← Back to all briefings
Infrastructure 6 min read Published Updated Credibility 88/100

DOE Finalizes 2023 National Transmission Needs Study

DOE’s 2023 National Transmission Needs Study projects tens of thousands of new GW-miles of lines and urgent interregional capacity gaps, forcing utility boards to embed transmission governance, operations teams to execute corridor-by-corridor build plans, and privacy leaders to align DSAR handling with the modeling data DOE expects utilities to submit.

Zeph Tech Research Lead

Research lead, Zeph Tech

Timeline plotting source publication cadence sized by credibility.
2 publication timestamps supporting this briefing. Source data (JSON)

Executive briefing: On 30 October 2023 the U.S. Department of Energy (DOE) released the 2023 National Transmission Needs Study, its most comprehensive modelling exercise on the grid’s long-distance transfer requirements in decades. DOE concluded that, even under current policy baselines, the United States must add roughly 47,300 gigawatt-miles of new high-voltage transmission by 2035, with needs present in every region. Higher electrification and clean-energy deployment scenarios push requirements beyond 90,000 gigawatt-miles and highlight critical interregional corridors linking the Midwest to the East Coast, the Mountain West to the Southwest, and ERCOT to neighbouring systems. The study underpins DOE’s designation of National Interest Electric Transmission Corridors and shapes how the Transmission Facilitation Program, loan guarantees, and Inflation Reduction Act incentives will be applied. Governance committees at utilities and grid operators must therefore interpret the study as binding strategic guidance, delivery teams must translate scenario findings into concrete siting, permitting, and interconnection programmes, and privacy officers must organise the customer, landowner, and operational data the study assumes utilities will supply when seeking federal support—ensuring DSAR readiness while protecting critical infrastructure information.

Key findings utilities must internalise

DOE’s modelling shows that existing transmission plans are insufficient to maintain reliability, integrate large-scale renewables, or meet resilience expectations in light of extreme weather. Even in the “base” case that only considers laws on the books, the nation requires a 57 percent increase in interregional transfer capacity by 2035. Under scenarios aligned with the Administration’s 100 percent clean electricity goal, required expansion reaches 90 percent, with urgent emphasis on connecting Midwestern wind to Eastern load centres, expanding north–south transfer capability in the Plains and Midwest, and building east–west ties for the Southeast, which historically has limited interregional interchange. DOE identified 10 macro-corridors where transmission would deliver outsized reliability and economic benefits; the study also recognises the need for grid-enhancing technologies but stresses that new lines remain indispensable.

The study calls out reliability vulnerabilities amplified by climate change. Increased transfer capability is necessary to handle correlated heat waves and winter storms, and to mitigate the risk of generator outages as fossil units retire. DOE signals that utilities should plan for multi-day events, incorporate probabilistic planning, and coordinate across independent system operator (ISO) boundaries. Importantly, the study links its findings to federal programmes: projects that address identified gaps are more likely to receive Transmission Facilitation Program capacity contracts, access the $3.5 billion Grid Resilience State and Tribal Grants, or qualify for expedited federal permitting.

Governance implications

Boards of investor-owned utilities, public power entities, and transmission developers must embed the Needs Study into strategic oversight. Directors should request formal management responses outlining how existing capital plans align with the study’s priority corridors and scenario ranges. Audit and risk committees must supervise methodologies for long-term planning, ensuring that integrated resource plans (IRPs), FERC Order 1000 compliance filings, and regional transmission expansion plans reflect DOE’s assumptions about load growth, electrification, and distributed energy resources. Boards should also ensure that management maintains an enterprise-level view of federal funding opportunities and regulatory milestones linked to the study, with a cadence for reviewing progress and escalating roadblocks.

Governance frameworks must address cross-jurisdictional collaboration. Many recommended corridors span multiple states and balancing authorities, so directors should set expectations for joint development agreements, cost allocation negotiations, and stakeholder engagement. Establishing a board-level transmission committee or expanding an existing infrastructure committee’s remit can help maintain focus on interregional coordination, permitting strategy, and alignment with state regulators. Given the study’s emphasis on resilience, boards need to include cyber-physical security metrics in their oversight, asking management to demonstrate how new transmission investments will incorporate NERC CIP requirements, dynamic line ratings, and wildfire mitigation measures.

