructure staff have dismissed the need for this initiative, without any stakeholder meetings to discuss the issues that motivated the initiative in 2016-2018, or to consider input from stakeholders on the current need for the TAC structure changes that were fully vetted and proposed to be adopted in 2018,” the group said.
The 2018 TAC initiative was supported by CAISO’s Department of Market Monitoring, California’s three largest investor-owned utilities, municipal utilities, independent transmission developers, retail marketers and the California Public Utilities Commission, the group said. The proposal supports CAISO’s resource adequacy capacity program for required contributions to coincident peak demand and DMM’s support for allocation of natural gas transmission infrastructure costs, they said.
The current TAC rules started in 2001, and the structure has remained “relatively stable” through the intervening years, CAISO staff said in the 2018 draft final proposal.
CDWR’s comments were filed in CAISO’s annual policy initiatives road map process, which determines the policy initiatives for the following three years. CAISO plans to release a final policy road map in December for the 2026-2028 cycle.
NV Energy Requests Policy Review Changes
NV Energy filed comments about CAISO’s policy road map, asking CAISO to evaluate the frequency, length and content that is reviewed in stakeholder policy meeting sessions.
The ISO’s policy meeting sessions have become longer but have been held less frequently. This approach to policy development with stakeholders has caused certain meeting materials to be condensed or skipped altogether, NV Energy representative Lindsey Schlekeway said in comments to CAISO. The long gaps between meeting sessions have made it difficult to track and follow issues raised by stakeholders, Schlekeway said.
“It would be helpful for CAISO to be mindful of the resource constraints considering the activities that are underway in the West,” Schlekeway said. “The stakeholder process may have large impacts to the market design, and NV Energy would like to dedicate sufficient time to each initiative in order to provide the most informed and helpful comments to CAISO.”
NV Energy recommended CAISO hold three-day meeting sessions, rather than one meeting per month, to review complex issues with stakeholders.
New Jersey should continue to pursue a strategy of heavy reliance on clean energy to head off the state’s looming energy shortage, with no increase in natural gas generation, says a new plan released by outgoing Gov. Phil Murphy (D).
The governor’s 2024 Energy Master Plan pays little heed to critics who say the state’s pending energy shortfall requires renewed consideration of new natural gas plants. Instead, it outlines a future that is heavily dependent on clean energy, along with building electrification and enhanced use of electric vehicles.
The plan says the “pillars of planning and decarbonization” should provide the state with stability in the face of a future in which the PJM region — which includes New Jersey — faces annual demand increases “for the first time in two decades.” That includes a forecast of 32 GW in additional peak demand in the PJM region by 2030 and a 58 GW increase by 2035.
“Any future aligned with the state’s economic, energy, and climate goals will require accelerated clean energy generation — solar, wind, advanced nuclear, green hydrogen and battery storage,” according to the plan. “Doing so will reduce electricity imports, boost in-state generation, grow clean energy jobs, increase resource diversity and support long-term cost stability.”
The clean energy recommitment by Murphy, who leaves office in January 2026, comes amid heated debate about how to speedily increase the state’s affordable energy generating structure to meet accelerating demand from artificial intelligence companies and data centers. Some politicians argue that the potential electricity crisis is so severe that the state should adjust its carbon emission commitments and consider expanding its natural gas generating fleet.
Former Gov. Chris Christie (R) said at an Oct. 28 energy conference organized by the New Jersey Business & Industry Association that the winner of the November gubernatorial election should look to “open two or three new natural gas generation plants as quickly as possible” (See N.J. Forum Explores Solutions to Looming Energy Shortfall.)
U.S. Rep. Mikie Sherrill (D), the eventual winner, said during a debate in October that she would “improve our gas generation in the state.” In a Nov. 20 television interview, she said: “We need to make sure our gas generation, which is about 40% of our production right now, is more, is modernized, so we can drive down carbon emissions while driving up much of the generation from gas generation.”
The New Jersey League of Conservation Voters released a statement calling the plan “an affordable energy road map at exactly the right moment.”
No Plans for Gas Plant Construction
Murphy, releasing the plan, called it the “culmination” of his two-term effort to tackle “the challenges of energy affordability, supply and demand, and climate change.”
Murphy’s staff, in a briefing on the plan, said it considers gas generation to be important as a “dispatchable resource” but contains no prescription to build more gas generators in the state.
Annual energy balance by scenario | New Jersey Energy Master Plan
The state “is projected to rely on investments in solar, battery storage and offshore wind to support growing demand” and meet its goal of zero emissions by 2035, the plan says. “Total gas generation declines by 2050 across all [the plan’s proposed] mitigation scenarios … driven by the expansion of renewable and nuclear capacity.”
