Search
December 7, 2025

Posted on

PGE to Explore Alternatives After Withdrawing from WRAP

Portland General Electric is exploring an alternative to the Western Power Pool’s Western Resource Adequacy Program (WRAP) that better suits its upcoming participation in CAISO’s Extended Day-Ahead Market, the utility has told Oregon regulators.

PGE expressed its intention in an Oct. 29 letter to the Oregon Public Utility Commission explaining why the utility was withdrawing from the WRAP ahead of the Oct. 31 deadline to commit to the program’s first “binding” — or penalty — phase covering winter 2027/28. Oregon rules require the state’s investor-owned utilities to participate in either a program such as WRAP or a state-run RA program.

The tone of the letter suggests PGE likely is closing the door on future participation in WRAP as developments point to an alternative program taking shape in the West.

“We are pursuing alternatives to WRAP that better align with the EDAM market to maximize the value to customers,” Sujata Pagedar, PGE senior director of regulatory and governance, told OPUC in the letter. “By maintaining open dialogue and focusing on shared objectives, we believe we can collectively build a framework that delivers lasting benefits for the region.”

The Oregon-based utility was one of five WRAP participants to notify WPP of their withdrawal by Oct. 29, although other dropouts are likely. (See 4 Entities Join NV Energy in Exiting WRAP, While Idaho Power Commits.)

Even before NV Energy conveyed its formal notice of withdrawal on Oct. 27, utility officials told Nevada regulators they were in discussion with other future EDAM participants about developing an alternative to WRAP. (See EDAM Participants Exploring Potential New Western RA Program.)

Asked whether PGE was participating in those discussions, utility spokesperson Drew Hanson told RTO Insider: “It is less about a specific new RA program and more about remaining committed to regional collaboration and actively exploring alternative resource adequacy solutions.”

‘Unwavering’ Commitment

In the letter to OPUC, Pagedar said PGE’s “decision was not made lightly” but reflected “the fact that there are significant unresolved uncertainties in the program design, reliability metrics, technology readiness and governance — with no clear timeline for resolving these issues and implementing necessary changes in time for PGE to adequately prepare the March 31, 2027, forward showing submittal for the first binding season, effective Nov. 1, 2027.”

She noted that PGE was a “foundational member” of WRAP, “worked diligently” to move to binding operations as quickly as possible and was the first participant to receive a “passing” score on the operations program report during the “nonbinding” phase.

Still, PGE had identified critical shortcomings.

Among those was WPP’s proposed realignment of the WRAP’s operation subregions with CAISO’s EDAM and SPP’s Markets+ (compared with the previous Northwest/Southwest breakdown), which Pagedar said was necessary for a “robust” RA framework but posed too much risk without postponing the first binding season.

She said such “a complete realignment in such a compressed timeline creates substantial risk regarding how these metrics will be recalibrated and how those changes will impact participants’ capacity demonstration and financial exposure” during the first winter binding season.

Pagedar said PGE was concerned about the outcome of efforts by the WRAP’s Planning Reserve Margin Task Force to evaluate new methodologies for setting planning reserve margins for program participants.

“These changes directly impact deficiency charge calculations and the risk profile for participants. The changes to the PRM methodology and timeline could directly impact the calculation of resource capacity contributions,” she wrote.

PGE expressed concern about the “technical readiness” of WRAP, which is being operated on behalf of WPP by SPP, saying the forward showing and operations platforms appear to “lack the technical stability and responsiveness needed for a binding adequacy program” and that user interface and system issues that “raise doubts about the operator’s ability to implement changes in time for market participants to adjust their IT systems.”

Pagedar concluded that PGE has an “unwavering” commitment to collaborating on regional RA.

“We will continue to work with partners across the West to advance solutions that strengthen reliability, affordability and resilience for all customers,” she wrote.

Posted on

Nvidia, Emerald AI, EPRI and PJM Announce Flexible Data Center Project

The artificial intelligence industry and power industry are working together to develop the first “power-flexible AI factory” at a 96-MW facility in Manassas, Va.

Nvidia, Emerald AI, the Electric Power Research Institute, Digital Realty and PJM are working to test the flexible capabilities of the Aurora AI Factory, which was designed from the bottom up to provide services to the grid. The power-flexible design, if adopted across the country, could unlock 100 GW of capacity on the grid, based on a study from Duke University. (See US Grid Has Flexible ‘Headroom’ for Data Center Demand Growth.)

Emerald is a startup working on the data center flexibility project with Nvidia, the largest company by market capitalization in the world because of its advanced chips that have fueled the rise of AI. The project is meant to help show the system can work, which would increase speed to market for data centers and take pressure off the grid, Emerald Chief Scientist Ayse Coskun said in an interview.

“AI data centers are facing a lot of wait time,” Coskun said. “In Virginia, we hear about five- to seven-year wait times for data centers to get connected.”

Load flexibility on the part of data centers means they can plug into the grid much more quickly because they can get offline when the system is stressed.

