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December 10, 2025

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CISA, International Partners Publish SBOM Guide for Industry

Seeking to help address software supply chain vulnerabilities, the U.S. Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA) and international partners released a document Sept. 3 highlighting the benefits of software bills of materials (SBOMs) for both the private and public sectors.

CISA developed the report, “A Shared Vision of Software Bill of Materials for Cybersecurity,” alongside the National Security Agency and the agency’s counterparts from Australia, Canada, the Czech Republic, Slovakia, France, Germany, India, Italy, Japan, the Netherlands, Poland and South Korea. The organizations said their goal was to “inform producers, choosers (i.e. procuring organizations) and operators of software about the advantages of integrating SBOM generation, analysis and sharing into security processes and practices.”

Cybersecurity professionals, including within the ERO Enterprise, have increasingly promoted SBOMs as a solution to a major perceived weakness in modern software development. (See ReliabilityFirst Plugs SBOMs as Essential Cyber Tools.) Rather than being written from scratch, software products today often comprise multiple “components, modules and libraries from open source and proprietary” sources, the guide said. Transparency about these components and their origins is “fundamental for a more secure software ecosystem.”

This is the role of an SBOM, which CISA defined as “a formal record of the details and supply chain relationships of various components used in building software.” The document is similar in scope to a draft guide that CISA released for public comment Aug. 22. That document laid out minimum elements for SBOMs to be generated or requested by federal agencies. (See CISA Seeks Comments on New SBOM Guidance.)

The new guide also includes those elements, such as the expectation that SBOMs use a common format to ensure they are machine-processable, and “contain enough information about the open-source and proprietary components in the software to correlate with other data sources.”

Along with these, the document gives some of the benefits of SBOMs for organizations. CISA said the information provided in SBOMs can improve users’ vulnerability and supply chain management, software development processes and their license management.

To illustrate the potential improvements in vulnerability management, CISA pointed to Log4Shell, a vulnerability in the Log4j software library from Apache that was discovered in December 2021 to contain a weakness that remote actors could use to take control of affected systems.

“Because Log4j was usually used as a transitive dependency (a dependency of other dependencies), it was not always easy to identify,” CISA said. “Organizations without SBOM capability often had to engage in time-consuming manual searches and risked remaining vulnerable. Organizations with SBOMs were able to report a relatively straightforward and efficient response.”

Another illustration showed how the presence of an SBOM reduced average time needed for organizations to identify and respond to a vulnerability. Without an SBOM, CISA said, “each actor is dependent on upstream [software component] suppliers for notification that the vulnerability impacts their software.” But when everyone in the supply chain has an SBOM, organizations can determine for themselves if they are using a compromised product.

The benefits of SBOMs are not limited to producers and users, CISA said: National cybersecurity organizations such as CISA and its peers can also use their information to track their countries’ overall cyber vulnerability, issue warnings and update policymakers.

“The ever evolving cyber threats facing government and industry underscore the critical importance of securing [the] software supply chain and its components. Widespread adoption of [SBOMs] is an indispensable milestone in advancing secure-by-design software, fortifying resilience, and measurably reducing risk and cost,” acting CISA Director Madhu Gottumukkala said in a statement. “This guide exemplifies and underscores the power of international collaboration to deliver tangible outcomes that strengthen security and build trust.”

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SPP, Members Developing 765-kV Transmission Overlay Plan

SPP has hinted to members that its 2025 transmission planning assessment will be another large one — larger, even, than last year’s record $7.65 billion package. 

One of the drivers is a draft 765-kV overlay that staff and members have been engaged with. It builds on SPP’s first 765-kV project that was approved as part of the 2024 assessment, Southwestern Public Service’s 354-mile transmission line crossing the New Mexico-Texas border. (See SPP Stakeholders Endorse Record $7.65B Tx Plan.) 

Casey Cathey, the RTO’s vice president of engineering, shared the overlay during a Sept. 3 education session with the Board of Directors and Regional State Committee. 

“What we have done is a preliminary look based on the [Integrated Transmission Planning] loads that the members have provided us,” Cathey said. 

The draft overlay extends from SPS’ Potter-Crossroads-Phantom line into Oklahoma, where much of the state would be encircled. Another 765-kV line would shoot off to the Southeast and into Louisiana, the site of two load shed events in April. (See SPP Addresses 3rd Load Shed Since March 31.) 

