Grid Resiliency

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.

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The dramatic fire that destroyed most of a 300-MW array at Vistra Energy’s 750-MW Moss Landing Energy Storage Facility late last week drew intense concern from local elected officials and may foretell closer scrutiny of utility-scale lithium-ion battery installations in California and nationwide.

Monterey County Supervisor Glenn Church called the incident a “worst-case scenario,” comparing it to the partial meltdown at the Three Mile Island nuclear power plant in 1979, while California Assemblymember Dawn Addis, D, called for “transparency and accountability” and said she was “exploring all options for preventing future battery energy storage fires from ever occurring again on the Central Coast.” 

A spokesperson for the American Clean Power Association, a trade group that advocates for the energy storage industry, pushed back on comparisons to the Three Mile Island incident — cleanup of which took 12 years and cost $973 million — and said operational U.S. energy storage facilities had seen only 20 fire-related incidents in the past 10 years, despite energy storage deployment growing by more than 25,000% since 2018.

Fire broke out at Moss Landing around 3 p.m. local time Thursday and burned out of control through the night, with local newscasts showing flames shooting hundreds of feet into the air. 

Officials closed nearby Highway 1, a major thoroughfare between Santa Cruz and the San Francisco Bay Area, and ordered about 1,200 residents to evacuate. The evacuation orders were lifted Friday evening as air quality monitors showed “no threat to human health,” officials said. No injuries or deaths were reported.

Though investigators have yet to determine the cause of the blaze, North County Fire Protection District Chief Joel Mendoza said Friday that a fire suppression system housed within one of the facility’s battery racks had failed, allowing the fire to spread. A Vistra spokesperson told CBS News that “an investigation will begin once the fire is extinguished.”

Church said in a Friday news conference that this was the fourth fire since 2020 on the property that houses Moss Landing and an adjacent 182.5-MW battery energy storage facility owned and operated by Pacific Gas & Electric. But the latest incident “does look and feel very different,” Addis added. Vistra, however, contends that two of the incidents were “overheating” and not fires.

The 300-MW battery array that burned is part of the 750-MW Moss Landing Energy Storage Facility, which occupies a decommissioned gas-fired power plant dating back to the 1950s. The retrofitted installation is among the less than 1% of U.S. energy storage facilities housing batteries indoors, American Clean Power Association spokesperson Phil Sgro said. 

“Safety is the first and foremost priority of the industry and, after the incident is resolved and there is a thorough investigation, [it] will ensure the lessons learned are applied to prevent future incidents and inform safety standards and best practices,” Sgro said.

In July, ACP released a model ordinance framework for states and municipalities to develop regulations for energy storage system safety, permitting, siting, environmental compliance and decommissioning. The framework draws on the NFPA 855 fire safety standard and the UL 9540 and 9540A standards, which deal specifically with energy storage system safety.

Legislation signed in October 2023 by California Gov. Gavin Newsom, D, required battery energy storage facilities in the state to develop “an emergency response and emergency action plan” in coordination with local authorities. Assemblymember Addis co-authored the bill.

Tom Stepien, CEO of South 8 Technologies, said the energy storage industry “should also take a closer look at the fundamental building blocks of lithium-ion batteries and understand how we can make the cells themselves safer.”

Stepien’s company makes a proprietary gaseous electrolyte that “enables [lithium-ion] battery operation in extreme climates with reduced fire risk” compared with liquid electrolyte. The gas escapes compromised cells in seconds, reducing burn time and the corresponding risk of an adjacent cell igniting, he said.

The battery array that burned was commissioned in 2020, making it one of the oldest utility-scale battery installations of its size in California. Its vintage suggests it may not have been built to the strict fire safety standards supported by ACP, said Dustin Mulvaney, an environmental studies professor at nearby San Jose State University who studies energy storage systems. Mulvaney added that he did not have direct knowledge of the Moss Landing facility’s design or safety features.

“I would go and inspect any energy storage system that looks like this one,” Mulvaney said. “We should have a thorough inspection regime.”

Despite local officials’ alarm at the Moss Landing fire, Mulvaney said the incident is unlikely to set back the energy storage industry in California, noting a state-led siting option that limits local governments’ power to block new projects that incorporate community benefits agreements. Moving forward, energy storage developers may face stronger pressure from the insurance industry to follow strict fire safety standards, which could prove beneficial for the industry’s safety record and reputation in the long run, he said.

“If the industry figures it out, this could be the biggest battery fire that ever happens,” Mulvaney said.

