Search
February 11, 2025

Posted on

SCE Probes Link Between Equipment and Eaton Fire

Southern California Edison told the California Public Utilities Commission on Feb. 6 that it is reviewing videos suggesting a link between its equipment and the devastating Eaton Fire in Los Angeles, while also acknowledging its equipment may have sparked the smaller Hurst Fire. 

SCE said in a letter to the CPUC that a video published by the New York Times “appears to show two flashes of light in the Eaton Canyon area” on the evening of Jan. 7, around the time the Eaton Fire started. The video led the utility to launch an internal investigation into whether there is a connection between the flashes and SCE’s equipment, according to the letter. 

“Information and data have come to light, such as videos from external parties of the fire’s early stages, suggesting a possible link to SCE’s equipment, which the company takes seriously,” the utility said in a news release. “SCE has not identified typical or obvious indications that would support this association, such as broken conductors, fresh arc marks in the preliminary origin area or evidence of faults on the energized lines running through that area.” 

However, SCE acknowledged in a separate letter that its equipment may have sparked the Hurst Fire, which burned roughly 799 acres and damaged two homes. There were no reports of fatalities or injuries associated with the fire. The Los Angeles Fire Department still is investigating, and SCE said it is cooperating with the probe. 

Eaton Fire

SCE has three transmission towers, which collectively carry four active transmission lines, in the area where the Eaton Fire started. The lines were reenergized briefly Jan. 19, but field workers deenergized them again after noticing small flashes of white light upon each reenergization, according to SCE’s letter to CPUC. 

Before-and-after photos of one of the towers show no “obvious signs of arcing or material changes.” SCE said it expects to learn more after it can thoroughly inspect the structure.  

Photos from a different structure approximately “five circuit miles from the preliminary origin area” did find “signs of potential arcing and other damage on the grounding equipment for two of the three idle conductors,” SCE wrote in the letter to CPUC. 

“SCE does not know when this damage occurred, and a comparison between pre- and post-fire photographs is underway,” the letter stated. “SCE continues to assess these facilities, including any potential relation to the cause of the fire.” 

The utility also said it had not found any faults with the four energized transmission lines that run through the Eaton Canyon in the 12 hours before the reported start time of the fire. 

The Eaton Fire began shortly after 6 p.m. Jan. 7 and burned more than14,000 acres. The deadly fire engulfed parts of the Altadena community, with thousands of structures either damaged or destroyed. The flames claimed at least 17 lives, according to Cal Fire.  

SCE filed an incident report related to the Eaton Fire on Jan. 9 after receiving “significant media attention” and preservation notices from counsel representing insurance companies.  

A spokesperson for the utility told RTO Insider in January that “no fire agency has suggested that SCE facilities were involved in the ignition of the [Eaton] fire, and they have not requested the removal and retention of any of our equipment.” 

In its most recent update to the CPUC, SCE contended it has performed numerous inspections from 2020 through 2024 on its transmission facilities in the Eaton Canyon. 

The utility said it is evaluating several “potential causes,” including whether one of the lines became energized through, for example, induction. SCE also is investigating “human activity near the county’s preliminary area of origin.” 

SCE said the investigation could take several months to complete. 

If SCE’s equipment is found to be at fault, the utility’s credit rating could take a hit, Moody’s Ratings cautioned in a report Jan. 16, per Reuters. The report also said the company could see financial damage if the California Wildfire Fund runs out of money. Utilities pay into the fund to receive reimbursements for some wildfire claims.  

Additionally, legal challenges are starting to trickle in. Some affected by the Eaton Fire have filed lawsuits against SCE, alleging the blaze began under one of the company’s transmission towers. SCE also has received preservation notices from counsel representing insurance companies.  

Posted on

SPP Sets Deadline for Markets+ Funding Agreements

Financial backers of Phase 2 of SPP’s Markets+ have until Feb. 14 to submit executed funding agreements, the RTO said in a monthly newsletter sent out Feb. 5.

SPP said it will distribute the agreements to “interested parties” — the key market participants — on Feb. 7. The RTO has estimated the Phase 2 implementation stage will cost about $150 million.