Looking ahead, the 2026 ITP is considering a 765-kV radial line that connects Kansas with North Dakota. One option would close the loop on the western side of the footprint. 

“The 2026 plan is going to be a much more detailed engineering analysis, so it may not look exactly like this next year,” Cathey said. 

Pointing to large loads “peppered throughout” the map, he said that will “necessitate a version of a 765 footprint.” 

“I’m giving some caveats here because there’s a lot of engineering connection points that we may need to change from a reliability perspective,” Cathey said. “However, we are seeing the need for some version of what this looks like moving forward.” 

One reason the time is now ripe for 765-kV transmission in SPP’s footprint is the 345-kV build that members have undertaken in recent years. Cathey said the 345-kV backbone gives staff options that didn’t exist 15 years ago to sustain the transfers necessary should a 765 line be lost. 

SPP has increased its 765-kV line costs from $4.2 million/mile to $5.8 million/mile, comparable to ERCOT’s and MISO’s projections for their 765-kV projects. 

“This is consistent. We’ve gotten some recent feedback from our membership that this is the right way to go and then that the costs are making more sense,” Cathey said. “We don’t have 765 in this region, but it’s been built before. We need to recognize that some things are going to come up. This is going to be pricey. We need to make sure that we’re going into it with eyes wide open.” 

The SPS project was awarded in February with an estimated cost of $1.69 billion. SPS filed a revised cost estimate of $3.62 billion in June, more than double the earlier projection and easily outside the variance bandwidth of +/30% that can lead to a re-evaluation. SPP has said the project still is viable, despite its cost. (See SPP Board Sets Aside 765-kV Costs, Large Load Policy.) 

The RTO has scheduled an education session on the 2025 ITP for the Markets and Operations Policy Committee meeting Sept. 23. The assessment and its portfolio will be brought before MOPC, state regulators and the board in October and November for their approvals. 

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West Must Step up Gas-electric Coordination, WECC Panelists Say

Coordination between the gas and electric industries is becoming increasingly crucial to meet demand and tackle extreme weather events, panelists participating in a WECC webinar said Sept. 3. 

Representatives from the Pacific Northwest Utilities Conference Committee (PNUCC), Williams, Arizona Public Service and Portland General Electric discussed coordination between the gas and electric sectors. 

The Northwest cold snap over the 2024 Martin Luther King Jr. holiday weekend prompted stakeholders to consider ways to improve coordination between the two sectors, said Crystal Ball, PNUCC’s executive director. (See NW Cold Snap Dispute Reflects Divisions over Western Markets.) 

The holiday weekend saw record-low temperatures along with historically high peak demand, prompting five different balancing authority areas (BAAs) to declare energy emergency alerts. 

Though the Pacific Northwest relies heavily on the Columbia River hydro system, the cold snap occurred during a low-water year, Ball noted. It also coincided with a fault that caused Washington’s Jackson Prairie natural gas storage facility to sharply reduce its sendout, prompting pipeline operator Williams to declare a force majeure that cut deliveries to interruptible customers, including some power generators.  

“We recognize that natural gas is the region’s second-largest power source behind hydro, and these two systems are very interdependent, and we will continue to depend on natural gas,” Ball said. 

To meet the mounting large-load challenges from data centers and the transportation sector, stakeholders must work together, not just on transmission and generation, but also focus on expanding the gas system, according to Ball. 

“We need policymakers, regulators, utilities to understand that situation,” she said. “There’s evidence that demand in our region is growing. But right now, this region is dangerously close to an energy supply shortage. And so I think that my advice to policymakers and other stakeholders is to learn about what these reliability risks are and to come together to think about how the region can maintain reliability.” 

For PGE, the January 2024 event meant there wasn’t any headroom in the utility’s systems, according to Aaron Rodehorst, manager of term trading at PGE. 

“We’re fully using our pipelines. We’re fully using our transmission systems,” Rodehorst said. “There’s a high degree of need for coordination.” 

Rodehorst said he works closely with balancing authority staff “to make sure they know everything I know that they can then also be coordinating with their peers.” 

