Many of the nation’s major high power electric transmission owners have formed entities called regional transmission organizations (RTOs) and independent system operators (ISOs) to manage the grid within their defined boundaries. Among other things, the RTOs and ISOs are responsible for maintaining the grid’s reliability as consumer demand rises and falls. The RTOs and ISOs do system-wide planning for the future and operate the grid in real time to ensure that sufficient power generation, transmission lines and other grid resources will be available to maintain reliability and keep the lights on.
One of the main ways grid operators maintain reliability is to forecast future “peak demand” periods – for example, especially hot summer days or especially cold winter days when demand for electricity is at its highest. Since predicting future demand is an inexact science, and extreme weather and unforeseen outages occur, grid planners add a cushion of additional generation above the amount needed to meet predicted peak demand, known as a “reserve margin,” into their planning assumptions. The reserve margin is sufficiently large to account for hot or cold weather conditions and unforeseen outages that could increase demand beyond predicted levels. It typically is based on a “one day in 10 years” standard, under which the expected frequency of having to curtail consumer electricity consumption to prevent larger blackouts should be no greater than one day every ten years, typically when extreme weather conditions and unforeseen outages occur. In practice, the reserve margin is at least 15% higher than the forecasted peak demand. Grid operators then plan to ensure that they have enough power plants and transmission capacity to meet their peak demand plus the reserve margin.
To be sure, the Polar Vortex was an extreme weather event. PJM, the nation’s largest grid operator with nearly 190,000 megawatts (MW) of power generation across 13 states in the Mid-Atlantic and Midwest, set 8 of its top 10 winter peak records in its history, and called the weather extreme (a “1-in-10 event”).[1] MISO, the nation’s second largest grid operator with 175,000 MW of generation in its Mid-Atlantic and South market, set a new peak demand record on January 6, when much of its region experienced the coldest temperatures in 20 years. Nevertheless, in these regions and everywhere else, and despite much many coal and gas cold weather-related power plant failures, the grid operators kept the lights on throughout the entire winter, they maintained the required reserves nearly the entire time, and there was no need to curtail consumer electricity consumption.
Another way that the grid operators plan for sufficient power capacity and reliability in the future is to consider the impact of public policies on the electric grid.[2] State renewable portfolio standards, the U.S. EPA’s Mercury and Air Toxics (MATS) rules, and carbon pollution standards for new and existing power plants, are the types of policies that the grid operators consider. The grid planning process accounts for these and other policies, along with power demand beyond what is expected in normal conditions, to help ensure continuing grid reliability.
[1] See also PJM’s response to FERC’s January 8, 2014, data request, at 6.
[2] Most RTOs and ISOs have been factoring public policies into their planning equations for some time. In 2011, the Federal Energy Regulatory Commission, which regulates transmission owners and operators including the RTOs and ISOs, issued Order 1000. Among other things, the Order requires any transmission owners and operators that were not already factoring public policies into their assumptions to do so going forward.
