The price consumers pay for electricity may vary from what a neighbor, shop owner, or others might pay. Utility rates are composed of many components and vary by customer type (residential, commercial agriculture, etc.), amount of energy used, income level, location, and other factors. Until recently, the time of day a customer uses energy has not affected a customer’s bill, even though the cost to produce and deliver electricity varies significantly throughout the day.
Traditionally, residential utility rates have a fixed price per-kilowatt hour (kWh) based on the seasonal average cost of providing electricity. The primary determinant of a residential customer’s bill is the amount of energy used. However, the cost to supply electricity varies significantly by time of use. Throughout the day, wholesale prices of electricity (the price utilities pay to purchase or generate electricity) reflect the actual real-time cost of supplying electricity. One major factor contributing to the real-time cost is the demand for electricity. During work and school hours, when most of the population is away from home, residential demand for energy is low. During morning and early evening hours, residential demand for energy is higher as customers get ready for the day or return home from work and turn on electronic devices, lighting, and cook meals. This time period is referred to as “peak” demand.
Utilities face many challenges meeting peak demand. Over the last 20 years, distributed energy resources such as solar and wind generation have grown exponentially. According to the US Energy Information Administration (EIA), in 2017 solar and wind electricity generation combined supplied 8 percent of all US electricity, at least 10 percent of all electricity in 18 states, and over 20 percent in nine states.1 Solar and wind resources by their nature are intermittent, generating electricity when the sun is shining and wind is blowing, and not necessarily when demand for electricity is highest (e.g., summer, late afternoon/early evening) causing rapid spikes in electricity demand, supply, and wholesale market prices.
Additionally, the ratio of annual peak hour electric demand to average hourly demand has risen over the past 20 years. In New England, the peak-to-average demand ratio has increased from 1.52 in 1993 to 1.78 in 2012.2 Utilities either build or procure reserve capacity to meet spikes in demand. On average, customers use less than half of the available generation capacity throughout the course of a day,3 resulting in higher than necessary electricity charges to support the utility and independent power producer investment in generation required to maintain this excess capacity. Rapid spikes in energy demand present challenges for grid operators, and the energy resources available to rapidly increase or decrease power output are often expensive and produce higher amounts of harmful emissions. Providing customers with price signals can reduce large spikes in electricity demand at critical times, such as hot summer days.
One potential solution to address these challenges is to offer customers time-varying rates (TVRs). TVRs provide customers price incentives to reduce electricity use at peak demand times. By pricing electricity closer to the actual cost of producing it, all consumers, from large commercial and industrial users to the average residential user, are incentivized to reduce their electricity use during the highest demand periods, reducing the need to build excess capacity and lowering costs and electricity prices for all users.
TVRs come in a few different forms, ranging in complexity, from the simplest time-of-use (TOU) rates to more complex programs such as critical peak pricing (CPP) and peak time rebates (PTRs) to the most complex and arguably most difficult to implement, realtime pricing (RTP).
TOU rates offer different prices for peak and non-peak energy use. Prices are lowest overnight and on weekends and holidays, when overall demand on the electricity system is lower. CPP has a lower fixed rate most days, with certain days designated as “event” days (usually identified 24–48 hours in advance) where elevated rates are charged. The reverse, PTRs, have a normal fixed rate but offer rebates for reducing use during the event days. Usually, utilities identify 12–20 “event” days, generally the hottest summer days, to reduce demand on those days where electricity demand is highest. RTP is the most complex TVR structure, with hourly prices determined by day-ahead market prices or real-time spot market prices for electricity. Figure 1 demonstrates how each pricing structure aligns with actual load, including on event days where load is higher than average at peak times.
Each pricing structure has benefits and drawbacks that must be considered by utilities looking to implement TVRs. Table 1 demonstrates the differences between the TVR structures and the benefits and disadvantages of each from a customer, grid operator, and utility perspective.
Aweh, Amanda and Goldstein, Adam (June 2019). “Alleviating Peak Demand Challenges and Improving Customer Affordability With Time-Varying Rates” Natural Gas & Electricity 35/11, ©2019 Wiley Periodicals, Inc., a Wiley company.