Grid Resiliency

Xcel Energy is focused on conversations at the state and federal level about wildfire, trade and tariff policies after the company's earnings declined during the first quarter of 2025, Chairman, President and CEO Bob Frenzel said during a Thursday earnings call.

Although first-quarter electric and natural gas sales increased year over year, the company also saw its operating costs surge, driven in part by higher nuclear outage amortization costs and increased insurance premiums, according to CFO Brian Van Abel.

Xcel Energy expects its costs to increase another 2% to 3% as a result of recent tariffs, which Frenzel described as “manageable.” However, he expressed concern about the impact of tariffs on battery and energy storage prices — technologies he said are necessary to meet surging electric demand.

Leaders from Xcel Energy have spent a lot of time engaging with Washington in recent months, Frenzel told investors on Thursday's call.

“We're in an unprecedented period of electric demand growth and believe that we need a broad scope of energy resources to meet those needs,” Frenzel said. He listed a half-dozen trends driving increased electric load, including electric vehicle adoption and data center expansion. “The infrastructure to serve this demand growth needs to be thoughtfully planned,” he said

Top of mind, Frenzel said, is advocating for the preservation of tech-neutral tax credits for wind, solar, nuclear and energy storage projects. But the company is also paying close attention to trade policy, he said. While company projections put the current cost of tariffs the Trump administration has imposed to date at a “manageable” 2% to 3%, Frenzel said he is concerned about tariffs’ potential future impacts to battery storage projects in particular.

Although Xcel Energy only has one “significant” battery storage project in its current capital plan, Frenzel said he sees a need for more battery and energy storage assets in the future to meet demand. He expressed optimism that the battery industry would follow solar's lead and build out a domestic supply chain in response to tariffs.

Limiting fire liability

Xcel Energy increased its estimated liability associated with the 2024 Smokehouse Creek Fire in Texas and Oklahoma to $290 million after adding in recent settlements involving railroad claims and tree damage. Frenzel noted that this remains well below the company's $500 million insurance cap, however.

The company expects a trial for lawsuits related to Colorado's 2021 Marshall Fire to begin in September. Discovery in the case has yielded two new theories as to what started the fire, Frenzel said. One theory suggests loose telecommunications equipment hit a power line, sparking the blaze, while another suggests an as-yet-unidentified object struck a power line.

Xcel Energy supports legislation recently introduced in Texas and in North Dakota that would allow a utility to use its compliance with an approved wildfire mitigation plan as an affirmative defense against civil suits for wildfire damages, Frenzel said, adding that he believes “these bills could also serve as frameworks in our other states for future legislation.”

“We and many in our industry have been advocating [at the federal level] for policies that allow for cost-effective and rapid adoption of new energy resources,” he said. “That includes ... advocating for siting, permitting and other federal actions that would allow for more rapid construction of the assets needed to serve this growing demand, and that includes advocating for federal actions that can mitigate the potential for wildfires and their associated financial impacts.”

The power grid performed well during extremely cold weather in January, a sign that steps taken since previous winter storms are paying off with improved electric reliability, according to a report released Thursday by the Federal Energy Regulatory Commission and the North American Electric Reliability Corp.

About 71 GW of generation was unexpectedly offline during winter storms in January that covered most of the United States, according to the report. About 91 GW was unexpectedly offline during Winter Storm Elliot, which mainly affected the Eastern Interconnection in December 2022.

There were no power outages in January, while grid operators instituted rolling blackouts totaling 5,400 MW during Elliott and 23,418 MW during Winter Storm Uri, which mainly affected Texas and the Southcentral U.S. in February 2021. The Texas Department of State Health Services estimates that 246 people died as a result of Uri, mainly from hypothermia as well as the use of alternate heating sources while their power was out.

Several factors appear to have contributed to the improved performance during the most recent bout of extremely cold weather, including improved communication and coordination between the natural gas and electric industries, according to the report.

Among the positives during January’s bitter cold, the PJM Interconnection exported 7,650 MW during a peak demand period, according to the report. Several electric entities declared “conservative operations” earlier than in past events to delay or cancel planned transmission outages to reduce grid congestion and enhance transfer capability, FERC and NERC staff said in the report.

Also, several entities surveyed by staff said battery storage helped their performance during the January arctic events, according to the report. “ERCOT stated that the rapid deployment of battery storage resulted in batteries providing 3,800 MW at peak times, alleviating stress on the grid during critical demand hours,” staff said.

Grid operators’ demand forecasts were more accurate than in the past and there was increased data sharing between generators and gas pipeline operators, which helped ensure power plants had fuel to burn, according to the report.

In comments on the report, FERC Chairman Mark Christie highlighted the role the Mountain Valley gas pipeline played in keeping the gas system operating and supporting electric reliability. Also, PJM’s ability to export power may shrink as its power supply margins fall, according to Christie. “You can't export something you don't have, and as PJM loses its surplus generating resources, there won't be anything to export,” he said. “That's a huge problem.”

