As NYISO continues its Capacity Market Structure Review, the Market Monitoring Unit used its second-quarter State of the Market report to highlight potential issues with how the ISO forecasts resource availability, with the late June heat wave as a test case.
All-in prices were up across all zones of the New York Control Area, driven by an increase in natural gas prices. But “in addition to the gas prices, I think the extraordinarily high load level that peaked in late June … certainly added a lot to real-time prices,” Pallas LeeVanSchaick, vice president of Potomac Economics, told the Installed Capacity Working Group on Sept. 8.
LeeVanSchaick offered a breakdown of the performance of fossil fuel generators, emergency capacity and large curtailable loads during the heat wave. He said the MMU wanted to highlight these resources because they have not been the focus of prior capacity accreditation discussions.
“It’s sort of outside the standard analyses that we do,” he said. “It has to do with capacity accreditation. … Obviously we and … NYISO and other regional market operators have spent a lot of time on how to improve capacity accreditation.”
The analysis compared the performance of fossil fuel resources systemwide during the June heat wave against their weighted average equivalent demand forced outage rate (EFORd), which measures how much capacity a resource could reliably provide when in demand. During peak hours in the heat wave, the MMU found that units were out of service more than predicted by their average EFORd.
“The concern here is if you look at the stuff that was unavailable due to either forced outages or performance, the number comes out to 24.9% on the 24th, compared to an average EFORd of 5.9%,” LeeVanSchaick said. This means that EFORd is being calculated too low because it is not taking into account how certain generators are being used, he said.
Some fossil fuel plants, like peakers, are dispatched to run at high outputs very rarely. These plants are aging, which reduces their ability to operate at high output. If they aren’t called on to push high power out frequently, EFORd will not capture when they fail to function at those levels, leading to far more optimistic rates. This problem also occurred with steam turbine units during the heat wave.
“This heat wave presented a unique opportunity because we haven’t seen conditions where so many units were asked to operate at high levels,” he said.
In addition, some capacity that was available to the ISO was not recognized by its real-time model as available. About 213 MW that previously participated in the Capacity Limited Resource and Emergency Capacity programs were not scheduled and did not produce energy; 73 MW of capacity that were not scheduled but produced voluntarily were also not recognized.
“What we found was that there was not an operating procedure to utilize these megawatts that was ready to be used on these days,” LeeVanSchaick said. “Although the conditions and operating reserve shortages would have warranted using this capacity, it wasn’t actually scheduled.”
Roughly 90% of large loads across 600 MW of demand response programs voluntarily curtailed during the peak load hour June 24, he said. These were resources participating in the Special Case Resource (SCR), Demand-Side Ancillary Service (DSASP), distributed energy resource and Behind-the-Meter Net Generation programs.
These DR actions had some inefficiencies. Over 200 MW of SCRs were curtailed when they could have provided DSASP reserves; 70 MW of SCRs curtailed for four hours as requested but then increased consumption during the peak, meaning they weren’t deployed when they were most valuable.
“We’re going to need to think further about how to potentially refine these programs so that these things are consistent for resources to be participating efficiently,” LeeVanSchaick said.
The U.S. Department of Energy is kicking off its Speed to Power initiative by seeking input on large-scale grid projects that would serve large-scale data centers.
The move is the latest in a series of efforts President Donald Trump initiated hours after his inauguration to boost American energy production. There has been an emphasis on boosting production and consumption of fossil fuels while hindering development of intermittent renewable energy resources, but energy infrastructure also is a priority.
DOE said Speed to Power is centered on multi-gigawatt generation, transmission and grid infrastructure projects that will enable the U.S. to accelerate artificial intelligence buildout.
“With the Speed to Power initiative, we’re leveraging the expertise of the private sector to harness all forms of energy that are affordable, reliable and secure to ensure the United States is able to win the AI race,” Energy Secretary Chris Wright said in a Sept. 18 news release.
The same day, DOE’s Grid Deployment Office issued a request for information that would help it identify projects that enable minimum incremental load of 3 GW and support up to 20 GW of incremental load.
These can include building new interregional transmission (minimum 1,000 MVA); reconductoring existing lines (minimum 500 MVA); bringing retired thermal generation facilities back online or using their interconnection capacity for new “reliable” power generation; and constructing new generation.
DOE reminded respondents about the funding and technical assistance programs available for such projects.