Maryland on Nov. 26 launched a $15 million electric resilience competitive grant program that officials say is “essential to reducing power outages and keeping the state moving toward its clean energy and greenhouse gas reduction goals.”

The Resilient Infrastructure for Sustainable Energy, or Maryland RISE program, is accepting applications from the state’s utilities, bulk power system operators and related power-industry stakeholders. About $13 million of the available funds will be provided through the federal Infrastructure Investment and Jobs Act. Awards are subject to funding availability, the state said.

“Our grid is battered and getting worse,” Maryland Energy Administration Director Paul Pinsky said in a statement. “In the face of rising demand for electricity and the more frequent and severe storms triggered by climate change, we absolutely must have a reliable electric grid.”

Eligible grant activities include weatherization efforts, fire-resistant technologies and fire prevention systems, monitoring and control technologies, undergrounding electrical equipment, utility pole management, the relocation or reconductoring of power lines, vegetation and fuel-load management and non-generation distributed energy resources, including microgrids and battery storage subcomponents.

The funds cannot be used for cybersecurity measures, new generation facilities or construction of a large-scale battery-storage facility not used for enhancing system adaptive capacity during disruptive events.

Applications are due to the Maryland Energy Administration by Jan. 21, with funds offered in two tranches: to applicants selling more or less than 4 million MWh annually to customers in the state.

Maryland has set a goal to reduce greenhouse gas emissions in the state 60% below 2006 levels by 2031 and achieve a 100​% clean electric grid by 2035.

The Public Utility Commission of Texas on Nov. 14 approved Oncor Electric Delivery’s $3 billion system resiliency plan, which aims to accelerate grid upgrades, reduce the duration of severe weather outages and address other physical and cybersecurity risks, including wildfires.

Oncor’s plan was based on two decades of weather and grid data, and includes increases in vegetation management near power lines and investments in automation. The improvements will “substantially reduce outage minutes,” Oncor CEO Allen Nye said in a statement.

Texas lawmakers passed legislation last year authorizing the state’s utilities to submit resiliency plans aimed at bolstering grid reliability. Oncor’s proposal was the first to be approved; regulators are still considering plans from American Electric Power Texas, Texas-New Mexico Power Co. and Entergy Texas.

Oncor’s resiliency plan represents a “substantial investment” paid for by ratepayers, but Commissioner Lori Cobos said she was “encouraged by the strong collaboration among parties that ultimately resulted in a settlement agreement and the data-driven, granular process that was open and transparent.”

The settlement agreement that led leading to Oncor’s SRP approval was supported by PUCT’s legal staff, consumer groups and cities, Cobos said. The Electric Reliability Council of Texas, the Alliance for Retail Markets and the Texas Energy Association for Marketers did not join the agreement but did not oppose it.

“These investments have been methodically selected to have the greatest impact in proactively addressing potential outage causes,” Nye said. “We will start implementing our SRP immediately and will keep customers informed of our progress in their communities.”

Investments outlined in Oncor’s system resiliency plan include:

• Modernizing and hardening legacy overhead system, including poles and crossarms;
• Improvements to Oncor’s underground system, including switchgear automation;
• Optimizing distribution automation through new ties, capacity and intelligent switches; and,
• Enhanced cybersecurity risk mitigation and investments in the utility's digital infrastructure.

Cobos asked Oncor representatives at the PUCT’s open meeting last week if the plan takes into account efforts to “sectionalize” the utility’s distribution grid. That approach includes creating additional ties between feeders from different substations to allow system flexibility to recover from an outage or to de-energize some portions while leaving others operating, potentially during a wildfire.

“Particularly where we are building new, that's just part of the current modern design standard. We will kind of build that sectionalization in,” said Brian Lloyd, Oncor’s vice president of regulatory policy. The utility’s system resiliency plan “really lets us bring that technology to the older parts of our system, [the parts] that when we built them decades and decades ago, that was not really the current design standard.”

In addition to the substantial investment in its distribution system, Oncor also expects to expand its transmission system.

In September, the PUCT approved an electric reliability plan for the Permian Basin region, where the oil and gas industry, data centers and other loads are driving electricity demand rapidly higher. The Permian reliability plan includes about $4 billion in local projects that can commence immediately, and another $9 billion for projects that will depend on whether regulators opt to move ahead with 765-kV transmission lines.

“We expect Oncor to capture a significant portion of the new capital investment opportunities given our current operations in the Permian Basin and ERCOT’s preliminary recommendations,” Nye said earlier this month during the utility’s third-quarter earnings call. Most of the local projects need to be in service by 2030 to meet expected demand, he noted.