The plan adds that the strategy will reduce the amount of imported electricity as battery storage, nuclear, wind and solar — utility-scale and distributed — expand to meet the new demand.
Changing Energy Landscape
What effect the master plan will have is unclear given that the transition from Murphy to Sherrill will take place in January. A Murphy staffer said the plan offers a “compendium” of what the state has done under his tenure, and it is up to Sherrill whether to incorporate the suggestions into her own strategy.
Sherrill’s transition team did not respond to a request for comment.
Murphy has come under criticism that his focus on developing a robust wind sector — he set an offshore wind goal of 11 GW — left the state short on new generating sources when the bet on wind failed. The state has no active wind project after developer Ørsted abandoned its two Ocean Wind projects in 2023 due to logistical issues and rising costs. A third, Atlantic Shores, withdrew amid the Trump administration’s opposition to offshore wind. (See Developer Shelves Atlantic Shores, Seeks to Cancel ORECs.)
A release from Murphy’s office said the master plan offers a “flexible, adaptive framework of ‘no-regrets’ strategies and policies” that can adapt to the “changing energy landscape.” Murphy’s staff said the concept means the state can pursue them, and any investment, without wholly committing the state to the strategy if the environment changes and a direction shift becomes necessary.
The strategy includes “doubling down on the state’s successful solar programming, while at the same time expanding programming to deploy battery storage projects, clean firm generation options, virtual power plants, as well as exploring the potential for advanced nuclear resources in the state,” the plan says.
Reliable and Modern Grid
The master plan was compiled by Energy + Environmental Economics (E3) through research, modeling and stakeholder input. A draft plan outlined three different scenarios that varied in how aggressive their pursuit of the state’s emissions reductions goals would be, and compared them with the scenario if the state did nothing. That comparison evaluated the effect on electricity rates.
The plan predicts that electricity use will increase by between 66 and 109% by 2050, depending on which scenario is pursued. It reports that customers wholly using electric appliances and vehicles will see a $50 increase in their monthly energy costs from 2025 to 2035. Customers using mainly gas would see a $95 increase, while those using a hybrid of both would see a $59 increase.
Average monthly energy bills projected by the plan | New Jersey Energy Master Plan
The completed plan does not recommend which of the three scenarios the state should adopt but instead makes a series of recommendations for strategies and policies.
They include “accelerating clean energy deployment” and “expanding decarbonization and efficiency programs.”
“Not only does more efficient equipment provide lower bills for program participants, it reduces overall electric demand, thereby taking pressure off the wholesale power market and reducing emissions from both the power and buildings sectors,” the plan states.
The plan calls for moves to ensure a “reliable and modern grid,” and for the state to continue pursuing transportation electrification. Although the state, with 260,000 EVs on the road, is nearly 80% of the way to reaching its target of 330,000 EVs, the plan does not suggest a new one.
The plan also calls for the state to enhance “regional coordination and advocacy.”
“New Jersey must continue to actively engage with PJM and neighboring states to ensure grid reliability, affordability and accelerate clean energy integration,” the plan says. “Additionally, the state should continue to take steps to have more formal involvement in the PJM decision-making process to ensure that its policy objectives are reflected in PJM’s market rules and policies.”
Higher prices under Ontario’s renewed market are causing heartburn for mines and greenhouse growers, stakeholders told IESO on Nov. 26.
During the ISO’s quarterly market briefing, IESO officials said the market is performing well, with “intuitive price formation,” and that no new “high-priority defects” have been discovered since their last briefing in August. (See Ontario Nodal Market Nearing ‘Steady State’ After Nearly 4 Months.)
“We’ve now got about six months of operating in the renewed market behind us and … I think everybody’s learning and building their understanding of the new market dynamics that we’re seeing as we shift through each season,” said Candice Trickey, IESO’s director of market readiness and customer experience. “Overall, [based on] everything I hear from you and that I see internally, we are all making, collectively, really good progress in working in this new system.”
However, several stakeholders said they are facing challenges from higher prices since the new market launched May 1.
Alain Cote of Vale Canada — whose five mines and other operations use about 200 MW per hour — said Ontario Zonal Prices in November have risen from about $50/MWh to about $80/MWh in November.
“I’m just having a hard time … forecasting that,” he said. “It’s a big swing.”
Consultant Stephanie Freund, who advises commercial greenhouse companies in southwest Ontario, said her clients have seen increasing price spikes since October, when they turn on their grow lights to nurture winter crops.
“They are really struggling … trying to keep up with the day-ahead [market] in order to manage their lighting schedules … to avoid the spikes,” Freund said. “They’ve never seen such high electricity prices as now. … They won’t be able to afford running” the lights. She asked if IESO had tools to help them manage the volatility.