Nvidia provides the chips and offers control services for the project. EPRI is involved with its “DCFlex Initiative,” and the data center will bid services into PJM’s wholesale markets. (See EPRI Launches DCFlex Initiative to Help Integrate Data Centers onto the Grid.)

Data centers have varying levels of flexibility, from little to none at customer-facing facilities that make up the bulk of the facilities in Northern Virginia’s Data Center Alley, to cryptomining facilities that fall off the grid as soon as prices make their production unprofitable. AI data centers can be somewhere in the middle.

“A key ingredient in our technology is to make sure we meet these quality-of-service or priority constraints of customers,” Coskun said. “Some AI workloads fall into this category of being urgent and therefore not being flexible, but there’s a lot of other AI workloads.”

Some of the computing processes can be slowed or delayed for the few hours at a time when the grid would need to count on demand response from data centers, she added.

“Overall, when you look into the performance impact for this kind of actions, it’s minuscule,” Coskun said. “And in some cases, it’s not even noticeable.”

With ample benefits from speed-to-market concerns and little impact on AI data centers’ operations, flexibility makes sense, but it is early days of the concept for the customer class.

“Emerald AI is positioning itself to be this interface layer between the data centers and the power grid,” Coskun said. “Traditionally, there wasn’t a ton of communication between the power grids and the data centers, but as we design our data centers in a smarter and more flexible way, we believe there’s going to be this communication and programs may evolve. … There’s a ton of mechanisms that are existing in power markets that are not heavily used by data centers.”

The exciting thing about the Aurora facility is that it is being developed from the ground up for flexibility, which normally is an afterthought for data centers, EPRI Emerging Technologies Executive Anuja Ratnayake said in an interview.

EPRI’s DCFlex initiative was started to help the power industry meet the fast-growing demand for electricity from their expansion. The program also is working on real-world demonstrations at data centers in North Carolina and Arizona, the latter of which also includes Emerald.

“The major challenge for the industry is powering the data centers that are coming up at the moment, and the challenge comes from the scale and the pace of the growth in the data center sector,” Ratnayake said. “For the last 20-plus years … data centers grew up for enterprise purposes and for social media purposes and then for cloud purposes. What we are seeing happening in the last about two years is there is sort of a new type of a data center, which is what Nvidia is terming the AI factories.”

Data centers used to be five or 10 MW on the large side, but now with AI’s need for computing power and the energy to run all those Nvidia chips, it is seeing requests for 500 MW or even 1 GW, which is the size of a major city, she said.

“Think about the grid that is planned around these little loads that come together in the form of a city versus a single point in the grid that represents that same load,” Ratnayake said. “That’s new, and what that means … is the grid has to do a whole host of new investments, both potentially on the generation side and on the grid side.”

It can take up to a decade or more to build new generation and wires, but the data centers want to connect in a year or two, she noted. If data centers can respond and cut the amount of energy pulled from the grid, they can get connected while the grid is being expanded.

“This is that seven- to 10-plus-year period,” Ratnayake said. “During that period, if you’re able to be flexible, we can potentially connect you faster. That’s where the flexibility piece becomes important.”

One of the questions EPRI is studying is how much flexibility data centers might continue to provide to the grid once it has been expanded.

“It will be tied closer to business models more than really the technology viability,” Ratnayake said. “The technology viability will exist forever, but it will be up to the data center operators to really embrace which business model makes the best sense.”

Posted on

Landmark Reached in Effort to Reshore Solar Manufacturing

With the start of production at an ingot and wafer factory in Michigan, all components of a photovoltaic solar module now can be sourced from U.S. manufacturers.

Every major piece of the solar supply chain has been reshored, the Solar Energy Industries Association said Oct. 29 as it marked this latest milestone in a solar manufacturing renaissance.

The news comes at a pivotal time for the solar power industry, given the federal policy changes engineered by President Donald Trump that will make solar power more expensive to develop and, in some cases, more difficult to site.

SEIA said 65 solar and storage component production facilities have come online or been expanded in 2025 through an investment of $4.5 billion. But more than 100 manufacturing projects and $31 billion in additional investments are at risk from the Trump administration’s attacks on the solar sector, SEIA added.

U.S. solar generation capacity has been soaring: It accounted for more than half of all new capacity added nationwide in the first half of 2025. Given its relatively low cost and relatively high speed to deploy at a time when other generation is slow and expensive, new solar arrays are not expected to suddenly stop being built. But the rate of growth is expected to slow.

Corning subsidiary Hemlock Semiconductor announced Oct. 30 it had started production in the third quarter at the largest solar ingot and wafer facility in the U.S. and is anticipating a steady stream of revenue from it, as it accelerates production from thousands of wafers per day to more than 1 million per day through the fourth quarter.

The new ingot and wafer factory is co-located with the Hemlock, Mich., polysilicon facility owned by Corning, which plans to build its solar business to a $2.5 billion annual revenue stream by 2028.

Corning said it has secured purchases of more than 80% of available polysilicon and wafer capacity for the next five years.