Even with the grid’s improved performance in January, the United States needs more energy infrastructure, according to Commissioner Willie Phillips. “The more energy infrastructure we get on the system, the easier it is for us to provide power to the American people, our homes, our business, to provide it in a way that they can actually afford it,” he said.

Here are four other takeaways from the meeting.

NERC eyes data center reliability impacts. NERC is exploring how data centers and cryptocurrency operations could affect grid reliability and whether standards are needed for those facilities, according to Mark Lauby, senior vice president and chief engineer at the grid watchdog organization.

As an example of the potential problem, about 1,800 MW of data center load went offline suddenly in northern Virginia in February and about 1,400 MW went offline in July, Lauby said at the FERC meeting. From November 2023 through January, there were 25 crypto mining load loss events in ERCOT, ranging from 100 MW to 400 MW. The sudden loss of load can affect the grid’s voltage and frequency, and potentially lead to wider power outages, Lauby said.

A NERC large load task force aims to develop risk mitigation guidelines by early next year, according to Lauby’s presentation. There are a “host of solutions” for dealing with large load risks, Lauby said.

Christie defends PJM. Christie, a self-described critic of PJM’s capacity market, defended the organization and its staff during the open meeting. “A lot of this criticism I have seen in the media, directed at PJM and its management, and blaming them for everything that’s wrong with the PJM capacity market, I think is in many ways misplaced,” Christie said. PJM’s staff “work very hard, and work in good faith.”

In part, problems related to the capacity market are driven by choices some states made about 20 years ago when they decided to rely solely on PJM’s capacity market for their power needs, Christie said during a media briefing.

Christie declined to respond directly to New Jersey Gov. Phil Murphy’s request that FERC investigate a capacity auction held in July that saw capacity prices jump to about $270/MW-day for most of the grid operator’s footprint, up from about $28/MW-day in the previous auction. The increase is leading to significant rate hikes in some states starting June 1 when the next capacity delivery year begins.

FERC has so many cases involving PJM that the agency is constantly investigating the grid operator in a general sense, Christie said. FERC is holding a two-day technical conference in early June to explore capacity markets and other approaches to ensuring there are adequate power supplies.

Christie: PJM-Transource stance “utterly outrageous.” Christie slammed arguments made in court by Transource — an American Electric Power and Evergy joint venture — and PJM that transmission projects included in the grid operator’s regional transmission expansion plans are exempt from state certificate of public need reviews.

The stance is an “utterly outrageous position” and runs counter to commitments AEP and Dominion Energy utilities made in 2004 when they sought to join PJM, Christie said during the media briefing. If Transource wins its case, states may reconsider allowing utilities to be members of regional transmission organizations, Christie said in a concurrence to an order issued Thursday. “As the debate continues over whether to give transmission developers/owners a perpetual [return on equity] adder for joining an RTO, the history recited herein is extremely relevant,” Christie said.

FERC staffing expected to fall. FERC is in a hiring freeze and its headcount is expected to fall by 9% by the end of its fiscal year, Christie said during the media briefing. FERC had a staff of about 1,500 people as of December. The agency expects 55 staff members will accept a deferred retirement offered by the Trump administration, Christie said.

“We want to keep the key people,” Christie said, pointing to FERC staff involved in natural gas permitting. “We don't want to lose people who are essential to getting those permits out.”

Phillips offered support for FERC staff amid Trump’s efforts to slash the federal workforce. “It's not exactly an easy time to be a federal employee right now, and I think it's worth being said that the work you do is outstanding,” Phillips said. “We're busy … and we're doing a lot of great work for the American people.”

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By Osmose Utilities Services

The Situation

With the recent increases in broadband funding, cable provider mergers, and wireless deployment, the demand for pole attachments has more than doubled for many utilities. This was the case for one large investor-owned utility in the Northeast that owns and maintains 32,000 miles of distribution circuits and over 2 million wood poles.

This demand was not a new challenge for the utility as it experienced a similar surge in pole attachments requests during the fiber expansion in the late nineties. However, the utility now faced the complexity of determining the necessary engineering modifications required for pole make-ready and who would bear the cost of those modifications. In many cases, the attaching applicants would cover the cost but if pre-existing issues with the pole plant were identified, the utility would be responsible for repairs or replacement poles and ensuring regulatory compliance

The Solution

For the past two decades, this utility has partnered with Osmose® to address the increasing number of attacher requests. It has depended on Osmose’s project management and engineering expertise to manage incoming applications, designate field teams to execute surveys, and draft engineering designs. These designs detailed the necessary modifications to accommodate new attachments while adhering to the utility’s design standards and meeting FCC and regulatory deadlines.