Darren Matsugu, IESO’s director of markets, said Ontario is seeing higher prices because it is the peak of the fall maintenance outage season. “We are definitely in the period where we have the most resources on outage to make sure that we have that availability before the winter,” he said. He suggested Freund talk to the ISO’s customer relations team about ways to manage the high prices.
Cal Brooks, of FirstLight Power, said that — even accounting for inputs like gas prices and system load — prices appear to be higher than under the Hourly Ontario Energy Price (HOEP), which the ISO used before the Market Renewal Program introduced nodal pricing and a financially binding day-ahead market.
“Do you see that as … something good in that maybe real supply and demand signals are now being reflected in a way they weren’t under the old market?” Brooks asked.
Matsugu noted that the HOEP uniform clearing prices did not include congestion and losses, which now are reflected in LMPs.
“The structural changes that we put in place are to better align the price signals we’re sending with the underlying system conditions,” he said. “Those system conditions are continuing to change. We are getting into tighter and tighter conditions than we have before, and so certainly we would expect that … the underlying prices [would] be higher.”
The ISO says the new market will produce net cost savings for consumers by reducing out-of-market payments and improving the efficiency of scheduling resources.
“I think we are seeing the benefits, particularly when we talk about our intraday unit commitment and our day-ahead commitment,” Matsugu said.
IESO officials said market prices have reflected system conditions, with real-time and day-ahead prices converging when actual conditions match forecasts and varying with deviations in real time.
Jennifer Jayapalan, of Workbench Energy, said her company has seen big changes in how some resources are being used. “We’ve seen a lot more demand response activations, not just in peak conditions, but also into the fall and as recently as the last week or two,” she said. “And we’re seeing a lot more operating reserve [OR] activations across this period as compared to really all years prior to MRP. And neither of these two actions are really publicly reported anywhere by IESO, and both are quite expensive.”
Matsugu said scheduled generation outages contributed to the DR and OR activations and that the ISO will consider whether it can provide more transparency on such actions. “We don’t have, necessarily, all the same resources available that we had during our peak of the summer, but we do that outage planning to correlate with the expected levels of demand.”
Defect Caused Demand Fluctuations
Trickey said the ISO investigated whether a defect that was causing demand fluctuations had an impact on hourly DR activations and concluded it did not create any inappropriate activations.
The defect caused the Ontario demand values published in IESO’s Realtime Totals Report to change by hundreds of megawatts for only a few five-minute intervals.
Because of the unpredictable nature of variables such as supply disruptions, sudden increases in heating or cooling demand, and neighboring system conditions, there often are changes in demand from one interval to the next. But “swings of several hundred megawatts for only a few intervals have historically been quite rare,” the ISO said in a presentation.
The summer brought higher demand, higher prices and greater price separation between day-ahead and real-time markets. | IESO
IESO said it identified a calculation that overstated demand when hourly DR resources are on standby. The ISO has implemented a manual workaround to counter the defect pending a permanent fix.
Without the workaround, the defect could result in incorrect prices for impacted intervals and incorrect peak demand hours for the Industrial Conservation Initiative if they occur on a potential peak day. ICI participants pay their share of Global Adjustment charges based on their peak demand factor, which is calculated based on their contribution to the top five peak hours over a year.
IESO identified 38 intervals with incorrect prices and corrected them with administrative prices. It confirmed that the top 10 peaks posted on the Peak Tracker webpage were not affected.
Settlements, Defects
IESO officials said they have improved settlement processing times, and that statements and invoices issued in October and November were delivered ahead of the ISO’s 5 p.m. goal.
Trickey said the new market is producing much more data “and that was taking longer to process than ideal. So we’ve been working on improvements.”
Of the settlement disagreements that have been resolved, the ISO said about 30% have been attributed to defects that have been corrected, with the remaining 70% of disputed statements confirmed as correct.
IESO continues to work through a backlog of disagreements, some of which are related to pending defect fixes. The ISO is notifying participants if there are delays in correcting settlements because of the pending fixes.
IESO officials said they had discovered several minor defects since August, including scenarios in which non-quick-start resources operating in combined cycle mode are receiving after-the-fact settlement mitigation calculated using the single cycle mode reference level.
LMPs are similar throughout Ontario when there is little congestion. When demand — and congestion — is higher, as in summer, prices separate between the Northwest and the rest of Ontario. | IESO
The ISO also disclosed economic operating point (EOP) errors that may result in adjustments to real-time make-whole payments (MWPs) in resettlement statements posted on Nov. 17 and Dec. 12. EOPs reflect the output a resource could have achieved based on its physical capabilities and LMP, under actual market conditions.
The impact of the resettlements will be small, “because they’re all fairly specific scenarios impacting just certain types of resources,” Trickey said.
Trickey said IESO will continue its quarterly briefings on the Renewed Market’s performance for the first year of operation.
