DOE 2026 Draft National Transmission Needs Study Webinar

Hello and welcome, everybody, to the 2026 Draft National Transmissions Needs Study webinar. My name is Larisa Kriwok, and I'll be your host today. Before we get started, I'd like to go over a disclaimer. None of the information presented herein is legally binding. The content included in this presentation is intended for informational purposes only relating to the 2026 National Transmission Needs Study. Any content within this presentation that appears discrepant from the To kick us off today, I welcome Assistant Secretary of the Office of Electricity, Katie Huraiza. Hello, I'm delighted to welcome you to today's webinar on the 2026 National Transmission Needs Study. The Needs Study provides insight into where our nation's grid and the communities it serves would benefit from additional transmission investment. It evaluates current and future transmission capacity constraints and congestion across the country. Efforts like the Needs Study underscore why our work at the Office of Electricity is so important. Our mission is to stabilize, optimize, and grow the electricity system to ensure the grid delivers affordable, reliable, and secure energy to the American people. We are working to achieve this mission with a focus on three strategic pathways. Stabilize, optimize, grow. We are stabilizing the grid to address the immediate, acute needs that are straining reliability. We are optimizing the grid to get improved performance from the grid while maintaining affordability. And we are growing the grid by tapping into the country's many energy resources, including nuclear energy, natural gas, and coal. Our strategy focuses on balancing near-term system needs with long-term transformation, ensuring the grid can support economic growth, national security objectives, and evolving customer and technology demands under increasingly dynamic conditions. Over the past year, DOE has advanced major grid modernization efforts, including new investments through federal transmission programs, updated technical assistance offerings, and ongoing support for grid resilience initiatives across states and regions. These efforts reflect the Administration's commitment to ensuring affordable, reliable, and secure electricity for all Americans. The Needs Study plays a foundational role in informing this work. The findings guide the implementation of various federal programs and authorities, particularly those focused on transmission expansion, grid reliability, and advanced grid technologies. But most importantly, they help shape our national conversation around electricity transmission. With that overarching goal in mind, we are entering a crucial public review phase for the Draft 2026 Needs Study. We are releasing a draft for public comment. I encourage you to share your input. We rely on your insights to help us determine where federal action and investment can have the greatest impact. As part of, and even beyond, this comment period, I am eager to engage with decision-makers and stakeholders across the country to advance real transmission solutions that support American energy dominance. In the short term, we will be using your feedback to improve this iteration of the Needs Study. In the long term, we look forward to catalyzing investments in new and upgraded transmission and grid infrastructure that work for local, state, and regional priorities, consumers, and landowners while advancing national interests. Together, we will stabilize, optimize, and grow the nation's grid. Finally, I want to extend sincere appreciation to the dedicated team who developed this study. Their work has been instrumental in producing this rigorous and comprehensive analysis. With that, I'll turn it back to our host to introduce our presenters. Thank you. Thank you so much, Assistant Secretary. Allow me to introduce your speakers today. Molly Roy, Management Analysis. Mark Severy, Lab Detail. Nikki Ragani, Fellow in the Transmission Division of the Office of Electricity. I'll turn this over now to Molly. Great. Well, thank you very much, Larissa, and thank you, Katie. Today, I will cover the first agenda item here, walking through the background of the Needs Study. This will include the statutory basis for this assessment and next steps for getting the study from draft to final. Then I'll hand it over to Mark and Nikki to cover the overview of the study and select results. The Needs Study is a report that is statutorily required under Section 216A of the Federal Power Act, which directs the Department to conduct an assessment of historic transmission constraints and congestion on the grid every three years in consultation with states, Indian tribes, and regional grid entities. The text that you see in red on this slide are changes that were made to the Federal Power Act Section 216 as part of the 2021 Infrastructure Investment and Jobs Act. In that law, Congress amended Section 216A to direct the Department not only to conduct an assessment of historic but also expected transmission capacity constraints and congestion and added the requirement to consult with Indian tribes. Next, we want to cover more specifically what the study is and what it is not. So you can go to the next slide. Here is what you can expect from the Needs Study. First, off the objective, it is to assess transmission needs across the nation. However, this study does not prescribe any specific transmission solutions to meet those needs. For our methods, on the next slide down, the Department has considered existing data, trying to fill in gaps where public data is