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December 14, 2025

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Calif. Officials Probe Utilities on Wildfire Safety Measures

California officials asked Southern California Edison to show humility in its approach to the January wildfires in Los Angeles and probed Pacific Gas and Electric about its safety culture after the utility’s 2019 bankruptcy during an interagency briefing hosted by the California Public Utilities Commission on Aug. 19.

SCE, PG&E, Bear Valley Electric Service, San Diego Gas & Electric, Pacific Power and Liberty Utilities briefed California officials on their wildfire safety procedures and mitigation work.

SCE independent board member Tim O’Toole opened the company’s presentation by discussing the deadly L.A. fires that ravaged the city in January. He called them “an awful catastrophe,” stating that SCE is focused on supporting impacted communities.

“Nonetheless, we remain very proud and confident in the progress we’ve made in all the areas we’re going to review with you today,” O’Toole added. “And I wouldn’t want that pride and that confidence to be misunderstood or mischaracterized as insensitive or that there’s some denial of reality.”

O’Toole noted also that the cause of the fire is unknown, adding, “what we do have knowledge of, and are confident in, is that our unmatched hardening of our grid and the other mitigation measures we’ve implemented have created ever greater protection for our communities and our customers.”

Among the steps SCE has taken are installing more than 6,610 miles of covered conductor and over 1,870 weather stations, 48 miles of undergrounding since 2021 and increased inspections in high fire-risk areas, according to SCE’s presentation.

Caroline Thomas Jacobs, director of the Office of Energy Infrastructure Safety at the California Natural Resources Agency, acknowledged the cause of the L.A. fires is still unknown but sought more humility from SCE.

Addressing O’Toole, Thomas Jacobs said, “Your tone sounded defensive and justifying the progress that’s made as opposed to acknowledging the humility of what an event like the January fires I would think would bring … to the board.”

Thomas Jacobs added that “hopefully all of us are learning lessons from the January fires, including our organization, on how we look at the wildfire mitigation plans. We need to … bring a humility to those events and a level of curiosity and openness to create the opportunity for us to all move forward and learn from it.”

O’Toole responded he is proud of his team but also wanted to acknowledge the pain the fires have caused.

“I just feel like I didn’t articulate it well enough, but I certainly believe that what you said is the appropriate sentiment,” O’Toole said.

Of the L.A. fires, the Eaton Fire and the Palisades Fire were the two most destructive. The L.A. County Fire Department and the California Department of Forestry and Fire Protection are still investigating the cause of the Eaton fire, but videos of the fire’s early stages suggest a possible link to SCE’s equipment, SCE representatives said in February. (See SCE Probes Link Between Equipment and Eaton Fire.)

On July 23, SCE announced a new wildfire recovery compensation program for victims of the Eaton Fire. The program is expected to operate through 2026, a company press release said.

‘Totally Different Place’

Also participating in the Aug. 19 meeting were representatives from PG&E. Similar to SCE, the company has focused on undergrounding, installing more weather stations and cameras, and other grid hardening efforts to mitigate wildfire risk.

The company received blame for a series of California wildfires starting in 2015. The fires included the 2018 Camp Fire, which leveled the town of Paradise, killed 84 people and drove PG&E to file for bankruptcy reorganization in January 2019.

Cheryl Campbell, chair of PG&E’s Board of Directors and Safety and Nuclear Oversight Committee, said the company is in a “totally different place” compared with 2019.

Campbell noted that with the hiring of Patti Poppe as chief executive officer in 2021, PG&E has made “tremendous progress.” She highlighted reductions in workforce fatalities and improvements in public safety power shutoffs.

PG&E has also reduced the unit cost for undergrounding. In 2019, the unit cost exceeded $4 million/mile. The average unit cost between 2023 and 2024 was $3.1 million, according to the utility’s presentation.

Sumeet Singh, executive vice president of operations and chief operating officer at PG&E, said the company sees opportunities to further reduce undergrounding costs by, for example, improving construction methods and entering cost-effective contracts with third parties. There are also regulatory efforts to improve undergrounding, Singh noted. (See Newsom Issues Order to Speed Undergrounding of Lines in Los Angeles.)

“We absolutely see opportunities to continue to improve upon the $3.1 million a mile that we’re currently averaging on the underground side, and our intent is to get to that glide path of $2.6 or below over the next several years,” Singh said.

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Former Journalist Helping to Build Domestic Solar Supply Chain

What does a journalist, two-time Pulitzer Prize finalist and author of two books do after three decades writing for respected publications like the Wall Street Journal and Texas Monthly?

If you’re Russell Gold, you leave your career as an energy reporter to join a company manufacturing solar technology and building an integrated domestic supply chain for solar and batteries.

Back in the 1970s and 1980s, when Woodward and Bernstein’s “All the President’s Men” was required reading for aspiring journalists, fellow ink-stained wretches of the Fourth Estate might have said Gold was leaving for the “dark side” of public relations. He says he simply is seeking a new direction in life.

“I was looking for a change of scenery. Like many people getting into their early 50s, I wondered what other challenges there might be,” Gold said.

He has found his challenge: helping build an American supply chain that creates jobs and an abundance of energy. “In this day and age, it’s a great challenge and one I eagerly signed up for,” he said.

In May, Gold joined T1 Energy as executive vice president of strategic communications. The company lauded him as a “respected leader and prominent voice” in the solar industry.

