Transmission Congestion Costs in the U.S. RTOs

Jesse Schneider, Grid Strategies LLC

August 14, 2019

Transmission congestion costs have significantly increased over the last three years across the Regional Transmission Organizations or Independent System Operators (RTOs/ISOs) that serve around 60% of U.S. electricity customers. Of the seven operators of wholesale electricity markets in the country, all except the California Independent System Operator (CAISO) publicly post congestion cost data.

Figure 1: RTO/ISO Regions


As shown in the table below, reported congestion costs increased by 9% from 2016 to 2017, and by 22% from 2017 to 2018:

Table 1: Transmission Congestion Costs ($ millions) for RTOs from 2016-2018


2016 2017 2018


497 976 1,260


38.9 41.4 64.5
MISO 1,400 1,500


NYISO 529 481


PJM 1,023.7 697.6



273.7 405.3


Total 3,762.3 4,101.3


Transmission congestion occurs when there is insufficient transmission capacity to deliver lower-cost generation resources to consumers, requiring the use of higher-cost generators closer to customers. This increases the price of electricity in congested areas, as reflected in higher locational marginal prices and higher electricity prices for consumers.

Even with the omission of congestion costs in the CAISO region* and the one-third of U.S. consumers who are not served by RTOs, these high costs reflect the challenges that face the U.S. power grid, which are ultimately paid for by American households and business each year. To estimate a national congestion cost figure that includes the one-third of the country that does not have transparent congestion pricing, one can scale the known RTO/ISO congestion costs in table 1 according to the peak load of the same regions and compare that to total U.S. load. Table 2 uses this peak load comparison to estimate that 60% of the country is covered by the six markets with transparent congestion cost data while 40% is not:

Table 2: Transparent Market Size in Relation to Entire U.S.


2016 Peak Load (GW)














% Covered


If it is assumed that congestion outside of these transparent markets is similar to congestion within them, dividing annual congestion costs totals from table 1 by .60 from the above approximates that annual U.S. transmission congestion costs totaled $6.2 billion in 2016, $6.8 billion in 2017, and $8.3 billion in 2018. This is likely to be a reasonable if not conservative estimate, as the price transparency and generally more favorable transmission expansion policies in the RTO regions should tend to reduce congestion in those areas relative to non-RTO regions. However, RTO regions have experienced more renewable deployment in recent years than non-RTO areas, which may somewhat offset those factors as renewable expansion tends to increase transmission congestion when it outpaces transmission expansion.

A closer look at the changes in congestion costs over the years identifies a few key drivers in congestion trends. ISO-New England, for example, found transmission expansion projects to be a major factor in congestion cost reduction. The ISO notes that 10 major transmission projects totaling $8 billion assisted in congestion cost decreases from over $250 million in 2002 to under $50 million annually starting in 2009, where congestion costs generally remained until an increase to $64.5 million in 2018.

Some of the transmission cost increases in 2018 can be attributed to the Bomb Cyclone in January 2018, which affected much of the Northeastern U.S. New York real-time congestion values, for example, increased from $79 million in the first quarter of 2017 to $202 million in the first quarter of 2018.

In PJM, congestion costs in the first half of 2018 tripled to nearly $900 million relative to a year earlier. This reflected that during the Bomb Cyclone event in January 2018, the low temperatures were far more extreme in eastern PJM than in western PJM, causing wholesale electricity prices in eastern PJM to be about three times higher than in western PJM. Specifically, during the Bomb Cyclone week, power prices in Virginia averaged about $222/MWh, versus $76/MWh in Northern Illinois. Greater west-to-east transmission capacity in PJM, and an ability to import more power from MISO, would have saved PJM consumers hundreds of millions of additional dollars during the Bomb Cyclone event alone.

Forecasting long-term congestion has proven to be a difficult task; however, there are a handful of signals that suggest congestion costs may continue to rise without any intervention. The first of these signals includes the projected $2.8 billion decrease in transmission investment from 2018 through 2021. This decrease, alongside the existing policy barriers associated with siting and planning regional and interregional transmission, may serve to reduce the amount of transmission built in the near future. The North American Electric Reliability Corporation (NERC) finds that while 10,017 circuit miles of planned transmission lines are expected to be completed in NERC assessment areas by 2020, this number drops dramatically by between 2021 and 2025 when only 1,248 circuit miles of planned transmission are expected to be completed.**

Transmission expansion reduces congestion by facilitating a more efficient transfer of load across the lines, especially in areas where congestion historically exists. The congestion-reducing abilities and other benefits of transmission expansion projects have been noted by a number of RTOs. In addition to the analysis from ISO-New England above, another retrospective transmission analysis from SPP finds that recent transmission expansion projects installed between 2012 and 2014 are expected to generate over $10 billion in net benefits for consumers and approximately $16 billion in production costs savings over the next 40 years. A comparison between total quantified benefits and the costs of transmission expansion results in a Benefit-to-Cost ratio of 3.5. Figure 2 below shows the benefits, as represented in the stacked column to the left, are expected to increase over time while costs, as represented in the orange columns, decline:

Figure 2: SPP Transmission Expansion Benefits and Costs from 2014-2023

SPP transmission

Additionally, one forward-looking PJM analysis finds that transmission enhancements approved between 2014 and 2023 will reduce costs to customers by over $280 million annually by alleviating congestion, in addition to the estimated congestion savings of approximately $100 million from the first four years of operation of five interregional projects. MISO has also estimated that the transmission upgrades currently underway in the region are expected to yield $12 to $53 billion in net benefits over the next 20 to 40 years, with congestion and fuel savings estimated to total between $20 and $71 billion.