The Feb. 5 newsletter also said SPP is “working to finalize” Phase 2 “intent to participate” agreements and stakeholder agreements for non-funding parties, which should be distributed later this month.

Markets+ so far has received solid commitments from Powerex, Arizona Public Service, Salt River Project, Tucson Electric Power, UniSource Energy Services, El Paso Electric and Chelan County Public Utility District in Washington.

The funding agreement deadline could pose a challenge for the Bonneville Power Administration, which repeatedly has affirmed that it plans to shell out its estimated $25 million share for funding Phase 2 before making a decision to commit to the market. But BPA, which would be the second largest funder after Powerex, also recently indicated it still is working out details around the exact amount and timing of its payment. (See BPA Considers Impact of Fees in Day-ahead Market Choice.)

Speaking at a Jan. 28 workshop at BPA’s Portland, Ore., headquarters, staff told stakeholders the agency estimates it would incur $13 million to $15 million in annual operating costs to participate in Markets+, on top of the $25 million in implementation fees. By comparison, CAISO’s Extended Day-Ahead Market would cost $2.5 million to $3 million in upfront implementation costs, with annual costs in the form of ISO grid management charges estimated at $29 million.

BPA did not respond to a request for comment in time for publication of this article.

Asked whether BPA might be allowed an exception to the deadline, SPP spokesperson Meghan Sever said: “Like with Phase 1, there will be a grace period to give entities the time needed to sign and return agreements.”

Sever also pointed out that non-funding parties signing agreements to participate in Phase 2 “will have a separate timeline for those agreements, which will be sent once the funding agreement process is complete.”

At a Feb. 4 meeting of SPP’s Board of Directors, SPP COO Antoine Lucas said the funding agreements already have been distributed for review by participants, and the RTO could receive those executed “as early as the middle of this month.”

Lucas said hitting the Markets+ scheduled go-live date of 2027 is “really going to depend upon the timeliness of receiving executed agreements to move forward with the market.”

Posted on

Xcel Sees Little Effect from Executive Orders on Energy

Xcel Energy CEO Bob Frenzel told financial analysts Feb. 6 that the Trump administration’s energy-related executive orders will have little effect on the company’s operations.

Frenzel reminded analysts during the company’s fourth-quarter conference call that Xcel doesn’t have any wind projects offshore or on federal lands and that its permitting needs for wind, solar and storage assets are “relatively light.”

“I think we’ll be able to work through it all, and I’m optimistic that our capital plans for 2025 and beyond are going to remain intact,” he said. “We’ll be able to work with the administration and all the agencies to make progress here.

“We need to be able to move very quickly on building our infrastructure and making sure that we can serve our customers. Look, we support permitting reform broadly at a national and even state and local levels in order to be able to build the infrastructure we need to meet this era of growth.”

Xcel faces 30% expected load growth over the next five years. It has added $10 billion of additional capital investment to its base five-year plan, now at $45 billion. Transmission plans approved by MISO and SPP in December will require as much as $4 billion in capital investments, Frenzel said.

The company in November completed the first phase of solar installations at its Sherco plant site, where Xcel is in the process of retiring three coal units. They will be replaced by a 710-MW solar facility that Frenzel said would be the largest in the upper Midwest.

Xcel reported year-end earnings of $1.94 billion ($3.44/share), compared with $1.77 billion ($3.21/share) in 2023. It said the year-over-year earnings growth reflected increased recovery of infrastructure investments, partially offset by higher depreciation, interest charges and operations and maintenance expenses.

The company said adjusted earnings per share were $0.81 for the fourth quarter. That fell short of the analyst consensus of $0.89/share. Revenue for the quarter was $3.12 billion, also below the consensus estimate of $3.77 billion.

Xcel’s share price closed at $67.12, dropping 83 cents on the day from its previous close.

Posted on

NERC Updates FERC on IBR Registration Progress

More than 850 inverter-based resources that are not currently registered with NERC likely will have to be so under the ERO’s proposed IBR registration criteria, the organization told FERC in a filing Feb. 5 (RD22-4). 