The U.S. Department of Energy selected 38 projects for nearly $2 billion in funding from its Grid Resilience and Innovation Program, DOE said Oct. 18.

“With these projects, we're investing in resilience, which means we're supporting communities before, during and after wildfires and storms and heat waves and other extreme weather across the country by hardening the grid by, for example, undergrounding power lines or adding technology that reroutes power during storms,” DOE Secretary Jennifer Granholm said Oct. 17 during a press briefing.

The projects will boost transmission capacity by more than 7.5 GW, speed up interconnection for clean energy and spark over $4.2 billion in public and private investment, DOE said in a press release.

Under the Biden administration, DOE has sparked $36.9 billion in public-private spending on grid projects, according to Granholm.

In its initial funding rounds, including yesterday’s announcement, the $10.5 billion GRIP project has committed to $7.6 billion in funding while receiving applications for projects totaling about $50 billion, Granholm said. DOE plans to launch a third funding round next year.

Selected projects include:

• $160 million for Georgia Power to install grid-enhancing technologies, including dynamic line rating technology and reconductoring.
• $100 million for Exelon’s Renewable-Aware project that will deploy a distributed energy resources management system and Unbalanced Load Flow technology to optimize distributed energy resources across its service territory, with an initial focus on disadvantaged communities.
• $117 million for Hoosier Energy Rural Electric Cooperative and Southern Illinois Power Cooperative to build 69-kV or 138-kV transmission feeds to loop transmission to substations in seven counties in Illinois and Indiana that face increasing outages from extreme weather events and tornadoes.
• $50 million for GridUnity, which will use cloud computing and other advanced processes to speed up the grid interconnection process around the United States. DOE expects the project will cut interconnection times by more than a year on average.

In October 2023, DOE announced $3.5 billion in GRIP funding for 58 projects in 44 states. In August, the department announced an additional $2.2 billion for eight more selections.

The Southwest Power Pool board of directors on Oct. 29 approved a slate of 89 transmission projects with an estimated cost of $7.7 billion, aimed at addressing “reliability, economic, policy and operational needs” across its 14-state operating footprint

The 2024 Integrated Transmission Plan is the “single largest portfolio, in terms of size and value,” that SPP has proposed in its 20-year history, the grid manager said in a statement. The plan includes 2,333 miles of new transmission and 495 miles of transmission rebuilds.

SPP’s footprint “is facing a generational challenge as the need arises to balance new sources of demand, like data centers, crypto mining, mining, and oil and gas production, with the retirement of conventional resources that use coal and natural [gas] as fuel sources,” according to the plan.

The plan addresses “uniquely sharp load increases in New Mexico” by recommending a 765-kV line be developed from the panhandle of Texas to southeastern New Mexico, “delivering much needed energy to a remote area of the region.” Rapid load growth in North Dakota and South Dakota will be addressed through a network of new and upgraded lines across both states, it said.

SPP said its winter storm resiliency analysis also identified transmission projects that “improve system voltages throughout the approved target areas,” including transmission necessary for generation from outside of this area to reliably reach the loads.

“Increasing imports is especially important when the limited natural gas supply restricts local generation or transmission congestion prevents local generation from coming online,” the report said. “SPP also identified projects that increased the transmission system’s ability to transfer power from north to south within the SPP footprint by approximately 1.5 GW. This further increases resiliency against extreme winter storms by enabling SPP’s northern generation facilities which are hardened to withstand extreme temperatures to deliver power to the southern portion of SPP’s footprint.”

Ahead of the board’s decision, SPP said its Markets and Operations Policy Committee voted in support of the plan with 95% approval.

“The high degree of consensus among our stakeholders in support of such a significant infrastructure investment demonstrates the quality of this remarkable planning effort which is expected to provide significant value for years to come,” SPP Executive Vice President and Chief Operating Officer Lanny Nickell said in a statement.

The projects “are expected to quickly pay for themselves and provide benefits exceeding costs by a rate of at least 8-to-1 while improving grid resilience in the face of extreme weather events,” SPP said. By reducing costs, the projects will create savings of $10.55 to $11.47 on the average retail residential monthly bill, according to the plan. The projects are expected to be “cost beneficial within the first year of being placed in-service” and to pay back the total investment “within the first three years.” 

“The magnitude of the 2024 ITP is larger than we’ve seen before, but the time is right,” said SPP Vice President of Engineering Casey Cathey.

“We’re seeing a large increase in demand for power throughout the nation and our region. Events like Winter Storms Uri and Elliott have highlighted the need for increased transmission capacity to ensure that all customers continue to receive reliable electricity service in the most challenging times,” Cathey said.