Because of the commitment and trust demonstrated by Osmose over the past two decades, it was clear to the utility that it should rely on Osmose to address the challenges brought on by the surge in broadband demand, electric vehicle charging locations, smart grid initiatives, and NJUNS tickets. Not only did Osmose have the technical expertise and a thorough understanding of the utility’s unique needs, Osmose also delivered a consistent scope of work and offered the scalability to meet the demands of the project, proving to be a valuable asset for both the utility and attaching applicants.

The Result

To date, Osmose has performed make-ready surveys and engineering analyses on more than 500,000 of the utility’s distribution poles. Throughout the years, Osmose has proven the adaptability of their service model and the ability to scale rapidly and effectively. Working directly with the attaching service providers and the utility has also created collaboration and consistency. In addition, when a service provider and Osmose work directly, it allows the utility to gain negotiation timeframe flexibility beyond the 45-day regulatory requirements.

Osmose’s longstanding partnership with this investor-owned utility, combined with their ability to manage complex makeready projects, has been essential in facilitating the expansion of internet access and telecommunication services throughout the area. As the digital landscape continues to grow, Osmose’s services stand as a testament to the power of effective collaboration between utility and telecommunication providers.

The North American Electric Reliability Corp. on Thursday filed proposed cold weather preparedness and operations rules with federal regulators, after two previous drafts of the standard failed to achieve stakeholder ballot approval.

Reliability Standard EOP-012-3 “represents a meaningful step forward in addressing the risks posed by cold weather, strengthening generator preparedness and performance through clearer and more effective requirements,” NERC said in a statement. “By focusing on consistent implementation and timely remediation of freezing issues [the revised standard] will help ensure that the grid is better equipped to withstand and recover from extreme cold weather events.​​”

NERC told regulators that the proposed EOP-012-3 would improve on reliability standard EOP-012-2 by:

• Providing clear criteria for determining when a generator could declare constraints that would preclude them from implementing a specific corrective action to address freeze protection issues;
• Shortening deadlines for generators to implement corrective action plans so that known freezing issues are addressed more quickly;
• Requiring generators with new bulk electric system generating units entering commercial operation on or after Oct. 1, 2027, to have required cold weather capabilities upon entering commercial operation; and,
• Requiring generators to review their cold weather constraints at least once every 36 months for continued validity, instead of at least once every five years, “to ensure that new technologies are considered and circumstances preventing implementation are reevaluated.”

NERC first developed the EOP-012 standard in 2022 to ensure generator owners would take appropriate actions to prepare for extreme cold conditions. Winter weather has been a major factor in reliability events in multiple years since 2011, NERC said, but Winter Storm Uri in February 2021 in particular was a cold weather event that caused rotating blackouts in Texas and led to hundreds of deaths

Winter Storm Uri, “with its devastating human and economic toll, underscored the need for strong Reliability Standards to address the causes of this and previous cold weather reliability events and help assure the reliability of the Bulk-Power System in future winter seasons,” NERC told regulators.

The NERC Board of Trustees invoked its authority on April 4 to approve the rules after stakeholders could not reach agreement.

“Representatives from the Standards Committee, along with members of the drafting team and NERC staff, prepared a responsive standard that built on the prior framework approved by FERC and took into consideration comments from a broad group of stakeholders and final recommendations to further clarify the standard,” the reliability organization said in a statement.

NERC asked regulators to authorize the new standard to be effective Oct. 1, or three months after FERC approval, whichever date is later.

“This relatively short implementation timeframe reflects NERC’s determination that the practical impact of implementing the proposed changes is not expected be significant,” the organization told FERC.

Rapid energy demand growth in the U.S. is threatening an aging and fragile electric grid, says the American Society of Civil Engineers, resulting in the group dropping the energy sector’s 2025 Infrastructure Report Card grade to a D+ from the C- they gave it in 2021. 

ASCE cited a shortage of distribution transformers, increases in severe weather events and a lack of transmission capacity as some of the challenges facing the U.S.

At the same time, “consumers and businesses are growing increasingly reliant on data storage facilities, artificial intelligence, and electrified products such as EVs, to name just a few examples of advancements adding immense strain” to the grid, said ASCE’s report.

“An increase in electric vehicles and a rise in data centers will demand 35 GW of electricity by 2030 alone, up from 17 GW in 2022,” said ASCE. “This rapid acceleration, compounded by federal and state net-zero greenhouse gas emissions goals, means utilities will need to double existing transmission capacity to connect new renewable generation sources.”

The report noted that transmission investments rose by $5 billion from 2017 to 2022, and the 2021 Infrastructure Investment and Jobs Act includes funding for infrastructure elements like transmission buildout. 

One IIJA investment, announced in 2023, is spending $1.3 billion on three interregional transmission lines across six states: the 175-mile Southline Transmission Project (New Mexico to Arizona); the 211-mile Twin States Clean Energy Link (New England to Quebec, Canada); and the 214-mile Cross-Tie Transmission Line (Utah to Nevada).