“I’ve been building a contingency plan at Portland General Electric for four or five years now, and every year it gets better, and it gets better also when I start to share it more broadly and get to think about what pieces I’m not putting into that plan,” he noted. 

‘No More Wiggle Room’

Carolyn Ebner, commercial services lead at Williams, said, “our system is fully subscribed.” 

Williams owns the nearly 4,000-mile bi-directional Northwest Pipeline. The pipeline crosses Washington, Oregon, Idaho, Wyoming, Utah and Colorado, according to the company’s website. 

“We have no more wiggle room,” Ebner said. “And Northwest Pipeline is not unique.” 

Ebner said the company will continue to have conversations with the electric sector, “both confidential and in these group platforms, [and] we’re going to continue to prepare options for growth and additional storage on our gas system.” 

Meanwhile, in Arizona, APS had a peak demand of about 8,500 MW in 2025, but the utility predicts peak demand will reach 13,000 MW by 2038, said Jason Hartzell, manager of fuels and contracts at APS. 

APS has had “positive” discussions with Arizona’s commissioners and has gained support for natural gas expansion through public forums facilitated through APS, Hartzell noted.  

To keep up with customer demand, APS has signed an agreement with Energy Transfer Partners to build a new pipeline from the Permian Basin to Arizona to support new gas-fired power plants, he added. 

“We would be one of the shippers of that pipeline,” Hartzell said. “So, we’re only one of the Arizona utilities that has seen this additional need for natural gas.” 

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BOEM Plans to Vacate New England Wind Project Approval

The Trump administration is moving to close the door on U.S. offshore wind development by remanding approvals for all projects not already under construction.

Federal attorneys filed a motion in the U.S. District Court for D.C. on Sept. 3 saying the U.S. Bureau of Ocean Energy Management plans to vacate the permit it issued to New England Wind during the Biden administration.

In late August, federal attorneys made similar comments about the SouthCoast Wind project off the New England coast, as well as about US Wind’s plans off the Maryland coast. And in March, EPA put a hold on an air permit for Atlantic Shores, at least temporarily blocking the New Jersey project from any start of construction.

Those four projects were the late movers among the 11 approved during the Biden administration. One of the 11 is completed; one was canceled by the developer; and five are in some stage of construction.

Numerous plans at earlier stages of development are on indefinite hold amid the clampdown President Donald Trump has ordered on the offshore wind sector, because of the restrictions themselves or from investors being driven away by the heightened risk and uncertainty that has resulted.

The recent motions were filed in three cases where wind power opponents had sued various federal agencies challenging regulatory approvals that allowed the three projects to move forward. In separate motions, Department of Justice attorneys asked the courts to delay the cases because the federal government is going to do essentially what the plaintiffs were seeking.

Federal attorneys said the government is planning to remand and vacate BOEM’s approval of the construction and operations plan for the Maryland offshore wind projects no later than Sept. 12 (24-cv-03111); move for voluntary remand of the SouthCoast approval by Sept. 18 (1:25-cv-00906); and remand and vacate New England Wind’s approval (1:25-cv-01678) no later than Oct. 10. The EPA action against Atlantic Shores on March 14 was a voluntary remand. (See EPA Puts Hold on Atlantic Shores OSW Permit.)

With Trump’s flat rejection of wind power, it is questionable when or if the approvals would be reinstated once remanded.

In the most recent New England offshore wind solicitation, SouthCoast and New England Wind were selected to feed 1,868 MW to Massachusetts and 200 MW to Rhode Island. (See New England OSW Contracts Delayed Again.)

Coupled with the BOEM’s stop-work order on Revolution Wind — an 80% complete project that would send 704 MW to Connecticut and Rhode Island — the pending actions represent a clear threat to New England’s clean energy ambitions.

“New England needs this energy,” Gov. Maura Healey (D) said Sept. 3. “Having already undergone years of expert review, these projects are primed to lower costs and improve reliability. There is absolutely no need for the Trump administration to reopen permitting processes and deny jobs, investment and energy to the states.”

ISO-NE had warned Aug. 25 that delaying Revolution Wind would increase reliability risks for the New England grid. (See ISO-NE Warns Halting Revolution Wind Boosts Reliability Risk.) On Sept. 3, it pointed to remarks by CEO Gordon van Welie about the importance the offshore wind sector holds for the region.