NERC submitted the estimate in its quarterly progress update on the registration initiative, which the ERO is required to perform under FERC’s June 2024 order approving changes to NERC’s Rules of Procedure. (See FERC Accepts NERC ROP Changes, Drops Assessment Proposal.) The ROP changes allowed the organization to register owners and operators of IBRs that currently are not required to register but that are connected to the grid and, “in the aggregate, have a material impact” on reliable operation.  

They did so by creating a new category of generator owners called “Category 2 GOs,” comprising entities that own or maintain IBRs that “either have or contribute to an aggregate nameplate capacity of greater than or equal to 20 MVA, connected through a system designed primarily for delivering such capacity to a common point of connection at a voltage greater than or equal to 60 kV.”  

According to NERC’s filing, there are 863 IBRs meeting the Category 2 criteria with a total nameplate capacity of 38,785 MVA, distributed as follows among the regional entities: 

    • MRO — 149 IBRs with a total nameplate capacity of 6,614 MVA. 
    • NPCC — 75 IBRs; capacity of 2,422 MVA. 
    • ReliabilityFirst — 100 IBRs; capacity of 4,194 MVA. 
    • SERC — 175 IBRs; capacity of 10,473 MVA. 
    • Texas RE — 41 IBRs; capacity of 2,167 MVA. 
    • WECC — 323 IBRs; capacity of 12,915 MVA. 

NERC developed the estimate after issuing a request for information to balancing authorities and transmission owners on July 9, 2024, for “relevant information on those entities within their footprints that could meet the … registry criteria.” The estimates for both the number of IBRs and their capacity were calculated as of Jan. 24 and may change as more information is gathered. 

In addition, the ERO said the “numbers do not necessarily reflect the total number of GOs or GOPs that will be registered based on the Category 2 criteria, as the Functional Entity assignment will be determined once the ERO Enterprise receives more information about the entities.” NERC said it will provide updated numbers in future quarterly reports. 

NERC is nearing the end of the second year of its IBR registration work plan, which FERC approved in May 2023. (See FERC Approves NERC’s IBR Work Plan.) The plan laid out a three-year process for completing the registration: revise the ROP to create an appropriate registered entity function within 12 months of the plan’s approval; identify candidates for registration within 24 months; and register appropriate entities within 36 months. 

The ERO said it already has “initiated communications with newly identified entities that may be candidates for registration as Category 2 GO/GOPs.” Training for the Centralized Organization Registration ERO Systems (CORES) will be provided to newly registered entities in months 25 and 26 of the work plan, or June and July 2025. NERC plans to complete registration by May 2026. 

Posted on

FERC’s Christie Discusses Making Electricity More Affordable at NASEO

WASHINGTON — FERC Chair Mark Christie wants to help bring down consumers’ power bills by addressing what has driven them up most in recent years: spending on the transmission and distribution system, he said at the National Association of State Energy Officials’ Energy Policy Outlook Conference. 

“The last four years [have] seen the highest rate of inflation in people’s monthly power bills over the last 25 years,” Christie said Feb. 6. “That’s a fact. People are struggling depending on the power bills.” 

Christie is accustomed to people complaining about their utility bills after 17 years as a state regulator in Virginia and since joining FERC in 2020. Natural gas prices shot up after Russia invaded Ukraine but have fallen back from that high. 

But the transmission and distribution parts of consumer bills have been climbing. State regulators oversee the distribution system, and they also have some oversight of transmission. But FERC sets rates for the interstate commerce lines. 

FERC regulates the RTOs, which have taken over the planning of transmission. But they often only lightly oversee smaller, “local projects,” as opposed to the more in-depth reviews the organized markets carry out in their regional planning efforts. RTOs, especially the large multistate markets, lack the resources to properly oversee all the local lines that come before them, Christie said.  

“We have to build transmission to serve consumers, not to serve special interests,” he said. 

Even if an RTO says a local line is needed, it is a healthy process to have a state regulator examine the project and what’s driving the need for it, he added. 

“Go back and check your state laws — you need a strong, robust permitting process,” Christie told the room full of state officials. 