unavailable. This study assesses data from over 120 recent published reports from a variety of different entities, which we'll talk about a little bit more shortly. These include historic data and regional assessments, as well as some forward-looking national-level capacity expansion modeling results, which we will also speak to more later in the webinar. The report does not conduct any large-scale new modeling, cost-benefit analyses, or system planning. So the study is not intended to replace any regional or industry-led transmission planning processes that already exist. Finally, study outputs. The Department assessed the data, and we have organized the findings by geographic region in the contiguous United States, as well as Alaska and Hawaii. However, these regions are not synonymous with specific transmission corridors. Specifically, it is not synonymous with National Interest Electric Transmission Corridors, or NITCs, if you're familiar with those. This study does not identify or designate any NITCs. Should the Secretary choose to designate a NITC, per the authority to do so granted in the Federal Power Act, the NEED Study may be one of the many inputs that could inform that decision. But please note that DOE would conduct corridor identification and designation in a separate process. On the next slide, here is a snapshot of the types of studies that were considered. There were over 120 studies that were reviewed, and the findings are primarily included from these studies in Chapters 5 and 6 of the NEED Study. These reports were published over the span of 2018 to 2025. In black, we have U.S. government reports. A lot of those are Department of Energy or National Lab reports, but this also includes some other U.S. agency reports. In yellow, we have consultant reports, notably consultants who are very active in the power sector space. In dark green, there's a thin slice of academic reports that felt very relevant to include, and the majority, roughly 60 percent of all the studies came from industry. That's the blue chunk. So next slide is my last slide, and here we have a summary of the engagement and outreach process for the NEED Study with the steps we will take to move the study from draft to final. So in conjunction with this webinar, the Department is releasing a draft version of the report to the public, as well as to the statutory required consultation entities, the tribes, states, and regional entities. For a public and consultation comment period. Once the comment period closes, we plan to diligently review all written comments. We receive and implement any suggested changes as appropriate. The final study is slated to be released in October 2026, and we hope you will consider commenting, as you heard Katie say as well. Thank you, and next up, Nikki will begin with an overview of the study, and then we'll dive briefly into each of the chapters. Thank you so much, Molly. Allow me to introduce Nikki Rougani to go over the study chapters. Thanks, Molly. So the NEED Study is a seven-chapter report. It is roughly 90 pages in length. We also publish a separate document on the website called the Supplemental Material, which outlines a lot of the methodology behind the Department's analysis, as well as background on findings referenced from national studies that have not been published yet. The report begins with an executive summary and introduction. Following this, a very similar and very similar to the 2023 NEED Study, we incorporate Chapter 2, which introduces some legislative language, including the Federal Power Act that motivates the Department to conduct the study, as well as how the study supports executive orders of the current administration. Following this, Chapter 3 is a discussion of transmission concepts, as the Department touches on a handful of these at great length in the report, and we want to catch all of our readers up to speed. Those first two chapters set us up for findings in the rest of the report. Chapter 4 through 7 contain the majority of the findings of the report. Let's walk through the content covered in each of these chapters. Chapter 4 is a discussion of historical investment data, which the Department uses to assess current transmission needs. Following this is Chapter 5, which is a discussion and review of recently published reports and transmission planning documents from a variety of entities that the Department uses to assess historical and current needs and the identification of transmission benefits. This chapter also includes new national laboratory studies of historical data to fill in data gaps in regions with limited publicly available data. Chapter 6 is a discussion and review of recently published reports and transmission planning documents from a variety of entities that the Department uses to assess future needs, breaking down the findings by region. This section also discusses tribal transmission needs as well as the trends driving future transmission needs. And lastly, we have Chapter 7, which summarizes the findings of four existing capacity expansion modeling studies and provides insight into anticipated future need. And finally, the supplemental material. The supplemental material provides background information on the methodology of the Department that the Department uses to analyze the results in Chapter 4, as well as providing background information on a forthcoming study referenced in Chapter 5. The forthcoming study referenced in the supplemental materials was undertaken by a national lab specifically to fill regional data gaps. The background provided serves as a placeholder until the