California’s Connection Conundrum: DLR Technology Utility
By: Giavanna Chopra
Abstract
As California strives to meet its renewable energy goals, insufficient grid capacity remains an inhibiting factor that needs to be addressed. An increasing number of battery and renewable energy projects are waiting for approval because of strains on existing energy infrastructure. New technologies promise to ease the integration of new energy sources with existing power grids without waiting years for new transmission line construction. One cost-effective way to rapidly increase the capacity of transmission within existing power grids is to switch from static line ratings to dynamic line ratings (DLR). Rather than electricity in a given transmission line remaining static or constant, DLR technology allows grid operators to make real-time adjustments to the amount of electric voltage a transmission line can handle based on a variety of conditions, including wind, temperature, line tension, and humidity. Increasing grid capacity is essential to integrate new renewable power sources, and the technology used to collect data for dynamic line ratings can also be used to detect dangerous conditions with the potential to spark wildfires preemptively. California ought to follow the lead of other utility operators who have successfully implemented DLR technology.
Background + Batteries: Public investment in energy storage increases the availability of renewable energy but not the ability to transport it.
Transmission lines are responsible for moving electric energy within power grids and typically operate under “static ratings,” meaning that a transmission line only carries the amount of electricity that would be deemed safe under the most severe weather and temperature conditions for a given geographical area. When the demand for energy exceeds the capacity of a grid’s transmission lines, transmission congestion occurs, resulting in increased consumer prices. Even when power providers can supply enough electricity to meet demand, limited transmission line capacity constrains the energy supply that can get to consumers. Increased demand and constrained transmission capacity led to the nearly $700 million paid by California energy consumers between 2009 and 2017 as a result of grid congestion. In 2016 alone, American consumers paid more than $4.6 billion in energy grid congestion surcharge costs.
In addition to increased consumer costs, grid congestion contributed to rolling blackouts or unplanned power shut-offs across California in August 2020. Widely blamed on variability in the energy output of renewable power sources like solar, a variety of concurrent failures, including “congestion due to transmission constraints,” contributed to the crisis. Exacerbated by storm damage to a major interstate transmission line, “transmission constraints” in the power grid managed by the California Independent System Operator (CAISO) resulted in “more energy” being “available in the north than could be physically delivered” to high-demand regions. As up to 2 million Californians experienced blackouts between August 14 and 15, 2020, the reality that grid operators declined available power due to grid capacity was an unfortunate failure of the state’s electric grid.
Since 2020, a variety of infrastructure projects have been undertaken and proposed to modernize California’s costly and unreliable power grid, primarily focusing on increasing battery storage to promote California’s mandated 100% transition to renewable energy by 2045. California’s energy battery capacity more than doubled between the end of 2020 and June 2024, increasing from a 500-megawatt maximum capacity to an 11,200-megawatt capacity statewide. While the “size” of the additional batteries “varies widely,” “most batteries” added to the California power grid “have a duration of four hours.” The approximately 10,700-megawatt increase multiplied by a four-hour maximum storage capacity means roughly 42,800 kilowatt-hours of available energy were added to the power grid. The estimated “capital costs for a complete 4-hour battery system” in 2023 ranged from a low of $347 per kilowatt hour to $500 per kilowatt-hour. Therefore, using 2023 cost estimates, construction costs for California’s 42,800-kilowatt-hour increase in battery storage between 2020 and 2024 totaled between $14.85 billion and $21.4 billion dollars. This investment was subsidized by California’s Self-Generation Incentive Program (SGIP), which offers “rebates for installing energy storage technology” on “residential and non-residential facilities” such as large-scale renewable enterprises and the Inflation Act of 2022. The Inflation Act of 2022 is a federal policy that expanded the Investment Tax Credit to include “energy storage technologies” not explicitly containing 75% or more on-site renewable energy. The tax credit is equal to 30% of production costs, imposes minimal labor standards on large projects, and offers additional 10% tax credits for building with American-manufactured materials and for building in low-income or communities traditionally reliant on mining jobs. The costly battery projects have effectively increased the amount of renewable power available to grid operators outside of peak solar hours but have not addressed underlying issues with grid capacity. Power is effectively useless without effective pathways to transmit it to end-consumers.
DLR + Cost Estimates: Dynamic Line Rating (DLR) cost-effectively addresses California's energy goals.