“The region is counting on the entry of resources in the form of large quantities of offshore wind to maintain resource adequacy,” van Welie commented to FERC in May (AD25-7). Solar panels and short-duration battery storage, he added, would not be an adequate replacement for the giant marine turbines.

Nick Krakoff, a senior attorney with the Conservation Law Foundation, told NetZero Insider that remanding and vacating the construction and operations plans for SouthCoast and New England Wind is a move that can be challenged in court by the developers and or the states involved, but the concept of victory is not clear-cut.

“There’s certainly legal avenues,” he said. “I think the bigger question is, what happens to industry? The Trump administration is just actually sabotaging an entire industry.”

Trump’s strategy has proved quite viable so far: Multiple offshore wind development efforts have been placed on hold since his election, Atlantic Shores among them. (See Developer Shelves Atlantic Shores, Seeks to Cancel ORECs.)

Those that remain face a regulatory limbo as the administration floods the zone with new hurdles and limitations. Projects that are under active construction can incur huge cost overruns because of delays.

All of this creates an untenable business environment.

“The longer this drags out, the more difficult it becomes for the developers financially,” Krakoff said. “I think it’s just another example of this administration’s disdain for the rule of law.”

The systematic attempt to kill an entire industry is unprecedented, he added. “You kind of expect this in other countries, but not this country.”

Trade group Oceantic Network criticized the administration’s stated intention to remand and vacate permits that were issued after years of review. “The unlawful and escalating actions by the Trump administration against fully permitted offshore wind projects up and down the East Coast represent one of the largest, economically devastating assaults on U.S. workers, businesses and energy in generations,” it said.

“Halting construction and revoking permits on approved projects after years of thorough agency review will raise electricity prices for millions across the country, jeopardize billions of dollars in private investment, threaten our national shipbuilding, steel and manufacturing supply chains, and undermine our nation’s energy security.”

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ACP Reports Shrinking Pipeline of Projects as Feds Turn Hostile

Developers installed more than 11 GW of new utility scale solar, storage and wind worth $15.2 billion in the second quarter, but signs point to abrupt decline in renewable development, the American Clean Power Association said Sept. 3. 

While those overall numbers were in line with last year, the clean power pipeline showed virtually no growth (adding less than 100 MW to an existing pipeline of 184.5 GW), solar installations declined 23% during the first half of 2025 and power purchase agreements plummeted, which are early indicators of federal policy attacks and fluctuating trade policies, according to ACP’s Clean Power Quarterly Market Report. 

“America’s clean energy industry continues to add much needed power to the grid. Unfortunately, federal policy obstacles and restrictive mandates are threatening hundreds of billions in planned energy investment,” ACP  CEO Jason Grumet said in a statement.  

“The uncertainty created by new bureaucratic delays and unclear demands is having a chilling effect on the pipeline for future energy projects, stalling growth precisely when our nation needs more energy to power a growing economy,” he said. 

Policy actions from nearly every federal department and an unstable regime of tariffs have led to a drop in clean power purchasing, despite skyrocketing demand across the country. PPA contracting fell 32% in the first half of 2025 compared to 2024, battery storage PPA announcements fell 88% from the first quarter to the second, and wind announcements were down 93% on the quarter. 

A graph from the report showing the leading states by clean energy capacity additions for the second quarter of 2025. | ACP

Corporate wind and solar PPA prices were up 6% quarter-over-quarter, and 8% on the year, which reflects instability in the purchasing environment. The pace of procurements slowed in the second quarter as developers and buyers waited for clarity on tax credits and attempted to budget with shifting trade agreements. 

While solar installations were down 23%, overall numbers of deployed projects were fairly level with 2024 installations, as storage deployments were up 63% to 6,510 MW and wind deployments were up slightly by 12%. 

Arizona became the third state to reach 10 GW of nameplate clean energy, as it added 1,220 MW of new solar and 1,369 MW of new storage. 

Texas has the most installed capacity and largest pipeline, and it edged out Arizona for additions in the quarter, while California took third place for quarterly additions. Eight of the top 10 states for deployments in the second quarter voted for President Donald Trump in last year’s election. 

Overall, the country has installed more than 330 GW of clean power as of June 30, 2025, which is enough to power more than 81 million homes. 