The interactive map offers some of the information developers need as they conduct site assessments, including: power demand from data centers that are planned, under construction or in operation; fiber-optic cable networks; transmission lines; power plants; substations; natural gas pipelines; day and night population; NERC reserve margins; FEMA risk indexes; and railroads.
DOE said its launch of Speed to Power will “ensure the United States has the power needed to win the global artificial intelligence race while continuing to meet growing demand for affordable, reliable and secure energy.”
The Problem Solvers Caucus, a bipartisan group of House members, has released a framework for energy infrastructure permitting legislation as momentum for a bill grows in Congress.
The caucus’ Permitting, Energy and Environment Working Group, led by Reps. Scott Peters (D-Calif.) and Gabe Evans (R-Colo.) and co-chairs Reps. Brian Fitzpatrick (R-Pa.) and Tom Suozzi (D-N.Y.), developed the framework over the past few months by working with energy producers, industry experts, members of relevant congressional committees and other stakeholders.
“America faces a choice between cheap, abundant energy from all-of-the-above sources or higher energy prices, falling behind China and an increased risk of blackouts,” Peters said in a statement. “It’s obvious where we need to go. To get there, we know we need to update our environmental laws to meet the challenges of today and invest in a grid for this century. This platform represents a bipartisan commitment to set aside ideology and solve this problem for the American people. I look forward to working with my colleagues to keep the momentum going and turn this into legislation that can pass both chambers of Congress.”
The framework for permitting reform covers a range issues from efforts to streamline reviews under the National Environmental Policy Act to changing how the largely untested National Interest Electric Transmission Corridors (NIETCs) work by allowing just one line (rather than a broader region) to qualify as a corridor. The NIETCs are designated by the Department of Energy and any lines qualify for backstop siting at FERC.
The NIETC process would be amended to allow for simultaneous state and federal reviews (recognizing state authority), and it would require DOE to act on applications within 90 days.
The process for judicial review of DOE- and FERC-approved linear infrastructure projects would be consolidated under the exhaustion and judicial review provisions of the Federal Power Act.
The framework includes categorical exemptions for simple updates to existing linear infrastructure, especially in disaster-prone areas. The Forest Service’s management and wildfire mitigation activities in utility rights-of-way should be expedited.
To help meet rising demand, the framework calls for FERC to initiate interregional planning (excluding ERCOT), with Congress providing “strong guidance on the allocation of the costs of these infrastructure projects” while excluding cost allocation to customers who receive no or trivial benefits.
On domestic supply chains, the Problem Solvers Caucus calls for DOE to “regularly assess electricity generation and transmission supply chains for security and resilience.”
“Reforming our permitting system is crucial, and this framework meets the moment for much-needed change. The demand for affordable and reliable energy of all kinds becomes increasingly urgent,” Evans said in a statement. “By cutting through red tape, we can meet energy demand, lower costs, strengthen national security and create high-quality jobs in America, while being responsible stewards of the environment and maintaining our position of global leadership and not cede ground to China. The urgency is real, and I am proud of this bipartisan push for change.”
The caucus’ permitting reform framework was welcomed by Grid Action Executive Director Christina Hayes, who said it shows Democrats and Republicans can come together to find solutions that strengthen the grid, cut red tape and speed up the development of transmission infrastructure.
“As demand for electricity soars, driven by the rapid growth of artificial intelligence, new data centers, and the everyday needs of families and businesses, the urgency of bipartisan action has never been clearer,” Hayes said. “This framework recognizes that meeting those demands means modernizing our permitting system so that transmission projects can move forward quickly, reliably and affordably.”
The Bonneville Power Administration has entered into a five-year power purchase agreement to buy wave energy from a test facility managed by Oregon State University (OSU), the agency said.
BPA will buy up to 20 MW/hour of test energy output from the OSU-administered PacWave project starting in 2026 at a purchase price of 75% of the CAISO Western Energy Imbalance Market’s index price, according to the PPA published Sept. 16.
Dan Hellin, PacWave’s director, called the agreement “a significant milestone for PacWave and Oregon State University.”
“We feel that it demonstrates the value of wave energy as an emerging renewable resource and provides a practical pathway for PacWave-generated electricity to enter the grid,” Hellin told RTO Insider. “This agreement not only validates PacWave’s role as a leading open-ocean wave energy test facility but also ensures that the technologies we host are evaluated under real-world market conditions — an essential step toward advancing wave energy from an experimental concept to commercial reality.”
