Executive Summary

Electricity storage can be used to reduce the cost incurred for electric service. The benefit can be significant. There are two variations on this value proposition. One involves electricity end-users that pay “time-of-use” (TOU) electric energy prices. That is, the price paid depends on the time that it is purchased. Second, commercial and Industrial end-users that use a significant amount of electricity qualify for electrical service pricing that includes both a) TOU energy pricing and b) demand charges. Demand charges reflect the end-user’s maximum power draw rather than energy use. Storage used to manage an end-user’s bill could also be used to provide the same functionality as an uninterruptible power supply (UPS). It could be used by the electricity end-user to time-shift energy from on-site photovoltaics (PV) or other generation system, or the storage could assist with integration of other nearby PV systems. As the electricity market structure evolves and as pricing becomes richer, the storage could also be aggregated and operated in concert with other distributed resources as a very flexible and reliable resource.

Discussion

Time-of-use Energy Cost Management

Utility retail electricity end-users who are subject to or eligible for time-of-use (TOU) electric energy pricing can use storage to reduce electricity-related cost by what could be called retail energy time-shift. The energy time-shift involves storing of energy is stored when demand for energy and thus price for energy is low. That energy is used later, when demand and price are high, instead of purchasing high priced energy.The benefit is the difference in price between on-peak and off-peak less the cost for energy losses during the storage charge-discharge cycle.

Pacific Gas and Electric Company’s (PG&E’s) Small Commercial TOU A-6 tariff is a good example. As shown in Table 1, the highest (peak) price occurs during the “summer” months of May to October, Monday through Friday. Commercial and industrial (C&I) electricity end users whose peak power requirements are less than or equal to 500 kiloWatts (kW),or 50,000 Watts, qualify for the A 6 tariff. As shown in Table 2. Summer on peak energy prices are quite high, at 44¢ perkiloWatt-hour (¢/kWh) while the price at night (13.7¢/kWh) is about 1/3 of the on peak price. Note also that during Winter there is no “on peak” price in the A-6 tariff.

Instead the highest price is characterized as “part peak” and it is maximum energy price during winter of 15.2¢/kWh is also about 1/3 of the summer on peak price.

Demand Charge Management

Commercial and industrial (C&I) end-users that use a significant amount of electricity qualify for electrical service pricing that includes both TOU energy pricing and demand charges. Demand charges reflect the end-user’s maximum power draw rather than the amount of energy used. (See {The Physics and Practicalities of Energy and Power} for details.)

To reduce demand charges, end-users can use electricity storage to purchase and store energy at night when the TOU energy price and demand charge are low. The stored energy is then used when the TOU price and demand charge are high (typically week-day afternoons, especially during summer). Note that the benefit is two-fold: 1) energy time-shift reduces TOU energy cost and 2) reduced maximum power draw during peak demand times.

Similar to TOU energy charges, demand charges are typically assessed based on the time-of-day, day-of-week and season. The highest demand charges tend to apply mid-day on weekdays during the “summer” months (May – October), and low demand charges apply at night, during weekends and the six “winter” months (November – April).

Unlike TOU energy prices, the demand charge is assessed based on demand during any 15-minute period, during times of the day and months when demand charges apply. Said another way, the demand charge is assessed based on the highest demand measured during any 15-minute period during specific times and days within a given month. So, for an end-user to avoid the demand charges, their power draw must be reduced during the entire (all hours within) the demand charge period.

Consider an extreme example. Nearly every afternoon during one summer month, an end-user’s peak demand is 200 kW. However, during one 15 minute period the end-user’s demand is 300 kW. So, even though the maximum demand was only 200 kW for almost the entire month, the demand charge is assessed based on the higher 300 kW demand. Given the foregoing, it is helpful to note that demand charges are usually denominated in units of $ per kW per month, or $/kW-month.

Consider the demand charges shown in Table 3 for PG&E’s “E-19” tariff with both TOU energy prices and demand charges. The summer monthly on-peak demand charge is $14.70 per kW of demand that occurs from 12:00 noon to 6:00 pm during weekdays during each of the six summer months. (Note that PG&E refers to on-peak times as maximum peak.)

Note that, as shown in Table 3, for PG&E’s E19 tariff, often TOU energy prices and demand charges are different depending on the voltage-level of the service to the end-user (see sidebar). The price for electrical service at higher voltages is lower because it costs less to serve those customers. Note that the most dramatic difference is in TOU energy prices.

So the most significant demand charges assessed are those based on the maximum load during the peak demand period in the respective summer month. It is somewhat common to also assess additional demand charges for part peak (partial peak) and in some cases off-peak times.

Part peak demand times are usually during times such as a) ”shoulder hours” (i.e. during summer weekday mornings and evenings), b) summer weekend days, c) winter weekdays and d) holidays. For the example in Table 3, the part-peak demand charge is $3.43/kW-month during summer and $0.21/kW-month during winter.

Some tariffs also include off-peak demand periods that encompass nights and weekends.

One other type of demand charge could be called “maximum,” or “anytime” demand charges. (In the PG&E example, those demand charges are referred to as “maximum” demand.) Though details vary, typically they are assessed based on the maximum demand without regard to what time the demand is present. In some cases they reflect the maximum demand during any time within a given month and in other cases they reflect maximum demand during any time during the entire year. In the example, PG&E charges for maximum demand within any 15-minute period during the entire month. The latter is important for storage because maximum demand charges apply at any time, including at night when most storage charging occurs: if storage charging increases the facility’s maximum or anytime demand then the amount paid for the maximum or anytime demand charges offsets some of the benefit for reducing demand during times when the higher peak demand charges apply.

Consider the simple example in Figure 1 which depicts the following scenario: A small manufacturing end-user whose demand is nearly constant at 1 MW during all hours of the day. At night, when the TOU energy price and the demand charge are low, the manufacturer stores energy for use when TOU energy price and demand charge are high.

In the example, net demand doubles at night as a) low-priced energy is stored at a rate of 1 MW b) while the “real-time” demand for operations requires another one MW of power. During peak demand time (12:00pm to 6:00pm), storage discharges (at the rate of 1 MW) to serve the end user’s direct demand of 1 MW, thus eliminating the real-time demand on the grid. So, if a maximum or “anytime”demand charge applies, it would be assessed on the entire 2 MW (of net demand) used to serve both load and storage charging. In the example, storage is 80% efficient. To discharge for six hours, it must be charged for 7.5 hours (6 hours ÷ 0.8 = 7.5 hours). The additional 1.5 hours of charging (relative to the six hours of discharging) is required to offset energy losses.

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Source: http://energystorage.org/energy-storage/technology-applications/end-user-bill-management