“The IIJA allocated $73 billion from 2021 to 2026 to modernize the electric grid, build thousands of miles of new power lines, and expand renewable energy,” ASCE said. “Much of the funding is dedicated to hardening [transmission and distribution] lines to be more resilient,” using measures like “undergrounding overhead power lines, implementing fire-resistant technologies, and replacing poles and other structures with stronger, more durable materials.”

The IIJA also “invested heavily in grid resilience,” ASCE said, with the law establishing a $10.5 billion Grid Resilience and Innovation Partnerships Program, one project of which is the Grid Innovation Program. The Grid Innovation Program is providing “$5 billion for [fiscal year 2022 through 2026] to support projects that use innovative approaches to transmission, storage, and distribution infrastructure to enhance grid resilience and reliability,” according to the Department of Energy.

However, ASCE said, state renewable portfolio standards and federal decarbonization initiatives are combining with surging energy demands and leading to “rapidly escalating funding needs in the generation and [transmission and distribution] sectors.”

“Even if funding levels established by the IIJA and [the Inflation Reduction Act] are reauthorized in 2026, the energy sector faces a $578 billion investment gap by 2033, which climbs to $702 billion by 2033 if the nation ‘snaps back’ to pre-IIJA/IRA funding levels when the bills expire,” the report said. 

For the U.S. to raise its energy infrastructure grade, ASCE made recommendations that include the adoption of a federal energy policy designed to meet current and future technology changes; the development of a robust national transformer inventory; a national grid hardening plan; and a requirement for “energy providers to adopt the most stringent consensus-based codes and standards for all overhead T&D lines, structures, and substations to ensure safety and increase reliability.”

In a nation increasingly divided over energy policy, two unexpected success stories have emerged from opposite ends of the political spectrum. While the rhetoric in Washington has turned sharply against the "green energy revolution," both California and Texas have engineered remarkable transformations of their electric grids — effectively eliminating the rolling blackouts that once plagued their systems during extreme weather.

As the Trump administration begins its second term with promises to roll back clean energy incentives and boost fossil fuel production — and even re-defining “energy” to not include solar and wind power — America's two largest states offer compelling evidence that the president's stance on renewable energy is fundamentally misguided.

The administration's skepticism toward green technology flies in the face of market realities that have made these solutions not just environmentally beneficial but economically superior.

It’s been an amazing year for battery storage, in particular, which “firms” variable renewable sources like solar and wind. By the end of 2024, California surpassed 13 GW of battery storage capacity, with Texas close behind. These formerly blackout- and brownout-prone states have achieved an unprecedented level of grid reliability through massive deployments of battery storage, despite facing increasingly severe weather challenges.

What's particularly instructive is how these states achieved similar results through different approaches. California pioneered the way with state-ordained incentives and mandates that pushed utilities into signing contracts for battery capacity. Texas, meanwhile, simply let private investors build whatever power plants they believed would make money in the competitive Electric Reliability Council of Texas market. Despite these differing philosophies, both states arrived at the same conclusion: batteries are essential for a reliable, affordable grid.

The results speak for themselves. During a heat wave in the summer of 2020, California ran short on power and had to initiate rolling blackouts. Now, when record heat hits and millions of Californians crank their air-conditioning, the state can call upon over 13 GW of batteries to shift its ample solar production into the evening hours when supplies run low. 

In 2023, ERCOT, Texas’s grid operator, issued 11 conservation notices during extreme weather, including notices for seven consecutive days in August. By contrast, 2024 saw no conservation calls during summer despite experiencing virtually identical peak demand.

The difference in both states? Massive battery capacity providing crucial grid flexibility when consumers needed it most.

This transformation didn't just improve reliability — it dramatically reduced costs. In Texas, August 2024 power prices were, on average, $160/MWh lower than the same month in 2023, with savings totaling approximately $750 million.

The battery revolution in both states demonstrates a fundamental reality that the Trump administration has failed to grasp: when clean energy technologies become cost-competitive, market forces drive rapid adoption regardless of political headwinds. Battery pack prices have plummeted 92% since 2010, making grid storage increasingly attractive to investors seeking returns.

California's grid transformation highlights how policies designed to address climate change have yielded unexpected reliability benefits. On Oct. 7, 2024, during a late-season heat wave, batteries discharged a record 8.35 GW into the California grid, representing over 21% of demand at that moment. This stored capacity — which would not have existed just a few years ago — prevented what would likely have required blackouts in the past.

Meanwhile, Texas demonstrates that even without climate-focused policies, the economic case for batteries has become overwhelming. In a system where companies can build whatever generation they believe will be profitable, batteries are winning because they deliver superior value for both investors and consumers.

The dramatic expansion of battery storage has significantly reduced renewable energy curtailment in both states. In California, curtailment of solar energy decreased by over 34% from 2023 to 2024, with batteries absorbing excess midday solar generation that would otherwise be wasted.

Similarly, in Texas, wind curtailment dropped by more than 40% as batteries increasingly charge during high-wind/low-demand periods, typically at night. This stored energy is then dispatched during peak demand hours, effectively transforming previously curtailed renewable energy into valuable peak capacity.