State officials should pay attention to what their RTOs are doing and that involves working with state utility regulators, who already are engaged with the organized markets, Christie said. 

Christie gave the standard disclaimer that he was talking about issues generally, and he did not mention any specific cases. But just before the holiday break, a major complaint seeking greater FERC oversight of local transmission was filed with the commission. (See Consumer Groups Seek Independent Oversight of Local Tx Planning.) 

National Rural Electric Cooperative Association CEO Jim Matheson wrote Christie a letter Feb. 5 congratulating him on his elevation to chair and urging him to focus on affordability, among other issues. The co-op trade group supports Christie’s efforts to give states a bigger role in the planning of the grid on Order 1920-A and agreed that state regulators, and co-ops (that set their own rates for consumer-members), are the first line of defense from excessive transmission costs. 

“Under Order 1920-A, there are significant holes in that line of defense where cooperative consumer-members are concerned, and we urge you to address this inequity in the future so that all consumers receive the protection they deserve,” Matheson said. 

Christie Addresses Other Issues

An attendee asked about natural gas and electric coordination. Christie noted that while the power increasingly relies on the fuel as part of its baseload supply, gas generators still largely rely on just-in-time fuel delivery. One rule change that should be examined is whether they should be required to store fuel. 

FERC has been working with the electric industry and the pipeline industry on improving gas coordination for years, and that work has seen progress, but Christie said that work could be expanded to bring in more entities. 

“What about everyone else that needs gas?” Christie said. “We have manufacturers that need gas. And, of course, the LDC [local distribution companies] still need gas.” 

Responding to another question on the rise of data centers and co-location with generation, Christie said every customer who uses power effectively is a cost-causer, whether it is a new residential account, or a massive data center with demand in the hundreds of gigawatts. 

“We have gotten a bunch of cases regarding what’s called co-location,” Christie said. “I’ve said this publicly several times and I’ll say it again — we’re going to address it; we’re going to address it soon.” 

FERC will handle the issues around data centers on the federal side, but ultimately, the facilities are customers of utilities, so states have a major role to play in the process of meeting their demand affordably, he added. 

Posted on

SPP Board Approves 8 Urgent Short-term Projects

SPP’s Board of Directors approved eight short-term reliability projects (STRPs), a $3.15 billion package with immediate needs for this year through 2028, that were identified in the 2024 Integrated Transmission Planning assessment.

They include the first 765-kV project in SPP’s history, a $1.69 billion, 293-mile circuit in Southwestern Public Service’s territory in Texas and New Mexico. An attempt to pull the project from the list because of its price tag and make it subject to competitive bidding under FERC Order 1000 failed.

The directors followed the language in SPP’s tariff, which defines STRPs as upgrades that meet the criteria for competitive projects but that are needed in three years or less to address “identified reliability violations.” In that case, STRPs are not considered competitive upgrades under the tariff.

The board’s Feb. 4 approval means the incumbent transmission owners will receive notifications to construct for the projects.

“As a transmission-dependent utility and representing many transmission-dependent utilities, there’s always been a lot of concern over … circumventing the Order 1000 process,” the Oklahoma Municipal Power Authority’s Dave Osburn said during the discussion preceding the vote. “We’re saying all these projects are required this year, and we know they’re not going to be done. Bringing $3 billion worth of lines with a need date of this year, something about that doesn’t sit well.”

Renewable interests and developers and cooperatives made their opposition known during a 30-day comment period earlier this year after staff’s designation of the STRPs. They said the projects would not be subject to the cost controls and schedule guarantees that competitive projects face, leading to a risk of delays. Previous directly assigned projects have been delayed without current means of holding the assignees accountable, they also said.

Transmission owners supported the designated projects, saying they complied with the tariff and FERC precedent, that they would address persistent operational needs and eliminate the need for load shed during future winter storms.