Hemlock said solar wafers have not been produced in the U.S. in nearly a decade. In its announcement, the company quoted Moustafa Ramadan, head of market research at PV Tech Research: “For the first time, a module can be completely U.S.-made, from polysilicon to the module. This is probably the first time in a long time that this is possible. It might not be sufficient to meet demand, but it is a big step for U.S. manufacturing.”

SEIA framed the development as a variation on the renewables-are-good-for-America theme the U.S. clean energy sector began broadcasting late on Election Day 2024, after Trump was elected on a pro-fossil fuel platform.

“This growth is a testament to the power of American innovation,” SEIA President Abigail Ross Hopper said in a news release. “We’re building factories, hiring American workers and showing that solar energy means made-in-America energy.”

But she added a caveat: “This industry has proven what’s possible when businesses have the certainty to invest. If the administration does not reverse their harmful actions that have undermined market certainty, energy costs will rise even further, and the next wave of factories and jobs could be at risk.”

In its latest update, SEIA’s Solar & Storage Supply Chain Dashboard shows $36.6 billion in U.S. solar manufacturing investments publicly announced since supportive federal policy changes in 2022 — $13.1 billion of which are operational, and $9.2 billion of which are under construction.

These facilities were expected to create 50,100 manufacturing jobs — 23,321 at facilities that are operational and 7,700 at facilities under construction.

Of the storage facilities announced since the Inflation Reduction Act’s passage, 21.8 GWh of battery cell and 69.4 GWh of battery pack manufacturing capacity have come online. Production facilities for components such as solar mounting systems, power electronics and grid technologies also have come online.

Posted on

J.H. Campbell Tab Rises to $80M on DOE’s Stay Open Orders

The J.H. Campbell coal plant in Michigan has racked up $80 million in net costs since late May to stay online, per emergency orders from the U.S. Department of Energy.

Plant owner Consumers Energy reported in an Oct. 30 filing to the U.S. Securities and Exchange Commission that from May 23 through Sept. 30, the costs of keeping the 1,420-MW plant online were about $164 million, with the utility offsetting $84 million with revenue from selling the plant’s output in the MISO markets.

J.H. Campell now costs more than $615,000 per day to operate since DOE issued its first emergency order to prevent the plant’s retirement as scheduled May 31. The plant now is operating under a second emergency order that expires Nov. 19. (See DOE Orders Mich. Coal Plant to Remain Available Another 90 Days.)

Consumers Energy divided the costs of running the plant into the two timespans of the emergency orders. From May 20 to Aug. 20, costs swelled to $120 million, with $67 million in revenues, leaving $53 million to be paid. From Aug. 21 through Sept. 30, costs reached $44 million, with power sales covering $17 million, leaving $27 million unpaid.

Consumers Energy will detail the remaining costs associated with the second DOE order in its next quarterly filing, due to the SEC in late January 2026.

Earthjustice senior attorney Michael Lenoff said DOE’s orders that the Campbell plant remain accessible are “extremely expensive.”

Earthjustice, the Sierra Club, Michigan Attorney General Dana Nessel and others are suing DOE, arguing separately that ratepayers are unfairly expected to pay for the plant’s expenses. (See Opponents Take DOE to Court over J.H. Campbell Retirement Delay.)

“Forcing this unnecessary coal plant to keep operating is bilking consumers for the benefit of the coal industry. Earthjustice is in court now to stop the administration from harming consumers, trampling markets and unlawfully usurping the authority of states and regulators to make decisions in the public interest,” Lenoff said in a statement.

Numbers from EPA’s Clean Air Markets Program Data show that J.H. Campbell’s three units were not consistently generating from July to September, when Unit 1 did not produce power on 25 of the 92 days; Unit 2 was dormant 74 of 92 days; and Unit 3 did not produce power 29 of 92 days.

Several organizations continue to argue that DOE’s pair of orders remain unnecessary.

In a September rehearing request challenging the second DOE order, Earthjustice and several other public interest groups argued that even on June 23, MISO’s tightest reserve margin day of the summer, the RTO had 3.3 GW of offers above what it needed to meet its 119-GW peak demand, with an additional 7 GW of emergency headroom from resources on standby. The groups argued that the “primary actors in the electric industry already protect resource adequacy without intrusion” from DOE (202-25-7).

The cost of operating the plant is set to be paid by ratepayers across MISO Midwest. (See FERC Rules Costs of Mich. Coal Plant Extension Can be Split Among 11 States.)

Minnesota Public Utilities Commissioner Joseph Sullivan said DOE is infringing on state jurisdiction by ordering the plant to be kept online in rolling, 90-day increments. Sullivan told the MISO Board of Directors Sept. 18 that Consumers Energy, the state of Michigan, MISO and the Independent Market Monitor all agree that J.H. Campbell was “properly planned for retirement and not needed for reliability.”

DOE claims it’s directing not states but MISO and FERC to keep the plant open. Sullivan said DOE relied on MISO’s previous warnings that resource adequacy was in peril despite the 2025/26 capacity auction clearing sufficient resources.