Funded by the U.S. Department of Energy and the state of Oregon, the agreement with BPA concerns one of two facilities under development by PacWave. The project is an open wave energy testing facility and sits seven miles off the Oregon coast. The university submitted a small generator interconnection application in 2015, and BPA has partnered with OSU to ensure the project meets the requirements for new generation in the agency’s balancing authority.
In March 2021, FERC issued a license for construction and operation of the wave project, and the facility was completed in early 2025, according to PacWave’s website.
BPA has agreed to buy energy at a delivery point within a Central Lincoln Public Utility District-owned distribution facility, according to the agreement.
Specifically, BPA entered the agreement under the Northwest Power Act’s section on conservation and resource acquisition. The agency can acquire output under the section if the resource is not a major resource, is experimental, has the “potential” to provide cost-effective services, and if BPA has included the resource in its annual budget to Congress.
The project meets all four conditions, BPA stated, noting the agreement covers only 20 MW of energy per hour and that the project is intended to test the potential of wave energy.
“Because the wave energy industry is in its early stages, the reliability, availability and economics of the various wave energy converter technologies are currently uncertain,” the agreement states. “The project will provide BPA, OSU and the project clients an opportunity to learn more about the operational characteristics and commercial feasibility of wave energy technologies, which will provide BPA with information regarding the industry’s potential cost-effectiveness.”
OSU will select four clients and provide “each with access to an offshore testing berth with a 5-MW-capable power and data cable connection to the shoreside grid connection facility,” the agreement states.
The partners expect the project will begin generating in the spring of 2026.
“This is a small resource purchase that makes economic sense for BPA customers and helps meet BPA’s responsibility to foster emerging technologies in support of its strategic plan, regional and national energy goals,” BPA said in an announcement.
In 2021, the Hawaii Natural Energy Institute announced it would receive $6 million from the Naval Facilities Engineering Command to research wave energy conversion technology. (See Hawaii Wave Energy Project Gets $6M in US Navy Funding.)
The U.S. clean energy industry is so over tax credits.
The passage of the Republicans’ One Big Beautiful Bill Act ─ extending President Trump’s 2017 tax cuts and decimating former President Biden’s 2022 renewable energy tax credits ─ was a shock to the system and already is slowing the growth of solar and wind in the United States.
But slowing down was not at all on the minds of the 37,000 industry professionals ─ and 1,325 exhibitors ─ who descended on Las Vegas Sept. 8-11 for RE+, the largest renewable energy trade show in the country.
What I heard, at more than one session over the four-day conference, was that if the industry had to lose the federal incentives, it could not have happened at a better time. Trump’s scorched-earth war on renewables may be a political reality, but the exploding growth in electricity demand from data centers, manufacturing and electrification is driving economic and technological change at a scale and speed well beyond the president’s control.
K Kaufmann
New figures from industry analyst Wood Mackenzie show that U.S. utilities currently have 17 GW of new electricity projects under construction specifically for large loads like data centers. An additional 99 GW of large-load projects are “committed,” meaning they have interconnection agreements, contracts or other solid financial arrangements.
Solar and storage made up 82% of new generation coming online in the first half of 2025.
“So, we’re in this state where there’s sort of two truths, two experiences, two realities,” said Abigail Ross Hopper, president and CEO of the Solar Energy Industries Association, which sponsors RE+ with the Smart Electric Power Alliance.
While the politics may remain “intensely chaotic and intensely unpredictable, there’s opportunity for entrepreneurship; there’s opportunity for innovation; there’s opportunity for success,” Hopper said during an industry update Sept. 10. “The market will take over politics, and we will ultimately win.”
Bifurcated Realities
I experienced a similar sense of bifurcated realities at RE+ as I attended panels and workshops and cruised the trade show floor.
Politics remains the industry’s Achilles’ heel. Leaders have yet to let go of their quixotic belief that at some point, they will be able to break through the ideological noise in Washington, D.C., with facts, figures and common sense.
A panel on how to frame clean energy policies for conservatives basically replayed many of the talking points I have been hearing at energy conferences for the past year or more, even before Trump was elected for a second term.
Eric Goodwin, vice president of business development at OMCO Solar, a steel company that manufactures solar tracking systems, talked about keeping a focus on jobs and drawing Trump’s attention through targeted use of social media.