“I don’t believe that this is circumventing Order 1000,” Evergy’s Denise Buffington said, responding to Osburn. “I think Order 1000 and the compliance filings that were in front of FERC contemplated the scenario that there would be times when there are projects that are immediate needs and that need to be done soon for reliability reasons. Load shedding is not a mitigation … I don’t think any incumbent transmission owner that has customers potentially going in the dark are going to wait on these projects. These projects are going to be the highest priority, and we are going to get them done as soon as is possible.”

Director Ray Hepper thanked members for their comments and said the board had an “incredibly important and challenging discretion” to determine whether the projects should be competitive or directly assigned.

“For me, this creates a real challenge. What criteria should I use to guide my vote?” Hepper said. “On one hand, I can simply say all these projects are needed within three years and therefore, they meet the terms of the tariff. On the other hand, I can argue that FERC has concluded that competition is good and therefore all these projects should go out for bids. These are the relatively more straightforward bookends of the discussion.”

Board Chair John Cupparo advocated the directors consider establishing clear mechanisms to avoid a similar situation in the future. He said should the board agree, it will engage staff and stakeholders to gather necessary input before the 2025 ITP is released in October.

“It’s my understanding that the board has full discretion over how to treat the short-term reliability project list, and it’s our role to determine how we want to treat it each time it comes before us,” Cupparo said. “In my opinion, we are obligated to evaluate and understand all reasonable options and the benefits and impacts on the entire SPP footprint and its 18 million residents.”

The Members Committee’s advisory vote rejected the motion to designate the 765-kV project as a competitive project, 7-11, with three abstentions. It approved the designation for all eight STRPs, 14-6, with one abstention. The board sided with both votes.

The STRPs were culled from the 89 potential projects in the 2024 ITP. The board in December approved 12 of those as winter-weather projects, with 11 staged on or before Dec. 1, 2025, to resolve the remaining winter reliability needs.

The eight STRPs are:

    • Holcomb-Sidney (Kansas), new 345-kV line, 135 miles.
    • Delaware-Monett (Oklahoma and Missouri), new 345-kV line, 114.5 miles.
    • Monett-North Branson (Missouri), new 345-kV line, 47.2 miles.
    • Phantom-Crossroads-Potter (New Mexico, Texas), new 765-kV line, 293 miles.
    • Iron House-Texaco (New Mexico), new 115-kV line, 2.3 miles.
    • Grapevine-Kingsmill (Texas), new 115-kV line, 10.7 miles.
    • Moore County-XIT (Texas), new 230-kV line, 46.2 miles.
    • Buffalo Flats-Delaware, new 345-kV line, 154.6 miles.

Three of the projects — Phantom-Crossroads-Potter, Grapevine-Kingsmill and Moore County-XIT — have been assigned to SPS, which is facing unprecedented demand from new manufacturing, oil and gas growth, and its communities.

Xcel Energy, the parent company of SPS, said all three lines are “crucial” for maintaining a reliable electricity supply. It said the Phantom-Crossroads-Potter line is “especially important” in supporting load growth.

“I understand the concern about one project being a significant cost in the portfolio. The alternative could have been multiple other lines in which this discussion may not be revolving around a single project, but it could have been multiple other projects,” SPS’ Jarred Cooley said during the board discussion. “SPS has a very strong track record of building projects on time and under budget. The last eight 345-kV projects in our footprint have done that, and we definitely would be ready, willing and able to build this line as soon as given the go-ahead.”

The eight projects completed over the past seven years added 318 miles to a high-voltage transmission network that now exceeds 8,000 miles.

Adrian Rodriguez, president of SPS, said in a statement Feb. 5 to RTO Insider that the utility is “honored to be entrusted with these critical projects.”

Posted on

NYPA Argues Clean Path Potential Benefits Outweigh Cost

The New York Power Authority has updated its petition to the Department of Public Service to get priority status for the transmission portion of the Clean Path project.  

The update includes cost estimates for the project, as well as an attachment forecasting the potential financial benefits to New York consumers. The total estimated cost for this version of Clean Path is about $5.2 billion. Most of the expense comes from the $3.8 billion cost of equipment, materials and labor.  

Industry watchers told RTO Insider on background that the estimates generally seemed reasonable for a project of its scope but wouldn’t speculate on the specifics.  