“We need to be careful with our narrative,” Sullivan said. He warned MISO against assuming retiring generation won’t be replaced or presuming that new load would be brought onto the system without the resources to support it.

The Michigan Public Service Commission in late August accepted annual capacity demonstrations from Michigan’s electric utilities, indicating that each has enough capacity to meet customer needs four years into the future (U-21775).

Posted on

DTE Energy Lands 1.4-GW Hyperscaler Agreement

DTE Energy has secured its first hyperscaler agreement and says it has enough excess capacity to power the 1.4-GW data center load without new construction.

The Michigan utility said it does plan to add 1 GW of storage capacity in connection with the hyperscaler project in a peak-shaving role, but the customer will cover the cost.

However, if DTE secures the other data center agreements it is negotiating, it will need to add capacity.

In its third-quarter earnings report Oct. 30, DTE said it is boosting its five-year capital investment plan from $30 billion to $36.5 billion and allocating almost all of the additional $6.5 billion to its electric business to support data center development and the transition to cleaner power generation.

CEO Joi Harris said during an earnings call with financial analysts that DTE is in late-stage negotiations with other hyperscalers for about 3 GW of new load and it has potentially 3 to 4 GW in other data center opportunities further down in the pipeline.

DTE is looking at new gas-fired generation for some of this load.

Harris said DTE already is in the manufacturing queue for a combined-cycle gas turbine to replace the coal-fired Monroe Power Plant, which is slated for retirement as DTE works toward a complete exit from coal by 2032. The new gas facility will cost about $2.5 billion, or $2,500/kW, she said.

Additional combined-cycle gas turbines will be needed for new gigawatt-scale data centers, Harris said, but new demand from smaller data centers could be met with a mix of renewable and fossil generation and storage.

The wait time now is three to four years for a new combined-cycle gas turbine, she said, but less for smaller-scale gas generation equipment.

DTE expects to have a better picture of what mix of generation it needs once it firms up negotiations with some of the other potential large-load customers and knows what their anticipated ramp rates are. It plans to provide more details in its next integrated resource plan.

But the utility does anticipate the need for greater generation capacity — the 1.4-GW hyperscaler project alone will result in a 25% increase in load as it ramps up over the next two to three years, Harris said.

DTE will submit the hyperscaler contract for regulatory approval Oct. 31. It includes a 19-year power-supply agreement with minimum monthly charges.

The hyperscaler also will pay for the new energy storage through a 15-year contract. Two-thirds of the new storage capacity will be met with construction to start in 2026; the remainder will be met through tolling agreements.

Nationally, hyperscaler proposals drawing as much power as a small city have consumer advocates fretting over the impact on electric rates.

But Harris presented DTE’s 1.4-GW data center deal as a win for existing ratepayers, as they won’t have to pay for infrastructure up front or face the prospect of paying for stranded assets down the road.

“We don’t have to build anything substantial to support the load,” she said. “We’re using our excess capacity to support the load and building batteries on top of it, just for peak-shaving purposes. And the customers get that full benefit, so it will show up in the form of a lower ask over our next rate case cycle.”

The 1.4-GW agreement also will help drive 6 to 8% annual growth in earnings per share through 2030, Harris said.

DTE reported third-quarter 2025 net earnings of $419 million or $2.01/share on revenue of $3.53 billion, compared with $477 million, $2.30/share and $2.91 billion in the third quarter of 2024.

Posted on

MISO Predicts 103-GW Peak for Winter

MISO said even a 109-GW peak this winter shouldn’t prove problematic, though the RTO said a more probable scenario would deliver a 103-GW peak in January.

MISO’s coincident peak forecast from members estimates a 102.6-GW winter peak in January. However, MISO said there’s potential for a 108.9-GW peak using a non-coincident peak forecast.

MISO attracted 123.1 GW worth of offers in its winter capacity auction, with 120.2 GW ultimately clearing. The grid operator also has about 11 GW in load-modifying resources that can assist in an emergency during the season.

At an Oct. 29 Winter Readiness Workshop, MISO Senior Resource Adequacy Engineer Gurman Kaur said MISO believes it has more than enough supply to get through the winter.

However, MISO Director of Operations Risk Management Jason Howard said ongoing fleet change coupled with increasing demand and extreme weather could make for thorny operations.

“The combination of load growth, resource flexibility needs during the riskiest times of the day and the ever-present possibility of larger winter storms is our new reality,” Howard said in a press release. “In response to this complex risk environment, MISO is enhancing our forecasting capabilities, dynamic reserves and outage coordination processes to ensure MISO maintains reliability for the 45 million people we serve.”

Howard said MISO would rely on its Forward Reliability Assessment and Commitment system tool, which looks six days ahead to make unit commitments, and would issue grid notices and warnings days in advance when it notices reserves are poised to shrink.