Heather Reams, president and CEO of Citizens for Responsible Energy Solutions, a right-leaning clean energy advocacy group, argued that, the OBBBA notwithstanding, the industry must continue to engage with congressional Republicans. Like Hopper, Reams called for a shift in priorities, from tax credits to innovation.
Tom Starrs, vice president of regulatory affairs at EDP Renewables, and Isaiah Menning, external affairs director of the American Conservation Coalition, both stressed the importance of building local support in rural areas where solar and wind projects often face opposition.
As always, the views and voices expressed here were authoritative, thoughtful and pragmatic, and unlikely to have any major impact. The problem is we have a president and administration that have little to no interest in facts that in any way counter their own skewed, fossil-fueled vision of what American energy policy might look like.
They are equally uninterested in any kind of constructive dialogue with the renewable energy industry, as witnessed by the almost complete absence of representatives from the Department of Energy at RE+, from Energy Secretary Chris Wright on down.
PERC vs. TOPCon
Had Wright been there, he would have seen an industry that is vital, optimistic and determined to out-innovate, out-AI and outlast Trump and his backward-looking energy policies.
Artificial intelligence was everywhere, with a small army of startups rolling out new products that can cut times and cost to design virtual power plants and microgrids, review contracts or local ordinances, promote home electrification and send robots to inspect solar panels out in the middle of nowhere.
Solar and storage companies from China and India also were highly visible on the trade show floor, many of them figuring out how to work around Trump’s tariffs and comply with OBBBA’s stricter domestic content requirements.
SolarSpace, a top Chinese manufacturer of solar cells and panels, is partnering with several American investors to build a solar manufacturing plant, according to John Van, a sales manager. While he was reluctant to provide details or name names, he said the new plant is scheduled to go online by the end of the year, and half of its initial 2 GW of panel capacity already is sold.
What’s significant here is that SolarSpace and other Chinese and Indian companies are producing solar cells and panels that are more efficient and durable than cells and panels currently being manufactured in the U.S. The American industry still is using PERC (passivated emitter and rear cell) technology, while the rest of the world has moved on to TOPCon (tunnel oxide passivated contact) and HJT (heterojunction with intrinsic thin layer) technologies. (The links connect to fairly wonky descriptions of the technologies.)
TOPCon and HJT panels are more expensive, but more efficient, which means projects using these technologies may not need as much land ─ a core issue for solar projects in rural areas. But rolling out these advanced technologies in the U.S. has stalled, in part due to legal disputes over intellectual property and patent ownership.
U.S. producers also have stuck with PERC because they can manufacture more panels at lower prices, despite their lower efficiency and durability.
In other words, Trump’s tariffs and domestic content requirements are not advancing the onshoring of solar manufacturing or fostering U.S. competitiveness, while Chinese and Indian firms are figuring out the business models that will enable them to enter the U.S. market and potentially offer better products.
The Interoperability Challenge
What one could see and hear at RE+ ─ at least what I’ve written about so far ─ is the tip of the proverbial iceberg, what’s visible above the water line. The changes needed to respond to current system challenges ─ political, economic and technological ─ can happen only when you drill down to explore the patterns, trends, behaviors and attitudes that lie below, according to Matt McDonnell, managing partner of the Current Energy Group, a policy and analysis outfit.
McDonnell was one of the speakers at a half-day workshop Sept. 8, laying out a holistic, “systems thinking” approach to grid planning and design, sponsored by the GridWise Architecture Council, commonly called GWAC.
“What are the assumptions and beliefs that people hold about the system? How do we really, really challenge some of these things that we take for granted … conventional wisdom, the way things have always been done?” he said.
Part of working toward such fundamental changes in the electric power system means nudging regulators and other industry stakeholders “down this iceberg model stack to really be challenging some of these underlying features that are below the surface often in proceedings.”
Taking the example of grid resilience following extreme weather events, traditional patterns and thinking might focus on grid upgrades or “hardening” that “drives up costs while often offering suboptimal performance,” McDonnell said. “Poles keep getting rebuilt and ice storms come through and keep knocking them down.”
Should the focus be on grid reliability or “energy service reliability?” he said. “Is what we really care about the poles and wires staying up all the time, or do we care about customers having access to energy even during extreme weather events?”
GWAC sees this kind of systems approach as integral to developing flexible and interoperable energy services that will allow individual buildings or groups of buildings ─ like data centers ─ to interact with the grid, from distribution up to transmission, to improve reliability and cut costs for consumers.