Clean Path originally was an $11 billion portfolio of projects between the developers and the New York State Energy and Research and Development Authority. The package would include 178 miles of HVDC line between upstate New York and Queens, and 23 renewable energy facilities. The public-private collaboration between NYPA and Forward Power was believed by many industry watchers to be dead when the original contract was canceled in November 2024. (See $11B Transmission + Generation Plan Canceled in NY.) 

The original petition to save the transmission portions of Clean Path did not include cost estimates or a cost/benefit analysis. (See NYPA Files Petition with New York PSC to Save Clean Path Project.) 

Cost/Benefit

NYPA projected two scenarios for assessing the benefits of Clean Path: one where the state does not achieve a 100% emissions-free electrical system by 2052, and another where the state achieves 100% zero-emission generation by 2040. Both scenarios assumed the Climate Leadership and Community Protection Act goal of 70% renewable generation will be achieved by 2033.  

Both scenarios evaluated the project’s impact on the “locational minimum installed capacity requirements” in New York City. NYPA evaluated the benefits of Clean Path in terms of the cost of energy production, locational capacity requirements, renewable energy and zero emissions credits, and congestion prices. Secondary market effects were not considered. 

In the less optimistic scenario, Clean Path would accrue $6.2 billion of benefits, roughly $4 billion of which comes from projected reductions in locational capacity requirements. This means the primary benefit would be felt in terms of reduced capacity prices, specifically by importing cheaper renewables to New York City.  

In the more optimistic scenario, Clean Path would accrue $21.5 billion in benefits. The difference between the less optimistic and more optimistic scenarios’ forecasts is driven primarily by dramatically increased “load payment savings.” In other words, NYPA predicts that if New York were to build Clean Path and transition to 100% emissions-free renewables, the market would spend about $11 billion less on load. Spending on the production of energy and congestion also would save about $5.8 billion combined. 

The Department of Public Service (DPS) has not yet solicited public comment on the updated petition. Sources consulted on background said comment probably would be solicited within a week or so. Comment periods typically are open for 60 days. It’s likely DPS already is assessing the findings put forward in the petition, but it’s unclear how long after the comment period DPS will announce a decision.  

Posted on

SEIA: US Now Manufacturing More Solar Panels Than It Installs

The U.S. now can manufacture enough solar panels to meet domestic demand but still must import most of the core components ― the solar cells and the silicon wafers used to make them ― according to the latest figures from the Solar Energy Industries Association. 

The U.S. has enough solar panel manufacturing capacity to produce more than 51 GW of panels per year, with an additional 17.5 GW under construction and 23.5 GW of additional capacity announced. The industry installed 40.5 GW of solar in 2024, according to a separate year-end report from SEIA.  

The upstream supply chain, however, lags far behind. The nation has only 2 GW of solar cell manufacturing online versus 42.6 GW announced and 11.8 GW under construction. Production of silicon ingots and wafers has yet to go online, with only 3.3 GW under construction.  

SEIA is putting a positive spin on the disconnect, noting that it originally set a 50 GW target for panel manufacturing in 2020, expecting to hit that goal by 2030. Reaching and exceeding the benchmark five years ahead of schedule “is a testament to what we can achieve with smart, business-friendly public policies in place,” CEO Abigail Ross Hopper said in a Feb. 4 press release.  

“The U.S. is now the third-largest module producer in the world because of these policy actions,” Hopper said. “This milestone not only marks progress for the solar industry but reinforces the essential role energy policies play in building up the domestic manufacturing industry that American workers and their families rely on.”  

Without actually naming the law, Hopper is referring to the clean energy tax credits and incentives contained in former President Joe Biden’s Inflation Reduction Act. SEIA specifically advocated for the law’s advanced manufacturing production tax credit, applicable to solar manufacturing, and bonus incentives for solar projects that use products made in the U.S., according to the press release. 

The organization also successfully pushed for a 25% investment tax credit for domestic production of solar wafers and ingots, contained in the CHIPS and Science Act, which like the IRA was passed in 2022. 

