Distributed Flexible AC Transmission Systems (D-FACTS)
June 2026
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Overview
Distributed Flexible AC Transmission Systems (D-FACTS) are a family of modular, power-electronics-based devices that attach directly to existing transmission conductors to dynamically control line impedance and redirect active power flows across a meshed network. The core concept, first articulated by Divan et al. at Georgia Institute of Technology and published in IEEE (2004–2007), addresses a well-documented limitation of conventional FACTS: centralized devices (UPFC, SSSC, etc.) require full high-voltage (HV) insulation, have high per-unit costs, and raise single-point-of-failure reliability concerns that have historically restricted adoption[1]. While the distributed architecture of D-FACTS mitigates many reliability concerns, outages can still occur. In the event of a D-FACTS outage, a remedial actions scheme (RAS) can be implemented to ensure grid stability through corrective actions such as generation dispatch or load shedding.
The primary D-FACTS device class studied and commercially deployed is the Distributed Static Series Compensator (DSSC) and its commercial derivatives (e.g., Smart Wires’ SmartValve PowerLine Guardia). Modules clamp onto existing HV/EHV conductors inductively, draw operating power from the line itself, inject a quadrature voltage component to increase or decrease effective line reactance, and communicate wirelessly for coordinated fleet control. Because modules are distributed—typically a few per conductor-mile—the system achieves desired power-flow control through aggregate reactance change, and individual module failure does not disable the system.
D-FACTS is classified by DOE, FERC, and ARPA-E as a subset of Advanced Power Flow Control (APFC) under the broader Grid-Enhancing Technologies (GETs) umbrella, alongside Dynamic Line Rating (DLR) and Topology Optimization. This assessment covers commercially deployed, modular series-compensation D-FACTS (DSSC/APFC class).
Benefits
Transmission Congestion Relief
U.S. electricity congestion costs reached $20.8 billion in 2022, nearly triple the 2016–2020 average, driven by insufficient transmission capacity to deliver lowest-cost generation to consumers. This estimate was developed by Grid Strategies, LLC using Independent Market Monitor data from six RTO/ISO regions and extrapolated to national load coverage[2].
D-FACTS can address certain congestion conditions by dynamically redirecting power from overloaded to underutilized parallel paths through reactive impedance injection. A 2022 DOE Office of Electricity case study of the NYISO service territory found that deploying both DLR and Power Flow Controllers together reduced locally-sourced energy curtailment by 23–43% providing customers access to lower-cost electricity and that the combination achieved more than either technology individually, paying for itself in approximately two years considering only the reduced cost of generation[3].
ARPA-E system-level modeling indicates that D-FACTS deployment can improve overall transmission system utilization by more than 30%, with present-value savings exceeding 80% relative to conventional transmission reinforcements in specific congested corridors[4].
Variable Source Integration and Interconnection Queue Relief
Transmission constraints are the primary bottleneck for locally-sourced energy interconnection in the U.S. A 2021 Brattle Group analysis of the Southwest Power Pool (SPP) system found that optimal GETs deployment would allow 5,250 MW of new wind and solar to interconnect over five years, versus 2,580 MW without GETs, at a one-time installation cost of $90 million against $175 million in annual production cost savings[5].
A 2024 analysis by RMI and Quanta Technology of five states in PJM’s footprint found that 95 GETs deployments costing $100 million could enable 6.6 GW of new solar, wind, and storage to interconnect by 2027, yielding approximately $1 billion per year in production cost savings across PJM — a benefit-cost ratio of approximately 70:1.
D-FACTS/APFC is now mandated for explicit consideration in both FERC Order 2023 (interconnection reform) and FERC Order 1920 (long-term regional transmission planning, May 2024)[6].
Deferral of Costly Transmission Capital Investment
DOE’s National Transmission Needs Study (October 2023) projects that regional transmission capacity may need to more than double by 2035 and interregional transfer capacity may need to grow by more than fivefold to meet moderate load growth and high clean energy scenarios[7].
D-FACTS can defer or eliminate a portion of these investments. ARPA-E modeling of the Smart Wires/TVA program indicates present-value savings exceeding 80% relative to conventional reinforcements in specific corridors. In New York, Central Hudson Gas & Electric reported that its 2023 SmartValve deployment at 345 kV required 25% less substation footprint and cost approximately $10 million less than the Fixed Series Capacitor alternative evaluated by NYISO, per the utility’s own reporting[4].
Technology Readiness Level (TRL)
- High-fidelity system configuration
- Tested in relevant (simulated) environment
- Components work together as system
- Close to real application conditions
D-FACTS/APFC has progressed through laboratory and prototype stages to real-world operational deployment by utilities.