In response to requests from market participants, the ISO is creating a new group, the Renewed Market Advisory Forum, to discuss ways to improve the market.
Trickey said the group will focus on incremental improvements, not “long-term, evolutionary” changes.
“We’ve implemented this new market. Is everything working the way we thought it would, or as effectively as we hoped?” Trickey explained. “And if we’re seeing some gaps — whether it’s information that people need, or some parts of the system that aren’t working as well as we hoped — this is where we would like to have those kind of conversations with participants that are really engaged in the market.”
Candidates interested in participating should submit expressions of interest by Dec. 19 to engagement@ieso.ca.
Load growth beyond PJM’s ability to serve is a clear and present danger to the reliability of the grid and the functioning of PJM’s markets. After stakeholders tried and failed to meet this challenge, it falls on PJM’s board to solve.
The politics around this are complex, but the answer is clear: The board’s duty is to protect the power grid and the 67 million people who depend on it. This requires decisive action. Putting off the problem or relying on hope are not options. (See PJM Stakeholders Reject All CIFP Proposals on Large Loads.)
Claire Lang-Ree
The sudden explosive growth of data centers might promise to add more load every year than PJM has added in the past 20. Persistent yearslong delays in getting new electrical generation online due to difficulties with the queue, supply chains and construction leave a sobering outcome.
PJM will barely meet reliability standards in 2026 and almost certainly will fall below them in 2027. The capacity market is pegged at its price cap with no prospect of relief. While the flood of new data centers overwhelms the trickle of new generation, things will only get worse.
In a way, the dire situation makes the board’s decision easy. The only way to keep PJM reliable is to hold back the flood. There are a few ways to do that.
Possible Solutions to Demand Growth
The Independent Market Monitor has proposed the direct approach of not letting data centers connect to the grid until supply is available.
Whichever solution the board chooses first and foremost must prepare for the possibility PJM won’t have enough power to promise it to everyone who wants it. Physics leaves no room for compromise.
Other proposals before the PJM board have helpful components. State governors proposed a package of incentives for data centers to support the grid. Many point to the old bugbear of speculative data centers in the hope that more rigorous forecasts can shrink the problem.
These are encouraging, and we hope they work out. But these are just hopes. Hope may be the currency for poets and politicians, but it’s poor coin for engineers and economists. While the board should support every fair chance for a positive outcome, its duty is to prepare for the worst.
Capacity Price Relief Needed
The PJM board’s solution must include capacity price relief. The prices coming out of the reliability pricing model (RPM) right now serve no purpose. Thanks to delays, high prices won’t stimulate new entry in reasonable time frames. Nor are high prices needed to prevent retirements.
We’re coming off a six-year run of prices under $200/MW-day. It’s silly to argue that plants will retire if they can’t get paid double that. No matter what RPM does, any power plant that can make a spark should be able to name its price to tech companies.
The capacity market is being asked to do a job entirely outside what it was designed for, and it’s failing in a way that transfers tens of billions of dollars from the public to lucky generation owners who already were comfortably profitable. Those owners should be thinking about geese and golden eggs.
Avoid Two-tiered Queue System
One thing the PJM board should not do is enable any kind of fast track for new generation that harms projects that already are waiting in the queue.
For many years, PJM has been telling projects — including some required by state law or supported by federal policy — to wait in line. It would be unconscionable for PJM to reverse itself now and let projects that support data centers jump to the front of that line.
This threatens to create a permanent two-tier interconnection system, with one level of service for power plants that support data centers and second-class service for clean energy. PJM stakeholders rejected those concepts, perhaps remembering that open access and fair competition are one of the reasons PJM exists in the first place. The board should do the same.
There’s still room for improvement on interconnection. ERCOT has kept up with the data center boom in Texas in part thanks to their “connect and manage” approach, where new power plants join the grid as-is, accepting the risk that sometimes the transmission system might not be able to deliver their power. PJM should consider reforms like this. But no matter what PJM does on interconnection, no state should tolerate its clean energy laws being treated worse than tech companies’ commercial interests.
PJM requires independence from its board members. Nobody with conflicts of interest that could influence their objectivity is even eligible to serve.
This is for good reason. The board makes final decisions on vital issues for the power grid, often with billions of dollars at stake. There are 67 million people who rely on PJM making independent, objective decisions, even when those are unpopular or painful to some. Now is the board’s chance to justify this confidence.
Tom Rutigliano is senior advocate and Claire Lang-Ree is advocate for the Sustainable FERC Project at the Natural Resources Defense Council.
FERC has approved a transmission security agreement between PECO Energy and Amazon for a data center planned in Falls Township, Pa. (ER25-3492).