MISO reminded stakeholders that it and its members “reliably and efficiently navigated several significant weather events last winter,” including an arctic 6.5-degree Fahrenheit average footprint-wide temperature Jan. 20-22 that sent systemwide peak demand shooting to 108 GW, with a record-high 33 GW of that from MISO South. (See MISO South Hit Record, 33-GW Winter Peak in Jan. Storm.)

MISO Manager of Operations Risk Assessment Matthew Campbell said during last winter’s trio of storms, MISO maintained consistent communications with members, conducted daily risk assessments and produced net uncertainty forecasts to guide unit commitments.

Campbell noted that the U.S. Energy Information Administration expects coal inventories at power plants to be lower than last winter and “on the lower end of the five-year average.” He likewise said natural gas storage is projected to be lower than a five-year average every month of winter.

MISO said winter 2024/25 — which was colder than usual due to periods of “durable” cold air — is the top comparison to draw on to predict winter 2025/26.

Ella Dankanics, a senior at Purdue University and a meteorological risk analyst for MISO, said the National Oceanic and Atmospheric Administration expects equal chances for MISO Midwest to have a colder- or warmer-than-normal winter. MISO interprets the equal opportunity could mean temperature swings.

Dankanics said warm and cold air could “battle” throughout the season, bringing a greater risk of equipment icing.

NOAA, meanwhile, anticipates above normal temperatures in MISO South. The agency also predicts active storm patterns and higher-than-average precipitation in the Great Lakes region with a drier season near the Gulf of Mexico.

Dankanics said there’s potential for a weaker La Niña weather pattern this winter that creates more opportunities for deep freezes, reinforced by weaker stratospheric winds.

Dankanics said in historical winters with a weak La Niña trend, MISO’s systemwide peak load consistently reached the 95th percentile, or about 97 GW.

Posted on

4 Entities Join NV Energy in Exiting WRAP, While Idaho Power Commits

Calpine, Eugene Water & Electric Board, Portland General Electric and Public Service Company of New Mexico have joined NV Energy in leaving the Western Resource Adequacy Program, while Idaho Power signaled its continued commitment, reflecting the complexity surrounding the emergence of day-ahead markets in the West.

PNM, PGE, EWEB and Calpine announced their intent to withdraw from the Western Power Pool’s WRAP in four separate letters posted on WPP’s website Oct. 29. NV Energy informed the Public Utilities Commission of Nevada about its plans earlier in 2025, but its formal withdrawal notice was published on WPP’s website Oct. 27. (See NV Energy to Withdraw from WRAP.)

PNM, PGE and EWEB each cited different reasons for leaving WRAP, while Calpine offered no details about its departure.

PNM’s Senior Vice President Laurie Williams said the decision to withdraw followed “careful consideration of several factors, most notably the emergence of two day-ahead markets in the West: the CAISO Extended Day-Ahead Market (EDAM) and SPP Markets+ (M+).”

All load-serving entities in Markets+ must participate in WRAP. By contrast, EDAM won’t require participation in an organized resource adequacy program. Instead, it will use a resource sufficiency evaluation to ensure participants’ RA going into the day-ahead and real-time time frames to meet their own needs without depending on others.

But some EDAM participants have discussed launching a separate RA program. NV Energy and the Imperial Irrigation District, both of which have committed to joining EDAM, have said they are discussing the potential for a new Western RA program. (See EDAM Participants Exploring Potential New Western RA Program.)

PNM’s withdrawal notice provided fodder for this idea, with Williams writing that the utility “believes it is prudent to pursue resource adequacy programs aligned with each market, consistent with practices in other ISO/RTOs.”

Williams commended WPP’s efforts to address concerns with day-ahead markets, planning reserve margins and deficiency charges. She noted that WPP has created task forces aimed at tackling those issues but said “these initiatives remain preliminary and require further development, and as such, PNM is unable to make a binding commitment to the program in its current state.”

“PNM remains committed to resource adequacy in the West and will continue to engage with WRAP and participate in [Resource Adequacy Participants Committee] during our transition over the next two years,” Williams wrote. “We remain confident that the foundational work of WRAP entities will support future efforts to coordinate across evolving market structures.”

PGE CEO Maria Pope said the utility would exit WRAP before the Oct. 31 deadline, citing “continued uncertainty regarding program design, technical readiness, and alignment with evolving market structures.”

Just like the other participants that submitted their exit notices, Pope expressed appreciation for WPP’s efforts, saying PGE “remains committed to working collaboratively with the Western Power Pool and regional partners to strengthen WRAP. We remain a member in good standing of the WRAP in a non-binding status with all the privileges and requirements of a member.”

NV Energy kept its formal withdrawal notice brief, stating it “appreciates the collaborative efforts of the WRAP community and looks forward to future opportunities for regional coordination.”

NV Energy announced its plans to leave WRAP in filings with the Public Utilities Commission of Nevada. The utility cited five “critical issues,” including “steep penalties for capacity deficiencies identified seven months before the compliance season,” and potential disadvantages for EDAM participants.

