Grid enhancing technologies (GETs) are the new buzz word in the electricity transmission sector particularly in the US. To support its long-term energy transition plans (the Biden administration has set a goal of achieving 100 per cent carbon pollution-free electricity by 2035), the country has planned the integration of large amounts of intermittent renewable energy over the next decade. This poses the enormous challenges of expanding transmission capacity on the one hand and managing load flow and preventing network congestion on the other. While this will require building new transmission infrastructure both on land and at sea, some part of the challenge can also be met by utilising the exiting network more efficiently.

In this backdrop, GETs are being considered as solutions to accelerate the clean energy transition, improve grid reliability and lower energy costs. Some of the GETs under consideration in the US are dynamic line ratings (DLRs), advanced power flow control, topology optimisation, and other hardware or software that increases the capacity, efficiency and reliability of the network. GETs promise to be a low-cost and faster-to-implement option than traditional transmission investments in addition to significantly increasing transmission capacity. This has become particularly attractive as several upcoming renewable projects in the US are facing long interconnection queues as well as uncertainly regarding the expenses that generators have to incur on transmission upgrades.

Although some utilities have also begun to implement pilots to gain experience, the general sentiment has been to push for regulatory incentives for their large-scale deployment. Transmission owners (TOs) remain reluctant to adopt GETs because it involves investing in equipment and manpower with little return.

Several recent developments indicate there is growing support for GETs from federal policymakers and regulators. For instance, the Federal Energy Regulatory Commission (FERC) is considering the best possible way to integrate GETs in the transmission planning process as part of its ongoing rulemakings. According to FERC’s definition, GETs include, but are not limited to, power flow control and transmission switching equipment, storage technologies, and advanced line rating management technologies. It largely refers to technologies that offer significant benefits to the grid and provide the situational awareness and real time control needed for a modern grid.

The discussion on GETs gained momentum after a recent study for the Working for Advanced Transmission Technologies (WATT) Coalition from the Brattle Group found that GETs implementation could enable Kansas and Oklahoma to integrate 5.2 GW of wind and solar generation currently in interconnection queues by 2025, which is more than double the development possible with only planned traditional transmission upgrades. According to the study, called ‘Unlocking the Queue with Grid Enhancing Technologies’, spending about USD90 million to implement technologies such as DLRs, advanced power flow controls and topology optimisation to integrate renewable energy into the grid operated by Southwest Power Pool (SPP) could yield a payback in less than a year with annual power cost savings of about USD175 million. Further, the study concluded that nationally, GETs could double the amount of renewables that could be integrated prior to building large-scale transmission lines, resulting in over USD5 billion in yearly energy cost savings.

Global Transmission Report presents recent developments at the policy and regulatory level as well as technology and recent utility experience.

Recent policy and regulatory developments

Efficient Grid Interconnection Act of 2021: At the federal level, serious consideration is being given to GETs. To integrate GETs into the interconnection study process, the Efficient Grid Interconnection Act of 2021 was introduced in the House of Representatives in June 2021. Under the proposed legislation, GETs would be considered as solutions to transmission constraints, and interconnection customers like renewable generators or energy storage providers could request their use. Specifically, the bill requires system operators to study the effectiveness of deploying GETs either in addition to or in place of traditional transmission upgrades and expansions. While it allows the interconnection customer to request GETs be deployed, the final decision on deployment remains with the transmission owner. The law will help reduce the long wait times in interconnection queues.

FERC’s proposed rulemakings related to GETs: FERC, through its advanced notice of proposed rulemaking (ANOPR) on transmission planning, cost allocation, and generator interconnection reform process notified in July 2021, is seeking comments on whether it should require transmission providers to consider GETs in interconnection studies to assess if their deployment can facilitate more cost-effective interconnections. FERC is also seeking comments from transmission providers who have already implemented and have experience with these technologies. Particularly, it seeks comment on whether GETs have the potential to not only increase the capacity, efficiency and reliability of transmission facilities, but also to reduce the cost of interconnection-related network upgrades. Further, it is seeking comments on whether an independent transmission monitor should evaluate and report on transmission providers’ consideration of GETs in the transmission planning process. The broader question relates to whether FERC should give greater consideration to GETs and the challenges and solutions to implementing the same. It also seeks feedback on whether to incentivise TOs to adopt GETs as alternatives to network upgrades.

