Building the Backbone: How an Interregional Transmission Overlay Can Fortify the U.S. Grid Against Climate and Market Shocks
By a Senior Technical/Financial Audit Journalist
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Introduction: The Grid's Missing Layer
The United States electrical grid operates under a fundamental structural paradox. Weather patterns, electricity markets, and extreme climate events span continental scales, yet the physical infrastructure that delivers power remains fractured along jurisdictional boundaries. The Eastern Interconnection, Western Interconnection, Texas (ERCOT), and Quebec Interconnection function as distinct electrical islands, interconnected only through a handful of weak direct-current ties with limited transfer capacity.
An interregional transmission overlay addresses this disconnect. Defined as a dedicated high-capacity backbone connecting diverse regional transmission organizations—including MISO, PJM, SPP, and ERCOT—the overlay bypasses local bottlenecks to establish a functionally integrated national grid (Source 1: Wiley Knowledge Hub, "Energy in Motion" Series). The critical insight is not merely the movement of electrons across longer distances, but the creation of a structural hedge against correlated failures. Wildfires in California, hurricanes along the Gulf Coast, and polar vortexes in the Midwest each affect discrete regions independently. A connected overlay means a generation deficit in one area can be compensated by surplus capacity in another, transforming regional vulnerability into system-wide resilience.
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Hidden Economic Logic: From Congestion Rent to Arb-Free Integration
The economic case for an interregional overlay rests on quantifiable inefficiencies that persist within the current balkanized framework. Annual congestion costs across U.S. wholesale electricity markets exceed $5 billion, with curtailment of renewable generation adding further losses (Source 2: FERC Congestion Reports, Multiple Years). Wind generation in SPP is routinely curtailed during high-wind periods while gas-fired plants in PJM operate at capacity, reflecting a spatial mismatch between renewable resource availability and demand centers.
The overlay functions as a risk-arbitrage asset. Regional price spreads between markets—the difference between day-ahead locational marginal prices in MISO South versus PJM, for example—represent the revenue wedge that can underwrite transmission investment. When these spreads narrow to zero through adequate transfer capacity, the system achieves full arbitrage efficiency. The capital cost of the overlay is thus recovered through the elimination of pricing inefficiencies that currently impose a hidden tax on consumers.
Beyond congestion relief, the resilience dividend provides a second revenue stream. The estimated economic losses from Winter Storm Uri in February 2021 exceeded $195 billion (Source 3: National Oceanic and Atmospheric Administration, Billion-Dollar Weather Events Database). These costs—including lost economic output, property damage, and healthcare expenses—represent a quantifiable risk that an interregional overlay mitigates. Securitizing this avoided outage cost as a revenue stream can lower the weighted average cost of capital for overlay financing, potentially reducing the required return on equity for transmission investors by 150 to 200 basis points.
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Technology Trends: HVDC and Power Electronics as the New Backbone
The shift from alternating current (AC) to high-voltage direct current (HVDC) technology represents the foundational enabler of the interregional overlay. Conventional AC transmission suffers from reactive power losses over distances exceeding 300 miles. HVDC systems, particularly multi-terminal configurations, can transmit power over 1,500 miles with total losses below 15%, making them the only viable technology for continental-scale power transfer.
Modular voltage-source converters (VSCs) provide additional operational advantages. Unlike traditional line-commutated converters, VSCs enable independent control of active and reactive power, islanding capability, and black-start functionality. A multi-terminal HVDC overlay can isolate failed sections while maintaining power delivery through redundant paths, a capability unavailable in the radial AC networks that dominate existing interconnections.
The supply chain implications are substantial. Each HVDC converter station requires high-voltage transformers, direct-current circuit breakers, and insulated-gate bipolar transistors (IGBTs) for semiconductor switching modules. These components have manufacturing lead times ranging from 18 to 36 months (Source 4: World Energy Council, Power Transmission Supply Chain Assessment). Any overlay deployment strategy must trigger early procurement orders to prevent construction delays, as the global converter station fabrication capacity is limited to approximately 20 to 30 major units annually.
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Suppliers Under Stress: The Unseen Bottleneck
A deep-dive analysis of the transmission supply chain reveals constraints that extend beyond converter station hardware. Global transformer production capacity is operating at near-maximum utilization, with lead times for large power transformers exceeding 80 weeks as of 2024. The critical constraint is grain-oriented electrical steel, a specialized material used in transformer cores. Only four global producers—AK Steel, POSCO, ThyssenKrupp, and Nippon Steel—dominate this market, and expansion plans remain limited due to the capital intensity of new production lines.