full study can be published, so that there is an opportunity for entities and the public to review the analysis and provide comment on the conclusions drawn in the main report. Finally, there is a comprehensive table listing the reports included in the literature review, incorporated into the findings of this study, as well as a detailed reference list at the end of the supplemental materials. So, let's get to the exciting bit and discuss some of the findings. Going over some high-level results, we have a couple of national takeaways. We find that there continues to be a pressing need for new transmission infrastructure due to load growth from growing industries, such as data centers, expanding domestic manufacturing, large loads, and the electrification of industries. We also find that among the various configurations of transmission deployment, inter-regional transmission continues to be recognized as serving the largest benefits. And in anticipation of the transmission needs ramping up, many regions are approving their largest transmission portfolios to date. The executive summary provides a visual overview of the national and regional-specific findings of the detailed study. We organize these findings across 20 geographic regions here, where a transmission need exists historically and could benefit from an upgraded or new transmission facility to meet the following four categories of need, which are included in this map. The categories are, number one, improved reliability and resilience, as identified in the report by the North American Electric Reliability Corporation, also known as NERC, called the 2024 Long-Term Reliability Assessment. This category is represented by orange bubbles. Number two is alleviate congestion within regions, as indicated by analysis discussed later in Chapter 5, Subsection A. This category is represented by dark green bubbles. Category number three is to alleviate transfer capacity limits between the neighbors, as indicated by the analysis discussed later in Chapter 5, Subsection A. This category is represented by lighter green bubbles. And finally, the fourth category, to provide resource adequacy through interregional transfer capacity, as indicated by the analysis discussed in Chapter 5, Subsection C. This category is represented by dark blue bubbles. The graphic uses color-coded buckets to indicate high-level transmission in the need study. These indicators of need are placed on the map within each geographic region. I'll note that these findings are just high-level summaries. The detailed findings are in the body of the report itself. Looking at this map, we can see a few things, which we'll go over. The first thing we'll note is that there is a need to improve reliability and resilience, as indicated by the orange or rust-colored circles. We find that nearly all regions in the United States would gain improved reliability and resilience from additional transmission investment. The need to alleviate congestion and unscheduled flows is indicated by the darker green circle. We find that regions with historically high levels of within-region congestion, so specifically looking at NISO, SIRTIP, FRCC, and Northern Grid South regions in particular, need additional strategically-placed transmission deployment to reduce this congestion. Moving on to the need to alleviate transfer capacity limits, we find that, historically, the data assessed shows a need for transmission to alleviate capacity constraints that prevent moving electricity across the interconnection seams. So, specifically, we find this need in most of the regions of the contiguous United States. And finally, the need to deliver low-cost generation to high-priced demand, thereby addressing resource adequacy through interregional transfer capacity. There are several regions that endure consistently high electricity prices, most notably areas within the KISO, ERCOT, PJM, SPP, Northern Grid, WestConnect, and the Southeast. And we find additional transmission to bring cost-effective generation to meet demand in those high-priced locations would help lower prices. Before we move on, we just wanted to quickly note a couple of things here. In instances where a circle or an indicator of need is not filled with any color or appears white in the map on the previous slide, the department concludes that there is not sufficient evidence to suggest that a transmission need exists or that there is an absence of data that does not allow for proper assessment of transmission need. However, the department may have found this need to exist using other resources, particularly those in Chapter 5 and 6 of the literature review. And then, finally, you'll notice asterisks in two instances. For those, we know that wholesale market price data is limited for Alaska and Hawaii, which is one of the data points that the department has used to assess whether such a need exists. The absence of data, however, does not necessarily indicate that there is no need for new transmission. Similarly, the department may have found this need to exist using other resources, particularly those in the Chapter 5 and 6 literature review. With that, we will move on to exploring key findings in each of the chapters beginning with Chapter 4. Chapter 4 analyzes publicly available data between the years of 2016 and 2024 assessing transmission investments. This chapter also explores transmission deployment, analyzing it by voltage type, developer type, as well as the primary drivers that have spurred historical transmission development. In Chapter 4, the main takeaways are that from 2016 to 2024, significant