The latest ANOPR follows another related FERC NOPR on managing transmission line ratings (RM20-16) issued in November 2020. This proposed rule will effectively end the use of the less accurate seasonal and static line ratings and require all US transmission providers to implement ambient-adjusted ratings (AAR) on power lines but stops short of mandating DLRs, giving transmission owners the option of implementing them. The industry has argued that AAR should not be considered as a GET due to its limitations. While AAR considers only ambient temperatures, DLRs rely on a range of inputs beyond ambient temperature, including all weather parameters (wind speed, cloud cover, solar irradiance intensity, precipitation) and line conditions such as tension or sag and provide situational awareness as well as reduce risks during contingency situations.

While the final order on this NOPR is still pending, several TOs are not in favour of FERC mandating DLRs. Renewable developers, on the other hand, have suggested that FERC could require implementation of DLRs under certain conditions including level of congestion costs, delays in new generation interconnection and curtailment of generation due to factors including thermal constrains on line capacity.

FERC workshop on shared savings model: As part of FERC’s review of its Electric Transmission Incentives Policy (RM20-10) to help speed up the build-out of the transmission grid to reach the pace and scale needed to ensure a smooth energy transition, the Commission held a workshop in September 2021 to discuss the shared savings model for GETs, previously proposed by the WATT and Advanced Energy Economy (AEE).

The workshop and the proposal followed a previous workshop held by FERC in November 2019 (AD19-19-000) to discuss how GETs are presently being used in transmission planning and operations, the challenges to their deployment and implementation, and what FERC could do regarding those challenges including providing incentives or mandating their adoption by transmission operators.

According to the WATT-AEE shared savings proposal, a part of the cost savings would be shared with the developer in addition to traditional return on equity for capital investments, which would accrue to the developer or TO depending on who undertakes the investment. Specifically, the proposal differentiates between mid-size (USD2.5-25 million) and small projects (less than USD2.5 million). For small projects having a minimum cost-benefit ratio of 4:1, a shared savings rate of 25 per cent is proposed, with the total capped at USD10 million. For mid-size projects, a competitive process is suggested in which the developers proposing the project also suggest the percentage savings share.

While the proposal has raised several challenges, there is broad support for implementing GETs. The key debate remains on how best to ensure their adoption by TOs and RTOs/ISOs, a call that FERC will finally have to take.

Key grid-enhancing technologies

The following are the key GETs that are under consideration and part of the debate and discussion in FERC’s recent proposed rulemakings.

Dynamic line ratings give transmission operators actual real-time or forecast power carrying capacity of overhead lines (OHL) based on a variety of data inputs, including ambient temperatures and line sag. It is essentially a way to operate OHL closer to thermal limits while ensuring no thermal damage occurs. Real-time monitoring of the line rating and line safety enables control of line load so that it utilises maximum capacity without exceeding the physical safety limits.  In addition to helping customers avoid expensive congestion costs, it can help incorporate additional renewable energy generation into the power system by allowing transmission operators to safely run power lines at a higher capacity. Notably, this can be achieved without changing the system structure or breaching the current technical specifications.

A FERC staff paper on managing transmission line ratings (August 2019) that evaluates both DLRs and AAR found that while the benefits of DLR are greater than that of AAR, the use of DLRs has greater challenges and costs. The key challenges unique to DLR implementation relate to sensor placement, sensor maintenance, and physical and cyber risks, as well as its tendency to cause line rating fluctuations. Meanwhile, both DLR and AAR face challenges related to automation, coordination with other TOs, market coordination, limiting elements and reliability.

Advanced power flow control, which can be achieved through modular flexible alternating current transmission systems (FACTS), help the operator reroute energy away from overloaded lines or towards under-utilised facilities. This technology does not increase the line capacity but regulates the power flow on a transmission line to provide the necessary system stability and increases transmission efficiency.