Implementation roadmap for delivery teams

Operations, engineering, and regulatory affairs leaders must convert DOE’s findings into actionable programmes. Core implementation steps include:

  • Scenario-aligned portfolio design. Planners should create multi-scenario portfolios that map the study’s gigawatt-mile requirements to specific line projects, grid-enhancing technology upgrades, and advanced conductors. These portfolios must show how projects perform across DOE’s base, policy, and accelerated clean-energy scenarios, enabling management to prioritise investments resilient to policy shifts.
  • Corridor development playbooks. For each DOE priority corridor affecting the organisation, develop playbooks covering route refinement, environmental review sequencing, indigenous and local community consultation, and land acquisition strategies. Incorporate GIS layers that track environmental justice metrics, existing rights-of-way, and wildfire or flood risk to support both federal funding applications and stakeholder transparency.
  • Regulatory filing readiness. Align interconnection requests, FERC filings, and state siting applications with DOE’s data expectations. That includes modelling congestion benefits, emissions impacts, and resilience improvements using the same assumptions DOE employed—especially fuel price trajectories, demand growth, and electrification rates.
  • Supply chain and workforce planning. The scale of required expansion necessitates early commitments for transformers, HVDC converters, and advanced conductors. Supply-chain teams should track lead times, diversify suppliers, and pursue domestic manufacturing incentives. Workforce planners must expand apprenticeship pipelines and contractor frameworks, documenting how projects will meet Davis–Bacon prevailing wage and workforce reporting obligations attached to federal support.
  • Data infrastructure. Build data platforms that consolidate load forecasts, grid models, outage histories, and stakeholder feedback. DOE funding programmes increasingly demand machine-readable submissions and evidence of quantitative benefits; operations teams should invest in reproducible data pipelines, version-controlled modelling scripts, and collaborative tools that allow regulators to audit assumptions.

Implementation leaders must also synchronise with neighbouring utilities and ISOs. Establish inter-utility working groups to coordinate applications for Transmission Facilitation Program capacity contracts or Joint Targeted Interconnection Queue studies. Share scenario analyses to align on assumptions about offshore wind integration, hydrogen hubs, or large industrial loads. Additionally, incorporate adaptive planning triggers—e.g., rehearse how portfolios shift if federal permitting reforms accelerate or if distributed energy uptake lags behind forecasts.

DSAR and privacy operations

The Needs Study assumes utilities and developers will supply granular datasets about customers, landowners, environmental sensitivities, and system operations when applying for federal assistance. Privacy teams must prepare to handle DSARs that target these datasets. Start by updating records of processing to include transmission-planning activities, noting legal bases such as compliance with FERC obligations or pursuit of federal funding. Document which datasets contain personal information—customer load profiles, land parcel ownership records, community engagement notes, and workforce rosters—and classify them according to sensitivity.

DSAR operations should implement retrieval scripts capable of extracting personal data from planning platforms, GIS systems, and document repositories. Because many records will also contain Critical Energy/Electric Infrastructure Information (CEII), privacy and legal teams must craft response templates that cite statutory exemptions, explain why certain details cannot be disclosed, and offer redacted summaries where appropriate. For multi-state utilities subject to GDPR or state privacy laws, ensure that DSAR response processes account for cross-border data transfers, especially when modelling work uses international contractors or cloud environments hosted outside the requestor’s jurisdiction.

Transmission planning generates long retention periods: environmental studies, right-of-way agreements, and stakeholder consultation records may need to be kept for decades. Privacy officers should align retention schedules with regulatory requirements while building archival processes that segregate personal data and apply encryption-at-rest. Maintain audit trails showing who accesses planning datasets, as these logs may be requested by regulators or DSAR requestors. Finally, embed privacy impact assessments into new data-collection initiatives (such as community-benefit surveys or workforce dashboards) associated with DOE-funded projects, ensuring that individuals are informed about how their data supports national transmission objectives.

By embedding the Needs Study’s findings into governance agendas, executing disciplined implementation programmes, and reinforcing privacy practices that respect DSAR obligations, utilities and grid developers can leverage DOE’s roadmap to modernise the U.S. transmission system while maintaining public trust.

Timeline plotting source publication cadence sized by credibility.
2 publication timestamps supporting this briefing. Source data (JSON)
Horizontal bar chart of credibility scores per cited source.
Credibility scores for every source cited in this briefing. Source data (JSON)

Related briefings

Curated signals from the same pillar or overlapping topics.

Continue in the Infrastructure pillar

Return to the hub for curated research and deep-dive guides.

Visit pillar hub

Latest guides

  • DOE
  • Transmission
  • Grid planning
  • Needs Study
Back to curated briefings