investments have been made to enhance the reliability, capacity, and resilience of the transmission system. Throughout all regions in the U.S., 85,000 circuit miles of newly constructed, upgraded, or rebuilt transmission lines rated at or above 69 kilovolts have been built. Transmission investment varies considerably by region. Between 2016 and 2024, ERCOT and MISO-North energized 6.2 and 5.1 circuit miles per terawatt hour of annual load, respectively, while Hawaii, Northern Grid South, Northern Grid West, PJM West, and SIRTIP built less than 1.2 circuit miles per terawatt hour of annual load. Capital investment costs also vary by region, with the highest expenditures in PJM East and ERCOT at $3.5 billion and $2.1 billion per year, respectively, on average across the nine-year analysis period. The majority, so about 66 percent, of new circuit miles are 69 or 138 kilovolts, with only 4 percent of new circuit miles at 500 kilovolts or above. We also find in this chapter that incumbent utilities developed 98 percent of all new transmission, with 11 out of 21 need study regions having 100 percent incumbent utility development. Some regions had higher levels of non-incumbent utility development, including West Connect South at roughly 12 percent, SPP North at roughly 10 percent, and Northern Grid South at roughly 7 percent. Reliability has emerged as a primary driver of transmission investments, reflecting the ongoing efforts to ensure a stable and efficient power supply. 38 percent of new circuit miles were driven by reliability needs, followed by aging infrastructure at 20 percent, load growth at 17 percent, and generation at 13 percent as primary drivers. Congestion and public policy were both drivers of less than 1 percent of new transmission circuit miles. For reference, the current transmission system in the contiguous United States is estimated to be at just over 525,000 circuit miles, as calculated by summing the length of all lines greater than or equal to 69 kilovolts from the Homeland Infrastructure Foundation-level spatial data for transmission. The 85,000 circuit miles added since 2016 would represent 16 percent of total existing circuit miles. So, looking on this slide, our very first finding of need in the need study is that transmission investments maintained at a steady pace during the first half of the 2020s. Plotted on this chart are circuit miles of new investments every year that were installed between 2016 and 2024 across different regions of the United States. The leftmost cluster of bars show all regions of the entire United States, but then we also break it out by individual region. In general, you can see that there's a steady pace in new transmission coming online between 2016 and 2023, and then a slight drop in 2024. Regionally, we see that, on average, ERCOT, MISO-North, and SPP-North have developed the most circuit miles of transmission when weighted against load requirements. Interestingly, ERCOT built, on average, 2,400 circuit miles per year over the nine-year study period. I'll note that, on this slide, we're showing circuit miles of new transmission installed weighted by load, which is why, for example, Alaska seems so high in comparison to the other regions. It's just because we're trying to understand an apples-to-apples comparison of how much load this transmission is trying to serve. But in the study itself, we also show just the absolute amount of circuit miles and the capital costs that were spent on new transmission investments in all the different regions. Load data for Alaska and Hawaii was pulled from the Energy Information Administration state electricity profiles that were pulled from the year 2023. All other region load data was pulled from the report called 2023 Standard Scenarios Report, authored by the National Laboratory of the Rockies, known at the time of publication as the National Renewable Energy Laboratory. Within that 2023 report, specifically the 2024 mid-case current policy scenarios were used for regional load data. Looking at what is driving transmission installation in recent years, shown here is the percentage of all transmission investments by the primary driver of the region. We find the biggest driver of transmission investments were these incremental local reliability needs, which are shown in the darkest shade of blue in certain regions, such as CAISO, all of MISO, as well as Northern Grid West, NISO, and all of PJM, SIRTIP, and SPP South. In other regions, we see aging infrastructure as the primary driver in regions like Alaska, Hawaii, ISO New England, and WestConnect North. As a nation, aging infrastructure drives roughly 20% of projects in this space. That concludes the main components of Chapter 4. Now I'll pass the baton to Mark to discuss Chapters 5 and 6. Thank you, Nikki. Chapter 5 of the NEED Study reviews historical and current transmission system operations, value, and constraints. It focuses on existing transmission congestion on the grid and bulk transmission system operations during periods of greatest stress and emergency events. Section A covers current national and interregional transmission congestion and transfer capabilities, diving into new analyses from DOE's national laboratories and a literature review of regional planning reports to highlight historical capacity constraints and congestion on the U.S. bulk. Section B of Chapter 5 covers regional congestion management needs reported by each region, summarizing regional planning reports and organizing the findings by regions, as well as some new analyses from DOE's national labs that map frequency and intensity