Calpine’s withdrawal letter was similarly brief, with Senior Vice President Neil Bresnan providing no explanation for the move. The independent power producer operates about 27 GW of resources across the U.S., with most of its Western plants concentrated in California, along with one combined cycle gas plant each in Arizona and Oregon.

‘Strong Supporter’

Of the five entities notifying WPP of their withdrawal from the WRAP, EWEB is possibly the only one seriously leaving the door open for future participation.

In its letter, the Oregon-based municipal utility, which sits within the Bonneville Power Administration’s balancing authority area, said its decision “is based on our need to align future participation in the Binding Program phase with the start of our next Bonneville Power Administration (BPA) Power and Transmission contracts, which take effect October 2028,” noting that BPA serves as the utility’s “primary energy/transmission supplier.”

“This notice reflects EWEB’s specific operational and contractual circumstances and should not be interpreted as a criticism of WRAP or its objectives,” EWEB CEO Frank Lawson wrote in the letter. “EWEB remains a strong supporter of the development of regional resource adequacy standards and recognizes the vital role WRAP plays in advancing reliability across the Western Interconnection. We value the opportunity to have participated in the program’s formation and remain committed to advocating for WRAP’s continued success.”

Lawson said the utility would seek to meet with WPP staff “to discuss the appropriate steps, timing and obligations associated with our participation during the notice and withdrawal period” and to ascertain “available options for fulfilling any residual obligations under the tariff during this time.”

EWEB spokesperson Aaron Orlowski told RTO Insider the views set out in the utility’s letter “weren’t just words” but genuinely reflected its position on the WRAP, including its continued support for the program. He said the financial risks of participating in the program’s penalty phase ahead of securing the BPA contracts prevented EWEB from committing at this point, but that it looked forward to joining in the future.

‘Continued Refinement’

Idaho Power was the clear standout in announcing its intention to remain in the WRAP, especially given that the Boise-based utility has signaled it is leaning toward joining EDAM rather than Markets+ — although it may be better positioned than most to avoid penalties. (See WRAP Participants Find Value in Program’s Nonbinding Phase.)

In its letter, CEO Lisa Grow lauded the “dedication and hard work” of WPP staff and stakeholders in developing the WRAP but pointed to “several key areas that warrant continued attention and improvement,” including issues related to the “ongoing volatility and variability” of planning reserve margins, day-ahead markets and deficiency penalties.

On the evolving markets in the West, Grow wrote that “[i]t is essential that WRAP continues to evolve in a way that equitably accommodates participants across different market structures — or those not in a market at all — to ensure broad and sustained participation.”

Grow noted the utility supports the WRAP’s recently approved deficiency charge deferral resolution and the “continued refinement” of deficiency charge provisions.

“This provision is especially critical for entities like Idaho Power that are making substantial investments in new generation and transmission infrastructure over the next five years,” she wrote.

Grow said that while Idaho Power is prepared for the first binding season, the utility thinks “it will be important to evaluate program and entity readiness between now and then,” pointing out that the WRAP tariff allows for potential delay in binding operations.

Looming Deadline

The withdrawal notices come as an Oct. 31 deadline looms for participants to commit to the WRAP’s first binding phase in winter 2027/28. Of the 11 members that so far have committed to the program’s first binding season, all but one are expected to join Markets+.

Carrie Simpson, SPP vice president of markets, told RTO Insider that “Markets+ continues to move forward with strong participant commitment. While some entities have provided notice of their intent to exit WRAP, it does not impact the viability of Markets+.”

The recent withdrawal notices come as other WRAP participants have expressed some concerns with the program. For example, PacifiCorp requested additional time before committing to the program’s binding phase. (See PacifiCorp Asks WPP to Delay WRAP ‘Binding’ Phase Commitment Date.)

PacifiCorp and PGE are slated to become EDAM’s first participants in 2026.

In response letters to PacifiCorp and PGE, WPP Board Chair Bill Drummond said delaying the binding phase “would have a detrimental effect on reliability for the region, including undermining confidence in WRAP data and modeling, limiting program compliance and preventing us from unlocking the full benefits of the program.”

Posted on

SERC’s Moran Warns of Growing Climate Security Risks

Utilities and regulators no longer can afford to think of extreme weather and grid-directed violence as separate reliability risks, a speaker at SERC Reliability’s Fall Reliability and Security Seminar said.

Travis Moran, SERC’s senior state government and regulatory affairs adviser, reminded seminar attendees that U.S. electric utilities have seen numerous close calls from attempted violence in recent years, including a plot by neo-Nazi leader Brandon Russell and an accomplice to attack electric substations in Baltimore in order to set off a civil war. (See Neo-Nazi Convicted in Baltimore Grid Attack Conspiracy.) Moran also mentioned Skyler Philippi, who recently pleaded guilty to planning a bomb attack against a substation in Tennessee.

While those schemes were thwarted by law enforcement, Moran asked attendees to think about what would happen if such attacks went as planned — and how a severe weather incident at the same time would complicate efforts to restore electric service. Experts have warned about this kind of attack before, but Moran emphasized that the danger is far from hypothetical.