Developers reported that 83,403 MW of renewable capacity was under construction as of midyear, which includes 580 projects. Construction activity was highest in Texas at 21 GW, followed by Arizona at 7.8 GW, California at 7.2 GW, New Mexico at 4.8 GW and Wyoming at 4.1 GW. 

Solar makes up just over half the national project pipeline, with 96 GW under construction or in advanced development. Storage took second place from land-based wind during the first quarter of 2023 and, along with solar, it has driven the growing pipeline of projects, with the backlogs growing by 32 GW and 22 GW, respectively, since the second quarter of 2022. 

“Clean energy is the fastest-to-deploy energy resource. With demand for electricity at historic highs, Americans cannot afford policies that limit power production and raise household electricity bills,” Grumet said. “The U.S. must support all forms of energy.” 

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WEIM Emissions Attribution Rules Apply to EDAM, Wash. Agency Clarifies

Washington’s Ecology Department has clarified that state cap-and-invest rules that apply to CAISO’s Western Energy Imbalance Market also will cover the ISO’s Extended Day-Ahead Market (EDAM) when it begins operations in 2026.

An agency guidance document released Sept. 3 explains how the cap-and-invest program attributes an appropriate volume of greenhouse gas emissions to energy imported into Washington via a centralized electricity market (CEM). The WEIM is the only centralized market operating in the West, with SPP’s Markets+ expected to go live in 2027.

The GHG attribution process is complicated by the difficulty of pinpointing exactly what resource in a centralized market produced the energy imported into the state to meet a market participant’s demand.

Under existing rules, energy transferred into Washington via the WEIM is classified as an “unspecified import” and assigned a default emissions factor of 0.428 MT CO2e/MWh. The rules require that the Washington-based load-serving entity or market participant receiving the import be responsible for reporting the emissions to the Ecology Department.

But a 2024 law (SB 6058) prompted Ecology last December to adopt a new framework that will allow the agency to trace the origin and emissions factor of CEM energy transfers into Washington — transfers that will be categorized as “specified imports” with specific associated emissions rates.

To do that, the new framework calls for centralized market operators such as CAISO and SPP to establish a system for identifying a “deemed market importer” for transfers into Washington, defined as “the market participant that successfully offers electricity from a resource or system into a CEM, which then is “attributed to Washington by the methods put in place by the market operator of that CEM.” The deemed market importer also will be the entity responsible for reporting emissions to the agency.

The Sept. 3 guidance notes that existing reporting rules will remain in place through 2026, but it advises market operators to put a “specified imports” system in place by Jan. 1, 2027.

It also clarifies that although the rules were written with the real-time WEIM in mind, they also apply to EDAM.

“Ecology notes that all optimization of electricity supply from market resources and attribution of imported electricity to Washington through the day-ahead market, EDAM, ultimately occurs in real-time, within the WEIM,” the agency wrote. “For this reason, Ecology clarifies that provisions applicable to the ‘energy imbalance market’ within WAC 173-441-124(3)(v), apply equally to entities participating in WEIM and EDAM.”

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Report: Big Beautiful Bill to Increase Power Prices in NYISO, PJM

A new analysis of the One Big Beautiful Bill Act from Aurora Energy Research found that the bill likelywill increase wholesale power prices in NYISO and PJM by up to $8/MWh, driven by reductions in renewable energy development and increases in fossil fuel plant operation. 

“When you cut off some of the capacity that was going to come through as a result of faster buildout of things like offshore wind, you get a lot of baseload gas moving in to fill in the gap, and that has a significant longer-term impact on prices,” said John Kidenda, a researcher for Aurora. 

Kidenda estimates PJM will experience a $6 to $8/MWh price increase by 2035. NYISO is estimated to increase by $5 to $7/MWh in the same time frame. 

The end of tax credits coupled with deployment hurdles and tariffs likely will cause PJM and NYISO to have 10% fewer renewable resources by 2040 compared to Aurora’s base case. Roughly 10 to 15 GW of renewables are at risk of missing the new in-service deadline for tax credits across both grid operators. This will force them to rely on thermal plants more often, resulting in 5 to 7% more runtime.  

A separate analysis of the clean energy and transportation sectors under the OBBBA by Rhodium Group and MIT illustrated the challenges that renewable energy development faces nationwide. New utility-scale clean energy projects declined 51% between the first and second quarters of this year. New industrial decarbonization developments declined 17% in the same period and 38% year-to-year. 