of congestion in each RTO-ISO region. The section reviews the current state of congestion, congestion patterns, and congestion impacts and management strategies within RTO-ISOs and non-RTO-ISO regions. Section C covers resource adequacy and resilience benefits of transmission as reported by planning reports and further supported by new analysis from DOE national labs. It explores the role of the transmission system enhancing reliability and resource adequacy. In Chapter 5, the main takeaways are that transmission congestion continues to be seen across all regions, which contributes to the growing price of electricity and is further exacerbated by extreme weather events and fuel price volatility. In studying the congestion value across regions, it was found that a majority of congestion value from the new transmission links is concentrated during times of unforeseen changes within one day of operations, especially in conjunction with high net load or cold weather. We're also seeing the highest load-weighted congestion costs in KISO, SVP, and ERCOT, while ISO New England and MISO show the least amount of congestion. Overall, we find that transmission investments can reduce congestion and wholesale electricity prices in the long term, and that system hardening and expansions that create redundancy improve resilience in the isolated regions during emergency events. Moving on to the next slide for three more key findings from the needs study resulting from DOE-funded studies at our national labs that we'll explore in the slides after this one. First, inter-regional and cross-interconnection transmission linkages typically show a higher potential to reduce the average wholesale price of electricity when compared to links within a region. Second, to explore congestion in the southeast U.S. where there is no organized wholesale electricity market, new analysis found that the estimated average transmission congestion value is nearly $10 per megawatt hour for transmission links within the southeast. We'll further explore this in the upcoming slides. Third, the studies found that inter-regional transmission enables regions to import power from each other when in need of additional supply to support resource adequacy due to diversity of load profiles and resource mixes between regions. Analysis of locational marginal prices, or LMPs, in the U.S. show that inter-regional and cross-interconnection transmission links have the highest potential value to relieve transmission congestion. Locational marginal price is defined as the marginal cost supplying the next incremental unit of energy at a particular location, considering factors like generation costs, demand, and transmission constraints. Differences in LMP indicate the system's transmission constraints limit the ability to deliver low-priced energy from one node to customers at the higher-priced node, adding transmission reinforcements on a path between the two nodes with a large price differential could alleviate transmission constraints and provide some congestion relief value by lowering the average LMP across the two nodes. Analysis from Lawrence Berkeley National Lab, or LBNL, evaluates the difference in real-time LMPs between 65 pairs of pricing nodes across the need study regions within the contiguous United States between 2012 and 2023 to approximate the value of connecting the two nodes with a new or reinforced transmission infrastructure. The maps here show average price differentials between nodes, with the darker red lines showing linkages with larger price differentials and more potential transmission value, and lighter yellow lines showing linkages with smaller price differences and less potential transmission value. The map on the left shows only links between regions and across interconnections, while the map on the right shows links within regions. Based on this analysis, we see that transmission links crossing electricity market seams between regions are interconnections, so the highest potential for transmission congestion value. For example, cross-interconnection links between the western interconnection and the eastern connection LMP differentials from $18 to $33 per megawatt hour reach across all hours from 2012 to 2023. Links between regions within an interconnect also have transmission congestion value, particularly between Northern Grid and WestConnect in the west and between ISO New England and NISO in the northeast. Lastly, transmission links within regions have lower LMP differentials than the interregional links, with the highest value within regional links between New York City and the rest of NISO around $17 to $18 per megawatt hour, and within Northern Grid South at $15 per megawatt hour. This is shown in the map on the right. This analysis also finds that many links are fairly balanced in terms of which direction power flow would be valuable over time, meaning that each side of the link has periods where it has their LMP. Thus, the transmission links would provide value on both ends of the link because each terminal experiences times and the lower cost generation is available on the other side. On the maps, you may notice that links within the southeast US are not shown because this region does not have a competitive wholesale electricity market with published LMPs. In order to estimate potential transmission congestion value in the US southeast, LBNL and National Lab of the Rockies modeled historic zonal production costs in the Southeastern Regional Transmission Planning and Florida Reliability Coordinating Council needs regions from 2016 to 2023 benchmarked with actual