High-voltage underground and submarine cables represent a second bottleneck. The global production capacity for cross-linked polyethylene (XLPE) insulated cables at 320 kV and above is concentrated among five manufacturers: Prysmian, Nexans, NKT, Sumitomo, and LS Cable. Annual production capacity for these cables is approximately 2,000 circuit-kilometers globally, insufficient for a national overlay project requiring several thousand circuit-kilometers.
The power electronics supply chain for HVDC systems has similar concentration. Hitachi Energy (formerly ABB Power Grids) and Siemens Energy control approximately 70% of the global HVDC converter station market. While newer entrants such as GE Grid Solutions and Chinese manufacturers (NR Electric, XJ Electric) are expanding capacity, the qualification process for U.S. deployments adds 12 to 18 months of certification testing (Source 5: International Energy Agency, Grid Infrastructure and Supply Chains).
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Cross-Validation: The Financial and Engineering Feasibility Framework
The interregional overlay requires capital investment estimated between $50 billion and $100 billion for a 50 GW backbone connecting the Eastern, Western, and Texas interconnections (Source 6: National Renewable Energy Laboratory, Interconnections Seam Study). This investment must be validated against three criteria: revenue sufficiency, construction feasibility, and operational reliability.
Revenue sufficiency analysis shows that capturing 50% of the existing $5 billion in annual congestion costs provides $2.5 billion in revenue. Adding a resilience dividend of $1 to $2 billion annually—representing a small fraction of avoided weather-related outage costs—yields total revenue of $3.5 to $4.5 billion per year. At a 6% weighted average cost of capital, this supports a capital base of $58 to $75 billion, covering the lower bound of the estimated investment range.
Construction feasibility requires addressing the supply chain constraints identified above. A 10-year deployment timeline, with early procurement of long-lead items in years one through three, aligns with expected transformer and cable capacity expansion. The critical path is permitting and right-of-way acquisition, which for interstate transmission projects has historically required five to seven years per segment (Source 7: U.S. Department of Energy, Transmission Permitting Database).
Operational reliability is enhanced, not degraded, by the overlay. Multi-terminal HVDC systems with meshed topology provide n-1 redundancy at the network level, compared to the n-1 redundancy at the path level in existing AC corridors. The ability to dynamically route power around contingencies reduces the probability of cascading failures, a key vulnerability demonstrated during the 2003 Northeast Blackout.
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Market Design Reforms: Unlocking Private Capital
Three concrete market design reforms are necessary to unlock private capital for the interregional overlay. First, congestion revenue rights must be reformed to allow merchant transmission developers to capture a minimum 20-year revenue stream based on realized congestion savings. Current FERC rules limit merchant transmission to project-specific participation, creating uncertainty that elevates capital costs.
Second, cost allocation must shift from beneficiary-pays to system-benefits metrics. The current approach requires detailed load-flow studies to assign costs to specific load zones, a process that takes two to three years and faces litigation risk. A system-benefits approach allocates costs based on aggregate reliability improvements and avoided outage costs across all interconnected regions, reducing administrative overhead and legal uncertainty.
Third, interregional transfer capability must be treated as a planning standard, not a market outcome. FERC Order 1000 requires transmission planning but does not mandate minimum transfer capability between regions. A standard requiring each region to maintain transfer capacity equal to 10% of peak load would create a regulatory backstop for overlay investment, independent of market revenue projections (Source 8: FERC Order 1000, Transmission Planning and Cost Allocation).
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Conclusion: Projected Market and Industry Outcomes
The deployment trajectory for an interregional overlay follows a predictable pattern based on analogous large-scale infrastructure projects in Europe and Asia. The first phase, years one through five, involves planning, permitting, and long-lead procurement. The second phase, years six through ten, sees accelerated construction as supply chains expand and regulatory processes converge.
Market implications are substantial. Regional price spreads will narrow to marginal differences reflecting transmission losses, reducing revenue for existing generators in high-cost regions. Renewable generation will face new curtailment patterns as the overlay enables delivery to previously inaccessible demand centers. The wholesale electricity market will increasingly resemble a national market, with price formation driven by continental-scale supply-demand balance rather than local generation cost.
The transmission supply chain will experience sustained demand growth of 4 to 6 percent annually above current baselines. Transformer manufacturers, cable producers, and power electronics suppliers will need to commit capital to capacity expansion in years two through four to avoid becoming the binding constraint on deployment. Companies with established relationships with European or Asian HVDC providers—including Hitachi Energy, Siemens Energy, and Prysmian—are positioned to capture first-mover advantage in U.S. deployments.
The interregional overlay represents a capital-intensive, long-duration infrastructure investment with returns secured by structural market inefficiencies. The engineering feasibility is established; the supply chain constraints are identifiable; the market design reforms are concrete. The question is not whether the economics support the investment, but whether the regulatory and permitting framework can compress the timeline sufficiently to deliver the resilience dividend before the next systemic failure event.