The data center is among the first in a $20 billion pool of investments Amazon announced it is making across Pennsylvania. It would not be co-located with any generation and would receive retail service under a schedule approved by the Pennsylvania Public Utility Commission, FERC said in an order issued Nov. 21.
The agreement includes a set of provisions intended to prevent costs associated with the interconnection from being shifted to other customers if the data center does not materialize. It lays out a ramp schedule on which the load is expected to come online, with shortfall payments if those milestones aren’t reached and termination fees if the load is permanently reduced. There is a committed revenue contribution that sets the baseline Amazon must pay, equal to 80% of what a load-serving entity would pay to serve 80% of the monthly load and billing — though that is subject to a customer shortfall event liability cap.
Monarch Energy Development and Constellation Energy argued the agreement should be considered on its own and not as setting precedent on other large load interconnections. The former said there are parallels between the agreement and a pending proposal from Commonwealth Edison seeking to require large loads to obtain a TSA.
Monarch also encouraged the commission to explore whether the PECO-Amazon agreement adheres to cost-causation principles, overestimates the risks large loads present to other customers and conflicts with the federal government’s goal of developing the infrastructure needed to support artificial intelligence.
The PJM Independent Market Monitor argued the agreement should not be approved unless it could be demonstrated that the data center would not adversely impact transmission reliability and resource adequacy. It also faulted the agreement for not considering the implications for energy and capacity market costs the added load could present for customers across PJM.
Throughout PJM’s Critical Issue Fast Path (CIFP) process focused on large load interconnections, Monitor Joe Bowring held that the RTO should not be obligated to accept load it cannot serve reliably, a stance the IMM extended to LSEs in comments on the TSA.
“Despite the protections included in the TSA, it is not just and reasonable to allow the interconnection of this large new data center load when it has not been demonstrated that either PECO or PJM has the capacity available to reliably serve this load,” the Monitor wrote.
It also filed a complaint against PJM on Nov. 25 arguing that its CIFP proposal would require it to accept large load interconnections it cannot reliably serve, degrading the quality of service for existing customers while imposing higher costs (EL26-30).
The commission determined the agreement can be limited to ensuring that Amazon contributes to PECO’s transmission revenue requirement without needing a demonstration that the load will not affect reliability.
“Given that the IMM raises no issue with the terms of the transmission security agreement itself, but rather raises concerns with the provision of service to the data center under PECO’s retail tariff and the provision of transmission service to large loads generally, the IMM’s concerns do not provide a basis upon which to reject the transmission security agreement,” FERC wrote. “We also note that the Pennsylvania commission retains authority to establish terms of retail service between Amazon and PECO, including retail consumer protection provisions.”
Commissioner Judy Chang concurred, writing that the agreement includes some consumer protections and recognition of state authority over retail rates, while urging the commission to develop a comprehensive framework for assigning transmission upgrade costs.
As large load interconnections with significant impacts to the grid become more common, she said the commission’s “higher of” policy could serve as a framework for determining how those costs could be allocated. Under that model, large loads pay the greater of the embedded or incremental cost rates, which she wrote would ensure that a large load pays for network upgrades it triggers.
“It may be time for the commission to proactively consider how to guarantee sufficient customer protections, such as the ‘higher of’ pricing policy, to ensure that we do not outsource our customer protection responsibility to bilateral agreements by the utilities we regulate,” she wrote.
She wrote it’s especially important for agreements between utilities and large customers to recognize the contours of state jurisdiction, particularly when the Mobile-Sierra public interest standard of review is applied, as in the PECO and Amazon agreement.
“Given the potential magnitude of new transmission investment triggered by large load additions, concerns about costs are increasingly spilling into commission proceedings, raising complicated jurisdictional and policy questions with significant implications for both state and federal regulators,” she wrote. “This critical affirmation will help ensure that the commission’s acceptance of the agreement and possible similar agreements in the future recognizes and preserves states’ essential role in protecting retail customers.”
The Virginia State Corporation Commission trimmed Dominion Energy’s rate increase and approved its plan to create a new rate class for large load customers like data centers.
In an order issued Nov. 25, the SCC approved the new GS-5 rate class to become effective Jan. 1, 2027. The new class will help insulate other customers from the rapid buildout of infrastructure needed to serve new data centers, the commission said. Any customers with demand of 25 MW or greater and a load factor of at least 75% will go into GS-5.
Customers in the new class will sign electricity service agreements that last 14 years. If they leave Dominion’s service early for a competitive service provider (CSP), they will have to pay an exit fee that covers 85% of the contracted demand’s distribution and transmission costs and 60% of its generation costs.
“Dominion must consider aggregate forecasted demand over a long-term planning period, must plan to meet those needs with supply resources that typically require many years to develop, and must construct generation to be ready to serve high load customers who are eligible to select a CSP in the future,” the SCC said in its order. “Accordingly, the commission finds that the minimum generation demand charges shall apply to these new shopping customers.”