Increased battery capacity necessitates increased transmission line capacity. In 2022, CAISO announced that nearly $11 billion is needed to build new transmission lines within the existing “footprint” of California’s grid. In 2023, CAISO approved $7.3 billion to build “new transmission infrastructure,” including brand new “towers, wires, transformers, and substations” to increase grid capacity and allow for the integration of renewables and batteries into California’s power grid. When utility companies within the CAISO network make high-cost infrastructure investments, those costs are passed on to consumers. As of January 2025, California energy consumers pay “among the highest” electricity costs in the country; in fact, “electricity rates in California are close to double those in the rest of the nation."
Rather than prioritizing the construction of entirely new transmission lines, California ought to start with the cheapest option: maximizing the productivity of the lines already available. DLR, or dynamic line rating, refers to the process of measuring the maximum capacity of a power transmission line in real-time based on fluctuating weather and environmental conditions and updating the amount of electrical current flowing through a transmission line based on current conditions. A type of grid-enhancing technology (GET), DLR technology is primarily implemented by installing sensors on existing transmission line conductors that measure temperature, line tension, and other conditions, such as wind speed. This information is transmitted back to a central hub where algorithms and human grid managers process the data and determine the amount of electricity that is safe to flow through a given transmission line at a given time. In the event that sensors or connectivity to the processing center are disabled, systems can “always” “revert” to static line rating safety standards and can be designed “to default automatically” back to static line ratings in the event of DLR technology failure. Unlike traditional static transmission lines that operate 100% of the time as if environmental conditions are at their worst, DLR technology enables utility companies to operate transmission lines at their maximum safe capacity.
Using a model of the Electric Reliability Council of Texas (ERCOT), which manages 90% of the electric power grid in Texas, researchers estimate that implementing DLR technology on eligible transmission lines would eliminate 77% of grid congestion. The congestion reduction would save operators an estimated $776 million per year on operation costs. Of the transmission lines in the ERCOT grid, researchers estimate about 2,308 are the appropriate length for DLR technology to be useful. Midcontinent Independent System Operator (MISO), which manages electric grids in fifteen states, self-reported in a comment to the Federal Energy Regulatory Commission in 2022 that the estimated cost of implementing DLR technology is between $100,000 and $200,000 per transmission line. Applied to the ERCOT grid study, an initial investment between $230.8 million and $461.6 million would save grid operators $776 million per year. Similar cost savings are applicable to California’s energy grid. Based on California utility company Pacific Gas & Electric (PG&E)’s cost-per-mile estimates, it would “cost approximately $500,000” to install and implement DLR and between “$22-$176 million” to upgrade the same amount of transmission lines using traditional methods. The most cost-effective measure to safely increase grid capacity and reliability should be implemented first. With billions spent on battery storage projects and even more planned, it is essential that grid capacity be able to transmit the influx of renewable power.
Renewable Implementation: California's policy goals can be achieved with infrastructure updates to accommodate renewable energy.
In addition to increasing battery storage capacities, the main roadblock to California’s ambitious mandate for 100% of the state’s electricity to come from “renewable energy and zero-carbon resources” by 2045 is insufficiencies in the power grid and transmission line capacity. Throughout California, “[g]rid infrastructure, particularly transmission, has not kept pace with the clean energy transition,” and as an increasing number of electricity operators vie for limited transmission capacity, the transition away from fossil fuels is stifled. California leaders and utility operators scrambling to meet renewable mandates have “diverted billions meant for grid maintenance to renewables.” PG&E faced intense criticism in 2018 for spending $44 billion on new purchase agreements with renewable energy suppliers but only $1.5 billion on power grid maintenance for the entirety of 2017. Critics argue that “state leaders pressured utilities like PG&E” to prioritize compliance with renewable energy mandates over grid improvements and safety assessments. Renewable power sources are only beneficial to climate goals and consumers if there is sufficient capacity for their utilization in the power grid. Despite massive spending on battery storage, California lost more than $1 billion worth of solar energy in 2024 because it could not be immediately used or stored, which is “enough [energy] to power over 500,000 homes for a year.” California occasionally has to pay neighboring states “to take excess electricity its residents” are not using to “avoid overloading its own power lines,” which can cause blackouts. As of mid-2024, renewable energy projects awaiting approval from CAISO totaled “more than three times the capacity California will need to meet its 2045 clean energy goals.” The energy to meet California’s 100% renewable energy goal is ready and waiting, but the grid is not ready to accept it.
