How close are we to the inflection point for the grid-enhancing technologies (GETs)?
What’s the problem?
The recent announcement of FERC Order 1920 highlights a critical issue: transmission lines are now the bottlenecks in our electrical grid, restricting the growing electricity demand and hampering the energy transition. Building new transmission lines requires significant capital investments, long development timelines, and extensive stakeholder and community engagement. Meanwhile, the need for increased transmission capacity is becoming urgent due to the rapid deployment of renewables, demand growth from reindustrialization, the rise of hyperscalers like AI data centers, and electrification across buildings, mobility, and industrial sectors. Another way to illustrate this bottleneck is the estimated total congestion costs across RTOs in the US, which surpassed $20 Billion in 2022 (note: congestion is defined as when the transmission system limits generation dispatch economics). To resolve this bottleneck, Order 1920 and FERC Order 2023require transmission providers to conduct long-range planning for transmission needs and assess various cost-effective alternatives to increase capacity.
One of these cost-effective alternatives is deploying grid-enhancing technologies (GETs). GETs are software or software-enabled hardware solutions that enhance transmission capacity and grid operational flexibility. They are an elegant solution because they unlock transmission capacity without the need for massive capital expenditures on new transmission lines. This is especially valuable considering that roughly 50% of the economic value of transmission is concentrated in just 5-10% of the total hours of the year, typically during extreme weather or unexpected conditions, according to ar Berkeley Lab’s study last year. But how much can they help with capacity enhancement and congestion relief? And how should stakeholders like technology providers, grid operators, financiers, and policymakers think about GETs?
What flavors of GETs can we get?
We’ll cover four types of GETs in this blog, across both hardware-based and software-based solutions. Also, to help the readers get the GETs better (pun intended), we’ll use the analogy between the transmission system and the transportation system from the DOE’s 2022 report.
Advanced Conductors: Advanced conductors push 50-150% more power than traditional lines. Often called “high-temperature low-sag” (HTLS) conductors, they operate at higher temperatures and use carbon-based cores instead of steel, reducing weight and allowing for more aluminum conducting materials. These conductors also reduce line loss and enhance thermal and mechanical properties for longer lifespans. Think of it like replacing an old, narrow road with a new, wider, and smoother highway that handles more cars at higher speeds without needing to build a new road. Companies scaling advanced conductors include TS Conductor, CTC Global, Advanced Conductor Technologies, Southwire, and 3M. Additionally, companies like VEIR aim to increase capacity by 5-10x with superconducting cables, which, in transportation system analogy, can be akin to Elon Musk’s Boring tunnels.
Advanced Power Flow Controllers (APFC): APFCs are compact, modular devices that can quickly redistribute power from overloaded to underutilized powerlines without changing generator dispatch or network topology. They function like traffic flow control systems (the name suggests quite the clue!), adjusting lanes and signs to direct cars to different routes and avoid traffic jams. Compared to traditional power flow controllers like phase-shifting transformers and series reactors, APFCs offer dynamic, low-latency control with unlimited operations. Companies developing APFCs include Smart Wires (SmartValve), Siemens Energy (UPFC PLUS), and ABB (FACTS line).
Dynamic Line Rating (DLR): DLR uses localized sensor data on weather, wind, and current/voltage to safely increase (or decrease) power flow on transmission lines by 20-40%. DLRs are like variable speed limit signs that adjust based on traffic and weather conditions, allowing more efficient travel when conditions are good. If the transmission line can use more power, it’s an economic benefit; if it can only use less, it’s a resilience or safety benefit to the ratepayers and operators. While there are many software-only offerings for DLR, a more sustained business advantage comes with software-enabled sensing hardware on the transmission lines ‒ some example companies are LineVision, Lindsey, Heimdall, and GridPulse. Companies like De Angeli offer “smart conductor” and “optical ground wire”, where they embed fiber optics cable within a powerline and relay them to the ground to send the data to the grid control center.
Topology Optimization (TO): TO software helps grid operators analyze the transmission network in real-time and semi-automatically reconfigure power flows around the bottlenecks (i.e. increased flow, decreased congestion cost, and enhanced reliability). Compared to optimization based on labor-intensive measurements or institutional knowledge, TO is like Google Maps, continuously finding the best routes for cars based on current traffic, accidents, and road closures. NewGrid, for example, offers topology optimization software that claims to reduce congestion costs by up to 50%.
As shown, not all GETs are the same ‒ they offer different pros and cons for grid operators and public-facing authorities based on factors like cost, capacity gain, congestion relief, and implementation risk. In other words, the deployment of different GETs should be case-by-case based on specific grid needs.
Then what should we invest / deploy first?
One might argue that we should deploy all GETs wherever they are most applicable, especially given their synergies. However, the deployment should be on a case-by-case basis, considering a detailed assessment of grid needs and technoeconomic benefits. Several factors, such as a lack of evaluation criteria for GETs or limited understanding among regulators and policymakers, can hinder this. Regulators might ask, "I know these GETs can help, but which one and by how much?"