“Militaries [have] known this doctrine for a long time — ours has and everyone’s around the world,” Moran said. “Russia is using it to great extent right now. They’ve been attacking Ukraine’s [energy infrastructure], always heavily during and before the winter months … to increase the suffering. The hope was that that suffering would lead them to cave; it didn’t work out that way, but the suffering is still great.”

The appeal of such a strategy is obvious, Moran said, because it means potential attackers “don’t have to create the chaos [but can] just wait for nature to do it.” As an example, he pointed to Hurricane Helene in 2024, when millions of customers across 10 states lost power. (See Helene Repair Efforts Could Last Weeks for Hardest Hit, Remote Areas.)

Restoration took weeks in some cases because the remote locations of some substations meant “roads couldn’t even support the heavy equipment they were trying to get in.” Repair prospects would have been even worse if attackers had taken advantage of the coming storm to damage key equipment such as transformers and repair crews had to find a way to deliver those through devastated infrastructure.

“You know they know this. Why would I want to attack you on a 65-degree day when there’s low load on the system? … All I got to do is pay attention to the weather forecast, and I can exacerbate the suffering of [everyone]. It’s just common sense, unfortunately, and that’s how they think,” Moran said. He added that the danger is not limited to physical attacks; enemies could easily choose to launch cyberattacks against utilities’ electronic systems while they are preoccupied with extreme weather restoration.

Staying ahead of determined adversaries will require equal determination from the grid’s protectors, Moran said, along with a willingness to learn. This means information sharing within their organizations, between employees on the same level and between management and lower-level employees.

Utilities also must be open about their challenges with each other, with regulators, and even with counterparts in other industries. Moran observed that utilities increasingly are co-dependent with data centers, which provide the computing power for many business processes but also account for a rapidly growing share of demand that, if interrupted suddenly, could cause stability problems on the larger electric grid. Given this vulnerability, he said, it makes sense for the electric and data center industries to work more closely.

Throughout his talk, Moran quoted the 9/11 Commission Report, which partly blamed a “failure of imagination” for the federal government’s inability to predict the Sept. 11, 2001, terrorist attacks that destroyed the World Trade Center and damaged the Pentagon. He stressed to attendees that “we shouldn’t want to be here again,” and that “if you can imagine it, [our enemies] have already thought about it.”

“You’re your own best protectors,” Moran said. “Your information that you share internally, and those contacts you have internally, that’s what’s going to save you.”

Posted on

FPL Leading Southeast in Solar Buildout, SACE Report Finds

Solar power generation will expand strongly but not uniformly in the Southeast through the rest of the decade, the Southern Alliance for Clean Energy said in its annual solar report.

The seven-state region ended 2024 with 27.84 GW of installed capacity in areas outside PJM and MISO territory and is expected to reach approximately 54 GW in 2030, SACE reported.

“We are very bullish on solar power; have been for a long time,” SACE Executive Director Stephen Smith said during an Oct. 29 webinar, “and as you’ll see in this report, we’re beginning to see that some states are really starting to make big bets in solar and break away and make it a workhorse technology that we think is necessary.”

“Solar in the Southeast” shows Florida leading the region’s buildout, with nearly 14 GW installed in 2024 and 29.5 GW expected by 2030. It says the steady growth in the Carolinas and Georgia is driven by the large projects of just a few major utilities. And it says Tennessee, Alabama and Mississippi bring up the rear, at least in part from the Tennessee Valley Authority’s challenging requirements for solar additions.

“There’s actually several utility-scale projects that are coming online from TVA in the next couple of years,” Senior Energy Policy Manager Heather Pohnan said. “However, the historical lack of ambition from the utilities that operate in these states really makes it difficult to keep pace with the rest of the region.”

The bulk of installed solar capacity is in utility-scale projects, and three utilities accounted for much of the 27.84 GW: FPL (8.38 GW), Duke Energy (8.22 GW) and Southern Co. (4.04 GW).

FPL also has the biggest ambitions among utilities studied, as judged by their integrated resource plans: 8.5 GW of new solar by 2030, or 64% of its planned capacity additions. The next-largest planned solar additions are TVA’s 2.83 GW, which would be 32% of its total. Least ambitious are Alabama Power and Santee Cooper, which plan solar to be just 9 and 7%, respectively.

Florida dominates and is expected to continue dominating installed solar capacity in the Southeast United States. | Southern Alliance for Clean Energy

The SACE report adds a caveat about TVA’s stated intentions: President Donald Trump has purged its board of directors and nominated new members who could change the solar plans. (See Trump’s TVA Nominees Reject Privatization.) Those nominees are before the full Senate after being advanced by the Environment and Public Works Committee on Oct. 29.

Speakers in the webinar praised FPL for its strong solar ambitions and track record in meeting them. SACE Clean Energy and Equity Director Stacey Washington pointed to FPL’s goal of 17,500 MW.