That will reasonably recover the costs of infrastructure Dominion built to serve such customers even if they retire early, the commission said.
GS-5 customers can reduce their capacity during the ESA term by up to 20% at no cost and an additional 30% if another customer agrees to assume the associated capacity. Each capacity reduction requires a 36-month notice.
The SCC also rejected Dominion’s requested base rate increases of $822 million for 2026 and $345 million for 2027, instead approving $565.7 million in 2026 and $209.9 million in 2027. Those translate into $11.24 more on a typical residential customer’s bill in 2026 and $2.36 more on monthly bills in 2027, which are 23.7% and 51.2% lower than what Dominion had requested, respectively.
The SCC also approved a higher return on equity for Dominion, raising it from 9.7% to 9.8%, which is below the 10.4% it requested.
“As the utility regulator, we are obligated by law to set a revenue requirement that affords the company an opportunity to recover reasonable and prudent projected costs and earn a reasonable rate of return,” the SCC said. “In this case, that has resulted in an increase in rates, but not to the extent requested by Dominion.”
In another order issued Nov. 25, the SCC approved Dominion’s Chesterfield Energy Reliability Center (CERC), a 944-MW natural gas plant made up of four GE Vernova 7F combustion turbines. The turbines will be built in the footprint of a retired coal plant and alongside two existing combined cycle power plants.
The plant is the first natural gas-fired generator that the SCC had to evaluate since the Virginia Clean Economy Act was passed in 2020. Dominion said it was needed to keep pace with demand growth. The plant will cost the average residential customer 60 cents on their monthly bill.
“This case therefore is not about choosing CERC over compliance with the VCEA (or CERC versus renewable generation, demand-side management or batteries, for that matter). Instead, the commission is called upon to determine whether a ‘threat to the reliability or security of electric service to the utility’s customers’ exists, such that the CERC project is required to obviate such threat,” the SCC said in its order. “As discussed herein, the evidence in this case clearly establishes that there is an imminent reliability threat for Dominion and its customers and that the CERC project addresses that threat in a manner that is in accordance with the public interest and the VCEA.”
While the commission acknowledged that some of the forecasted load growth for Virginia and the rest of PJM may be overstated, it also said the demand for power is certainly on the rise. It cited the spiking capacity prices in the RTO, as well as NERC reports that PJM could run short of reserves in extreme weather in the second half of this decade.
The CERC order was opposed by environmental groups including Clean Virginia, which called the approval disappointing.
“Despite major flaws in Dominion’s application and planning process, the commission granted approval to a gas plant that breaks Virginia’s commitments to clean air, further drives up electric bills and which would not be necessary absent the gluttonous energy demands of Big Tech companies,” Executive Director Brennan Gilmore said. “If this is the decision the commission came to under existing rules, then it is upon Virginia’s elected leaders to better align these rules with the interests of all Virginians.”
Citing developments within the Western Power Pool’s Western Resource Adequacy Program, the Oregon Public Utilities Commission waived penalties for electric service suppliers participating in the state’s alternative RA program.
The three-member commission voted Nov. 25 in favor of staff’s recommendation to grant a waiver for electric service suppliers (ESSs) that make filings in Oregon’s state resource adequacy program and directed staff to work with the PUC’s Administrative Hearing Division to decide whether to open a rulemaking or investigation to consider amendments to RA rules.
ESSs are the product of Oregon’s electricity restructuring law, which gave non-residential customers the option to purchase energy from independent PUC-certified suppliers rather than their utilities through the state’s direct access program.
The PUC’s vote came after the Northwest & Intermountain Power Producers Coalition filed a motion asking the commission to consider the waiver because of developments within WRAP, which impacted Oregon’s separate RA program.
Entities not part of WRAP must participate in the state’s RA program, which is modeled mostly on WRAP, except it does not have specified penalties. Those instead are determined by the commission, according to a staff memo.
The commission previously waived penalties for the 2025-2027 compliance period after WRAP delayed its first binding period. Until the recent vote, no waiver existed for the 2027-2029 cycle, but the commission approved one in response to recent WRAP developments.
WRAP participants had until Oct. 31 to commit to the program’s binding season beginning in winter 2027/2028. Citing concern about the program’s readiness, Oregon-based utilities PacifiCorp and Portland General Electric exited, along with Calpine Energy Solutions, which operates as an ESS in the state. (See WRAP Wins Commitments from 16 Entities.)
The entities could choose to rejoin WRAP, but if they do not, they must demonstrate compliance with Oregon’s RA requirements unless another regional RA program becomes available.
In light of these developments, NIPPC asked the Oregon PUC to provide clarity by adopting a penalty framework for the state RA program and adopting an alternative compliance pathway for ESSs.