“The challenge of our time is to build a domestic, affordable and renewable energy system, and T1 is at the forefront of that effort,” Gold said at the time.

Previously known as Freyr Battery, the company rebranded itself as T1 Energy in February and relocated to Austin, Texas. The company last year acquired the U.S. assets of a Chinese company, Trina Solar, which included a 5-GW solar panel manufacturing facility near Dallas. Texas Gov. Greg Abbott (R) mentioned T1’s Dallas factory while celebrating the state’s 12th Gold Shovel Award for achievement in job creation and capital investment.

Gold said the facility, G1 Dallas, employs 1,000 people. T1 plans to start construction on another facility in Rockdale, east of Austin. The $850 million G2 Austin factory is expected to be one of the largest solar manufacturing facilities in the U.S. and will create 1,800 new direct advanced manufacturing jobs, T1 says.

“It’s jobs, but it’s also advanced manufacturing,” Gold said, referring to G1 Dallas. “If you go to the factory, you’ll see a mix of people and robots and AI working together to drive down the cost of panels.”

According to English think tank Ember, the cost of solar power combined with batteries dropped 22% in 2024 alone, and 43% since 2019. That’s no surprise to Gold.

“The cost of solar is always coming down,” he said. “Right now, there’s no question that solar is among the most cost-competitive energy source available at scale.”

T1 CEO Daniel Barcelo says more than 80% of new electric capacity in the U.S. in 2024 came from solar and battery technology. The company has stayed ahead of the curve, weaning itself off Chinese products when it saw they would be cut off from U.S. tax credits.

Gold said T1’s “mantra really is our mission:” building domestic solar and battery supply chains to invigorate America with scalable, reliable and low-cost energy.

“We feel it’s really important for jobs and energy security that those solar panels be made from a supply chain in the U.S.,” Gold said. “We want to provide a lot of energy. We want it to be affordable, and we want to make sure that no one around the world can cut off our supply chain.”

Asked how a supply chain is built, Gold said there are four steps to making solar panels. Start with polysilicon, which T1 sources out of Michigan. The polysilicon is turned into wafers and wafers are turned into cells. Cells are made into solar panels. Gold said cells will be made at G2 and the company is “actively” investigating how to produce wafers in the U.S.

Glass, glue, weather-stripping, other petroleum products and aluminum all go into the final product: solar panels.

“So, we’re looking for and building suppliers into a supply chain that’s all domestic and not imported,” Gold said.

T1 may have completed that task. It said Aug. 15 it has reached an agreement with glass maker Corning to source wafers beginning in the second half of 2026. The deal expands on an existing supply contract for solar-grade polysilicon and establishes a domestic solar supply chain connecting polysilicon, wafers, cells and panels.

The wafers will be used at G2 Austin when it is up and running. The cells will be assembled in G1 Dallas, the companies said.

“We’re really a poster child that it’s difficult, but it can be done. We just need to put in the work,” Gold said. “It’s exciting to be part of a broader trend toward creating an emerging solar industry.”

Gold graduated from Columbia University in 1991 with a degree in history and soon landed a job as a suburban correspondent for the Philadelphia Inquirer. He transitioned into investigative journalism with a focus on energy, first for the San Antonio Express-News and then for the Wall Street Journal. Gold joined Texas Monthly in 2021, just in time to cover the aftermath of Winter Storm Uri after it almost brought the ERCOT grid to its knees.

Russell Gold (right, with Grid United’s Michael Skelly) | © RTO Insider 

His coverage of the Deepwater Horizon disaster and Pacific Gas and Electric’s Camp Fire has earned him numerous awards and honors, including the Gerald Loeb Award for business and financial journalism twice. Gold’s books include “The Boom,” a history of fracking, and “Superpower,” about Grid United CEO Michael Skelly’s quest to build an HVDC line to ship wind energy to urban centers. (See Book on Tx Developer Transmits Climate Hope.)

Now, he’s part of the story, helping explain the importance of solar energy in helping meet the growing demand from AI and data centers.

“For the next six or seven years, we’re going to need an abundance of energy, whether it’s coming from new gas or new nuclear or new geothermal or predominantly coming from two sources: solar and any existing gas projects,” Gold said. “But let’s not fool ourselves. If we want our economy to grow and remain affordable and we want to avoid 1970s energy prices, we will need solar over the next few years.”

The budget reconciliation bill that passed Congress in July sunsets the clean energy sector’s production and investment tax credits and poses a significant threat to wind and solar power development, industry observers said. The bill boosts thermal projects, but a backlog for gas turbines extends into next decade. (See Senate Passes Trump’s Big Bill that Slashes Clean Energy Tax Credits.)

According to pv magazine, nearly $8 billion in U.S clean energy investment and 16 large-scale factories were canceled during the first three months of 2025. Gold noted that the production manufacturing credit was left untouched, saying, “That’s our primary tax credit.”

“I think it remains to be seen what impact that will have on solar growth in the United States, for a number of factors,” he said. “First of all, the production tax credit isn’t going away immediately. Demand for energy is insatiable, and we need to keep growing … to have an abundance of energy. So, we feel very strongly that solar and storage are absolutely critical parts of our energy growth and will continue to be.”

The industry did get a small boost when the U.S. Treasury Department released new rules on new wind and solar construction qualifying for tax credits. While the rules removed a 5% safe harbor provision, they were not as stringent as originally feared. (See IRS Guidance on Wind and Solar Credits Not as Bad as Feared.)