SEIA frames the lag in cell and wafer manufacturing as the result of “sequencing the build-out of a domestic solar supply chain. Establishing production of downstream components like modules ensures there is sufficient demand for upstream manufacturing,” according to the press release.  

Tariff-proof Chinese Wafers?

Since President Donald Trump won the election in November, SEIA has been focused on protecting solar’s federal tax credits by positioning the industry as a critical part of Trump’s vision for U.S. energy dominance and independence, as well as a major source of the clean, affordable power needed to meet growing demand from data centers. 

The organization also continues to tout the private investment and jobs that solar manufacturing has brought to Republican states and congressional districts. By SEIA’s count, new or planned solar manufacturing facilities are located in 23 states with Republican governors and 122 districts with Republican representatives in Congress, versus 20 states and 90 districts with Democratic leaders and lawmakers.  

The industry’s weak spot, however, could be its continued dependence on imported cells and wafers. Private investments in new U.S. facilities could be at risk if congressional Republicans take steps to reduce or roll back clean energy tax credits and other incentives as part of their plans to extend the 2017 Tax Cuts and Jobs Act.  

First published by Politico, a recently circulated short list of potential budget cuts Republicans are considering includes discontinuing $300 billion in clean energy funding from the Infrastructure Investment and Jobs Act and an additional $56 billion in grants from the IRA.  

In an email to NetZero Insider, Elissa Pierce, a research analyst at Wood Mackenzie, notes that in 2024, “62.5% of US cell imports came from Cambodia, Malaysia, Thailand and Vietnam,” the four nations subject to antidumping and countervailing duty tariffs imposed by the Commerce Department in 2024. 

An investigation by the International Trade Commission found that companies in those countries were using Chinese components in their products, while seeking to circumvent existing U.S. tariffs on Chinese solar cells and panels.  

Pierce expects the percentage of solar cell imports from the four nations will decrease in 2025, with imports from Indonesia, Laos and South Korea rising.  

More to the point, she said, prospective cell manufacturers in the U.S. could still import wafers and ingots from China — even with increased tariffs — because “Chinese wafers are so cheap that this isn’t very impactful. Some of the cell manufacturers coming online this year have stated that they will get wafers from Southeast Asia.” 

The industry recently celebrated the opening of a new U.S.-owned cell manufacturer, ES Foundry, in South Carolina, Christian Roselund, senior policy analyst at Clean Energy Associates, wrote on LinkedIn. But he cautioned that “U.S. solar manufacturing is a long way from being able to meet the demands of our internal market at the cell level.” 

Erecting trade barriers and cutting federal incentives “will set back U.S. solar manufacturing, not advance it,” he said. 

Posted on

Puget Sound Energy Partners with Tech Co. to Promote Hydrogen

Puget Sound Energy and clean energy technology company Modern Hydrogen have launched an initiative aimed at expanding hydrogen technology among large gas customers to meet decarbonization goals.

The two Washington state-based companies have teamed up to boost the implementation of Modern Hydrogen’s technology, which can convert natural gas to hydrogen at the point of consumption. The focus is on customers in the commercial and industrial sectors, according to a Jan. 29 news release.

“PSE is undergoing the most significant transformation in our history as we strive to meet Washington state’s clean energy laws — some of the most ambitious in the nation,” Josh Jacobs, PSE vice president of clean energy strategy and planning, said in a statement. “Our partnership with Modern Hydrogen is a significant step towards achieving this vision, as their technology has the potential to help our largest gas customers accelerate their decarbonization programs and reduce their greenhouse gas emissions.”

Melanie Coon, public relations manager at PSE, told NetZero Insider that the utility is “in the process of identifying customers who use large amounts of natural gas and have considerable decarbonization goals. How they end up utilizing the hydrogen will be customized to their unique business and energy needs.”

The main target is heavy industrial and manufacturing customers. PSE is exploring the application of Modern Hydrogen’s technology in sectors like commercial and industrial heat, industrial HVAC, heavy equipment and fleet fueling, and distributed power generation, according to Coon.