The Rhodium/MIT group also examined the outstanding projects receiving Inflation Reduction Act credits. Roughly $517 billion of outstanding investment remains to be spent on construction and installation; $406 billion of that is tied to electricity and industrial investment, and 42% is tied to wind and solar generation projects.  

The findings of both reports point to large nationwide pressures on renewables to get to market and qualify for tax credits, a far cry from Aurora’s stance late in 2024, when it said the projected impact of a second Donald Trump presidency on New York’s grid were “minimal.” The assumption was that, despite Trump’s promise of ending the IRA’s tax credits, congressional Republicans would be unwilling to pass legislation repealing them because they benefited their districts. (See NY Well Positioned to Push Forward on Climate Goals Under Trump.) 

That assumption — like that of President Joe Biden and congressional Democrats when the IRA was enacted in 2022 — turned out to be very wrong. 

Kidenda said that despite Trump’s desire to keep natural gas prices down and increase gas generation, the long waits for new turbines coupled with increased demand mean there is significant upward pressure on gas prices. 

“As that tightness comes through and you get demand from heating, then you get price increases,” Kidenda said. “Not because baseline gas prices are increasing but because people are bidding up the right to access the pipeline.” 

Kidenda said it was critical for New York to ensure that renewable projects like Sunrise Wind are finished. The state runs the risk of blackouts and loss of load without added capacity, particularly in New York City and Long Island, he said. 

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Ontario Energy Board Plans 22% Spending Increase

The Ontario Energy Board (OEB) plans a 22% increase in its 2025/26 budget with the addition of 32 employees, its biggest hiring surge in at least five years.

The board cited “the increased volume and complexity” of its job in announcing the hirings, which would increase OEB’s staff by 14% to 260 full-time equivalents.

“We are building an organization that can enable government policy and be the regulator Ontario needs during the energy transition,” OEB said in its Business Plan for 2025/26 through 2027/28, which outlines $70.3 million in spending for the current fiscal year (beginning April 1) and preliminary budgets for the following two years.

The board said the $12.5 million budget increase was needed to respond to the Ministry of Energy and Mines’ 2024 vision statement and the ministry’s Dec. 19, 2024, Letter of Direction, which outlined the province’s strategy for responding to an expected 75% increase in electric demand by 2050.

“These additional resources will enable the OEB to deliver on its mandate, which, when coupled with the minister’s letter, requires taking on additional deliverables at a time when the organization is at full capacity with existing commitments and adjudicative work,” the board said.

“Resources will be applied across the organization to meet the highest-priority needs at any point in time, balancing adjudicative support and policy development, and matrixing resources depending on expertise, topic and timeline,” it added.

Three initiatives each will receive six new FTEs:

    • Advancing the Energy Transition: ensuring regulated entities plan across fuel types; considering how to apply the “beneficiary pays” principle; and streamlining approvals for electric connections and “priority” pipeline projects.
    • Driving System Modernization: developing local market opportunities for distributed energy resources, such as distribution system operators; implementing performance-based rate regulation for electric distribution companies; supporting Indigenous participation; and ensuring cost-effective integration of innovative business models.
    • Sustaining Resources: adding legal, public affairs, finance and human resources staff to support OEB’s expanded operational requirements and strategic priorities. OEB said those functions “have not kept pace with recent growth across the organization.”

The board plans five new staffers to boost DERs, including providing incentives for implementing non-wires solutions, publishing capacity maps for distribution and transmission systems, and reducing barriers for new energy efficiency programs.

The Ontario Energy Board plans to hire 32 new employees in 2025/26, the biggest contributor to a 22% budget increase for the year. | Ontario Energy Board

In total, the salaries and benefits budget is increasing by 19% to $50.4 million.

Because they will have staggered start dates, the 32 new hires will cost $4.15 million in 2025/26 and $6.2 million annually thereafter.

The budget also includes $1.8 million for salary increases for existing staff and $1.2 million for short-term contract staff needed to “backfill” for subject-matter experts shifted under the Business Operations Optimization and Systems Transformation (BOOST), a new platform for data and workflow management across OEB processes.