reported data. The maps here show estimated transmission congestion value for interregional and regional links in the US southeast derived from the modeled LMP. It shows transmission value by zone in the southeast for 2012 on the left map, which was the highest value year, and in 2023 on the right map, which was a lower value year. Darker lines show transmission linkages that would have more influence on reducing congestion costs between zones by increasing their transfer capability compared to the lighter colored linkages. The three linkages with the highest transmission congestion value in both 2022 and 2023 are interregional linkages between Southern Company and FRCC, Duke and PJM, and TVA and MISO South. In addition to enabling the exchange of lower cost electricity throughout the year, interregional transmission can provide additional value during peak hours and stress periods, which are the hours driving resource adequacy needs. Transmission plays a critical role in maintaining resource adequacy by enabling generation to move where it is needed each hour, which is important both within regions where generation resources may not be located near major load centers and between regions that manage varying load profiles and resource mixes. A recent LBNL study examined the opportunity for interregional transmission to support resource adequacy by trading with neighboring need study regions whose net peak periods occur at different times. The study looked at the highest net load hours and the highest, the 100 highest net load hours and the 100 highest priced hours per year from 2016 to 2023. The map on the left shows the percent of overlap for the peak net load hours in each region with its neighbors. The map shows that the Pacific Northwest has hardly any overlap with peak net load hours with adjacent regions, for example, in California and the two regions in the interior west. This is driven by the Northwest's tendency to experience peak demand in the winter rather than the summer, like in the neighboring regions. On the other hand, the northeastern regions of the U.S. had the greatest overlap in peak net load hours, with NISO sharing 72 percent of net peak load hours with ISO New England to the north and 74 percent of net peak load hours with PJM east to the south. Other regions throughout the contiguous United States had moderate overlap in net peak hours with its neighbors. The table on the right shows the correlation between price in neighboring regions during peak price hours. Darker colors indicate more price correlation where a high price in one region aligns with high price periods in neighboring regions. Low overlap of high price periods, as shown as lighter colors in the table, suggests that there would be potential resource adequacy value associated with increasing interregional transmission capacity between those regions. Regions across Northern Grid, WestConnect, SPP, and ERCOT exhibited mean prices in approximately the 50th to 70th percentile during the highest price periods of adjacent regions. For example, WestConnect South's mean price during SPP South's and ERCOT's peak price periods was in the 53rd and 55th percentile, indicating potential for resource adequacy benefits through transmission linkages to the adjoining region not experiencing peak price. And now we'll move on to a review of Chapter 6, which conducts a future needs assessment focused on what the industry is telling us. Section A highlights key findings across the regional transmission planning documents and includes a review of tribal transmission needs, referencing a study from DOE's national labs. Next, Section B discusses key factors driving future transmission need, comparing the results of three national level reports. Key takeaways from the regional planning documents across the U.S. indicate that given resource changes, additional transmission will be needed to maintain reliability. Additional factors driving the need for transmission include aging infrastructure, resource retirements, and new generation interconnects. Regional planning processes indicate that regions are investing substantially in new transmission. Some regions approved their largest transmission planning portfolios in recent years. Interregional transmission is increasingly recognized for its contributions to increasing reliability, greater resiliency, and meeting demand growth in at-risk areas. Several planning regions have initiated joint planning processes to better identify interregional transmission and have already identified significant risk if transfer capacity has not increased between certain regions. The graph on this slide shows projected data center energy demand growth through 2030 and was developed by the Department of Energy using information sourced from Lawrence Berkeley National Lab, the Electric Power Research Institute, or EPRI, and McKinsey. Commercial and industrial growth contribute to increased electricity demand across the U.S. This growth includes data centers, artificial intelligence, and cryptocurrency mining, expanded domestic manufacturing, including of batteries and fuel cells, the addition of other large commercial and industrial loads, including smelters, manufacturing centers, hydrogen electrolyzers, and future electrified mass transit or shipping charging stations. Recently, the load growth from data centers has become a particular focus in the industry and is driving upwards trends in demand. Many utilities, as well as financial and industry analytics firms, cite data centers, often specifically AI data centers, as the main driver for electricity demand