With a decline in expected transmission investment on the horizon, renewable capacity on the other hand is expected to continue to expand. Renewables expansion without transmission expansion to facilitate integration onto the grid tends to increase congestion and renewable curtailment, which occurs when transmission congestion is so extreme that wind or solar plant output must be reduced. As shown below, wind curtailment increased earlier this decade in ERCOT, SPP, and MISO as wind additions outpaced transmission expansion. However, as those regions have since added transmission, congestion and wind curtailment has decreased.

Figure 3: Wind Curtailment and Penetration Rates by ISO

RTO wind

Additionally, the question remains of whether or not extreme weather events like the Bomb Cyclone are to be considered an anomaly or the new normal due to climate change. According to the National Centers for Environmental Information (NOAA), the frequency and cost of environmental disaster events has increased dramatically since the 1980s:

Figure 4: Environmental Disaster Events from 1980-2018

NOAA graphic.png

As extreme weather events increase in cost, frequency, and magnitude, major power system failures and instances of congestion are likely to increase as well without transmission expansion.


*For reference, the most recent public account of congestion costs in CAISO was reported by the U.S. Department of Energy to total $483 million in 2014. In addition, overall congestion costs on interties as reported by CAISO in the State of the Market reports were $92 million in 2016, $114 million in 2017, and $108 million in 2018.

**Note: The planned transmission projects that are expected to be completed by 2020 and between 2021-2025 are located in NERC assessment areas, which extend into Canada. Additionally, these numbers only include planned projects which “refers to projects where the line is included in a regional transmission plan, or where (a) permits have been approved; (b) a design is complete; or (c) the project is necessary to meet a regulatory requirement.” These do not include Conceptual lines which are “those that are in a project queue, but not included in a transmission plan, or where (a) a line is projected in the transmission plan; (b) a line is required to meet a NERC TPL Standard or powerflow model and cannot be categorized as “Under Construction” or “Planned”; or (c)projected lines that do not meet the requirements of “Under Construction” or “Planned.” See Annual U.S. Transmission Data Review.

Appendix A: Sources for Table 1 – Transmission Congestion Costs ($ millions) for RTOs from 2016-2018

ISO-NE (2017), 2016 Annual Markets Report, May 30, 2017,, p. 90.

ISO-NE (2018), 2017 Annual Markets Report, May 17, 2018,, p. 84.

ISO-NE (2019), 2018 Annual Markets Report, May 23, 2018,, p. 91.

Monitoring Analytics (2018), State of the Market Report for PJM, March 8, 2018, pjm-volume2.pdf, p. 503.

Monitoring Analytics (2019), State of the Market Report for PJM, March 14, 2019, pjm-volume2.pdf, p. 512.

Potomac Economics (2017a), 2016 State of the Market Report for the ERCOT Electricity Markets, May 2017, State-of-the-Market-Report.pdf, p. i.

Potomac Economics (2017b), 2016 State of the Market Report for the MISO Electricity Markets, June 2017, SOM_Report_Final_6-30-17.pdf, p. x.

Potomac Economics (2017c), 2016 State of the Market Report for the New York ISO Electricity Markets, May 2018, content/uploads/2018/06/NYISO-2017-SOM-Report-5-07-2018_final.pdf, p. 9.

Potomac Economics (2018a), 2016 State of the Market Report for the ERCOT Electricity Markets, May 2018, the-Market-Report.pdf, p. i.

Potomac Economics (2018b), 2017 State of the Market Report for the MISO Electricity Markets, June 2018, SOM_Report_6-26_Final.pdf, p. vi.

Potomac Economics (2018c), 2017 State of the Market Report for the New York ISO Electricity Markets, May 2019, content/uploads/2019/05/NYISO-2018-SOM-Report            Full-Report    5-8-2019_Final.pdf, p. 8.

Potomac Economics (2019a), 2016 State of the Market Report for the ERCOT Electricity Markets, June 2018, the-Market-Report.pdf, p. i.

Potomac Economics (2019b), 2016 State of the Market Report for the MISO Electricity Markets, June 2019, SOM_Report_Final2.pdf, p. vi.

SPP (2019), State of the Market 2018, May 15, 2019, 0report.pdf, pp. 6 & 176-177.

Appendix B: Sources for Table 2 – Transparent Market Size in Relation to Entire U.S

ERCOT (2016), 2017 ERCOT System Planning Long-Term Hourly Peak Demand and Energy Forecast, December 14, 2016,, p. 2.