In 2024 alone, batteries helped avoid approximately 27,500 MWh of renewable curtailment in California and a similar amount in Texas, representing a combined economic value of over $750 million while simultaneously reducing reliance on fossil fuel peaker plants.

President Trump's characterization of renewable energy as expensive and unreliable has been thoroughly debunked by actual market performance, on the ground, in a state not known for environmental activism.

The rise of battery storage in both California and Texas challenges conventional wisdom about renewable energy integration. The administration has long argued that wind and solar's variability makes them unsuitable as primary power sources. Yet these states have shown that with sufficient battery capacity, renewables can deliver reliable service even during extreme weather events. The days of choosing between clean energy and reliable energy are over.

Perhaps most importantly, these success stories offer a path forward amid political polarization. While California and Texas took different routes to their battery booms, both arrived at similar outcomes: cleaner, more reliable and more affordable electricity. This suggests that the clean energy transition can succeed regardless of the political environment, so long as technologies are allowed to compete based on their performance.

Yet the developments in both California and Texas suggest that even aggressive intervention to favor fossil fuels may matter less than fundamental market dynamics. The American Clean Power Association's analysis reveals that battery storage now dominates ancillary services markets in Texas, providing up to 80% of regulation services in 2024. In California, battery storage has become essential for managing the evening ramp when solar generation decreases and demand increases. These shifts occurred because batteries simply perform these functions more efficiently and at lower cost than alternatives.

The market fundamentals driving battery adoption show no signs of reversing. BloombergNEF reports that battery prices have dropped to unprecedented lows, making storage economically viable for an expanding range of applications. Both California and Texas have proven that at scale, batteries can effectively eliminate concerns about renewable variability while simultaneously lowering system costs.

What does this mean for America's energy future? First, it suggests that the energy transition will continue regardless of the Trump administration's fossil fuel advocacy. Grid-scale batteries have proven their value across political contexts — in progressive California and conservative Texas alike.

Second, it reveals that the administration's characterization of renewable energy as unreliable and expensive is demonstrably false. In both states, the combination of renewable generation and battery storage has produced more reliable grids at lower costs than the fossil-dominated systems of just a few years ago.

Third, it points to a potential path for depolarizing the energy debate. When technologies compete on their merits — whether in a mandate-driven market like California's or a laissez-faire environment like Texas — the same solutions have emerged.

The remarkable transformations of both states' electric grids carry lessons for the Trump administration. The president's skepticism toward renewable energy contradicts the market realities playing out in America's largest and most energy-intensive states. Far from being costly boondoggles, technologies like battery storage and solar power are proving to be economic powerhouses that enhance grid reliability while lowering costs.

The future of America's energy system will ultimately be determined not by presidential declarations or ideological preferences, but by economic reality. And increasingly, that reality favors a system where battery storage and renewable energy play central roles in maintaining reliability and localized energy production, while reducing costs.

Microgrids don't pose an immediate threat to diesel generators as the way most managers ensure their facilities have backup power, but Allan Schurr, the chief commercial officer at microgrid company Enchanted Rock, expects more operators to look at what he says is a cleaner, administratively easier approach that microgrids offer. 

“Diesel generators are in short supply and sometimes it's two years before you can get a diesel generator delivered,” Schurr told Facilities Dive. “By having a microgrid … you can [have something] more reliable and cleaner” and have it up and running within a year.”

A microgrid is a self-contained electrical network that companies like Schurr’s install on their client’s property. Enchanted Rock builds its network using half-megawatt natural gas generators that it gangs together based on the amount of load the client wants to back up. For a hospital, it might be a network of 10 generators. For a grocery store, it might be two or three. 

“Our standardization of equipment is part of our differentiator,” said Schurr, referring to his company’s use of a single-size generator. “That allows us to dial in exactly the amount of backup power that's needed for any facility size.”

Power from the microgrid is cleaner, Schurr says. In the case of Enchanted Rock, it’s cleaner because it’s generated from natural gas. But microgrids can also use solar, wind and other non-fossil-fuel burning sources. 

The cleaner power might be important to organizations that make sustainability a priority but it can also help lower energy costs by enabling the microgrid to run power outside of emergency situations and sell it as a supplemental power source to the local utility grid. That revenue goes to the microgrid and helps offset what the property owner pays for its backup power. 

“So, [our clients] can get the air permits to operate in nonemergency hours, and that's where the cash register comes in,” Schurr said. “If you can operate outside of emergencies, you can get paid by the grid to run during certain critical peak hours, and those payments offset the cost of the resiliency function.”

Avoiding test disruptions

Having the power run alongside the grid also solves one of the biggest headaches facilities managers deal with when they have a backup generator, Schurr said: the annual test. 

In the typical case, the operator can start up the generator only after first shutting down the regular power, disrupting work for about 10 seconds at the start of the test and then again at the end, during which gaps there’s no power flowing to the facility. 