growth. These projections show data center load growth to over 400 terawatt hours by 2030, which is equivalent to over 10 percent of total electricity end use in 2023 and driving specific needs for investment in transmission across regions in the U.S. In addition to the findings from regional planning documents, Chapter 6 summarizes on tribal transmission needs completed by the lab of the Rockies. The U.S. has 575 federally recognized tribes across 34 states. The map on this slide shows how the tribal lands are distributed across the need study regions. It is known that individual tribal nations have a wide array of energy needs and goals, ranging from access to basic electricity service and increased reliability to the development of utility-scale generating plants. Access to transmission is a key part of the multifaceted tribal energy landscape. Tribal proximity and access to transmission infrastructure varies widely across the country, which presents challenges to achieving the range of goals that include improving electricity access, reducing electricity outages, reducing household energy burdens, and enabling utility-scale generation to address growing electricity demand nationwide. About 2.3 percent of the nation's transmission miles are located on tribal lands. The tribal transmission needs section of the needs study quantifies over 1,000 substations at voltages above 100 kilovolts that are currently located on or near tribal lands, with the highest numbers in SPP South and in the Southeast. However, circumstances vary widely when considering the nation's miles of transmission and substations on or near tribal lands. Much of the transmission is for local network delivery around 138 kilovolts, which can limit opportunities for utility-scale development without significant transmission upgrades. There are some high-capacity 500 kilovolt lines, but in many cases, tribes have limited access to them even when those lines run across their reservation. Generally, a significant lack of information and data is a major challenge in quantifying energy-related needs in tribal communities, and consequently, more analysis and support specifically focused on energy needs and goals on tribal lands can help better understand opportunities for transmission development or expanding access where the transmission infrastructure already passes through tribal lands without delivering power. That concludes summary of the main components of Chapter 6. Now I'll pass it back to you, Nikki, to go over the Chapter 7 findings. Thanks. Thank you, Mark. Looking at Chapter 7, this section of the report briefly highlights recent national modeling studies conducted outside of regional planning processes. These studies include analyses guided by capacity expansion modeling, as well as analyses of inter-regional transfer capacity to support reliability and resource adequacy needs. The reports referenced are the National Transmission Planning Study DOE conducted in 2024 in partnership with a number of national labs, as well as NERC's Inter-Regional Transfer Capability Study published in 2024, DOE's Resource Adequacy Report completed in 2025, and the National Laboratory of the Rockies, formerly known as National Renewable Energy Labs Report, impacts of regional coordination on transmission needs for power system resource adequacy, which was published in January 2026. The collection of studies indicates the need for significant transmission investment over the next 20 years to support increasing electrical demand and new generation while maintaining high reliability and low costs. We have a couple key takeaways we'd like to highlight from these capacity expansion studies. Firstly, results from the capacity expansion studies show strong correlation between future electricity demand growth and needed transmission capacity, indicating that planning for and investing in transmission infrastructure is vital to support low growth of the nation's industry and population. And secondly, long-term studies from NERC and NLR found that inter-regional transmission expansion supports improved resource adequacy across multiple regions and mitigates the impact of extreme events in coordination between regions, if coordination between regions can be achieved. Transmission's role to improve deliverability and resource sharing for resource adequacy can be particularly pronounced for large power systems like the U.S. electricity grid. Resource sharing between regions can offer large potential benefits given the longer distances involved. DOE's Resource Adequacy Report identified resource adequacy as a growing concern for the electricity grid. Transmission ensures that generation can be delivered to load when needed by enabling the sharing of energy resources across regions with different load profiles, weather patterns, and generation mixes. This connectivity allows systems to better manage peak demand, reduce reliance on local reserves, and respond more effectively to extreme events. With that, we conclude the main components of Chapter 7. Thank you for sticking it out with us until the end of the presentation. Now I'll pass it back to our host to conclude the webinar. Thank you everyone for joining our webinar today, and thank you to our speakers. That wraps up our webinar. If you would like to submit feedback, please send your comments to the email address provided here. You may also find relevant information about the National Transmission Needs Study and comment period deadlines on the Office of Electricity's National Transmission Needs Study website. Thank you again, and enjoy the rest of your day.