NIPPC said ESSs are struggling to meet both WRAP and state RA requirements, in particular because of difficulties procuring transmission rights from third-party transmission providers and rights holders.
“[NIPPC] said that uncertainty about ESSs’ ability to comply with requirements or reasonably limit penalties for non-compliance in either WRAP or the state program could irreparably harm the direct access (DA) market by leaving DA customers with ‘no reasonable choice’ but to provide notice to their incumbent utilities of their intent to return to cost-of-service rates,” according to the memo. “Although WRAP and state program penalties are not scheduled to apply until 2027, NIPPC stressed the urgency of its first request, that the commission clarify state program penalties, noting that DA customers must typically provide at least two years’ notice to return to their incumbent utilities.”
In response to NIPPC’s motion, PUC staff said it “believes there is good cause for the commission to waive [RA penalties] for ESSs for the next state program compliance process. This waiver would remove the requirement for the commission to make a compliance determination on ESSs’ forward showings and the firm requirements related to remedies and penalties.”
Staff added that the waiver should give it enough time to investigate and consider changes to the state RA program.
Staff also provided a five-point checklist for what it believes the commission should accomplish moving forward:
Provide load-serving entities with near-term clarity about state RA requirements and consequences of noncompliance.
Ensure, to the extent possible, non-preferential treatment between ESSs and utilities and fair treatment between participants in the state RA program and those in WRAP.
Minimize disparities between available RA programs while also incentivizing participation in a regional RA program.
Ensure the commission maintains visibility into the RA positions of LSEs and the potential for impacts on all retail customers.
Ensure compliance with state program requirements is feasible and incentivized by the program’s design.
‘Ensuring Reliability and Competition’
Stakeholders participating in the meeting backed staff’s recommendations.
Marie Barlow, an attorney with NewSun Energy, said the organization supports the efforts.
“We just want to emphasize that the goal for the resource adequacy and the direct access programs should remain focused on ensuring reliability and competition,” Barlow said. “The outcome that we absolutely do not want is for the direct access program to collapse under the weight of those resource adequacy obligations, resulting in those loads returning to the utilities and further burdening those utilities with their greenhouse gas reductions obligations and additional reliability obligations, especially at a time when they’re already going to be burdened with rapidly increasing loads.”
Other organizations and companies also voiced their support, including PGE, PacifiCorp and Calpine.
PUC Chair Letha Tawney noted that the vote does not mean there will be no RA obligations for ESSs and that most parties appear to agree they should continue to present forward showings.
“I think there may be interim data requests that staff will have to request and ESSs might need to be responsive to,” Tawney said. “As we go forward through this time frame, it might be that every … 24 months showing is sort of sufficient given how dynamic the space is. But I’m hearing an openness to that dialog, and I appreciate that.”
A new report examines CAISO, MISO, PJM and SPP efforts to accelerate interconnection queues and concludes that while some may succeed in speeding generation additions, some sacrifice fairness, transparency and open-access principles.
Early evidence suggests these emergency mechanisms produce portfolios heavily weighted toward thermal resources that potentially face high network upgrade costs, according to the analysis performed by Grid Strategies for the American Council on Renewable Energy.
The ACORE report warns that these programs are labeled as one-time measures but could be extended or repeated. Instead of that, the authors urge a long-term strategy that upholds open access and competition, and they propose two paths to this goal:
An Enhanced Readiness Fast Lane — a narrowly tailored, transparent pathway for projects that address verified near-term reliability needs, activated only under specific conditions and governed by transparent, objective and nondiscriminatory criteria.
Proactive Integration with Transmission Planning — a restructured baseline queue that aligns project intake with available and planned transmission capacity, using scoring systems to prioritize commercially ready and policy-aligned resources.
ACORE released “Interconnection Queue Rationing Reforms” on Nov. 25. The authors acknowledge that while priority interconnection processing can be designed to uphold the open-access principles that are the cornerstone of competitive wholesale energy markets, many such efforts fail to meet this ideal.
“Discriminatory queue processing undermines fair competition among technologies and interconnection customers,” they write, “introducing regulatory uncertainty that ultimately harms consumers.”
The report drills down on four efforts:
CAISO’s Interconnection Process Enhancements;
MISO’s Expedited Resource Addition Study;
PJM’s Reliability Resource Initiative; and
SPP’s Expedited Resource Adequacy Study.
All were implemented after FERC Order 2023 directed a shift from the first-come, first-served approach to queue management to first-ready, first-served.
The driving factors for the changes are well known: The U.S. interconnection queue has grown to more than 2.3 TW of potential capacity, interconnection timelines have grown to more than five years on average and fewer than 20% of queued projects reach commercial operation. Meanwhile, power demand is expected to grow significantly, costs are increasing and the supply chain to build all this capacity is bottlenecked in places.