- Prototype-to-field: Under ARPA-E GENI funding, Smart Wires moved from prototype to a field-ready Distributed Series Reactance (DSR) device in under one year, completing laboratory testing and a Tennessee Valley Authority (TVA) field trial in the U.S.[4]
- Operational deployment: Central Hudson Gas & Electric (New York) deployed 15 SmartValves on the 345 kV Leeds-Hurley Avenue circuit in 2023 — following a 2019 pilot at 115 kV — providing 150 MVAr of power-flow control and unlocking 185 MW of grid capacity. Per utility reporting, the deployment required 25% less substation space and approximately $10 million less than the alternative Fixed Series Capacitor. From an operations and maintenance perspective, SmartValves are mounted directly on the transmission structure and designed for field-replaceability without major civil or substation work. Utilities report that most module-level maintenance can be performed with short, planned outages, while full live-line replacement is feasible with standard hot-stick or bare-hand procedures, depending on utility practice. In Georgia, DOE funded Georgia Tech and Southern Company (2023–2025) to deploy APFC and DLR in combination on statewide grids, described by DOE as the first large-scale combined APFC+DLR U.S. deployment[8].
- Large-scale, multi-device, coordinated deployments at the regional system level in the U.S. remain limited. INL and EPRI (2024) explicitly state that “the implementation implications of using multiple PFCs for system operation and reliability have not been analyzed in detail” and that “the lack of information and practical experience on these aspects hinders adoption.” U.S. deployments at VELCO/EPRI (Vermont, 2026) and Avista Utilities/Idaho Power (WA/ID/OR, GRIP Round 2, funded October 2024) are in procurement or construction phases[9].
Adoption Readiness Level (ARL)
Value Proposition
Delivered Cost
Low Risk
D-FACTS modules are manufactured from conventional industrial-grade power electronics, which reduces manufacturing costs compared to centralized FACTS devices. However, while the internal components do not require high-voltage insulation, the installed system must still be insulated and mechanically rated for the full line voltage when mounted on a transmission structure. ARPA-E modeling indicates that, even with these installation requirements, present-value savings can exceed 80% versus conventional reinforcement in specific applications. Under U.S. cost-of-service regulation, GETs are typically classified as operating expenditures rather than capital expenditures eligible for rate base. This means utilities do not earn a regulated rate of return on D-FACTS investments — a structural cost-recovery risk not present for new transmission line construction. This misalignment is the dominant delivered-cost barrier identified across the literature[4][10].
Functionality Performance
Low Risk
U.S. field deployments confirm primary power flow control functionality across multiple voltage levels. The DOE 2022 NYISO case study found combined DLR and PFC deployment reduced locally-sourced energy curtailment by 23–43% and more than doubled utilization on underutilized line segments. Central Hudson’s 345 kV Leeds-Hurley Avenue deployment (2023) unlocked 185 MW of capacity and reduced substation costs versus the FSC alternative to achieve similar performance (per utility reporting). ARPA-E modeling found potential for over 30% improvement in system-wide utilization. INL and EPRI (2024) confirm PFC devices can address power flow balancing, mitigation of unscheduled and loop flows, and both preventive and corrective contingency management[11][4]
Ease of Use/Complexity
Medium Risk
Clamp-on installation eliminates most HV insulation work and, in some configurations, can be performed without taking the line out of service[1]. Installation and replacement are typically conducted as live-line operations which require utilities to ensure field crews receive appropriate training in hot-stick or bare-hand procedures, consistent with their existing maintenance practices. However, INL and EPRI (2024) explicitly identify that coordinated control of multiple PFC devices requires non-trivial engineering: self- and mutual-power-flow sensitivity factors must be calculated for each deployment, and improper coordination can produce adverse device interactions. Transmission planners and operations engineers require specialized modeling skills and workflow integrations not yet standardized across U.S. utilities[1][9].
Clamp-on installation eliminates most HV insulation work and, in some configurations, can be performed without taking the line out of service[1]. Installation and replacement are typically conducted as live-line operations which require utilities to ensure field crews receive appropriate training in hot-stick or bare-hand procedures, consistent with their existing maintenance practices. However, INL and EPRI (2024) explicitly identify that coordinated control of multiple PFC devices requires non-trivial engineering: self- and mutual-power-flow sensitivity factors must be calculated for each deployment, and improper coordination can produce adverse device interactions. Transmission planners and operations engineers require specialized modeling skills and workflow integrations not yet standardized across U.S. utilities[1][9].