A 2023 report found that CAISO had the slowest median duration from grid connection request to project operation out of any regional transmission organization in the country, with projects proposed between 2018 and 2022 taking an expected average of nearly six years to come online. A surge in requests has contributed to lengthy review times and astoundingly high withdrawal rates for projects waiting for CAISO review. In response to their exceptionally slow approval times, CAISO has recently approved a “revamp [of] the grid operator’s interconnection process” to prioritize approval for projects located in areas with existing transmission capacity available. However, CAISO simply cannot approve the many projects located where existing grid capacity is insufficient. CAISO is forced to turn down renewable energy proposals when more “[c]ongestion on the transmission grid” would make it “difficult to either export excess renewable generation out of an area or to import renewable energy into an area to meet demand” due to limited transmission line capacity. CAISO is working “to help project developers identify areas with available transmission capacity,” but long-term increases to overall capacity are needed to implement a sufficient number of renewable energy projects to meet California’s clean energy goals. CAISO predicts that the additions and improvements to transmission lines required “to transition to clean energy” will cost Californians “a $30.5 billion investment.” Even if funding was made immediately available, “[t]ransmission infrastructure projects require long lead times,” with some individual projects taking eight to ten years to implement.
DLR technology is a pivotal innovation for cheap and rapid grid capacity increases to make space for renewable energy. Traditional transmission projects, such as line construction and reconductoring, are capital intensive and can take up to 5-10 years to site, permit, and build.” Current cost estimates and timelines for increasing grid capacity do not include the implementation of DLR in their reports, which can be implemented in mere months at a fraction of the cost of traditional upgrades. Proponents of DLR deployment in California argue that DLR “can increase [grid] capacity by 30% at a fraction of the cost of new lines.” By using technology costing a few hundred thousand dollars to implement rather than tens of millions, grid operators can increase grid capacity without passing on costs to consumers via massive rate spikes.
Fire Prevention: Modernizing California's power lines with sensors will increase wildfire safety.
DLR technology is an essential tool in California’s ongoing fight against increasingly devastating wildfires. Until final estimates for the Palisades Fire earlier this year are available, the Camp Fire officially remains the costliest fire in California history and was the “costliest disaster worldwide in 2018,” burning for seventeen days in November 2018. It destroyed “18,733 structures, including 14,000 residences,” and killed a record eighty-five people. Officials have since confirmed that “electrical lines caused the fire.” Utility operator PG&E corroborated that “a part had separated from a transmission-line tower,” causing the active electrified transmission line to sag into what was likely “dry vegetation” below. Mere months after “Cal Fire announced that PG&E equipment triggered 12 Northern California wildfires [in 2017], which killed 18 people and destroyed thousands of structures”, PG&E was once again found at fault for the Camp Fire tragedy. PG&E is not the only California utility company with transmission lines sparking deadly wildfires. Preliminary reports on the January 2025 Eaton fire that “killed 17 people and destroyed part of the Los Angeles area” suggest that a transmission line owned and operated by Southern California Edison may have sparked the fire.
Transmission operators can decrease the likelihood of tragedies reminiscent of the Camp Fire happening again by implementing DLR technology. Transmission lines retrofitted with sensors that can detect when a power line is overheating or has an unsafe tension reduction (i.e. an overhead power line sagging too low to the ground) enhance the “ situational awareness” of grid operators to better “protect the public from… issues of safety” including “fire.” Regulators discovered that PG&E had not inspected the transmission line that caused the Camp Fire in roughly seventeen years when the hook holding the line up failed. PG&E manages roughly “18,466 circuit miles of interconnected transmission lines.” It is not exactly shocking that every hook on thousands of miles of transmission lines is not individually inspected on a regular basis. However, if power lines themselves could communicate with central hubs, alerting operators to unusual conditions, power operators could de-electrify specific power lines and prevent wildfire sparks with significantly increased efficiency and precision. Since 2018, PG&E has been conducting Public Safety Power Shutoffs (PSPS), intentionally de-electrifying or turning off vast swaths of the power grid and electricity service in areas most likely to be at risk of wildfires. PSPS can pose dangers to some customers and is extremely disruptive, with an estimated three million Californians losing power in October 2019. By relying on real-time data, “the proposed DLR approach can significantly reduce [power outages] relative to an alternative approach” and “provides an inexpensive approach for mitigating wildfire-ignition risks.” From reducing “the risk of wildfires caused by overloading transmission lines” to identifying sagging grid lines and alerting algorithms or human grid managers of potential physical infrastructure failures, DLR is needed to modernize California’s power grid and mitigate the onslaught of wildfires caused by power grid failures.