The plan pointedly reiterates the board’s belief that “diversity, equity and inclusion (DEI) is not just an ideal but also our competitive business advantage, a defining characteristic of our culture and an essential organizational strategy.”

The new hires will allow OEB to “provide strategic and prudent oversight of Ontario’s energy sector through initiatives that support broader government priorities such as planning for growth, keeping costs down, enabling energy system modernization and streamlining solutions that will make Ontario an energy superpower,” the board said.

Impact of Integrated Energy Plan?

Roy Hrab, senior manager for policy research at Power Advisory, noted on LinkedIn that OEB’s plan was completed before the release of Ontario’s Integrated Energy Plan (IEP) in June “and the accompanying (quite prescriptive) implementation directive to the OEB.” (See Ontario Energy Plan Gives IESO Long ‘To Do’ List and Ontario Integrated Energy Plan Boosts Gas, Nukes.)

“How the OEB’s planned key projects presented in the plan have changed and will be prioritized post-IEP (and directive) remain to be seen,” he added.

The big spending increase caught the attention of Martin Benum, former director of regulatory affairs for London Hydro.

“The OEB is supposed to regulate industry costs, not grow into another bloated cost-recovery machine itself,” Benum said in response to Hrab’s posting. “Is the OEB still focused on consumer protection and efficiency, or are we watching another cost monster take shape here in Ontario?”

Capital Spending Trending Down

While the board is increasing spending on personnel, it expects capital spending (business systems, infrastructure and end-user computing) to drop slightly, from $474,000 in 2025/26 to $451,000 in 2027/28.

“With more resources available as services, the OEB’s IT capital budget is expected to be stable in the coming period with some spending moving to the IT operating budget,” it explained.

Priorities

The board’s priorities for the coming year include simplifying the connection processes for DERs, incentivizing electric distribution companies to use third-party DERs as non-wires alternatives and a benefit-cost analysis framework for addressing system needs.

OEB also is considering changes to its rate design to accommodate electric vehicles and battery storage, following up on its analysis of the impact of delivery costs on EV charging facilities. “The OEB is also planning to consider reforms to rate design for resources providing grid services and other emerging technologies,” it added.

Also on the schedule for the board is a ruling on Enbridge’s 2026-2030 electric demand-side management application, which includes a residential program that would be delivered through a “one-window” approach in conjunction with IESO. OEB said it expects to rule on the case this fall.

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ERCOT Fills out Board with 2 Final Selections

ERCOT’s board selection committee has chosen two new independent directors, restoring the Board of Directors’ full complement of seats after several departures earlier in 2025.

The grid operator said Houston’s Christopher Krummel and Austin’s Kathleen McAllister will fill the remaining vacancies on the 12-person board. The selections were announced and became effective Sept. 3.

Christopher Krummel | Centuri Holdings

Krummel has more than 30 years of financial executive experience in the energy and construction industries. He is a founding partner of Krummel, Ellis & Weekley Advisory, which provides sell-side transaction advisory services to energy focused clients, and previously served as McDermott International’s CFO.

He has a bachelor’s degree in business administration from Creighton University and a master’s in business administration from The Wharton School of the University of Pennsylvania.

McAllister has more than 15 years of experience in corporate governance as a CEO, CFO and board director. She currently serves on the boards for Black Hills Corp. and Höegh LNG Partners after spending years in executive roles with offshore driller contractor Transocean Partners.

Kathleen McAllister | NACD

McAllister holds a bachelor’s degree in accounting from the University of Houston and is a certified public accountant.

Board Chair Bill Flores welcomed the newest members to the board, saying in a press release, “Their background, knowledge and expertise will continue to support ERCOT’s strategic objectives of maintaining a dynamic, reliable and resilient electric grid.”

Two independent directors resigned from the board earlier in 2025 to pursue “new opportunities” in the ERCOT market. That left the 12-person board three short of full membership. Industry insider Bill Mohl was selected in July to fill one of the vacancies. (See ERCOT Adds Industry Vet to Board of Directors.)

The ERCOT board is subject to oversight by the Public Utility Commission and the Texas Legislature. By law, all board members must be Texas residents.

The board’s selection committee was created by state law in 2021. It is composed of three appointed members, with the governor, lieutenant governor and the speaker of the Texas House of Representatives each selecting a representative.

