How much capacity is on the transmission grid? The answer is that there is more than you think. The reason is that transmission system operators build a substantial reserve capacity margin based on conservative assumptions and worst-case scenarios. A transmission line's true maximum transfer capability can vary significantly depending on the ambient weather conditions. Higher temperatures, wind speed, and direction significantly impact the transmission capacity.
Many utilities use transmission line ratings that reflect broad average temperatures and are set so that operators can guarantee the available capacity on the network. In most network regions, ratings are set on a seasonal basis or even just twice a year. To extract more capacity from the existing infrastructure, US regulators have mandated that system operators increase the frequency of their capacity ratings. The goal is to utilize transmission grid capacity more efficiently and lower consumer costs.
Under Federal Energy Regulatory Commission (FERC) ruling 881, current weather conditions improve the accuracy of line ratings allowing increased throughput in many cases. The ruling passed in late-2021 requires Independent System Operators (ISOs), Regional Transmission Organizations (RTOs), and Transmission Owners (TOs) to apply hourly ratings during daylight hours to consider solar heating. At night, the frequency of rating calculation is longer than during the day but still assessed much more frequently than in the past. This order of magnitude improvement in the frequency of rating assessment based on almost real-time conditions allows operators to determine the short-term rating capacity more accurately. Typically, this allows the transmission of more energy across the network. As electrification increases, this becomes even more important.
The FERC order covers the BES (Bulk Electric System), transmission above 100 kV, sub-transmission, and some distribution.
Responding to real-time weather conditions is an issue that is likely to become more significant for resiliency in the face of the increasingly extreme weather patterns associated with climate change, but it has significant cost implications now.
According to MISO Energy figures, using Ambient Adjusted Ratings (AARs) in the summer of 2020 would have produced $100 million in savings across their service area alone. Those savings come from not buying expensive local thermal capacity because they cannot import more wind energy from the West. Grid constraints are a significant price driver for MISO Energy, just one of the many market operators across the US.
Improving line rating performance
Beyond AARs, dynamic line ratings (DLRs) bring another level of sophistication to line ratings. In a DLR setup, equipment connects to the network control system that measures the ambient temperature and other weather conditions. Again, like AARs, this information helps determine the available capacity. An AAR approach can include DLRs, but they require additional capital investment in equipment. For AAR, weather service information is the basis for derived weather data without hardware investment. There, however, is a need for investment in software and resources used in developing weather data. Another distinguishing factor is that DLR systems measure real-time capacity, but in US energy markets, the line ratings are typically based on forecasts of future temperature and weather.
The final FERC ruling does not mandate the adoption of DLRs that can account for these additional weather factors, like wind speed. However, the FERC rule requires transmission systems and market operators to establish procedures that allow transmission owners to use dynamic line ratings. Such dynamic line ratings may bring additional capacity benefits, and regulators are keen to explore the potential to squeeze still more from the grid using dynamic line ratings.
Certain European entities are already using that approach, even within the distribution sector. For example, this technique provides an alternative where it is difficult or impossible to build another transmission line to reinforce the grid. Instead, grid operators use DLR technology to increase regional capacity.
Even so, the complexity of the U.S. energy market and its related transmission system meant the regulation took considerable time to develop. With the ruling in place, the more innovative and proactive transmission operators are already ramping up the necessary tooling and staff in their energy management systems (EMS) to implement FERC 881 on time. Transmission providers must implement the ruling no more than three years from the compliance filing due date, in any event, no later than 12 July 2025.
Putting data in play
Although the FERC 881 ruling will not come into force for around 30 months, this change represents several significant challenges for network operators. There are numerous functions that FERC 881 could potentially impact, and transmission operators need to invest in improving processes, addressing related operational issues, and potentially improving computer infrastructure as well.
At the most basic level of implementation, they must retrieve and process much more data and determine if the data is valid. They need to build checks and balances. Transmission companies must share their transmission line ratings and methodologies with their respective RTOs, ISOs, and market monitors. From the ISO perspective, they need to take all this information from all the different transmission owners across their region and quickly execute market analysis for up to 10 days or as little as five hours for the real-time markets.
Progress is being made; for example, Midwest ISO (MISO) is proposing an OpenAPI-based application to transmit forecast AARs that will be known as Transmission Ratings and Operating Limits (TROLIE). It will support the submission of up to 240 hours of rating data and will be used in conjunction with a temperature look-up table and a MISO weather source. Meanwhile, California ISO (CAISO) is proposing to enhance its Transmission Ratings (TR) application with new user interfaces to submit and retrieve AARs as well as with enhanced validation.
It is an added layer of complexity in what is already quite a complex challenge, and many players in the sector are still trying to figure out what they need to do. Many transmission utilities run Energy Management Systems from vendors like GE, Siemens, or Aspen Tech, so they already have the data they need for the real-time system. However, the methodology for collecting the data by the real-time system and flows between the various stakeholders is still a major uncertainty. Some vendors have their solution, and a few transmission operators are already sending this data to the ISO, but it has yet to be fully revealed how this data will establish the ambient line ratings for every single transmission line within a region.
In any event, even with the deadline over a year away, there is the real danger that if utilities don't take timely action, they will be put under much more pressure when 2025 comes around. Mistakes occur with rushed and ill-considered implementations.
Utilities with these new structures can run through the process and see where problems can arise and the best way forward. PSC is certainly able to support this effort by exploring not only where weaknesses exist but also where the opportunities lie, for example, from utilizing the information transmission operators may already have to compute and understand new limits. Utilities need to be aware that this change is happening, though, and they need to understand that implementing the necessary systems is a winning scenario. By more accurately determining actual transmission capacity based on real-time ambient conditions, they can extract considerable value for both them and energy consumers. It's like a magic trick. That grid capacity was always there, just hiding in plain sight.