“This is a large goal, but FPL has demonstrated that it is capable of adding a lot of solar to the grid at a steady pace. With 2,250 MW coming online in 2024, FPL has established a process to source and build utility-scale solar at a fast pace.”

An audience member at the webinar questioned why praise was being showered on FPL.

“Let’s just be really clear,” Smith said: “Florida Power & Light has laid down the most ambitious solar deployment program of any utility in the Southeast, by far, and … probably one of the most ambitious programs of any utility across the United States.

“It needs to be recognized,” he said, “and it needs to be called out, and we need to hold other utilities accountable, because this utility is actually moving away from fossil gas. They’re still highly dependent on it, but you’re actually seeing the reductions. You’re seeing the deployment.

“What we don’t have is — in Georgia and in the Carolinas, and definitely at TVA — a real commitment to this technology.”

There are practical impediments to solar deployment, such as transmission constraints and disappearing federal subsidies.

“Transmission has become a roadblock to solar; in many places, it’s quite significant. In other places, it’s just a matter of time, it seems,” said SACE Research Director Maggie Shober.

Washington recited the list of 2025 federal program cuts and tax credit phaseouts and said distributed solar would feel the impact before utility-scale solar.

Distributed solar already has a difficult path in the Southeast, Shober said, even with FPL. There is a bias toward utility-scale, she said, and there is not a good net-metering program that can make small-scale solar more attractive.

“I think the utility business model in our region is set up that utilities are inherently against rooftop solar and customer-based solar,” she said, “not because they don’t like it, but just because it’s not in their financial interest to encourage it, and so they are setting up as many roadblocks as they can.”

Smith said electricity costs are rising to the point of an affordability crisis, so the industry should focus on the capacity it can add in the least time at the lowest cost: solar and storage.

He also put in a plug for utilities and regulators to embrace energy-efficiency programs. “The greenest electron [and] most cost-effective electron is the one that you never use.”

SACE drew data for the report from the utilities’ integrated resource plans and U.S. Energy Information Administration reports on currently operating utility-scale and distributed solar resources.

Posted on

ISO-NE Talks Order 2023 Updates at NEPOOL Transmission Committee

Proposed tariff changes, intended to update how ISO-NE assigns capacity rights to resources not subject to its interconnection processes, were introduced at the NEPOOL Transmission Committee meeting Oct. 28.

Alex Rost, director of transmission services, said ISO-NE proposes to “formalize the concept of equivalent capacity network resource capability (CNRC) and address how equivalent CNRC is established, managed and reduced.”

CNRC values define the capacity interconnection rights of resources that are subject to ISO-NE’s interconnection procedures. Before FERC Order 2023, resources established CNRC by obtaining capacity supply obligations (CSOs). In the new interconnection framework, those resources gain CIRs via the cluster study processes.

The Order 2023 changes have created a need “to clarify how equivalent CNRC is assigned, managed and reduced” under the new interconnection framework, Rost said.

Resources not subject to the RTO’s interconnection procedures that could receive equivalent CNRC values include those connected to the distribution system, aggregations of distributed resources and active demand resources, he noted.

“For consistency with resources subject to the ISO interconnection procedures, the process to establish equivalent CNRC … should be supported by clear and trackable commitments related to a resource achieving commercial operation,” Rost said.

To establish equivalent CNRC, resources would need to prove their deliverability in an “all-or-nothing deliverability analysis screen,” which would be coordinated with the similar deliverability analyses performed in ISO-NE interconnection cluster studies.

Deliverability analyses for resources seeking equivalent CNRC would be performed “right after the conclusion of a cluster study” and would be adjusted “as needed” following cluster restudies, Rost said.

After proving deliverability, resources could achieve equivalent CNRC by obtaining a CSO or by “locking-in” equivalent CNRC prior to participating in a capacity auction, Rost said.

The rules for the CSO pathway to achieving equivalent CNRC would be “very similar to the pre-Order No. 2023 approach used to establish CNRC,” Rost noted. CNRC values would “equal the highest amount of CSO obtained in a capacity market activity,” with seasonal adjustments to account for varying winter or summer capabilities.

To achieve equivalent CNRC prior to auction participation, developers would need a commercial operations date within the following two years and would need to demonstrate adequate financial commitment to the resource.

For resources following this path, ISO-NE would rely on winter and summer qualified capacity estimates “consistent with capacity market qualification.”

“‘Locked-in’ equivalent CNRC must be assigned to a specific project and will be withdrawn if the specific project has its interconnection agreement (or equivalent) terminated or fails to achieve commercial operation within two years from the date that equivalent CNRC is requested,” Rost said.

ISO-NE plans to maintain its existing methods for reducing or retiring equivalent CNRC; resources could request deactivation or would be automatically retired if they are inactive for three years.

Rost said the RTO plans to implement the changes prior to the 2026 interim Reconfiguration Auction qualification process. ISO-NE will discuss the proposal with stakeholders in the coming months and is targeting a TC vote in January.