ISO-NE (2016), “Net Energy and Peak Load by Source,” September 12, 2016, https://www.iso-

MISO (2017), 2017 Summer Resource Assessment, May 8, 2017,, slide 5.

NYISO (2017), 2017 Load and Capacity Data “Gold Book,” April 2017, Book.pdf/8f9d56cc-dc20-0705-ca19-52e35a535b44, p. 12.

PJM (2016), PJM Load Forecast Report, January 2016,, p. 3.

SPP (2017), State of the Market 2016, April 10, 2017,, p. 18.

U.S. Energy Information Administration (EIA) (2018), “Noncoincident Peak Load, by North American Electric Reliability Corporation Assessment Area, 1990-2016 Actual, 2017-2027 Projected,”

—–Jesse Schneider is a Research Analyst at Grid Strategies LLC

Natural Disaster Relief

Maggie Alexander, Smart Wires

Combatting natural disaster impacts with advanced transmission technologies

Over the past two months, Hurricane Florence ravaged the East Coast followed shortly by Hurricane Michael, causing widespread evacuations and leaving millions of people without power for an extended period of time. At the same time on the West Coast, wild fires ripped through California, Colorado and Montana – burning tens of thousands of acres and leaving many households without power. These natural disaster events and the many we will face in the future mean that our electric grid is increasingly vulnerable.

As climate change continues to intensify weather patterns, natural disasters (such as floods, hurricanes, wildfires, snow storms, and tornados) are becoming more frequent and more intense. Utilities are on the front lines – expected to maintain safety and reliability for their customers and workforce, alike. Keeping the lights on – or restoring power as quickly as possible in the event of an outage – requires extensive planning, tireless work and unending commitment.

Power providers are rethinking disaster management, especially when it comes to prevention, planning and adaptation measures. In California, recently passed legislation (SB 901) aimed to address wildfires, including key measures to move California toward better wildfire preparedness, response and resiliency. The law includes language to address a wide range of factors that contribute to extreme fire threat in California and mandates utilities to develop a wildfire preparation plan, including the tools and technologies they will utilize to address wildfire-related risks and impacts.

This all points to the conclusion that, in the face of increasingly destructive natural disasters, it is critical for utilities to have a variety of tools and resources available to keep the grid safe, resilient and reliable. Advanced transmission technologies, such as Dynamic Line Ratings (DLR), Topology Optimization and Advanced Power Flow Control, are highly valuable in these circumstances and belong in utilities’ toolkits. Each of these technologies now have mobile forms, which can be re-located and re-deployed quickly which makes them fundamentally different animals from traditional solutions that go through multi-year planning cycles.

Advanced power flow control pushes or pulls power away from overloaded lines and onto underutilized corridors within the existing transmission network and is quickly deployed, can scale to meet the size of the need, and is easily redeployed to new parts of the grid when no longer needed in the original location. Mobile platforms can be deployed in 8 hours. This mitigates numerous wildfire-related risks, such as reducing power flows in anticipation of hot, dry conditions; minimizing the impact of forced outages by limiting the load shed to areas requiring shutdowns for safety reasons; and increasing the speed of restoration efforts by quickly connecting customers and enabling system reconfigurations. These are just a few examples of the benefits that advanced transmission technologies can provide to address the negative impacts of natural disasters on the grid.

DLR is another advantageous technology that allows utilities to operate lines at higher power capacities based on actual weather conditions. While DLR technology offers utilities many economic benefits under normal operations, it also provides strong grid resilience benefits. During long-term substation or transmission line outage scenarios, DLR can enhance recovery by maximizing the utilization of surviving transmission assets. DLR may also be part of a system to limit or prevent cascade line outages and the potential system collapse such scenarios present.

Another valuable technology utilities to deploy is Topology optimization. Topology optimization acts as a “Waze” for grid operators, identifying grid reconfigurations to route power flow around overloaded transmission elements using alternative, underutilized routes. The reconfigurations are implemented through switching on/off existing high voltage circuit breakers, which can be done remotely and rapidly from control centers. Topology optimization has been used to successfully mitigate overloads during severe winter storms, heat waves, wildfires and other natural disaster conditions. Traditionally, operators identify reconfigurations based on their experience and knowledge of the system—a challenging task considering the grid complexity. With topology optimization, the technology performs the identification automatically and quickly, enabling operators to better utilize the grid.

Beyond natural disaster support, advanced transmission technologies can help utilities optimize their existing transmission grid by allowing hidden transmission capacity to be identified and utilized. Widespread deployment of these technologies could reduce the cost of electricity to consumers by as much as $2 billion per year while improving reliability and resiliency.

There are numerous reasons why advanced transmission technologies belong in every utility’s toolkit, including as utilities plan for, address in real-time and recover from natural disaster events. As the West Coast wildfires continue to burn, and as the East Coast braces itself for a long hurricane season, the time is now for utilities to ensure they are familiar with and ready to deploy advanced transmission technologies.

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Maggie Alexander is Director of the Western Region at Smart Wires, a modular, scalable, redeployable power flow control technology company based in Northern California.