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.)
At its monthly open meeting Sept. 18, FERC approved the latest version of NERC’s cold weather preparedness standard while ordering follow-up informational filings on progress with its adoption.
In a press conference after the meeting, Chair David Rosner said that grid reliability remains “job No. 1” for the commission and that he was “really pleased” that FERC was able to advance the cold weather standard and other reliability items on the agenda. (See FERC Tackles Cybersecurity in Multiple Orders.)
NERC submitted EOP-012-3 (Extreme cold weather preparedness and operations) on April 10 in response to the commission’s directive that it develop “targeted modifications” to its predecessor, EOP-012-2 (RD25-7). FERC had called for the ERO to clarify the term “generator cold weather constraint” (situations in which a generator owner may declare that a specific freeze protection measure would result in a net loss of reliability on the grid) and ensure that the ERO confirms the validity of each constraint, along with clarifying requirements around corrective action plans.
In the new standard, NERC proposed a new, clearer definition for generator cold weather constraints that removed ambiguous references to “cost,” “reasonable cost,” “unreasonable cost” and “good business practices.” An attachment to the standard provides examples of acceptable constraint declarations, such as a case in which “the cost of retrofitting a generating unit would be unduly burdensome such that it would retire prematurely or cancel plans to finish the development of a new generating unit.”
The standard also introduces the concept of a compliance abeyance period for the requirement that GOs calculate the extreme low temperature for their generating units, a move intended to allow some flexibility in the initial application of this requirement. During the abeyance period NERC will “monitor the implementation of this requirement and identify, as appropriate, any revisions to the extreme cold weather temperature formula,” FERC said.
The commission indicated it would approve the standard without any of the modifications called for by the Union of Concerned Scientists, which claimed the cold weather constraint language remained too subjective. (See NERC Replies to UCS’ Cold Weather Standard Criticism.) FERC said the standard was “consistent with commission guidance to provide a limited set of defined circumstances” in which constraints could be granted.
However, the commission did direct the ERO to collect and submit to FERC informational filings every two years, starting no later than October 2026 and ending in October 2034. The filings must include:
the number of cold weather constraint declarations submitted to each regional entity;
the number of declarations approved, and their aggregate megavolt-amperes; and
a summary of the rationales provided for approved declarations.
NERC must also submit a narrative analysis in the filing addressing:
whether reliability coordinators, transmission operators and balancing authorities are notified in a timely fashion of constraint declarations and extensions to corrective action plans (CAPs);
the reliability impact of allowing 36 months to correct freeze-related issues, rather than a shorter time frame;
whether compliance enforcement authorities interpret and apply the constraint declarations approval process;
whether constraint declaration criteria are adequately defined and understood by registered entities; and
the reliability impact of cold weather constraint declarations and CAP extensions.
The standard will take effect Oct. 1. This is a departure from NERC’s request that the standard take effect either that date or three months after regulatory approval, whichever is later. That plan would have resulted in an effective date in December, but FERC said that the earlier date would allow the standard to be in effect before the upcoming winter.
The commission also observed that “industry was involved in NERC’s standard development process and was made aware of pending changes,” meaning the new requirements should not be a surprise for registered entities.
The Texas Reliability Entity’s Member Representatives Committee agreed to send a proposed regional reliability standard before industry stakeholders for a 45-day comment and ballot period at its open meeting Sept. 17.
The comment period for BAL-001-TRE-3 (Primary frequency response in the ERCOT region) is expected to run from Sept. 22 to Nov. 6, with the ballot period occurring in the last 15 days. (See page 19 in the committee’s agenda.) The standard drafting team will meet to discuss comments within 30 days of the end of the comment period.
If the standard fails to receive enough votes from industry, a second comment and ballot period will be held in 2026. If the standard passes, a final ballot will be conducted, after which it will be presented to the Texas RE Board of Directors for approval. From there it would go to NERC, and then to FERC.
BAL-001-TRE was created in 2013 after NERC requested, and FERC granted, a waiver of BAL-001-0 (Real power balancing control performance) for ERCOT on the grounds that one of its requirements was not “feasible under ERCOT’s competitive balancing energy market” and that the grid operator could not create inadvertent flows or time errors in other control areas.
The new version of the standard adds language clarifying that it applies to battery energy storage systems (BESS) and performance requirements for BESS, along with generating facilities, and sets maximum governor deadband settings for generating units that are not qualified to provide operating reserves and have obtained approval from the balancing authority to widen settings. It also updates the compliance monitoring period and circumstances under which the compliance history for the standard may be reset by the compliance enforcement authority.
At the board meeting following the MRC’s, Texas RE Chief Engineer Mark Henry reviewed the region’s performance during the summer. While the hot and dry summer that was predicted did not develop “to the expected degree,” demand continued to increase, with renewable and storage resources setting records; battery discharge during the summer months so far has totaled 7 GW, while solar generation totaled 29 GW.
Henry also confirmed that demand from large loads, particularly data centers and artificial intelligence operations, continues to grow, with load expected to more than double from 18 GW to 37 GW between 2025 and 2026, and again to 83 GW in 2027. He referred to NERC’s Large Loads Action Plan, which envisions the Reliability and Security Technical Committee’s Large Loads Task Force developing recommendations through mid-2026 alongside NERC-led collaborative industry sessions and collaboration with large loads efforts in ERCOT and other areas.