The authors say Order 2023 produced only modest changes, but early evidence suggests grid operators’ reforms beyond the order have begun to streamline and speed queue processing, and show great promise.
The authors take a critical view of the emergency rationing mechanisms being implemented and say the RTOs and ISOs should give their reforms enough time to work before resorting to emergency measures.
“Queue rationing mechanisms like these should not become the default operating model or a substitute for comprehensive reforms,” the report states. “As a guiding principle, grid operators should exhaust all other alternatives that make the standard interconnection queue more effective before invoking new emergency rationings.”
Rationing measures are drawing legal challenges, with environmental groups recently filing suits against the MISO and SPP processes in the D.C. Circuit Court of Appeals, arguing the programs are unjustly preferential by allowing primarily fossil fuel generation to jump queues while ratepayers are billed for the upgrades needed to accommodate it. (See Enviros Challenge MISO, SPP Queue Express Lanes.)
The authors draw a distinction between the temporary fast-track programs MISO, PJM and SPP adopted and the permanent restructuring CAISO undertook.
CAISO’s changes were not without controversy, they write, but “on balance, CAISO’s IPE represents one of the most comprehensive queue reforms among system operators to date.”
Nonetheless, timelines remain extended, the percentage of projects advancing remains low and transmission constraints continue to strand low-cost energy potential.
“The upcoming refinements under IPE 5.0, particularly around energy-only conversion, long lead-time upgrades and equitable scoring oversight, will determine whether CAISO can transform this framework into a sustainable, scalable model for integrating the volumes of clean energy required to meet California’s 2030 and 2045 goals,” the authors write.
FERC has dismissed Ameren’s bid to gain exclusive rights to build nearly $2 billion of MISO regional transmission projects in the state free of competitors.
The commission in a Nov. 24 order refused to interpret Illinois’ “first-in-the-field” doctrine as Ameren Illinois asked (EL25-105). It said the matter is best left to the state.
Ameren argued in a July petition that Illinois’ first-in-the-field doctrine is the functional equivalent of a right-of-first-refusal law and gives it license to develop the Illinois portions of the lines in MISO’s second, $22 billion long-range transmission plan. (See Ameren Argues Exclusive Rights to MISO Illinois Competitive Tx Projects.)
“We believe that the interpretation of Illinois’ first-in-the-field doctrine is a matter of state law,” FERC agreed. “We are concerned that issuance of a merits order on the petition at this time could conflict with subsequent Illinois court decisions or inappropriately interfere with the Illinois courts’ consideration of Ameren’s arguments.”
FERC said its “declaratory orders to terminate a controversy or remove uncertainty are discretionary” and that it exercised its discretion not to take up the petition.
MISO has put two Illinois projects up for bid from the second long-rang portfolio: the $717.6 million portion of the $984.6 million Woodford County–Illinois/Indiana State Line 765-kV project; and the $940.1 million Sub T–Iowa/Illinois State Line–Woodford County 765-kV project. Ameren argued it should build both.
Among others, the Illinois Commerce Commission (ICC) asked FERC to reject Ameren’s petition and let the state deal with the issue.
FERC pointed out that Ameren already has asked an Illinois court to declare the first-in-the-field doctrine the functional equivalent of a right-of-first-refusal law and allow it to bypass MISO’s competitive bidding.
FERC said it believed Ameren was asking it to construe the law for not only the two long-range transmission projects, but all future transmission projects in Ameren’s Illinois service territory that “otherwise would be eligible to be included in MISO’s competitive developer selection process.”
“In this sense, Ameren appears to request a categorical finding from the commission that the first-in-the-field doctrine will always result in a finding that the doctrine applies. But in each of the cases cited by Ameren in setting forth the doctrine, first-in-the-field determinations appear to have been made on the basis of a contemporaneous record,” FERC wrote.
Ameren argued that Illinois had “broadly” applied the doctrine in bus service, telephone and pager service, for moving companies and for water and sewer service.
FERC concluded Ameren could not cite any case law where the ICC or Illinois courts applied the doctrine “in this manner.”
“[W]e believe that Ameren’s request implicates a question of first impression under Illinois law, and we are not the correct forum for such a novel application of state law,” FERC wrote.
Ameren claimed it wasn’t seeking an interpretation of Illinois law, just FERC’s confirmation that the doctrine is an applicable law MISO should recognize. The ICC accused Ameren of “forum shopping,” with FERC on its list as a means to crush transmission competition.
MISO disagreed with Ameren’s claim that it was wrong to put the projects up for solicitation. The RTO said there wasn’t a “binding determination from an Illinois court or other competent tribunal” to clearly show the doctrine is applicable to the projects.