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CPUC Approves Guidelines for Large IOUs’ Dynamic Rate Designs

The California Public Utilities Commission (CPUC) has approved guidelines for utilities to use to design dynamic electricity rates, with one commissioner asking for more research on whether implementing such rates will leave some customers further behind financially.

The decision applies to Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric, which must propose dynamic rates in their general rate cases for approval by the CPUC.

And it comes just weeks after publicly owned utilities Sacramento Municipal Utility District and the Los Angeles Department of Water and Power outlined their challenges with implementing the practice in reports submitted with the California Energy Commission. (See Calif. Utilities Move Cautiously on Dynamic Pricing.) The dynamic rate design idea comes from the CEC’s load-management standards.

“This is an exciting proposed decision and it really marks another step … to support California’s long-term goals: grid reliability, electrification and affordability,” CPUC President Alice Reynolds said at the commission’s Aug. 28 voting meeting, during which the decision was approved.

Reynolds said the decision addresses key demand flexibility — or dynamic rate — design elements: marginal energy costs based on CAISO’s hourly load; day-ahead prices at default load aggregation points; marginal generation capacity costs; marginal distribution capacity costs; marginal transmission costs; non-marginal costs; and line-loss factors.

“Demand flexibility is one of the most important things we are doing as a state and will help provide additional resources that we can use,” Commissioner Darcie Houck said at the meeting. “I know a lot of time, effort and thought has gone into this decision.”

The goal of dynamic rates is to “motivate customers to shift electricity consumption away from high-demand periods, when polluting, peaking plants run and electricity is most expensive,” Commissioner John Reynolds added at the meeting. “Dynamic rates promise to achieve this by providing accurate price signals that reflect actual grid consumptions.”

However, as California moves from the approved guidelines to implementing these new rates, it is important to evaluate their effect on different types of customers, he said.

It may prove true that factors like income, whether a customer owns their home, or a customer’s climate zone could “substantially impact their ability to shift energy usage to lower-cost hours,” he said.

“We should evaluate these rate design changes to understand these consequences,” he said. “This is an equity concern that I think we need to attend to.”

In the decision, the commission said community choice aggregators (CCAs) should be able to either design their own dynamic rate or use their associated IOU’s dynamic rate. IOUs should describe how they will collaborate with CCAs on dynamic rates and programs, the commission said.

Marginal vs. Fixed Costs

In the decision, the commission said IOUs’ dynamic rates must include a marginal generation capacity cost (MGCC), which is the cost to procure and maintain sufficient generation capacity to reliably serve an incremental unit of electric demand at all times, including during peak demand and ramping periods.

The MGCC price “must account for costs associated with both peak and flexible capacity needs during periods of grid stress,” the commission wrote. An IOU’s proposal must include a price component that recovers an IOU’s MGCC revenues “to ensure that generation capacity costs are appropriately reflected in DF rates.”

“I expect the marginal costs on our grid to be much lower than our current electric retail rates,” John Reynolds said at the meeting.

The reason for that is that California’s electric system has many fixed costs, he said.

“For example, using more electricity does not really change the amount of money needed to trim vegetation to reduce wildfire risk,” he said.

Historically, the state recovers these fixed costs in the electricity rate, making that rate higher than the marginal costs of energy.

However, the modest fixed charge that the state already adopted still “does not fully cover our fixed costs of the system,” John Reynolds said.

“There will be debate about which costs are actually marginal and which are fixed, and that’s healthy, and we will need policy decisions resolving that debate,” he said.

“As we make policy decisions evaluating the nature of marginal costs, I expect that truly reflecting marginal costs in hourly prices will be lower rates and higher fixed charges,” he added. “These will be revenue neutral … and should actually lead to a lower overall cost grid.”

But fully moving to hourly marginal pricing will mean customers who can shift their usage will “have greater opportunities for bill savings than customers with inefficient appliances and leaking homes that don’t stay cool on hot days,” he said.

The large IOUs should use CAISO’s locational marginal prices at default load aggregation points in CAISO’s day-ahead market, CPUC staff said in the decision. This approach provides customers with a degree of rate certainty because electricity prices in the day-ahead market at default load aggregation point prices represent a majority of load-serving entities’ actual energy purchase costs, staff said.