The proliferation of grid-edge technologies has created an “interoperability challenge,” said Shawn Chandler, a director at consulting firm Guidehouse. Distributed generation and computing power can be combined “to get all that sensing and all that information into a hybrid, decentralized system that brings together … system distribution operations, customer service, market operations and regulators.”
“If you can do that, then all your information flows are leading to the same outcome, which is [that] we want the most optimization, and most importantly, we avoid what I would call unintended consequences,” he said.
Ultimate Inertia
The language may be a bit abstract and jargony, but the connections to the industry’s current debates on how to meet demand growth are immediate and clear.
Under Trump’s drive to stand up new fossil-fueled and nuclear generation ─ at the tip of the iceberg ─ is the basic assumption that the need for new power can be met only with traditional, 24/7 dispatchable forms of generation.
What drives such assumptions is the deeply engrained industry desire for quick and simple solutions that require little change in business or regulatory models, an approach that increasingly is untenable.
Radical and rapid growth in electricity demand presents complex challenges that call for new and complex solutions.
The factors under the waterline here include backed-up supply chains for natural gas turbines, with delivery times of three to five years or more. Building out new plants, natural gas pipelines and transmission lines could mean ongoing utility bill increases for consumers, an unintended consequence and political minefield for any candidate for public office. New approaches to affordability will be critical.
Technology may move faster than policy or regulation, but the ultimate inertia in the system is rooted in human attitudes and behavior. What I saw at RE+ is that clean energy is moving fast and more than ready to embrace the complex challenges ahead. Trump or anyone else holding on to simple, outdated solutions will be left in the dust.
Livewire Columnist K Kaufmann has been writing about clean energy for 20 years. She now writes the E/lectrify newsletter.
Texas regulators have proposed new rules on large load forecasting criteria and net metering following the state’s recent biennial legislative session and opened them up to public comment.
The two projects are among four active dockets related to Senate Bill 6’s implementation. One of the state Senate’s top priorities, the legislation, among other things, directed the Public Utility Commission to determine a cost allocation for large loads to ensure they’re paying their fair share of infrastructure expenses. (See Texas Bills Targeting Renewables Come up Short.)
The PUC has recommended that to gather as much feedback as possible, the large-load criteria be standardized to include loads exceeding 25 MW. The criteria intentionally excludes loads below 25 MW, which primarily interconnect at the distribution level (58480).
PUC Chair Thomas Gleeson said during the commission’s Sept. 18 open meeting that he has yet to agree projects should be included in ERCOT’s load forecast if they meet a pair of criteria by submitting attestations to the transmission or distribution service provider. He asked stakeholders to comment on the benefits provided by submitting attestations that show “significant, verifiable progress” toward: 1) completion of required site-related studies and engineering services and 2) obtaining state and local regulatory approvals required before a project’s energization.
“I’m going to need to be sold on having this in this rule going forward,” he said.
The proposed net-metering rulemaking will apply to large loads and existing generation resources and establish the criteria for ERCOT’ s study of the arrangements. It sets the procedural steps for staff to complete their study of a net-metering proposal within 120 days and the commission’s procedure to approve, with or without conditions, or deny a net-metering proposal within 60 days after ERCOT files its study results and recommendations (58479).
ERCOT staff was on hand to share details of ERCOT’s studies of the net-metering arrangements’ reliability effects while the rule is being developed. They said the studies will evaluate the effects on transmission security, resource adequacy and the stranding or underuse of existing transmission facilities.
The analysis will consist of a before-and-after capacity reserve margin evaluation using ERCOT’s most recent capacity, demand and reserves (CDR) report as a baseline. Reserve margin effects over the next five years will be reported for both the forecasted peak load hour and net load hour in line with the CDR reserve margin reporting requirements.
Participants in ERCOT’s market have until Oct. 17 to file initial comments or request a public hearing. Reply comments are due by Oct. 31.
SETEX Reliability Project
The PUC once again delayed action on Entergy Texas’ proposed 500-kV single-circuit transmission line in northeastern Texas after hearing oral arguments from more than a dozen landowners or their attorneys (57648).
Gleeson promised the commission would reach a decision on the transmission line during its Oct. 2 open meeting. The project has 61 proposed routes, with PUC staff and Gleeson each favoring different routes.