A useful approach is to apply a Multi-Criteria Decision-Making (MCDM) framework, such as the Analytic Hierarchy Process (AHP). AHP is effective because it allows for considering both quantitative and qualitative attributes of varying importance. To illustrate, we can look at four dimensions as a proxy for criteria assessed during real transmission planning:
Project cost / affordability: How affordable is the project, considering total project cost, operations, and maintenance costs?
Incremental reliability gain: How much does the technology improve grid reliability metrics such as SAIDI, SAIFI, and outage reduction?
Incremental capacity gain: How much additional transmission capacity will the technology unlock? How much improvement in average capacity utilization will the technology enable?
Environmental & community impact: How will the technology implementation affect the surrounding environment, visual impacts, air emissions, land use, habitat loss, and public safety?
We surveyed industry experts like Hudson Gilmer at LineVision and Phil Giudice at FirstLight Power, on the relative weighting across the evaluation criteria and the relative preferences across the technologies.
The results highlighted the distinctive benefits of each technology. Advanced conductors were 50%+ more preferred for capacity increases, while PFCs were 35%+ more preferred for reliability. DLRs and TOs were seen as the most affordable and least environmentally impactful solutions. These preferences might vary depending on the experts surveyed, but the key point is that an analytical framework can help regulators and policymakers gain confidence in their investment and regulatory decisions, expediting the deployment of GETs.
But do we have enough incentives to deploy?
When it comes to economics, it’s a well-known fact that utilities make money at a specific rate of return on equity (ROE) when they spend on capex projects, such as new transmission lines. This creates a misalignment of incentives because utilities can earn higher returns with large, new transmission build-outs compared to upgrades or software-based efficiency improvements. Additionally, utilities are typically risk-averse, favoring tried-and-true technologies to guarantee grid reliability. This has led to a strong business case against deploying GETs.
However, this time could be different. With the need to double or triple the transmission capacity in the next 10-15 years, utilities have no choice but to deploy as many GETs as possible alongside building new transmission lines. In addition, the hardware-based GETs can be considered capitalized investments (i.e. be a part of the rate base), which can bring additional capex spend for asset replacement cases. Furthermore, required transmission upgrades resulting from interconnection studies ‒ now more frequent due to the increasing size of new renewables and an aging grid ‒ can significantly improve ROE due to the relatively short deployment time of GETs. According to according to WATT Coalition, the payoff period for GETs can often be one year or less, which is remarkable for hardware-based products.
Federal and state regulators are also introducing policy measures to incentivize the deployment of GETs. On the “stick” side, state regulators are requiring utilities to study congestion issues and consider GETs during transmission planning. House Bill H.R.6747, if passed, would allow interconnection customers to request utilities to deploy GETs. On the “carrot” side, DOE recently made categorical exclusion to simplify lengthy environmental review on transmission reconductoring above 20 line-miles, potentially reducing project development time by years. Senate Bill S.3918 if passed, would allow FERC to establish a shared savings mechanism for GETs, enabling utilities to capture a percentage of the value from congestion cost reduction. Additionally, FERC recently released an Advanced Notice of Proposal Rulemaking (ANOPR) on DLR, poised to remove barriers to further the DLR deployment.
In response to these incentives, utilities have been launching pilot projects and scaling GETs in partnership with GET providers. For example, Great River Energy in Minnesota is partnering with Heimdall Power to deploy 52 DLR sensors on transmission lines. Utilities like Basin Electric Power Cooperative and NextEra Energy are demanding reconductoring wires from TS Conductor, so much so that TS Conductor is building a new 50k line-mlies/year production facility in the US. National Grid is working with Smart Wires to coordinate the installation and operation of advanced power flow controls while identifying the best locations for additional deployment of GETs like DLRs (a double win!). These partnerships and deployments suggest that the inflection point for widespread GET adoption might be near.
So how do we know when the inflection point will be?
According to DOE’s April 2024 Liftoff report on Innovative Grid Deployment, mass deployment of GETs is achievable within 3-5 years, with a targeted inflection point in the 2027-2029 timeframe. The report suggests that 6-12 large in-field deployments of GETs, coupled with industry-wide knowledge sharing and refined investment and incentive approaches, are crucial steps to reach this goal.
To understand the trajectory towards this inflection point, we can look at the order of operations across three key players:
Technology/industry: Extensive technology development and demonstration in partnerships with asset owners give confidence to the policymakers to introduce the regulatory framework and incentive structure.
Policy/regulation: With the above confidence, policymakers introduce regulatory frameworks (e.g., recommendations, criteria, mandates, etc.) and incentive structures for market mechanisms to take off.