Gold said that based on T1’s initial review of the Treasury rules, “We believe there will be a good pipeline of demand for our modules. We’ve already seen, and are continuing to seek, strong demand in ’25 and ’26.”

“This is an incredibly challenging opportunity, but also incredibly important one to build an American solar champion,” he said. “That’s what we’re really trying to do.”

Domestic solar, he added, “will create jobs and affordable energy.”

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New England TOs Add 39 New Projects to Asset Condition Forecast

New England transmission owners (TOs) have added 39 new projects in the annual update to the region’s asset condition forecast, the companies told the ISO-NE Planning Advisory Committee (PAC) on Aug. 20.  

The TOs categorized the projects as either “under development” or “under evaluation.” The projects do not yet have cost projections, but most have estimated cost ranges. The TOs forecast 23 projects to cost less than $10 million, nine to cost between $10 million and $25 million, two to cost between $25 million and $100 million, and one to cost more than $100 million. 

Growing costs associated with asset condition projects have been a major focus of New England states and consumer advocates in recent years. While investor-owned transmission companies have insisted the high costs are necessary to maintain the region’s aging grid, states have expressed concern that a lack of oversight and transparency on spending has contributed to higher costs.  

According to a June update provided by the TOs, the total estimated cost of in-progress asset condition projects with official price projections is about $5.9 billion. This does not include forecast projects that have only projected cost ranges. (See New England Transmission Owners Add $95M to Asset Condition List.) 

Earlier in the summer, ISO-NE agreed to take on a non-regulatory “asset condition reviewer” role to help increase transparency into projects. (See ISO-NE Open to Asset Condition Review Role amid Rising Costs.) The RTO said in late June it will need about 18 months to develop internal review capabilities but said it plans to hire a consultant to help review the most significant asset condition projects in the interim. (See NEPOOL PC Briefs: June 24-26, 2025.) 

The TOs also have implemented new guidelines around PAC presentations in recent years intended to standardize the presentation format and increase transparency. But PAC presentations remain strictly advisory, and the committee does not have any regulatory authority. 

Project Presentations

At the PAC meeting, Chris Soderman of Eversource Energy presented an $18 million asset condition project to replace deteriorating wooden structures with steel structures, reinforce overstressed wood structures, and replace Copperweld shield wire with optical ground wire (OPGW) on a 115-kV line in Connecticut. 

Soderman said the project would cost about $1.8 million less if the company replaced the shield wire with Alumoweld Static Wire but installing OPGW also would address telecommunication needs. 

He also noted that the ISO-NE 2050 Transmission study indicates the line would be overloaded in a 51-GW winter peak scenario and that the upgrades are “setting ourselves up so that when we do look at a reconductor in the future, these structures will be able to handle that.” 

Carol Burke of Eversource presented an update to a substation upgrade project in southern New Hampshire. The project originally was presented to the PAC in 2022 with an estimated cost of about $20 million. Burke said this estimate has increased to $35 million due to an expanded project scope, delayed construction and increased material costs.  

Lastly, Kyra Lagunilla of Rhode Island Energy presented a $15 million project to replace wooden poles with steel structures and install OPGW and lightning protection on three 115-kV lines. She said the added lightning protection is necessary because the lines do not meet the company’s lightning performance standards and lightning has triggered two long-duration outages on the lines since 2011. 

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U.S. Could Gain 33 GW of Solar, 18 GW of Storage in 2025

The United States is on track for a record increase in power generation capacity in 2025, the U.S. Energy Information Administration reports. 

The EIA said Aug. 20 that developers reported plans for 64 GW of new generation this year, which would surpass the current record — 58 GW — set in 2002. 

A key difference is that the 2002 total included 57 GW of natural gas-fired generation, while only 4.7 GW of gas generation is expected to come online in 2025. 

Instead, the majority of new capacity this year will involve the sun: EIA predicts 33.3 GW of new photovoltaic solar generation. 

Solar’s benefits to the planet notwithstanding, its capacity factor is much lower than gas-fired generation’s. But EIA reports 18.3 GW of battery storage capacity is expected to be commissioned in 2025, which will help smooth out the peaks and dips in solar generation. That would be a whopping 76% increase over the 10.4 GW of storage installed in 2024. 

Storage is not generation, but it is classified as a secondary source of electricity, so EIA includes it in its roundups of generation statistics. 

Rounding out the 2025 picture, EIA predicts 7.8 GW of wind generation being added to the grid this year. 

EIA’s solar and storage projections have changed in the six months since President Donald Trump returned to office, but not to a degree that would reflect his strongly anti-renewable, pro-fossil-fuel agenda. 

In its January 2025 Short-Term Energy Outlook, EIA said it expects 26 GW of new solar capacity in 2025 — substantially less than the 33.3 GW that developers now say they expect to complete this year.  

And in March 2025, EIA said the energy sector expected to add 19.6 GW of storage this year, a bit more than the 18.3 GW now expected. 

EIA’s Aug. 20 update also touched on the other side of the coin: retirement of generation. 

A significant amount of coal generation retirements are expected this year, despite the Trump administration’s efforts to slow the trend. | EIA

The industry expects to retire 8.7 GW of capacity this year, including 6.2 GW of coal and 1.6 GW of gas generation. But it had retired only 2 GW by the end of June and had canceled or delayed retirement of 3.6 GW of capacity. 