“As I sit here right now, I’m still not prepared to make a decision,” he said. “I think it’s appropriate to extend it one more meeting to take into account everything that was said and to make sure that anything we’re considering from that oral argument is in the record.”
The 150-mile SETEX Area Reliability Project has drawn opposition from local landowners, who requested a rehearing of the State Office of Administrative Hearings’ decision to recommend a certificate of convenience and necessity for the line. The project’s various routes range from 131 to 160 miles, and its costs are projected to be between $1.33 billion and $1.52 billion.
“Entergy Texas is sympathetic to the concerns landowners may have about the line,” said attorney Everett Britt, representing Entergy. “Each of the 61 routing options before you satisfies the need for the project. It is viable and constructible. We’ve heard a number of arguments and issues raised today. We do think these have been addressed, if not by parties here today than in the extensive briefing and exceptions filed in this case.”
A federal judge has lifted a stop-work order on Revolution Wind, handing a rare victory to the U.S. offshore wind industry amid the Trump administration’s relentless effort to torpedo it.
Judge Royce Lamberth issued the directive Sept. 22 in response to Revolution Wind LLC’s Sept. 4 complaint in U.S. District Court for D.C. (1:25-cv-02999).
The U.S. Bureau of Ocean Energy Management slapped the stop-work order on Revolution Wind on Aug. 22, offering vague references to threats to national security and potential interference with reasonable uses of territorial waters.
Revolution in its counterclaim said the order was arbitrary and capricious, violated the due process clause of the Fifth Amendment and is beyond statutory authority.
On Sept. 22, Lamberth granted Revolution’s request for a stay and injunction, writing: “Revolution Wind has demonstrated likelihood of success on the merits of its underlying claims, it is likely to suffer irreparable harm in the absence of an injunction, the balance of the equities is in its favor, and maintaining the status quo by granting the injunction is in the public interest.”
Offshore wind construction is extremely expensive. The idle month likely has cost Revolution tens of millions of dollars and potentially set up a series of future costs, such as extended vessel charters due to the delay.
Later Sept. 22, Revolution Wind said it would resume construction work as soon as possible. It said its lawsuit challenging the stop-work order will progress, but also said it would continue to seek collaboration with the Trump administration and other stakeholders to find a resolution.
Revolution Wind is a 50-50 joint venture of Ørsted and Skyborn Renewables through their subsidiary, Revolution Wind LLC.
The project has its roots in a September 2013 federal auction of a seabed lease south of Rhode Island and Massachusetts. After years of planning and review, BOEM issued a record of decision in favor of Revolution in August 2023 and approved its construction and operations plan in November 2023. Construction was approximately 80% complete when halted, and commercial operation had been targeted for 2026.
The project is designed to produce a maximum of 704 MW of electricity; Rhode Island and Connecticut have agreed to take 400 MW and 304 MW, respectively.
Trump launched his attack on offshore wind power hours after his second inauguration, and his administration soon commenced a thorough and effective effort to block development. However, most of the measures have been directed at early-stage projects, or later-stage projects that have received BOEM approvals but have not yet begun construction.
The five projects now under construction have not been targeted as clearly. An April stop-work order against Empire Wind was widely seen as an attempt to muscle through two natural gas pipeline proposals, and BOEM allowed work to resume in May after New York agreed to consider the pipeline plans.
If the Trump administration has an ulterior motive for stopping work on Revolution Wind, it has not surfaced.
BOEM did not immediately respond to the Sept. 22 injunction or indicate what its next move would be.
But however fleeting the court victory may turn out to be, it drew cheers from national trade group Oceantic Network: “Today’s decision allowing work to resume on Revolution Wind is welcome news for the hundreds of skilled workers who can now return to their jobs while the legal process continues. Revolution Wind is critical to securing New England’s electric grid, lowering energy costs for businesses and families, strengthening the local supply chain, and achieving energy independence. This Made in America energy project is putting Americans to work building reliable, affordable power to communities across New England that desperately need it.”
The California Public Utilities Commission is preparing to overhaul its demand response programs, policies and data systems to ensure uniform DR standards statewide and better position the Golden State to meet its energy policy and emissions goals.
During a Sept. 18 voting meeting, the CPUC approved an order instituting rulemaking intended to improve the “consistency, predictability, reliability and cost effectiveness of demand response resources in California,” the commission said in its decision approving the rulemaking.