Market Acceptance
Demand Maturity/Market Openness
Medium Risk
Regulatory demand signals are strengthening but utility adoption in the U.S. remains nascent. FERC Orders 1920 (May 2024) and 1920-A (November 2024) now require transmission providers to explicitly evaluate APFC in long-term regional planning, and FERC Order 2023 includes similar mandates for generation interconnection studies. Minnesota, Virginia, and California have enacted state laws requiring utilities to evaluate GETs in planning processes; similar legislation is tracked in 18 states (WATT Coalition, 2024). However, BPC (2026) documents persistent utility inertia driven by incentive misalignment: utilities do not earn a return on GETs because they are treated as an operating expense (OPEX), and vertically integrated utilities hold monopoly access to congestion data needed for third-party benefit modeling[10][6].
Market Size
Low Risk
The addressable market is large. U.S. transmission congestion costs reached $20.8 billion in 2022 (Grid Strategies LLC, July 2023). DOE’s National Transmission Needs Study (October 2023) projects regional transmission capacity may need to more than double by 2035, implying sustained multi-billion-dollar annual transmission investment requirements. RMI and Quanta Technology (2024) found that GETs applied within just five PJM states could yield $1 billion per year in production cost savings, demonstrating the per-region scale of opportunity[2][12].
Downstream Value Chain
Medium Risk
The APFC/D-FACTS commercial market is currently served primarily by a single vendor, Smart Wires Inc. (California), cited as the only commercial manufacturer of modular FACTS devices in relevant literature (Brattle Group, 2021). While alternate series-compensation technologies do exist, most notably Thyristor-Controlled Series Capacitors (TCSC), which offer lower losses and are widely deployed internationally. These systems are not modular and require conventional substation-based installations. Consequently, U.S. deployments of modular APFC/D-FACTS solutions, including Central Hudson (NY, 2023), Georgia Tech/Southern Company (GA/AL, 2023–2025), VELCO/EPRI (VT, 2026), and Avista Utilities/Idaho Power (WA/ID/OR, GRIP Round 2, 2024), all rely on one vendor’s hardware and proprietary control platform. This concentration creates supply-chain risk, limits price discovery, and raises counterparty concerns for utilities planning on 20–40-year horizons. No multi-vendor competitive market or open interoperability standards have emerged as of this writing[13].
Resource Maturity
Capital Flow
Low Risk
Federal funding has supported D-FACTS/APFC through development and into initial deployment. DOE’s Office of Electricity allocated $8.4 million in November 2023 across four projects, including approximately $2.1 million to Georgia Tech for APFC deployment with Southern Company. Under GRIP Round 2 (October 2024), DOE funded Avista Utilities/Idaho Power for SmartValve deployment with 50% capital cost coverage. However, as of early 2026, BPC reports that DOE has pulled back funding from projects previously awarded under the 2021 Bipartisan Infrastructure Law. Private capital for D-FACTS manufacturers remains project-by-project revenue dependent, with no large-scale institutional investment pool established. The revenue model for APFC is not yet clearly bankable under current U.S. regulatory structures[10][13].
Project Development, Integration, and Management
Medium Risk
INL and EPRI (2024) identify this as a leading gap: “the implementation implications of using multiple PFCs for system operation and reliability have not been analyzed in detail” and “the lack of information and practical experience on these aspects hinders adoption.” Multi-device coordination requires calculating self- and mutual-power-flow sensitivity matrices for each deployment — a step for which standardized utility workflows and tools do not yet exist. The report was produced specifically to address these gaps and provide guidance to transmission planners and operations engineers. VELCO’s first U.S. SmartValve project is scheduled for commissioning in 2026, indicating that even straightforward single-site deployments take years under current U.S. utility processes[9][14].
Infrastructure
Low Risk
D-FACTS modules generally require no new substation land, no HV insulation structures, no right-of-way expansion, and no line reconstruction, as they are typically mounted on existing conductors with the existing transmission corridor. However, some utility deployments have reported exceptions where limited substation integration, grounding modifications, or switching accommodations were required. Central Hudson, for example, reported a 25% reduction in substation footprint compared to the FSC alternative (per utility reporting). Overall, the ability to minimize new substation infrastructure remains a structural advantage relative to both conventional FACTS and new transmission construction[1].
Manufacturing and Supply Chain
Medium Risk
D-FACTS modules use conventional industrial-grade power electronics components, avoiding the critical mineral dependencies (lithium, cobalt, rare earths) that constrain other clean energy supply chains[1]. However, the manufacturing base is currently limited to a single commercially active vendor. There is no broad, multi-manufacturer supply chain with associated economies of scale. The volume-driven cost reductions that transformed solar and battery markets have not yet occurred for D-FACTS[1].