“All the tenants in that building, whoever they might be, experience that first little outage, and then when you go back onto grid power, you take another outage before you connect to the grid again,” he said. 

To avoid the disruption, some operators conduct the test without transferring the load to the generator. By doing that, they can get assurances the generator works but not whether it can carry the load that would be needed if there’s a power loss. 

“They just start up the generator and it idles,” he said.  “‘Started. Worked. We're good.’”

Some operators get around the disruption by testing the generator on a simulated load. “You bring in what's known as a load bank, which is literally like a giant toaster,” he said. “It creates a load for you to test,” but it’s expensive.

The other alternative is not to test at all. That’s not an option for hospitals and other regulated facilities that require annual testing to ensure continuous power to critical infrastructure. But for other facilities, the annual test rarely survives a budget cut. 

“Those service contracts are one of the first things that get deferred,” he said. “Facility managers know this well. They never have the budget to do what they want to do, and so they're always looking for ways of stretching their O&M dollars, [which could yield] the kind of slippery slope that is a lack of reliability.”

One-year installation

Diesel generators are in short supply right now, so Schurr sees an opening for companies like his. Rather than wait two years to get a generator installed, operators can get backup power within a year. That’s about what it takes to get the network built out on the client’s property and tie the network into the local utility grid. 

“One of the critical path items is getting the gas interconnect from the local gas utility,” he said. “So, we order the equipment for the electric switch gear, the gas interconnection and then we do permitting and construction. And usually within a year, we can be completed and operational.”

Separate from providing the property on which to build the grid, the client pays a set-up fee to do the construction work and install the network and then a monthly service fee – basically, a subscription – to have the company maintain and operate the microgrid. 

“They get the full gamut of the maintenance and operation inside of that fee unless there's an outage, and then they pay fuel during that outage,” he said. 

Enchanted Rock typically owns the microgrid and therefore owns any revenue it generates from selling surplus power to the local grid, which helps keep down the service fee to the client. In some cases, the client elects to own the microgrid, making it the seller of the surplus power.  

Schurr touts this resiliency-as-a-service model as a way to make backup power generation economically feasible for organizations that might otherwise hesitate to invest in it. 

“We have grocery stores that want to be there for their customers when there's an emergency,” he said. “They don't want to close down. They don't want to throw out all the food. They want to be open for business. So, we have customers in a lot of different industries that are trying to serve their customers better. And by so doing, they think that the business case is very strong.”

A North American Electric Reliability Corp. study on interregional transfer capability is inadequate for determining how much transmission capacity should be added between regions, according to grid planners across the Eastern Interconnection.

NERC’s study — ordered by Congress in 2023 — provides “helpful information” but lacks enough detail to drive actions, the Eastern Interconnection Planning Collaborative said in comments filed with the Federal Energy Regulatory Commission on Monday.

In its study filed with FERC in November, NERC found that the U.S. could use an additional 35 GW of transfer capacity between regions to bolster reliability during extreme weather.

However, the study fails to adequately consider the costs and benefits of building transmission lines to increase transfer capacity between regions, according to EIPC, which includes ISO New England, the Midcontinent Independent System Operator, the New York ISO, the PJM Interconnection, the Southwest Power Pool and utilities such as Southern Co.

“Large nationwide studies, like the [Interregional Transfer Capability Study,] have no way of achieving sufficiently detailed results to effectively weigh the cost/benefit associated with adding transfer capability within or between different regions, or to appropriately assign costs to the true beneficiaries,” the group said. 

Transmission planning entities should assess interregional transfer capability needs, according to EIPC. “Those entities have complex models of the system, and they are in the best position to evaluate resource adequacy and transmission security as well as an understanding of enhanced needs due to extreme weather conditions,” the group said.

Determining how much transfer capability is needed should be informed by how it could improve system reliability, but also the cost of the upgrades, the ability to assign the costs to beneficiaries and the overall cost/benefit ratio compared with other options, such as generation resource additions, demand side management or operational measures, EIPC said.

Further, adding transmission capacity doesn’t improve reliability if there isn’t enough electricity to move from one region to another, according to the group.

EIPC urged FERC to consider developing metrics to help guide decision-making around interregional transfer capability. Instead of setting a specific, desired level of interregional transfer capability, the metrics would be used by transmission planners to determine whether there are “prudent additions” that could enhance interregional transfer capability, the group said.

Factors that could be considered include need, costs and benefits, and feasibility, according to EIPC.

NRG Energy told FERC that the NERC study contains flaws, including a “feedback loop” on the viability of power-generation business models.

“New interregional transfer capabilities would lead to more resource retirements and fewer resource additions in certain markets that have no capacity mechanism, particularly the Electric Reliability Council of Texas … which would ironically undermine reliability in the state during critical times when the imports on which ERCOT became increasingly reliant were unavailable,” the independent power producer said in a filing filed at FERC on Thursday.