Case Studies: Direct Line Rating is being used in New York, the United Kingdom, and Denmark with positive results.
DLR technology has moved past the hypothetical, maximizing grid capacities in the United States and globally. The largest power grid operating with DLR technology in the United States came online in 2024 in Western New York, using transmission lines owned by National Grid. Following a successful pilot program, the company LineVision’s “DLR software and sensor platform” was deployed on “four 115-kilovolt transmission lines” to provide “‘automated, condition-specific line ratings to [the] transmission control room.’” National Grid “expects average capacity increases of between 20% and 30% across those lines,” prompting the consideration and testing of “similar deployments” in grids they operate in New York, Massachusetts, and the United Kingdom. While details of how much National Grid paid LineVision for the New York project are not publicly available, National Grid says future deployments will be faster and take less effort - indicating satisfaction with the cost-effectiveness of the LineVision system. Brian Gemmell, CEO of electric operations for National Grid New York, emphasizes that DLR implementation is helping to “...further unloc[k] renewables and reducing transmission congestion for New Yorkers.”
In an effort to free up grid capacity for the integration of energy from offshore wind into the United Kingdom power grid, National Grid UK is following New York’s lead and working with LineVison to implement DLR technology. Based on tests conducted on actual UK transmission lines, a 2023 case study indicated that “the average capacity increase will be between 29-33%” if LineVision’s system is implemented into the English energy management system with an estimated annual total cost savings of “£14.25 million” (or about $18 million USD) “for the grid operator” based on 2021 expenses. National Grid UK has moved forward with “trialing dynamic line rating technology from LineVision,” and it is currently in effect “on a circuit near Merseyside in northern England.” The current LineVision DLR system being sold to grid operators provides “another data point” to human operators “when deciding to increase capacity in a particular line.” LineVision and National Grid partnered to determine the optimal amount of data to display to grid operators to be helpful but not overwhelming. Companies comparable with LineVision currently advertise the use of AI to make decisions using data from DLR technology; it is likely AI will replace human operators in determining the dynamic rating for a given line in the future, enabling the maximum amount of data from LineVisions sensors to be utilized.
Another successful implementation of DLR technology took place in Denmark in early 2023. Energinet, Denmark’s national electricity transmission operator, partnered with Ampacimon, “a global leader in Dynamic Line Rating (DLR) technology,” to retrofit “approximately 20” Danish transmission lines with DLR Technology. The “dynamic line rating makes it possible to transport… up to 30% more power in high wind generation areas,” which are common in Denmark. Officials estimate that the “transmission capacity of overhead lines” is improved by DLR technology “for 90 percent of the year's hours,” allowing Denmark to “make use of all the new green electricity that is being produced.” The grid updates will also save Energinet an estimated “400 million DKK” (or about $56 million USD) “by 2030,” making it a net cost-effective investment. Ampacimon DLR sensors are known for their ease of installation and can be “attached to transmission lines in 90 seconds,” even by drones for high-up power lines. Energinet grid operators compare real-time capacity data with predictive models of upcoming weather events to set a dynamic line rating for each of the 20 transmission lines currently using DLR. Energinet planned to finish implementing DLR technology on all 90 of Denmark’s overhead transmission lines by early 2024, but no information is publicly available on whether this goal was met. Energinet has not responded to requests for comment on the current number of Danish transmission lines using DLR technology. While not a comprehensive list, the New York and Denmark examples demonstrate the utility of DLR technology on large-scale power grids to increase transmission capacity and enable the inclusion of renewable energy.
Moving Beyond Reports: California ought to do more than merely collect reports on DLR technology.