The rulemaking seeks to:
Update demand response “guiding principles” designed to align statewide policies around DR programs.
Update policies related to the state’s “dual participation” model, valuation methodologies and evaluation metrics.
Standardize DR data system and process requirements.
Standardized data processes will help the commission reduce data costs and errors, staff said in their proposed decision.
“This is a big moment for demand response in California,” Commissioner John Reynolds said during the voting meeting. “At our present moment, rates don’t yet provide a clear signal to manage electric usage as efficiently as possible or desirable.”
“I wouldn’t be surprised if California one day reaches a point where most, if not all, demand response programs rely on economic signals that are integrated into existing retail and wholesale markets,” Reynolds added.
In a presentation during the meeting, CPUC staff said demand response principles should be “predictable and reliable” so they can be incorporated into California’s forecasting and planning frameworks.
Inconsistent or unpredictable demand response programs “jeopardize grid reliability, trigger emergency procurement of costly backup resources and erode confidence in the capability of demand response resources to play a significant role in achieving the state’s energy and environmental goals,” staff said in the presentation.
“Without furthering our demand response policies, it is my belief that we’re not going to be able to meet our clean energy goals,” Commissioner Darcie Houck said at the voting meeting. “These [upcoming] policies are going to be absolutely critical.”
CPUC staff plan to publish a full proposal for the new rules in the first quarter of 2026, followed by commission vote in the third quarter.
SCE General Rate Case Revenue Approved
The commission also approved Southern California Edison’s (SCE) test year 2025 general rate case that includes a total revenue requirement of $41.8 billion for 2025-2028.
The approved revenue requirement will increase average residential monthly bills by about $9.80 for California Alternate Rates for Energy (CARE) customers and $15.52 for non-CARE customers — a rise of about 9.1% for both groups.
A significant portion of the money in the rate case — about $3.1 billion — will be used for work that reduces wildfire risk in SCE’s territory. SCE plans to spend about $554 million specifically on trimming and removing vegetation that is near electrical facilities to reduce the risk that those facilities start a fire.
“A large part of utility expenditures today have to do with wildfire mitigation, and this decision recognizes the need to target undergrounding of powerlines and also authorizes covered conductor projects, all of which will dramatically cut wildfire risks,” CPUC President Alice Reynolds said at the meeting.
“[This decision] recognizes the importance of all of [SCE’s] investments and costs, but [it] also [recognizes] the really urgent need to impose discipline on those costs, and that’s just as important given the challenges that Californians are facing for cost of living,” she added. “I think this decision does that. It’s not easy. We can’t find a perfect solution.”
SCE Approved to Sell 7 Hydro Facilities
The commission also approved SCE’s request to sell seven of its small hydroelectric facilities to the San Bernardino Valley Municipal Water District for about $34 million.
The facilities are Mill Creek 1, Mill Creek 3, Ontario 1, Ontario 2, Santa Ana River 1, Santa Ana River 3 and Sierra. Six of the seven facilities are operational and generate about 11.6 MW, or about 1% of SCE’s total hydroelectric facility capacity of 1,164 MW.
SCE will incur a pre-tax loss of about $60 million due to the transaction, the decision says.
SPP has named Tim Vigil, chief member relations and strategy officer for the Pacific Northwest Generating Cooperative (PNGC), as director of the Market Monitoring Unit’s office dedicated to Markets+.
In the role, Vigil will lead the development of market monitoring reports and metrics for Markets+, manage processes for identifying and addressing market design flaws, monitor market operations functions and support a future surveillance team responsible for screening market participant behavior.
The new position within the MMU was created in advance of the RTO’s launch of its Western day-ahead and real-time market in 2027, SPP said in a press release.
Carrie Bivens, SPP’s vice president of market monitoring, said Vigil’s broad industry knowledge, strong market insight and long experience in the Western Interconnection “will be invaluable to our monitoring preparation efforts for the new market and future oversight responsibilities.”
SPP said Vigil was instrumental in forming and implementing SPP’s Western Energy Imbalance Service market. He chaired the stakeholder-led Western Markets Executive Committee from 2020-2021.
Vigil joins the SPP MMU from PNGC. He previously served as director of development-origination at NextEra Energy, COO at Delta-Montrose Electric Association and in various roles at the Western Area Power Administration. He holds a bachelor’s degree in economics from California State University Northridge.