Traditionally, phase shifting transformers (PSTs) (also known as phase angle regulators in the US), capacitors and other devices installed in substations have provided this type of control. However, PSTs are expensive with limited deployment on a few lines with very high loads as they are long-term fixed assets. Another disadvantage is their size and inflexibility, particularly given the fast changes taking place in the electricity system.

New power electronics-based power flow devices that provide a real-time response and are less expensive are now available. These include distributed reactances, static synchronous series compensator (SSSC) and unified power flow controller (UPFC), which can reduce power flow on a line. SSSC and UPFC are second-generation FACTS devices. SSSC is a series-connected synchronous-voltage source that can vary the effective impedance of a transmission line by injecting voltage containing an appropriate phase angle in relation to the line current. It has the capability of exchanging both real and reactive power with the transmission system. UPFC is a combination of a static synchronous compensator (STATCOM) and SSSC and comprises voltage source converters coupled through a common direct current (DC) link. STATCOM is a shunt-connected reactive-power compensation device that is capable of generating and/or absorbing reactive power, and in which the output can be varied to control the specific parameters of a transmission system.

Topology control and transmission switching: Developed with the support of the Department of Energy’s (DOE) Advanced Research Projects Agency Energy (ARPA-E), topology optimisation is a software system that determines in real-time how to optimise the power transfer capacity of the grid by deciding which circuit breakers should be opened and closed. This technology is deployable with existing hardware. It helps increase grid reliability, resiliency and economics. It provides situational awareness due to near real-time simulation.

Other GETs: The industry is also offering other GETs such as asset monitoring systems, phasor measurement units (PMUs) and dynamic relay settings. Some DLR systems offer transmission asset monitoring capabilities by tracking conductor behaviour and determining whether asset life is shortened due to overload events or can be extended. Other types of asset monitoring include monitoring of transmission tower structures and insulators. PMUs provide system operators situational awareness into the performance of longer transmission lines and help increase system reliability. Dynamic relay settings refer dynamic adjustment relay settings in real-time based upon transmission line capacity, network configuration, and dynamic control elements. As per industry experts, modern relay communication protocols can support such setting changes and would be a natural layer to place on top of other technologies to deliver a truly optimised grid.

Recent utility experience

Over the past few years, several utilities have collaborated with DLR technology providers, which have been improving their platforms to provide more functional data for grid operators. Belgium-based Ampacimon has deployed its patented line-mounted systems on the transmission lines of five North American utilities including Arizona Public Service and New York Power Authority during 2020. Ampacimon’s DLR solution installs sensors on OHLs to measure real-time environmental, asset and electrical conditions and allows utilities to increase transmission capacity while also reducing congestion costs. Additionally, Ampacimon is providing system forecasting software that allows utilities to safely and accurately forecast transmission capacity ratings into the future for use in N-1 scenarios and to reduce market constraints. Meanwhile, US-based Lindsey Systems has also installed its sensors on power lines operated by various US and Canadian utilities.

Another DLR provider LineVision Inc. has secured deals with National Grid, Dominion Energy, Xcel Energy, Tennessee Valley Authority, and most recently Duquesne Light Company (DLC). Under a partnership DLC entered in September 2021, the utility plans to implement a pilot involving the installation of LineVision’s 12 no-contact sensors on a single line.

Previously in April 2021, National Grid, through its unregulated corporate investment and innovation arm National Grid Partners, invested in LineVision’s technology. National Grid is currently utilising LineVision’s V3 platform to assess conductor asset health, obtain greater situational awareness, and increase transmission line capacity with DLRs. The utility first deployed LineVision’s solutions in 2018 on transmission lines in Massachusetts. Thereafter, in 2020, it installed LineVision’s asset health monitors on lines in New York. The V3 sensors collect real-time data on critical parameters of OHLs including line temperature, sag, horizontal motion and other anomalies. This data alerts the utility to problems before they happen and can prevent costly power interruptions. It also helps the utility better understand the condition of its assets while enabling it to modernise the grid and integrate more renewables.