Materials Sourcing
Low Risk
D-FACTS modules use standard power electronics hardware (inverters, capacitors, magnetic cores, wireless communication modules) without reliance on DOE-designated critical minerals. No materials sourcing constraints are identified in the primary literature reviewed[1].
Workforce
Medium Risk
INL and EPRI (2024) produced INL/RPT-24-78148 specifically to address the workforce knowledge gap, framing it as a resource for “transmission planners to make informed decisions about the adoption of the technology and operation engineers to define specific operation and control procedures.” The report’s existence as a knowledge-gap-filling document signals that PFC planning expertise is not yet broadly distributed across U.S. utility workforces. Physical installation (clamp-on) is accessible; analytical and operational expertise for coordinated multi-device control is the binding workforce constraint[9].
License to Operate
Regulatory Environment
Medium Risk
FERC Order 1920 (May 2024) and its rehearing order 1920-A (November 2024) now require transmission providers to evaluate APFC as part of mandatory long-term regional planning, representing the strongest regulatory signal to date. FERC Order 2023 includes a similar mandate for interconnection studies. However, the core structural barrier — GETs classified as OPEX rather than a capital expenditure (CAPEX), generating no regulated rate of return — remains unresolved. A shared-savings incentive mechanism discussed at FERC since 2019 has not been adopted. As BPC (2026) documents, under current cost-of-service ratemaking, utilities have no financial incentive to deploy GETs because more MWs flowing through a line generates no additional revenue[6][10].
Policy Environment
Low Risk
Policy momentum is positive, at the federal level: FERC Orders 1920/1920-A, FERC Order 2023, DOE GRIP (Rounds 1 and 2), and proposed Advancing GETs Act in Congress. At the state level: Minnesota, Virginia, and California have enacted GETs evaluation requirements; GETs legislation is active in 18 states (WATT Coalition, 2024). Countervailing signal: BPC (January 2026) reports DOE has pulled back Bipartisan Infrastructure Law GRIP funding under the current administration, creating near-term project pipeline uncertainty.
Permitting & Siting
Low Risk
D-FACTS modules deploy on existing conductors within existing transmission corridors. No new right-of-way acquisition, land-use permits, environmental reviews for new corridors, or community engagement for new structures are required. This eliminates the single largest source of delay and cost escalation for conventional transmission projects[1].
Environmental & Safety
Low Risk
No new land disturbance, no new visual or noise impact beyond existing lines, no SF6 or hazardous gas use. Modules operate at low power relative to line ratings; safety risks are managed through standard HV clamp-on protocols. No significant environmental or safety risk factors are identified in the primary literature reviewed[1].
Community Perception
Low Risk
D-FACTS involves no new transmission corridors, no new tower structures, and no new visual, noise, or land-use impacts. Public opposition, a primary driver of transmission project delays, is not a meaningful risk factor for D-FACTS deployments. No community perception concerns are identified in the primary literature reviewed[9].
Case Studies & Implementation
ARPA-E GENI Program – Smart Wires / TVA Field Trial, Tennessee (2012–2014)
Under ARPA-E’s GENI program, Smart Wires moved from prototype to a field-ready Distributed Series Reactance device in under one year. Following laboratory testing under worst-case environmental and operational conditions, the company completed a field trial with the Tennessee Valley Authority (TVA). System-level modeling demonstrated potential for over 30% improvement in overall transmission system utilization, with present-value savings exceeding 80% relative to conventional transmission reinforcements in specific congested corridors. This project established proof-of-concept for D-FACTS in a U.S. utility operating environment and was the foundation for subsequent commercial development.
ARPA-E GENI Impact Sheet: https://arpa-e.energy.gov/impact-sheet/smart-wires-geni
Central Hudson Gas & Electric – Leeds-Hurley Avenue 345 kV, New York (2023)
Following a 2019 pilot at 115 kV, Central Hudson Gas & Electric deployed 15 SmartValves on the underutilized 345 kV Leeds-Hurley Avenue circuit in New York State. NYISO had identified the corridor as a constraint limiting locally-sourced energy interconnection in the eastern part of the state. The deployment provides 150 MVAr of power flow control and unlocks 185 MW of additional grid capacity. Per Central Hudson’s reporting: the SmartValve solution required 25% less substation footprint and cost approximately $10 million less than the Fixed Series Capacitor originally evaluated. The deployment also presents lower risk of sub-synchronous resonance and can be expanded with additional modules as locally-sourced generation grows. As of 2024, the New York Power Grid Study includes multiple additional APFC projects across the state.
Note: Capacity and cost figures are reported by the utility/vendor and have not been independently verified by a third party or regulator.