Capital/market: The asset owners and capital allocators invest in the technology deployment at scale, from which market mechanisms such as economy of scale, learning by doing, and learning by using improve the technology and drive more competitive benefits.
While the report was published recently, some early indicators can point to the green lights for the inflection point in the next few years:
Technology/industry indicators: Technology standardization is a measure of industry maturity and is especially crucial for utilities that are sensitive to performance certainty. Although industry standards have yet to be established currently, organizations like EPRI are designing standard testing methodologies and specifications for GETs. Equally crucial indicator is the formation of and activities by industry groups, whose policy support and technical thought leadership influence policymakers and regulators. The good news is that industry groups like WATT Coalition (WATT stands for Working for Advanced Transmission Technologies) and Advanced Energy United have been increasingly advocating for GETs adoption and innovation in transmission planning improvements.
Policy/regulation indicators: Some leading indicators include the major policy changes and regulatory reforms to incentivize/expedite the implementation of GETs. One example in action in addition to the ones covered above is the Federal-State Modern Grid Deployment Initiative, a multi-level commitment between the federal government and 21 state governments to accelerate the adoption of GETs. Another leading indicator is the amount of government funding to support the technology demonstration and deployment, which is critical until the market mechanism takes off. For example, DOE’s Grid Resilience and Innovation Partnerships (GRIP) Program is administering a whopping $10.5B for grid innovation and improvements.
Capital/market indicators: The recipients of the aforementioned federal funding will be sharing the learnings and feedback on the technology and implementation with a broader audience in the industry. This in turn will help the grid operators accelerate the deployment decision-making. Then the positive feedback loop is created where the learnings will be shared with more grid operators and regulators, who will develop and publicize request for proposals (RFPs) from technology providers and installers to deploy the GETs. I.e. the pilot post-mortems and the number and dollar amount of RFPs could indicate the market takeoff. Finally, one indicator to keep an eye out for is the growth capital from private growth equity investors onto technology startups like Heimdall and TS Conductor. As these startups prepare to scale and take larger market valuations, investors will cast their vote of confidence on the upward trajectory of GETs with various financial measures and take presence in the capital stack.
Above being said, one of the first areas for large-scale GETs deployment (which could indicate the inflection point) could be in the Pacific Northwest and California regions. This is because of several factors that make GETs the perfect candidate: 1) favorable regulatory support (e.g. California seeking $2B in federal grant for GETs deployment), 2) the urgency of cost-effective transmission capacity (e.g. large community pushback in both regions due to already high electricity price), and 3) the limited alternatives to GETs (e.g. Pacific Northwest is notorious for having very constrained right-of-ways that physical grid expansion is difficult).
What are the next steps?
Thankfully, most decision-makers and significant actors on the path to the inflection point are committed to deploying GETs ‒ an exciting development for such a complex industry. To row in the same direction and cross the finish line, however, the stakeholders must continue to push forward. For GET providers, this would mean continuing to partner with utilities for deployment and educating the policymakers and regulators. For the grid operators, this would mean deploying pilot programs now while investing in further technology validation, including leveraging standardized lab testing services such as EPRI’s GET SET initiative. For the policymakers and regulators, this would mean proactively collecting information from the stakeholders to establish a working incentive structure and cost recovery mechanism, as well as coordinating with each other for national-level adoption until the market mechanism takes the driver’s seat. By continuing to collaborate and push forward, we can ensure that the industry reaches the inflection point for mass deployment of GETs, driving significant advancements in grid capacity, congestion relief, and reliability ‒ all at affordable prices.
For any inquiries, suggestions, or collaboration requests – feel free to contact us at energytransitionnotes@gmail.com.
About the author(s)
Dennis Cha is a recent graduate from the MS/MBA program at Harvard Business School. Prior to Harvard, he worked at Google on hardware supply chain, with PG&E on electric infrastructure operations and wildfire analytics, with SoCalGas on asset decarbonization, and at Taslimi Construction on sustainable construction management. He is trained in civil engineering and data science, and began his career in structural engineering. Outside of work, he enjoys scuba diving, youth mentoring, and traveling.
Daniel Anastos is a current Masters System Design & Management (SDM) candidate at MIT and the current Director of Energy Markets at Nexamp, a Boston-based solar company. He leads optimization and market operations for Nexamp’s entire energy storage fleet. Prior to MIT and Nexamp, Daniel worked in Nigeria developing microgrids for off-grid communities in rural areas for PowerGen Renewable Energy.
Luis Velasquez-Mansilla is a current Ph.D. Candidate in Electrical Engineering and Computer Science at MIT and the Co-Founder at Power Plant Solutions, a technical services provider for the energy and marine markets in the Caribbean, Latin America, Africa, and Europe. He also served as Researcher at MIT Energy Initiative, where he focused on the optimization of planning, development, and operation of future offshore wind projects. He holds a BS in Mechatronics Engineering from Universidad del Valle de Guatemala.