In February 2021, Xcel Energy, a major investor-owned energy utility with operations in eight mid-western and western states, installed LineVision’s V3 transmission line monitoring system in Colorado, Minnesota and Wisconsin to increase grid capacity and safety. This project is a collaboration between Xcel Energy, LineVision and Oak Ridge National Lab and the data collected will be analysed as part of a study on advanced line ratings. The deployment utilises three analytical modules. This includes LineHealth, which evaluates the current condition of conductors, helping Xcel Energy determine when and what types of maintenance are required. The second is LineRate, which can reliably increase conductor capacity with forecasted line ratings and real-time DLR. Meanwhile, LineAware technology provides real-time situational awareness, triggering real-time alerts to support corrective actions that protect system reliability and public safety. The data is collected using Velodyne’s Light Detection and Ranging (LiDAR) sensor system, which allows installation on live wires without having to de-power a transmission line.

In a recent development in September 2021, power utility Exelon partnered with Prysmian Group to pilot a new grid-enhancing technology—the application of a heat-dissipating E3X coating on existing power lines. This new E3X application process will enhance capacity for utilities on in-service OHLs and enable more power to be supplied across existing transmission grids. In late May 2021, an innovative robotic technology was used to apply Prysmian Group’s thin, resilient E3X on 138 kV overhead wires, lowering conductor operating temperatures and increasing capacity. This pilot, managed by ComEd – an Exelon company that serves northern Illinois – was successful. E3X coating on bare overhead wires boosts radiated thermal radiation and minimises sun absorption, allowing lines to run cooler, reduce energy losses, and eliminate sag-related safety hazards.

This technology has been used by utilities for over seven years to add capacity while reconductoring. Now with the ability to apply this special coating to existing lines, the aim is to use E3X to reduce power grid congestion and unlock additional capacity, thus increasing the amount of energy that can be delivered without the time or money involved in the construction of new lines. In the next phase, Exelon will evaluate the performance of coated lines and consider existing lines that could benefit from additional capacity or lower sag.

As of now, there is limited experience with applications of advanced power flow control and topology optimisation technologies by US utilities. For instance, US-based start-up company SmartWires, which offers a single-phase modular SSSC called SmartValve, claims that its technology is modular and scalable with the ability to start small and scale the investment over time or to remove and reinstall on a different voltage line. The company has got significant deals for its technology outside the US.  In the UK, SmartWires has a five-year framework agreement with National Grid for installation of SmartValves that will increase the transfer capacity on their system by 1.5 GW. It is also deploying the technology in Ireland and Australia. In the US, the company has deployed its line-mounted device, which helps in voltage control, in utilities such as Southern Company, Pacific Gas & Electric and Minnesota Power, but is yet to bag an order for its latest modular FACTs device, which provides flexible power flow control.

With regard to application of topology optimisation, a study by the Brattle Group and topology control software vendor New Grid that investigated the benefits of topology optimisation for the SPP market in 2018, found that topology reconfiguration can result in real-time market congestion cost savings of USD18-44 million annually (based on historical congestion costs). The study observed from SPP experience that the two most severe constraints in Kansas and southeast Oklahoma could be fully relieved with topology optimisation. The optimisation software automatically finds reconfigurations to route flow around congested elements. In fact, it found single-action reconfiguration options that fully relieved overloads and congestion on a critical, frequent SPP constraint under multiple conditions. Another study estimates USD100 million in congestion cost savings from using topology optimisation in PJM real-time markets under historical conditions.

The way forward

Over the last couple of years, there has been an acknowledgment of the significant role that GETs can play in the country’s energy transition plans, in addition to the requisite new transmission build-out. At the federal level, the proposed bill and FERC’s recent rulemakings are considering ways to integrate GETs into the transmission planning process. While utilities are insisting on providing appropriate incentives for implementing GETs that offer clear benefits to make up for the costs and risks that accompany them, the industry is pushing for a shared savings scheme. There is also a view that competitive incentives should be established to ensure competition among technology providers. Nevertheless, there is broad agreement that transmission providers must adopt these technologies sooner rather than later to help consumers save on transmission congestion costs as well as facilitate the faster integration of renewable energy sources into the grid to support US’ energy goals.