Conservative Texans for Energy Innovation urged FERC to consider provisions under the Federal Power Act as a pathway for Texas to expand its transfer capacity without infringing on ERCOT’s independence from direct FERC authority. 

“The study reveals a strong need to bolster ERCOT's grid reliability,” the group said, noting the study’s “conservative assumptions” fail to account for recent load growth in Texas. FERC should streamline and prioritize regulatory reviews for interregional transmission projects that address reliability risks identified by NERC, especially between ERCOT and MISO and SPP, the group said.

NERC’s finding that 35 GW of interregional transmission additions would be prudent represents a minimum level of interregional transfer capability needed to protect grid reliability, according to the Department of Energy.

“DOE’s own power grid studies find that even more interregional transfer capability would both support grid reliability and lower consumer costs,” the department said in comments filed on Jan. 17 during the Biden administration.

The urgently needed modernization of the U.S. power system is being impeded by slow access to vital new electric transformers.

Advanced computing and economy-wide electrification are expected to grow demand almost 16% by 2030, increasing the need for both more and bigger transformers, according to a December National Renewable Energy Laboratory study. And that need is being accentuated where extreme weather events like the Los Angeles wildfires and East Coast hurricanes require rebuilt distribution systems.

But global supply chain disruptions continue to slow access to the transformers critical to stabilizing power system voltages and efficiency.

“Delivery of a new transformer ordered today could take up to three years,” said National Association of Electrical Manufacturers, or NEMA, Director of Government Relations Peter Ferrell. “Five years ago, that wait time was four to six weeks.”

Faster access to transformers will take time and investment, manufacturers said.

“The short term appears to be painful for the large investment areas” and “projects have been postponed one to two years already,” said Jeffrey DeSain, general manager, North American Transformer Business, for manufacturer Schneider Electric. “It will take a variety of investment de-risking solutions for supply chains and manufacturers to catch up.”

Load growth pressure on existing infrastructure will likely continue for years, and perhaps for a decade or more, manufacturers and analysts say. Meanwhile, transformer supply solutions, like standardizing transformer designs or organizing and funding a reserve supply, will take policymaker cooperation, if they can be implemented at all, many said.

More than 80,000 types of transformers

There are differences in lead times for the many different types of transformers that step up and step down voltages throughout the power system.

At wind and solar projects, small pad mounted transformers step up voltage to medium or larger sized transformers at production site substations, according to Doug Wolken, Hitachi Energy head of marketing and sales, transformers, North America. Large transformers at natural gas, nuclear, and hydropower plants also step up voltage to the transmission system, he said.

At distribution substations, large pad-mounted transformers step down voltage from the transmission system to medium or small pad mounted transformers, Wolken said. Small pole mounted or pad mounted distribution system transformers step the voltage down for homes and businesses, he said.

The U.S. system had 60 million to 80 million distribution transformers in late 2024, and the 2050 need “could increase by up to 260% compared to 2021 levels,” NREL reported. About 55% of residential transformers are near the end of their lives, with many now more than 40 years old, the lab said.

And there are over 80,000 transformer types throughout the U.S. power system, according to the 2024 National Infrastructure Advisory Council, or NIAC, report from industry stakeholders. 

Larger transformer lead times range from 80 to 120 weeks, according to a Wood Mackenzie, or WoodMac, April report. Special electrical steel vital to transformer power loss reductions remains expensive and difficult to obtain domestically, WoodMac said.

Individual manufacturer slowdowns vary. Lead times for pad-mounted distribution transformers “are double or triple” what they were pre-pandemic, said Hitachi Energy’s Wolken. “Transmission scale unit lead times are now three years to six years, with specialized transformers taking the longest time,” he added.

Puget Sound Energy is seeing longer lead times for some equipment, confirmed Andrew Padula, a utility spokesperson, said.

And “realistically, those lead time increases are not expected to improve in the near term,” because their causes are amplifying, WoodMac Senior Analyst, Supply Chain Data and Analytics, Ben Boucher said.

 

What drives growing transformer demand?

Continuing load growth, aging system infrastructure and worsening extreme weather events are driving the need for transformers, manufacturers and analysts say.

The current shortage began during the COVID pandemic with manufacturing shutdowns and the slowing of global supply chains, Xcel Energy spokesperson Kevin Coss said. Numerous factors continue to drive transformer demand higher, he said.

“We're approaching a time of unprecedented demand for transformers,” Senior Researcher and Distribution Edge Group Manager Killian McKenna, author of an NREL study on transformer supply. Growing electricity demand is straining infrastructure that is approaching the end of its life, from “renewables, data centers, and building and vehicle electrification like EV charging stations and heat pumps,” McKenna added.

Extreme weather events like hurricanes and wildfires impose further distribution system transformer losses, McKenna said. Replacement needs exceed utility inventories to meet everyday failures and new customer requests, according to McKenna.