The MMU is independent of the RTO and its contract services, including Markets+. It functions independently to avoid actual or apparent conflicts in its oversight role.
FERC has directed SPP to submit a compliance filing for its proposal to unwind credit payment obligations assessed under Attachment Z2 of its tariff for transmission service taken from 2008 to 2016.
In an order issued Sept. 18 at its monthly open meeting, the commission determined that SPP lacked specifics in its proposed five-year plan to process about $138.5 million in refunded transmission service revenue credits paid during the refund period (March 2008 through August 2015) and an additional $8.2 million to refund point-to-point rates that increased during that time (ER16-1341).
FERC directed the RTO to explain how the refunds from entities that elect the payment plan will be allocated to entities owed refunds and to lay out how the plan interacts with a separate short-payments plan. It ordered the grid operator to clarify the allocation of “necessary revenue reduction in proportion to the outstanding net amounts owed by each entity on an aggregate basis after netting together the individual amounts payable and receivable for that invoice date.”
“We acknowledge that an option for a five-year payment plan could provide needed flexibility to the parties that must make repayments, but details of the specifics of the payment plan, and what the impact on refunds of this plan will be, remain open questions,” the commission wrote. “Accordingly, we direct SPP to explain how it would proceed both for entities that owe and are owed refunds in a situation where an entity selected the five-year payment plan option but was unable to pay refund amounts during the five-year period.”
SPP’s response is due within 45 days of the order.
The Z2 issue has dogged SPP since 2016, when the grid operator owed $147 million plus interest to transmission customers for the historical period. Staff said in October 2024 that interest at that time stood at $33.4 million. (See “Grid Operator Waiting for FERC Order to Resettle Z2 Funds,” SPP Markets & Operations Policy Committee Briefs: Oct. 15-16, 2024.)
Under the attachment, transmission upgrade sponsors receive credits from any upgrade users whose service could not be provided “but for” the upgrade. The attachment also requires the RTO to invoice the charges monthly and to make any adjustments within one year.
However, software problems delayed the attachment’s final implementation for eight years before 2016, during which the RTO did not invoice for the upgrade charges. FERC approved a waiver request to settle more than 365 days in arrears, but in 2019, the commission reversed course and said SPP should have settled Z2 from only September 2015 forward. (See FERC Reverses Waiver on SPP’s Z2 Obligations.)
In January 2022, the grid operator updated its proposed refund plan and made an informational update to the commission in September 2024. If approved, SPP plans to send out refund invoices with interest for the refund period, accrued to the current invoice date.
Once a new settlement system is deployed in the coming months, invoices would be issued for the September 2015-January 2020 operating days. Additional resettlements from February 2020 would be run monthly in the current settlement system, along with normal current day Z2 settlements, until SPP catches up to the operating month.
SPP told FERC that the refunds and resettlement, before interest on refunds, total at least $657.8 million (as of June 2024). That amount grows by between $3 million and $4 million each month, it said.
The RTO has said it expects to resettle everything in about four years.
2nd Order 2222 Compliance Filing
Also at the open meeting, the commission accepted SPP’s second Order 2222 compliance filing, subject to another compliance filing to be submitted within 60 days (ER22-1697).
FERC found that in SPP’s December 2024 filing, the RTO complied with the first compliance order’s directives related to the commission’s decision to decline its jurisdiction over the interconnections of distributed energy resources to distribution facilities for the purpose of aggregation. The commission also found that SPP met Order 2222’s requirements of allowing distributed energy resource aggregators to register aggregations under one or more participation models to accommodate their physical and operational characteristics and proposing a maximum capacity requirement.
The commission said it rejected MISO’s first timeline because the RTO proposed to defer Order 2222 implementation for several years. It said SPP’s proposal to implement the order in the second quarter of 2030 complies with the requirement for a “reasonable implementation date with adequate support to show that the proposal is appropriately tailored for its region and implements Order No. 2222 in a timely manner.”
“Here, SPP is not proposing to defer Order No. 2222 implementation. Rather, SPP has adequately explained why an effective date five years from the commission’s acceptance of its revised proposal is appropriate for its region due to its implementation needs,” FERC wrote.
Approved in September 2020, Order 2222 directed all FERC-jurisdictional regional grid operators to revise their tariffs to allow DERs to participate in their capacity, energy and ancillary service markets. (See FERC Opens RTO Markets to DER Aggregation.)