Finally, Henry discussed NERC’s Level 3 alert on inverter-based resources, which the ERO sent to industry on May 20. The alert laid out essential actions for IBR performance and modeling with responses from registered entities required by Aug. 18. Answers were mixed; more than half of utilities said they lack internal processes to confirm the dynamic performance of IBRs following system events, but more than 75% said they do have internal processes to update transmission entities about changes to IBRs that can alter performance.
In two Notices of Proposed Rulemaking issued at its open meeting Sept. 18, FERC proposed to approve 11 new Critical Infrastructure Protection (CIP) standards intended to allow utilities to use virtualization technology, along with a further modification to one of those standards that would improve cybersecurity at low-impact grid-connected cyber systems.
NERC submitted the virtualization updates in July 2024 (RM24-8). (See NERC Sends Virtualization Standards to FERC.) Along with four new and 18 revised definitions for the NERC Glossary of Terms, the filing touched almost every entry in the library of CIP standards:
CIP-002-7 (Cybersecurity – BES cyber system categorization);
Virtualization constitutes “the process of creating virtual, as opposed to physical, versions of computer hardware to minimize the amount of physical hardware resources required to perform various functions,” according to the National Institute of Standards and Technology. NERC said in its filing that the current versions of these standards are “designed around the concept that devices have a one-to-one relationship between software and hardware,” which prevents entities from taking advantage of security advances made possible by virtualization techniques.
In the NOPR, the commissioners wrote they “support NERC’s efforts to … accommodate virtualization and other nascent technologies” and that the new standards should “allow responsible entities to [adapt] to emerging risks with forward-looking security models.” They emphasized the revisions would allow, but not require, utilities to adopt these technologies.
However, commissioners questioned NERC’s proposal to replace the phrase “where technically feasible” with “per system capability.” While the ERO said this change would ease the “administrative burdens” of reviewing technical feasibility exceptions, FERC expressed concern it “would eliminate transparency … by introducing a self-implementing exceptions process with no reporting obligations.”
In light of these concerns, the commission asked for comments in three areas: first, whether there stillis a need to maintain a technical feasibility exception program and what administrative burdens are associated with the current program; second, if the proposed changes would result in entities seeking new exceptions using the “per system capability” language; and third, alternative approaches that would meet the streamlining goals while also allowing effective oversight.
Low-impact Cyber System Concerns
In the other NOPR, FERC sought comments on its proposal to approve CIP-003-11 (Cybersecurity — security management controls), which NERC submitted Dec. 20, 2024 (RM25-8).
The update to CIP-003-10 is intended to address the risk of a coordinated attack using low-impact cyber systems, which constitute most of the systems within the grid. They are considered to pose less of a risk to reliability than high- or medium-impact systems and thereforeare subject to fewer CIP requirements than other systems. However, after the SolarWinds Orion cyberattack of 2020, in which hackers infiltrated the update channel of a popular network management tool and sent malicious code to users around the world, NERC began an investigation into the potential threat posed by a coordinated attack against multiple low-impact systems.
In the proposed standard, NERC staff said it would require utilities to add controls to authenticate remote users, protect authentication information in transit and detect malicious communications to or between low-impact cyber systems with external routable connectivity. These changes still would allow entities “the flexibility as to where the [authentication] control is implemented based on their architecture,” the authors said.
FERC’s NOPR called for comments on developments in the cybersecurity environment since the SolarWinds attack, such as the China-linked Volt Typhoon group that has been accused of embedding itself in the information technology networks of U.S. critical organizations for at least five years. The commission asked whether such actors, who infiltrate a protected network and then move laterally into others, could pose a threat to grid reliability, and whether FERC should direct NERC to perform a study or develop a white paper on the issue.
Comments on the NOPRs are due 60 days after they’re published in the Federal Register.
Supply Chain Standards Due in 18 Months
FERC also directed NERC to develop standards addressing entities’ supply chain risk management (SCRM) plans (RM24-4).
The order also ended a related inquiry regarding reliability risks posed by grid-connected cyber equipment originating overseas, particularly equipment manufactured by Huawei and ZTE (RM20-19).
The final rule “largely adopts” a NOPR issued in 2024 in which FERC identified “multiple gaps” in NERC’s existing SCRM standards. Those standards did not specify when or how entities should identify and assess supply chain risks or require entities to respond to supply chain risks through their SCRM plans, the commission said.
The new standards will have to address “the sufficiency of responsible entities’ SCRM plans related to the identification of and response to supply chain risks,” as well as whether the SCRM standards will apply to protected cyber assets (PCAs). PCAs are defined as “one or more cyber assets connected using a routable protocol within or on an electronic security perimeter [ESP] that is not part of the highest-impact [grid] cyber system within the same” ESP.
One element not included from the NOPR was a directive to require utilities to validate data received from vendors. Instead, FERC encouraged entities to do so voluntarily “as appropriate.”
The final rule directed NERC to submit the required standards within 18 months of the date of issuance.