EIA reported in February 2025 that electricity generators planned to retire 12.3 GW of capacity this year, 65% more than in 2024. The great majority of this was to be coal plants and simple-cycle natural gas turbines. 

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States’ Interregional Transmission Efforts Examined

Advocates for interregional transmission should focus more on allocation of benefits than on allocation of costs, a researcher said during an ACORE webinar. 

This — along with identifying the constituency for a project and the regulatory gaps that would thwart it — would help advance the longstanding goal of building more wires to move electricity across state lines and RTO/ISO boundaries, said Abe Silverman, who is facilitating a nine-state collaborative to advance interregional transmission. 

The American Council on Renewable Energy hosted “Powering Progress: States Leading on Transmission Collaboration” on Aug. 19 to look at the outcome of past multistate collaborations and at the ongoing efforts toward further collaboration. 

ACORE’s Kevin O’Rourke was joined by Silverman, an assistant research scholar with the Ralph O’Connor Sustainable Energy Institute at Johns Hopkins University; Anya Poplavska, senior policy advocate at the Acadia Center; and Beth Soholt, executive director of the Clean Grid Alliance. 

Soholt spoke of CapX2020, the successful $2.1 billion effort by 11 utilities to build nearly 800 miles of 345- and 230-kV transmission lines across Minnesota and into three neighboring states. 

There was a long process of lining up internal and external support, financing, regulatory approval and community acceptance, she said, as well as the challenge of shaping a disparate group of cooperatives, municipal utilities and investor-owned utilities into a coalition of the willing with a consensus on a common goal. 

“It’s a lot easier to kill a project, it’s a lot more difficult to make it happen,” Soholt said. “And this group did come together and make it happen.” 

Poplavska spoke about the Northeast Grid Planning Forum, convened by the Acadia Center and Nergica to lay the groundwork for collaboration to meet what is projected to be a 100% increase in power demand over the next quarter century — and to loop in neighboring parts of Canada, which has a deep and longstanding infrastructure connection with the U.S. Northeast. (See New Initiative Focuses on Interregional Tx Coordination in the Northeast.) 

There is only piecemeal and fragmented decision-making now, she said. “And [the forum is] really born of the synergies between Canada and the Northeastern states. The whole point of it is to really create a framework across these different regions that facilitates planning, coordination and decision making.” 

Accentuate the Benefits

Poplavska identified three steps in the process: identification of needs; design and selection of projects; and, most difficult of all, allocation of costs. 

“How are costs going to be borne across different regions?” she said. “I don’t think it’s a stretch to say that this is a huge limitation and reason that interregional projects just don’t get pursued as much.” 

A potential best practice, Poplavska added, would be to move beyond a strict 1-1 benefit-cost ratio on cost allocation and allow states to voluntarily cover additional costs that contribute to meeting their policy goals. 

“Cost allocation is a bit of a red herring,” Silverman said. “Because what we really need to talk about is benefits allocation. Because all these projects have such enormous net benefits that if we really get hung up on how we’re allocating the costs without taking into consideration the benefits, we end up having sort of a circular conversation that we very rarely get anywhere.” 

It is a very different discussion, he added, to go to the governors of three states and say “We have a billion dollars of benefits we have to allocate between the states” rather than “We have $500 million of costs that we need to allocate.” 

Silverman is facilitator of the Northeast States Collaborative on Interregional Transmission — an effort that spans nine states from Maine to Maryland served by three grid operators. (See State Officials in the Northeast Discuss Interregional Transmission Plan.) The states entered a memorandum of understanding in 2024 to accelerate the siting and permitting of regional and interregional transmission.  

All signs point to the benefits of regionalization, Silverman said, and it serves the competing visions of decarbonization and fossil fuel-based energy dominance. 

“There’s probably 20 high-quality studies all showing enormous consumer benefits if we get interregional transmission right,” he said. “And that’s everything from faster deployment of data centers and clean energy and economic development in our states. It’s also often lowering costs for consumers, and it’s certainly improving reliability.” 

Silverman added: “But what we sort of have encountered is that there is a regulatory gap between the benefits and the people who see the benefits and the people doing the grid planning.” 

He said the value of the collaborative he is working with and the forum Poplavska is working with is that they create the constituency that can advocate for those gaps to be closed, and allow these types of projects to move forward. 

“If all we needed was another study talking about how beneficial interregional transmission was, we’ll just keep writing those studies forever,” Silverman said. 

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Texas RE Analyst Urges ‘Extravagant’ Utility Cyber Plans

Utilities should ensure their cybersecurity incident preparations are “as extravagant as possible,” so they are protected in the event of an attack from malicious entities, a manager with the Texas Reliability Entity told entities.

“Whether or not you think [a cyber incident is] actually going to happen, you want to make sure that your response plan is capable of withstanding any type of scenario that occurs,” Chris Mejia, Texas RE’s CIP cyber and physical security analyst, said in the regional entity’s regular Talk with Texas RE webinar Aug. 19.

Mejia was discussing the reliability standard CIP-003-8 (Cybersecurity — security management controls), which specifies requirements for entities to include in the security plans for their low-impact cyber assets. NERC defines low-impact systems as those not considered a significant risk to grid security.