That last category includes operations that require firm, on-site power generation with gas turbine infrastructure. This means that the data center, compressor station, warehouse and industrial equipment sectors could potentially apply the technology to their operations, Coon said.

Leigh D’Angelo, manager of communications and public relations at Modern Hydrogen, told NetZero Insider via email that the company’s technology allows customers to remove carbon from natural gas at the meter, converting the gas into hydrogen by a process called methane pyrolysis.

It does so by heating the gas to “extremely high temperatures in a zero-oxygen environment.” The carbon falls out as a solid “black snow” that can be used in asphalt products.

To burn the decarbonized gas, most end-users need to make “minimum equipment” alterations, according to D’Angelo.

Natural gas equipment can burn lower blends of hydrogen. To accept higher blends of clean hydrogen, a hydrogen-rated burner is needed to control the flame.

“Additional retrofits might be needed, depending on the equipment and application characteristics (gas lines, storage tanks, valves, etc.),” D’Angelo wrote. “This can be performed by the [original equipment manufacturer] or by a qualified engineering firm. Overall, these modifications are reasonable in cost. Most OEMs estimate that a [gas-to-hydrogen] retrofit is not more than 10% of the equipment cost.”

Posted on

House Hearing Examines How to Ensure US ‘Energy Dominance’

The House Energy and Commerce Subcommittee on Energy looked into how to meet demand growth in its first hearing of the new Congress on Feb. 5, which showed a clear partisan divide on how to meet it.

“In the last Congress, I asked every witness that appeared before us in this subcommittee the same question: Do we need more energy or less energy?” subcommittee Chair Bob Latta (R-Ohio) said. “And all of those witnesses all responded by saying we need more. The U.S. Energy Information Administration projects the United States will consume record amounts of electricity in 2025. The Department of Energy’s Berkeley Lab estimates that U.S. data center load growth, which already encompasses half the data centers in the world, is projected to double or triple by the year 2028.”

A reliable and affordable energy system involves building on policies from the Biden administration, Ranking Member Kathy Castor (D-Fla.) said.

“Nothing in [President Donald Trump’s] executive orders is designed to lower energy prices or help hard-working Americans,” Castor said. “Instead, across the board, the actions are a gift to big oil companies. They’re designed to boost their profits at the expense of working families across this country. It’s outlandish that the president declared an energy emergency at a time when the United States is producing more oil and gas than any country in history.”

While the two parties clash on many issues, Castor said that they share some interest in strengthening the electric grid, advanced nuclear power, critical minerals and battery recycling.

“We’re already producing record amounts of oil and gas. American manufacturing is booming thanks to the Inflation Reduction Act and the Infrastructure Investment and Jobs Act,” said Tyler O’Connor, partner at Crowell & Moring. “And our geopolitical adversaries like China and Russia are struggling to keep pace with American ingenuity and resolve. In other words, we have unleashed American energy, but there is still work to be done.”

Repealing those two laws, or withholding appropriated funds from projects that were supported by them, would serve to raise prices and be a blow to regulatory certainty, said O’Connor, who was the minority’s witness at the hearing.

Growing electric load requires more legislative action, with O’Connor asking the committee to consider what steps it can take to facilitate the permitting, planning and cost allocation of transmission lines. Supply chains for some critical components of the grid are still lagging, even years after the emergency conditions of the COVID-19 pandemic.

O’Connor also suggested that Congress ensure agencies that site energy projects, such as FERC, have their staffing levels maintained so they can get that work done.

“As I listen to both sides, believe it or not, I think there’s more consensus here than maybe we might think,” said Brigham McCown, senior fellow at the Hudson Institute. “We do need an approach that includes everything in our energy mix, and … the percentages of that mix will change over time as technology and innovation move forward.”

But how quickly the transition happens cannot be willed through congressional mandates, McCown argued.

“We have to be careful about how we change this mix, and we have to understand the reality of today is that fossil fuels are powering the future,” McCown said. “And if we want to reduce our carbon footprint, we should start by talking to the Chinese and the Indians.”

Working on technologies like carbon capture and storage and sustainable aviation fuel is critical to meeting the future’s energy needs, he added.