Smart Wires press release, September 2024: https://www.smartwires.com/2024/09/18/smart-wires-collaborates-with-central-hudson-gas-amp-electric-to-provide-185-mw-extra-capacity-for-renewable-energy-in-new-york/
Renewable Energy World, September 2024: https://www.renewableenergyworld.com/power-grid/transmission/case-study-how-a-new-york-utility-unlocked-185-mw-of-capacity-without-building-new-transmission/
Georgia Tech / Southern Company / DOE – Statewide APFC+DLR Deployment, Georgia & Alabama (2023–2025)
Georgia Tech’s Center for Distributed Energy received approximately $2.1 million from DOE’s Office of Electricity in November 2023 to deploy and demonstrate Advanced Power Flow Control (SmartValve™) and Dynamic Line Rating in combination on Southern Company’s Georgia and Alabama transmission grids. DOE describes this as the first large-scale U.S. deployment combining APFC and DLR in an integrated configuration. The project includes a one-year live performance period designed to generate replicable operational data for other U.S. utilities. No independently verified performance outcomes have been published by DOE or Georgia Tech as of this writing; results are expected upon project completion.
DOE Office of Electricity: https://www.energy.gov/oe/grid-enhancing-technologies-improve-existing-power-lines
DOE EERE, “Smart Transmission Tools Modernize America’s Power Grid,” November 2025: https://www.energy.gov/eere/wind/articles/smart-transmission-tools-modernize-americas-power-grid
References
- D. M. Divan et al., A Distributed Static Series Compensator System for Realizing Active Power Flow Control on Existing Power Lines, IEEE Transactions on Power Delivery, pp. 642-649, 2007.
- R. G. M. &. S. A. Doying, Transmission congestion costs rise again in U.S. RTOs. Grid Strategies LLC, 2023.
- U.S. Department of Energy, Office of Electricity, DOE study shows maximizing capabilities of existing transmission lines through grid-enhancing technologies (GETs) can reduce transmission investment and increase renewable integration, 2022. [Online]. Available: https://www.energy.gov/oe/articles/doe-study-shows-maximizing-capabilities-existing-transmission-lines-through-grid.
- Advanced Research Projects Agency–Energy, Smart Wires (GENI), 2026. [Online]. Available: https://arpa-e.energy.gov/impact-sheet/smart-wires-geni.
- RMI, GETting interconnected in PJM: Grid-enhancing technologies (GETs) can increase the speed and scale of new entry from PJM’s queue, 2024. [Online]. Available: https://rmi.org/insight/analyzing-gets-as-a-tool-for-increasing-interconnection-throughput-from-pjms-queue/.
- Federal Energy Regulatory Commission, Explainer on the transmission planning and cost allocation final rule, Federal Energy Regulatory Commission, 2025.
- U.S. Department of Energy, Grid Deployment Office, National transmission needs study, https://www.energy.gov/sites/default/files/2023-10/National_Transmission_Needs_Study_2023.pdf, 2023.
- Smart Wires, Smart Wires collaborates with Central Hudson Gas & Electric to provide 185 MW extra capacity for renewable energy in New York, 2024. [Online]. Available: https://www.smartwires.com/2024/09/18/smart-wires-collaborates-with-central-hudson-gas-amp-electric-to-provide-185-mw-extra-capacity-for-renewable-energy-in-new-york/.
- E. Idaho National Laboratory, Implementation and Operation of Power Flow Control Solutions for Transmission Systems, Idaho National Laboratory, 2024.
- A. &. K. T. K. Cowie-Haskell, Unlocking the potential of grid enhancing technologies: Pathways to widespread adoption, Bipartisan Policy Center, 2026.
- U.S. Department of Energy, Office of Electricity, DOE study shows maximizing capabilities of existing transmission lines through grid-enhancing technologies (GETs) can reduce transmission investment and increase renewable integration, 2022. [Online]. Available: https://www.energy.gov/oe/articles/doe-study-shows-maximizing-capabilities-existing-transmission-lines-through-grid.
- U.S. Department of Energy, Grid Deployment Office, National transmission needs study, 2023. [Online]. Available: https://www.energy.gov/gdo/national-transmission-needs-study.
- SmartWires, Smart Wires’ advanced power flow control solution selected for new GRIP projects, 2024. [Online]. Available: https://www.smartwires.com/2024/10/24/smart-wiress-advanced-power-flow-control-solution-selected-for-new-grip-projects/.
- SmartWires, Technology in focus: APFC and PSTs, 2024. [Online]. Available: https://www.smartwires.com/2024/07/22/technology-in-focus-apfc-and-psts/.
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