The cybersecurity plan requirements, found in Attachment 1 of the standard, include the following five mandatory sections:

    • Cybersecurity awareness — “reinforce … cybersecurity practices” among staff, including physical security practices if applicable, at least once every 15 calendar months.
    • Physical security controls — restrict access to the cyber asset itself or the location of the low-impact system within the asset, as well as any cyber assets that provide electronic access controls over the system.
    • Electronic access controls — “permit only necessary inbound and outbound electronic access as determined by the responsible entity” and authenticate any dial-up connectivity that can provide access to low-impact cyber systems.
    • Cybersecurity incident response — develop incident response plans that provide for identification, classification and response to cybersecurity incidents; identify roles and responsibilities for incident response; and test response plans at least once every 36 months.
    • Transient cyber asset and removable media risk mitigation — address the risk of malicious code spreading from removable media and other transient cyber devices, whether managed by the entity or by a third party.

Mejia emphasized that while the standard specifies minimal targets for compliance, such as the 36-calendar-month timeline for testing cyber incident response plans, entities should be willing to go above and beyond those requirements to keep their systems safe.

For example, in the case of the cybersecurity awareness element, Mejia observed that entities have multiple options for informing their staff of best practices: direct communication between managers and employees, indirect communication such as posters in common areas and visible support for cybersecurity from management. A good plan will involve using all three while also ensuring they are used in the best way for the organization rather than just satisfying the minimum for compliance.

“Let’s say you’re putting up a poster. Are you leaving that poster up for the entirety of those 15 months, and only changing it once every 15 months?” Mejia said. “You’ve got to be careful with that, because a lot of times that poster does end up kind of blending into the wall. People have blinders on, and they don’t see it anymore. So maybe a best practice is that … you go ahead and do it a little bit more frequently than that.”

Regarding physical security controls, Mejia observed again that there are “many different ways you can do this,” with common approaches using fences or walls and gates. But just having these facilities in place may not provide the level of security that entities expect without continuous testing. Mejia also urged entities to make sure they implement a layered approach with multiple reinforcing security mechanisms.

Finally, Mejia reminded entities that CIP-003-9, the successor to CIP-003-8, will take effect April 1, 2026, after being approved by FERC in 2023. (See FERC Approves NERC Cyber Protection Expansion.) The new standard will add a new requirement for “vendor electronic remote access security controls” to entities’ cybersecurity plans for low-impact cyber systems.

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Black Hills-NorthWestern Merger Could Reshape Western Market Map

The proposed merger between Black Hills Corp. and NorthWestern Energy likely will reshape the map in the competition between CAISO’s Extended Day-Ahead Market and SPP’s Markets+ — but it’s still too early to know where new boundaries will be drawn. 

The two companies announced Aug. 19 that their respective boards of directors voted unanimously to approve an agreement to merge in an all-stock, tax-free merger that will incur no new debt.  

The deal, which is expected to close in 12 to 15 months pending federal and state approvals, would “create a premier regional regulated electric and natural gas utility company with a pro forma market capitalization of approximately $7.8 billion and a combined enterprise value of $15.4 billion,” according to a joint statement. 

“The combined company will have greater scale and financial strength to consistently deliver for customers across our service territories and invest at the pace and scale that today’s energy transformation demands,” Black Hills CEO Linn Evans said in the statement. “Our vision is to be the energy partner of choice for our customers, communities and investors, and this merger will accelerate our ability to achieve this goal.” 

“Our merger with Black Hills will create a premier regional regulated utility company with a larger, more resilient platform consistent with mid-cap peers,” NorthWestern CEO Brian Bird said. “Together, we will be better positioned to meet rising demand, accelerate investment in energy and grid infrastructure, and support customers and communities through a rapidly evolving energy landscape.”  

Upon closing of the deal, shareholders of Rapid City, S.D.-based Black Hills will own 56% of the combined company, with the remaining 44% owned by shareholders of Butte, Mont.-based NorthWestern, leaving the Black Hills as the greater among equals in the merger.  

The combined company — whose name has yet to be determined — will have its headquarters in Rapid City, and its board will include six representatives from Black Hills and five from NorthWestern. Bird will take the helm, with Evans retiring.  

Black Hills serves 1.35 million electricity and natural gas customers across eight states: Arkansas, Colorado, Iowa, Kansas, Montana, Nebraska, South Dakota and Wyoming. The company’s electricity operations are concentrated in the Western Interconnection and include its Black Hills Power and Cheyenne Light, Fuel and Power subsidiaries, which serve customers in southeastern Montana, western South Dakota and northeastern Wyoming, and its Black Hills Colorado subsidiary in the southern part of that state. 

NorthWestern serves about 800,000 electricity and natural gas customers in Montana, South Dakota and Nebraska and operates a balancing authority area that covers a large portion of Montana. 

The territories of the two Black Hills Energy utilities joining the Western Energy Imbalance Market are represented on this map by the orange areas in Montana, Wyoming and South Dakota. | Black Hills Energy

In their joint statement, the two companies said the combined electric utility will serve about 700,000 customers and operate roughly 38,000 miles of transmission and distribution lines and approximately 2.9 GW of owned generation capacity consisting of a mix of thermal, hydro and wind. The combined natural gas utility will serve about 1.4 million customers and operate 59,000 miles of natural gas lines.  

“Over time, this increased scale is expected to drive operating and cost efficiencies across the combined enterprise,” the companies said. 