Following hurricanes Helene and Milton, Duke Energy needed to replace about 16,000 transformers, according to its November earnings report. That is more transformers than other utilities require in a year, WoodMac’s Boucher said.

The rebuilding in Los Angeles has not really begun, according to city officials. As of February 2, Southern California Edison crew members, contractors, and mutual-assistance partners have installed nearly 400 transformers in the Eaton and Palisades wildfire areas, Jeffrey Monford, the utility’s spokesperson, reported.

Soon there will be “enormous new electricity use in bitcoin mining, training artificial intelligence and quantum computing, reshoring U.S. manufacturing, and system modernization initiatives,” said NEMA’s Ferrell. Demand has “catapulted exponentially on a system with a manufacturing base and supply chain sized to meet the market of five years ago.”

The boom in virtual power plants composed of distribution system resources, could reduce system strain, according to developers. But significant added load from electric vehicle charging or electric heat pumps could require larger or more distribution transformers, Scheider Electric’s DeSain, NREL’s McKenna and others said.

After a 2022-23 delayed reaction to growing transformer demand, manufacturers announced $600 million in new transformer capacity investments in 2024, WoodMac’s Boucher said. Schneider Electric “is investing hundreds of millions of dollars in capacity expansion,” DeSain added.

Hitachi Energy North America is investing $500 million in transformer manufacturing capacity through 2027, said Wolken. This is part of a $1.5 billion global transformer production investment, which is based on demand expected to be sustained for at least 10 years, he added.

But that investment may be inadequate to meet demand, and other more innovative solutions have been proposed, manufacturers and analysts said.

Solutions to transformer shortage

Of seven solutions described in the NIAC report, three are already being used by manufacturers, utilities and other stakeholders.

More accurate demand forecasting and longer-term agreements between electric companies, manufacturers and suppliers of raw materials like electrical steel are already in practice, said Edison Electric Institute, or EEI, Senior VP, Security and Preparedness, Scott Aaronson.

Utility resilience planning against extreme weather events has led to “storm stock” inventories, which are in-house supplies of distribution system infrastructure, according to Aaronson. “Big utility companies may have access to large power transformers and 10,000 or more distribution transformers through mutual assistance networks,” he said.

Integrated planning has allowed anticipating when and where transformers will be needed and partnering with manufacturers to ensure supply, said Xcel’s Coss.

“Until recently, few utilities, manufacturers and supply chain partners had strategic alignments, but five-year projected plans and long-term agreements are becoming the norm,” said Schneider Electric’s DeSain. “A multi-year view and choosing more standard designs, materials and electronics can mitigate risk,” he added.

“Replacing aging infrastructure can be a massive opportunity or a lost opportunity,” NREL’s McKenna said. “Near term decisions that don’t anticipate future load growth and the growing need for resilience will impose high labor costs,” but building for long-term needs can be an opportunity to make them one-time costs, he said.

The NIAC report’s call for federal policy and funding support for expanded transformer production will come before the 2025 Congress as the just released Moran-Cortez Masto bill. 

“Extending the federal 45X tax credit for domestic manufacturing would support more U.S. transformer production,” NEMA’s Ferrell said, adding that “state or federal initiatives that grow the workforce could be the best policy solution because automated manufacturing of so many unique types of transformer and transformer components is not plausible.”

The NIAC report also proposed a virtual transformer reserve with the U.S. government as the buyer of last resort.

“The reserve would not be a physical stockpile, but a way to retain spare manufacturing capacity,” NEMA’s Ferrell said. “It would be a commitment to sustain medium to long term manufacturing capacity certainty, but it is not clear how to determine the needed federal investment and who would provide it and how to manage the reserve.” 

There would, however, be little risk because current demand growth seems to be long term, Aaronson said.

The NIAC report’s most important proposal might be standardizing transformer design.

Standardization “would make it easier to share equipment and to produce more transformers faster to meet the growing demand,” EEI’s Aaronson said.

But because of the many types of transformers, “it may not be possible to significantly reduce production times,” said NEMA’s Ferrell. Utilities could agree on standard specifications, “but that will be difficult because a newer utility in Southern California will have very different operational needs than an older Maine utility,” he said.

Schneider Electric’s DeSain and Hitachi Energy’s Wolken agreed. The U.S. power system “is one of the most novel machines in the world, with transformers designed and manufactured to very specific local distribution system intricacies, which makes standardization a real challenge,” Wolken said.

On average, for every 1,000 transformers on a distribution system, there would likely be 200 or more different transformer designs, according to Wolken. “But there may be areas where, with utility leadership, some level of standardization is possible,” he said. 

Even if transformer variation was reduced from 80,000 types to 60,000 types, “it would allow a little more efficient manufacturing process,” said EEI’s Aaronson.

Standardization may seem complicated, said WoodMac’s Boucher. But when a severe weather event occurs, utilities “take whatever transformers they can get, which suggests standardized specifications and designs are realistic and can be a key to resolving current shortages,” he added.