California’s first step towards DLR implementation occurred on September 25, 2024 when Governor Gavin Newsom signed SB 1006 into law, mandating “each transmission utility” in California to “prepare a study of the feasibility of projects using grid-enhancing technologies,” including dynamic line rating systems. In addition to grid-enhancing technologies, SB 1006 also requires utility operators to report on which of their utility lines can be feasibly reconductored or rewired to have a more efficient static line rating. The law has been dubbed “groundbreaking,” with proponents claiming that initial utility company proposals due to the California Public Utilities Commission (CPUC) in January 2026 have “the potential to double the energy-carrying capacity of existing transmission lines within a 12 to 18-month timeframe.” While SB 1006 reports to CAISO on DLR “feasibility, cost, rating, implementation time…” are beneficial for eventual DLR adoption, the law does not mandate any kind of implementation or trial usage of the technology. It simply requires utility companies to conduct grid-enhancing technology feasibility reports every two years, with the first being due by January 1, 2026. By comparison, when California passed SB 100, ambitiously requiring California utility companies to fully transition from fossil fuels to renewable energy sources by 2045, the legislature did not request feasibility studies; they requested progress reports. Rather than mandating perpetual reports, California ought to pass legislation mandating regional grid capacity increases by target dates. As the most cost-effective option on the market to substantially increase the capacity of individual transmission lines and overall power grids, utility companies operating under CAISO would be incentivized to invest in DLR technology trials and implementation instead of writing reports that may or may not ever translate into actual grid improvements. Meeting California’s renewable energy goals will take more than solar panels on every roof; it will require a modernized grid, maximizing its capacity to reliably transport power where Californians need it most.
In late 2021, the Federal Energy Regulatory Commission (FERC) issued Order 881, mandating that grid operators implement “ambient-adjusted ratings” by July 2025. Ambient-adjusted line ratings (AAR) can be considered the halfway point between status-quo static line ratings and dynamic line ratings (DLR), which collect and transmit a variety of useful data. Typically, AAR forecasts the transmission capacity of power lines using current and historical temperature data. It does not require sensors to be installed on transmission lines or any infrastructure updates. Instead, utility control rooms go from having static line ratings to calculating differences in transmission capacity based on temperature and regional weather conditions “while data on parameters like humidity, lighting levels, wind speed and wind direction” that would require sensors remain “static assumptions.”
Unfortunately, all six grid operators in the United States mandated to update transmission line capacity ratings to include AAR by July 2025, including CAISO, report that they will be unable to meet the deadline for a variety of reasons, including the claim that there are not enough companies selling the necessary AAR software. While operators are far behind in meeting the initial deadline, the order has sparked interest in DLR technology implementation. CAISO has approved a limited number of grid-enhancing technology projects since the order was issued. PG&E has launched a project “conducting an objective side-by-side demonstration” of various DLR systems and, depending on the test results, plans to “incorporate it into PG&E’s implementation of the FERC Order 881.” Dynamic line ratings encompass the data Order 881 requires to be calculated into line ratings. As utility companies work toward Order 881 compliance, some may turn to the superior solution of DLR. FERC likely anticipated this outcome because Order 881 includes a provision requiring “organized market operators” such as regional transmission organizations like CAISO to “establish and maintain systems and procedures necessary to allow transmission owners” like PG&E “to use dynamic line ratings” if they choose. This provision ensures that all utility operators have the legal right to use DLR technology even if their transmission lines are incorporated into a larger power grid that has not fully transitioned to DLR. More localized operators now have the opportunity to implement DLR and may serve as test cases for neighboring utility operators to evaluate the merits of the technology within the context of their grid.
While FERC issued Order 881 under the previous Trump administration, recent priority inconsistencies at the federal level have left many questions about the future direction of FERC and its parent agency, the Department of Energy. In the event that Order 881 is repealed or not enforced, California ought to pass a similar law mandating the transition away from outdated static line ratings. State officials also ought to consider mandating DLR technology be incorporated into California utility operators' plans to become compliant with Order 881. Once all CAISO utility operators are compliant with the order, grid control rooms only using static line ratings will be a thing of the past. When operators can adjust transmission line capacity ratings on an hourly basis depending on temperature and weather conditions as mandated in Order 881, they will be better positioned to comply with future state DLR technology mandates. California legislators should consider expanding mandates in FERC Order 881 to include a transition timeline from AAR to DLR with accompanying tax breaks for compliant companies to help offset costs. Constructing more renewable energy sources is useless if the grid cannot support them, and Dynamic Line Rating effectively addresses California’s need to expand capacity in a safe and cost-effective way.
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