‘Just too Soon’

With such a sprawling territory, the combined electric utility operations of the two companies could shape the footprints of the two competing Western day-ahead markets in key ways, and the stakes could be especially high for Markets+. 

NorthWestern, which has been participating in CAISO’s Western Energy Imbalance Market (WEIM) since 2021, has not committed to either EDAM or Markets+ or expressed a leaning in either direction. According to sources close to the market decision process, the utility’s decision still is very much in play. 

Bordering NorthWestern’s BAA to the west is the Bonneville Power Administration, which has committed to funding and participating in Markets+, although that decision is being contested in a suit filed in the 9th Circuit Court of Appeals. (See BPA Sued in 9th Circuit over Day-ahead Market Decision.)  

To NorthWestern’s southwest is Idaho Power, which has not committed to either market but is leaning heavily to EDAM, while to the south is the PacifiCorp-East BAA, which will become the first EDAM participant in spring 2026. To the east and southeast are Western Area Power Administration (WAPA) BAAs that plan to participate in SPP’s RTO West expansion.  

If NorthWestern were to commit to EDAM, the Northwest portion of the already-fractured Markets+ footprint would be further cut off from the islanded portion of that market represented by Public Service Company of Colorado’s (PSCo) BAA. Alternatively, NorthWestern’s participation in Markets+ would put connectivity between the Northwest and PSCo within closer reach. 

But at first glance, the union between NorthWestern and Black Hills suggests the former scenario is more likely.  

That’s because in August 2024, Black Hills Power and Cheyenne Light — both currently located in WAPA’s BAA — announced plans to exit SPP’s real-time Western Energy Imbalance Service (WEIS) and join CAISO’s WEIM in 2026. (See CAISO’s WEIM Plucks Black Hills Utilities from SPP’s WEIS.) 

Among the reasons the utilities gave for the move was the fact that, with the expansion of both Markets+ and RTO West, SPP will disband the WEIS. 

“The planned formation of the SPP RTO West required us to assess our future market path, as it did not appear that the WEIS market status quo would remain an option after RTO West is operational,” Black Hills told RTO Insider at the time. “We have found imbalance market participation to be beneficial for our customers, and the opportunity for our utilities to participate in the WEIM allows us to continue to optimize our generation operations while maintaining our high reliability and creating long-term value for the customers we are privileged to serve.” 

At the time, the move appeared to represent a geographically small but symbolically large victory for CAISO, since it would put the ISO’s presence as far east as South Dakota. Now it could translate into a significantly greater advantage for CAISO as it seeks to court NorthWestern. 

The WEIM implementation agreement signed between CAISO and Black Hills Energy stipulates that one of the company’s utilities will be required to register a new BAA to facilitate participation in the market. The merger could enable the Black Hills utilities to instead join NorthWestern’s BAA, but that would dictate that all three utilities participate in the same market, whether that be CAISO’s WEIM or EDAM, or SPP’s Markets+. 

When asked how the merger could affect NorthWestern’s decision to join a day-ahead market, and whether the two companies planned to consolidate BAAs in the West, utility spokesperson Jo Dee Black told RTO Insider: “NorthWestern and Black Hills will evaluate operational opportunities over the coming months and apply best practices where they are appropriate.” 

Black Hills spokesperson Theresa Donnelly offered a similar response to the same questions. 

“With the newness of today’s announcement, we’re not able to respond to your questions,” she said. “It’s just too soon.” 

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ISO-NE Proceeding with Shortfall Threshold After Positive Feedback

After receiving positive feedback from stakeholders, ISO-NE plans to proceed with its proposal for a quantitative threshold to determine an acceptable level of energy shortfall risk for the region.

The regional energy shortfall threshold (REST) project is one of the RTO’s key initiatives for 2025 and is intended to establish a threshold reflecting “the region’s level of risk tolerance with respect to energy shortfall during extreme conditions.”

The REST, which incorporates both shortfall magnitude and duration, would be used for seasonal assessments forecasting energy shortfall risks heading into each summer and winter period, along with long-term assessments looking at risks five and 10 years into the future.

When calculating the threshold, ISO-NE would consider the tail 0.25% of 21-day model cases with the most shortfall risk. The REST would be triggered if the average shortfall magnitude of these tail cases exceeds 3% and the shortfall duration exceeds 18 hours. (See “Regional Energy Shortfall Threshold,” NEPOOL Reliability/Transmission Committee Briefs: July 15-16, 2025.)

Jinye Zhao of ISO-NE said at the NEPOOL Reliability Committee (RC) meeting Aug. 19 that, on average, one of the extreme 21-day cases would occur “approximately once every 90 three-month periods.” Accepting this threshold means that “about once every 90 three-month periods, the region can tolerate up to 3% of unserved load on average across the 72 most severe hours.”

“Stakeholders have generally expressed support for the ISO’s proposed tail α% of 0.25%, proposed shortfall magnitude threshold of 3%, and proposed shortfall duration threshold of 18 hours,” Zhao said. “As a result, the ISO has retained its REST proposal as introduced at the June RC.”

Zhao clarified that the duration metric will evaluate the cumulative shortfall hours within a 21-day period instead of the longest period of consecutive shortfall hours. She said focusing on consecutive shortfall hours would introduce significant noise to the data, as small gaps between shortfall periods could mask the length of shortfall events.

