Measuring Electric Demand

The measurement of demand is fundamental to most electric rate structures. It is a tool that allows a utility to differentiate capital cost requirements for serving customers of varying usage patterns. By measuring and billing for demand, the utility can assign costs more fairly to customers.

As opposed to gas utilities, the demand interval for electric utilities is extremely short, usually 15 or 30 minutes. It is not an instantaneous measurement, but an average of discrete measurements over time. If, for example, a facility experienced a rate-of-use pattern of 200 kW for 5 minutes, 300 kW for 5 minutes, and 700 kW for five minutes, a 15-minute demand interval meter would register an average demand of 400 kW. The demand recording meter would log 400 kW and reset only when a higher level of demand was reached. Sometimes, utilities set peak demand by averaging peaks of a few demand intervals over the billing period.

Many customers use demand monitoring and loadshedding techniques to minimize the impact of peak demand billing. These facilities often attempt to synchronize their operations with the utility demand interval and use intermittent load shedding to reduce their average rate-of-use during intervals when a large surge of power is required for a period less than the full demand interval.

From the utility perspective, this load shedding technique may partially defeat the purpose behind demand metering, which is to charge for peak capacity requirements. A sliding demand interval is sometimes used to more accurately measure the impact of peak demand. With a sliding demand interval, for example, a 15-minute demand interval may be broken into smaller intervals of 5 minutes. These smaller intervals are averaged and then added together, as in the previous example, to set the peak demand for the entire 15-minute interval.

In some cases, utilities simply use smaller demand intervals, starting as low as 5 minutes. More common, however, is the use of the typical 15 or 30 minute interval with a clause in the rate schedule that states that in cases of rapidly fluctuating loads or other special conditions in which the established demand measurement time interval does not equitably compensate the utility, demand may be based on the peak for a shorter period.

Traditional rates often use only one peak demand measurement for billing. Some rates call for demand measurement only in certain peak periods. The rationale is that individual facility peaks in utility off-peak periods have no real impact on capacity requirements. TOU rates, however, measure peak demand in several periods. Demand charges may be set at a different rate for each period. For example, peak demand might be billed at $20/kW during peak periods and $5/kW during off-peak periods. In some cases, off-peak period peak demand may only be billed for the portion that exceeds peak period peak demand. This is referred to as excess demand billing.

Integrating Power Factor into Demand Billing

Utility generation is measured in volt-amperes (VA), or apparent power, while most customer meters are measured in watts (W), or real power. In alternating current (ac) circuits, watts (power) are equal to volts (potential) times amps (current) only when the wave-forms of voltage and amperage are in phase. This is an ideal condition that does not exist in electric distribution systems. Many types of equipment, such as induction motors, require more apparent power than the amount of real power consumed because their inductive impedance causes current and voltage to be out of phase.

The difference between apparent power (VA) and real power (W) is called volt-amperes reactive (VAR). This is the component of VA that circulates back and forth between the utility and the equipment, but is not consumed by the load. It is, however, partially consumed by distribution losses.

Power factor (PF) is the ratio of W to VA. A facility with a PF of 0.75, requiring the same wattage as another facility with a PF of 1.0, for example, will be more costly to serve, because the utility will require one-third more system capacity (1.00 W/0.75 PF = 1.33 VA) to serve the facility with the PF of 0.75.

To more accurately allocate capacity costs through demand charges, some utilities measure and bill demand charges based on kVA rather than kW. This shifts the cost for maintaining non-productive capacity, or a PF of less than 1.0, to the customer and acts as an added incentive to improve the facility's PF.

Many utilities simply institute a penalty for a lagging PF. For every increment below a required minimum PF, a charge is levied against the facility. The minimum allowable PF is typically in the range of 0.80 to 0.90. Many utilities establish this penalty on the rate schedule, but often do not invoke it.

Another way utilities establish a PF penalty is to specify a maximum free kVAR as a percentage of the maximum kW of demand. Utilities then bill for all metered kVAR above this level. There are several other ways to build PF into billing, such as increasing the peak demand measured by a certain percent for every percent the PF is below a specified level.

Many utilities currently do not penalize for lagging PF, and many that do only impose modest penalties. In those cases, from the customer's perspective, the advantages of a higher PF and the benefits of investment in capacitors and other higher PF equipment are savings from reduced internal line losses, down-sized equipment, and avoided billing penalties. To encourage such customer actions, utilities attempt to set PF penalties at levels that will have sufficient economic impact. Refer to Chapter 24 for a detailed technical description of PF.

Metering Point and Transformer Ownership

Another factor that is often an element in electric utility rate structures is metering point and transformer ownership. Utility distribution voltage is almost always greater than the voltage required inside a facility. The main transformer brings the voltage down to a suitable level for the service entrance at the facility. Typically, the utility owns the transformer and meters usage on the customer (low-voltage or secondary) side of the meter.

These factors will figure into rate design. If the customer owns the transformer, the utility saves on capital and maintenance costs and can pass those savings on to the customer. If power is metered on the high side of the transformer, the utility saves on transformer-related power losses and can pass those savings on to the customer to compensate for losses now occurring on the facility side of the meter.

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