She noted that ISO-NE never has experienced load shed due to a lack of generation, so it is not possible to back-test these thresholds for accuracy. However, she stressed that the lack of energy shortfall events in the past does not guarantee a risk-free future, and the increasing uncertainties stemming from climate change and a shifting resource mix and load profile could increase risks.

ISO-NE has said the REST will be a key tool to help identify when solutions are needed, but it is “premature to calculate the value of lost load (VOLL)” associated with extreme shortfall periods, Zhao said.

“While there are methodologies available to calculate metrics like VOLL, applying them may be more appropriate if a specific system risk has been identified through the long-term or seasonal assessment process,” she said. “A cost/benefit analysis could be helpful at that time to evaluate whether potential risk mitigation options are economically justified once the nature and scale of tail risk are identified and better understood.”

Some stakeholders urged the RTO to start thinking about how to identify and pursue solutions if the REST is violated, noting that, if the region identifies significant risks in one of the initial REST analyses, it likely would take years to establish a process for selecting a solution, work through the process and ultimately develop the selected project.

ISO-NE plans to run the REST analysis in conjunction with its seasonal assessments and will report the summer results in June and the winter results in November. For annual long-term assessments, the RTO plans to begin work in February or March and produce a report in November, beginning in 2026.

Mike Knowland of ISO-NE said the RTO will allow stakeholders to suggest modeling sensitivities to include in REST analyses and that ISO-NE plans to include three to five stakeholder-requested sensitivities in each long-term REST assessment. The RC is scheduled to vote on the REST proposal in September.

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State Tx Entity, Regional Markets Feature in Ore. Energy Strategy

The Oregon Department of Energy’s new draft energy strategy points to the importance of new transmission development and expanding electricity markets for meeting the state’s energy goals.

ODOE’s draft Oregon Energy Strategy, released for public comment Aug. 14, sets out recommendations by which the state can meet its greenhouse gas emissions policy objectives, which call for fully decarbonizing investor-owned utility electricity deliveries by 2040 and, by 2050, reducing fuel emissions by 90% and economy-wide emissions by 80%.

“An energy strategy could help align policies and programs; it could help navigate hard decisions with a focus on how to maintain affordability and reliability, [and] keep an eye on economic growth, on advancing equity and maximizing benefits, while minimizing harms,” Edith Bayer, ODOE energy systems senior policy analyst, said during an Aug. 14 call to discuss the draft document.

The wide-ranging strategy document identifies five “pathways” for meeting state objectives, including improving energy efficiency, increasing electrification across the economy, investing in clean electricity infrastructure, using low-carbon fuels in hard-to-decarbonize sectors and strengthening “resilience” throughout the energy system.

A section describing the clean electricity pathway warns that the state presently lacks the infrastructure needed to meet its energy transition goals.

“There is not currently sufficient transmission capacity, generating resources or storage to reliably power Oregon’s future electricity needs, particularly if new data centers come online as quickly as forecasted,” ODOE writes, pointing to the need to prioritize construction of new utility-scale resources, which often take years to site, plan, permit, build and interconnect with the grid.

“Failure to develop sufficient resources will not only threaten system reliability and hinder progress toward Oregon’s clean energy objectives, but will inhibit economic development and discourage new businesses from entering the state,” the report says.

ODOE’s top recommendation for addressing the challenge: establish a state “transmission entity” — one that appears to be modeled on New Mexico’s Renewable Energy Transmission Authority and the Colorado Electric Transmission Authority.

The department says the Oregon entity should be given authority to “identify and designate transmission corridors,” undertake “partial siting and permitting approvals” for projects in the corridors and offer direct financial support “through state bonds for projects that are determined to benefit the public interest.”

“Across the Pacific Northwest, transmission constraints hinder access to least-cost generation and contribute to reliability concerns,” the agency wrote. “Line expansions and additions are not proceeding at the pace or scale necessary to meet Oregon’s policy objectives.”

ODOE said the new entity could help simplify the process of siting and permitting transmission lines that traverse both state and federal jurisdictions, a key challenge in a region in which the Bonneville Power Administration controls more than 70% of the transmission network.

“To reduce this barrier, a new state entity could establish designated corridors for transmission development and obtain limited siting approval for development within the corridor, including development of enhanced, expanded or new transmission facilities but also of storage and electric generating resources,” the report notes. “Having a new state entity pursue limited siting approval for an entire corridor would retain Oregon’s historic focus on robust siting and permitting processes, while enabling individual projects within a given sited corridor to proceed more rapidly than is currently possible.”

Bayer noted the recommendation might resemble an Oregon House of Representatives bill (HB 3628) to establish a state transmission authority that failed to emerge from committee during the 2025 session.

“We hope that the text in the draft report captures the potential value that such an entity could provide, as well as the potential risks,” she said. “There’s near universal agreement in all of our engagement and everything that we heard that transmission is one of the most critical areas to meet our goals of clean, reliable and affordable energy.”

Coordination Through Markets

The strategy document also urges Oregon to step up collaboration with its neighbors, specifically through increased engagement with regional markets and other grid efforts.

ODOE calls out the “billions of dollars” the West has saved through expanded participation in CAISO’s real-time Western Energy Imbalance Market since 2014 and notes the development of the region’s two competing day-ahead markets: the ISO’s Extended Day-Ahead Market and SPP’s Markets+.

“Utilities in the region are moving toward more organized power markets to reduce costs and improve reliability. This is essential to more efficiently utilize existing infrastructure and to benefit from geographic and resource diversity across the region,” the agency wrote.

It said regional diversity will become “increasingly important” as states decarbonize, with a more diversified supply mix allowing load-serving entities to “take advantage of different weather patterns, resource mixes and time zones to integrate more renewable generation while mitigating risks from weather changes, including extreme weather events and wildfires.”

ODOE said movement toward an RTO would be “an important step to improve West-wide coordination and reduce costs for consumers.”

The document mentions also the two efforts managed by the Western Power Pool: the Western Resource Adequacy Program to develop regionwide RA requirements, and the Western Transmission Expansion Coalition to identify cost-effective interregional transmission projects.

“It is important that the state of Oregon engage in these activities to advance state energy policy objectives, ensure that regional activities are consistent with state policy and strengthen Oregon’s cooperation on vital areas including market development, resource adequacy, emissions accounting and transmission planning,” the report says.

The comprehensive strategy document recommends a wide range of additional energy-related actions, including those dealing with the electrification of buildings, transportation and industry; energy efficiency and conservation improvements; developing and expanding adoption of low-carbon fuels; and reducing vulnerabilities in the state’s energy system. It also explores equity issues stemming from the transition to cleaner sources of energy, including jobs impacts.

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Calif. Utilities Move Cautiously on Dynamic Pricing

Despite a state mandate to implement dynamic pricing, two of California’s publicly owned utilities told regulators they’re not ready to make the leap to rates that change hourly or more often. 

The two utilities — Sacramento Municipal Utility District (SMUD) and the Los Angeles Department of Water and Power (LADWP) — outlined the challenges of dynamic pricing in reports submitted to the California Energy Commission. 

The reports are intended to show utilities’ compliance with the CEC’s load management standards, which include a requirement to offer customer rates that can respond to hourly or sub-hourly price signals. 

The commission on Aug. 13 approved compliance plans from SMUD and LADWP, as well as from two community choice aggregators: the Clean Power Alliance of Southern California and Ava Community Energy Authority, which serves the East Bay. 

The dynamic pricing requirement is based on the idea that electricity customers can use smart devices, such as thermostats, water heaters and EV chargers, to reduce or shift their electric loads in response to price or other signals. 

In addition to saving money for customers, the rates may encourage the use of energy at off-peak hours, improve grid reliability, decrease the need for new electrical capacity, and reduce fossil fuel consumption and greenhouse gas emissions. 

SMUD, which was the first utility in California to implement time-of-day pricing, said in its plan that it is “fully supportive of the goals of the LMS regulations.” 

“We are focused on scaling up programs, including programs that can help reduce the need to purchase costly resource adequacy and to avoid the need to upgrade neighborhood transformers as EV charging loads grow,” Katharine Larson, SMUD’s regulatory program manager, told the commission. 

But with projected net annual costs of $2.4 million to $3.7 million to implement hourly or sub-hourly pricing, dynamic pricing wouldn’t be cost-effective, SMUD said.  

Customer Interest Uncertain

SMUD was also concerned about a potential lack of interest in such a program. The utility cited its experience with its critical peak pricing (CPP) plan, in which customers agree to pay a higher rate when the utility calls a “peak event” in exchange for discounted rates at other times. 

The peak events can occur at any time of day during the summer and can last from one to four hours. Program participants must allow automatic adjustments of smart devices enrolled with SMUD. 

After two years of active recruitment for CPP, fewer than 700 customers have signed up for the program. 

The commission approved SMUD’s compliance plan with the condition that the utility provides an updated cost-effectiveness analysis for dynamic pricing by August 2028. 

In its compliance plan, LADWP said implementing dynamic rates by the load management standard’s April 1, 2026, deadline wouldn’t be feasible and would cause an “extreme hardship” for the utility. 

LADWP doesn’t have advanced metering infrastructure needed to implement dynamic rates, but its plan includes other programs to encourage customers to shift their loads. Those include an electric vehicle managed-charging program. 

Among the CCAs, Ava said it doesn’t yet have enough information to know whether dynamic rates would be cost-effective or benefit customers.  

Ava said “significant uncertainties exist” regarding the potential for load-shift under dynamic pricing, customer acceptance of a complex new rate and administrative costs of the program. To help answer those questions, Ava is participating in a dynamic pricing pilot program with PG&E. 

Similarly, the Clean Power Alliance plans to participate in Southern California Edison’s expanded dynamic rate pilot through 2027. 

Customizing Compliance

The commission’s vote Aug. 13 follows compliance plan approval for six other utilities in May. The commission will consider plans from another nine CCAs at a future meeting. 

Commissioner Andrew McAllister said CEC staff had done a good job in “almost customizing” the implementation of the load-management standards for each utility, “responding to the realities on the ground.” 

“We have a big, diverse state,” McAllister said. “We’re doing something new; we’re sort of creating a new playing field.” 

The CEC approved an update to its load management standards in October 2022. (See California Moving to Dynamic Pricing for Retail Customers.) 

In addition to requiring dynamic pricing, the update directs utilities to maintain up-to-date rates in a database called the Market Informed Demand Automation Server (MIDAS).  

Utilities also must develop a standard tool to support third-party services’ access to rate information for their customers. The commission voted to extend the deadline for submitting the tool to May 8, 2026.