Billing Factors

Utilities use a number of billing factors in their rate structures. Some of these factors are clearly stated in all utility bills, some are considered in every transaction but not necessarily identified separately in all bills. Others are considered and applied, depending on the particular characteristics of the utility or the customer class under a given tariff. The most common billing factors are:

• Basic, or customer, service charge. A fixed charge is assessed to each customer based on costs related to connection, metering, billing, service maintenance, etc. Typically, basic service charges are greater for rates designed to serve large users because of the greater cost associated with larger pipes, regulators, and metering equipment. Facilities with multiple services under the same rate may have summarized billing with only one basic service charge. Facilities with multiple services under different rates will often pay a basic service charge for service under each rate.

• Minimum charge. This is the lowest bill a customer is required to pay for service on a given rate schedule during each billing period, regardless of actual usage. In most cases, this is equal to the customer charge. However, for larger customers, it can include other charges, such as demand charges or charges established by individual contracts between the customer and the utility.

• Commodity charge. This is a charge based on energy usage or the number of energy units actually consumed by the facility during each billing period. Commodity charges generally include the utility's incremental operating costs, plus some contribution to fixed costs.

— Common natural gas billing units are: cf (cubic feet), Ccf (hundred cubic feet), Mcf (thousand cubic feet) and therm (100,000 Btu or 105,480 kJ). While a therm is a specific quantity of energy, a cubic foot of gas has varying Btu or kJ levels. Typically, 1 cf of pipeline quality natural gas contains about 1,000 Btu, but this can vary by several percent, depending on the specific source of natural gas.

— Common electricity billing units are: kilowatt-hours (kWh) and kilovolt-amperes (kVA).

• Demand, or maximum level of service, charge.

This charge is based on a customer's peak rate of consumption and takes into account the utility's required investment needed to serve that load. Measurement of demand, or rate-of-use, is somewhat like a car speedometer. However, a demand meter does not measure rate-of-use instantaneously, but averages it over a discrete utility-selected interval. This interval, or "demand window," for electric utilities is usually 15 or 30 minutes. The interval for gas utilities is usually the highest daily consumption or, in some cases, it may be measured as the peak usage for one month. Demand can be measured in multiple-use periods, and charges can be differentiated for each use period.

Demand charges are assessed in several different ways. They may vary by season, TOU, and level of use:

— Seasonal variation produces greater charges for peak demand during months in which the utility experiences its highest peak demand. With gas utilities, demand charges are often applied only in winter months.

- TOU variation can be applied in several different ways. In many cases, demand is only measured by electric utilities during a peak period. In other cases, demand is measured during several different periods, such as peak, shoulder, and off-peak. The charge per unit of demand varies with each period, with peak charges being the highest.

- Level-of-use variation produces different charges for increasing blocks, or steps, of demand. For example, the first 500 kW or 500 Ccf of demand will be billed at one rate, the next 1,000 kW or 1,000 Ccf of demand billed at another rate, and so on.

— Minimum demand charges are sometimes set at a given level for each rate tariff. In some cases, they may be based on a percentage of the customer's connected load or main transformer or gas meter size.

• Ratchet adjustments. A demand ratchet adjustment sets minimum monthly billable demand at a certain percentage (usually 60 to 100%) of the highest month's peak demand in a given preceding period (typically 11 or 12 months). When the utility has a severe summer or winter peaking system, the ratchet may be based on the highest month's peak demand only in the peaking season. The minimum monthly demand charge assures the utility of cost recovery for investment in peak capacity, even if a customer does not require that peak capacity in a given month. In some cases, this preceding period may be as long as several years or for the life of a contract. Ratchets serve as a mechanism to approximate the true cost of service and to distribute that cost impact on the customer over several months.

Consider the example of an electric utility with an 80% demand ratchet adjustment. If one month had a peak demand of 2,000 kW and the next 11 months had a peak demand of 1,000 kW, each of the proceeding 11 months' demand charges would be based on 80% of the 2,000 kW figure, or 1,600 kW The result would be an additional annual billable 600 kW per month, totaling 6,600 kW additional billable kW over the next 11 months. Figure 21-1 provides an example of the impact of an 80% ratchet on an 11 month rolling basis.

The reasoning behind ratchet adjustments is that monthly demand charges alone do not sufficiently compensate the utility for the impact of a customer who sets a large peak once per year rather than every month. The utility must have sufficient capacity to meet the annual highest peak hour of demand at all times and must incur the cost of building or securing contracts to purchase the needed capacity. A customer that does not need that peak demand every month must still pay for a large portion of the demand in order to reserve it for the peak month.

• Energy adjustment charge (EAC). This mechanism is designed to pass increasing or decreasing fuel costs per billable unit directly to the customer. EACs may vary on a monthly, quarterly, or annual basis. It is normally based on a 12 month rolling average of fuel costs and is used to maintain rate stability between

Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Peak Season

| Actual demand

Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Peak Season

| Actual demand

| | Difference between minimum billed demand due to ratchet and actual demand

Fig. 21-1 Impact of 80% Demand Ratchet.

Actual Fuel Cost

Actual Fuel Cost

Month

Fig. 21-2 Representative Illustration of FAC Charge to Monthly Electricity Charges.

Month

Fig. 21-2 Representative Illustration of FAC Charge to Monthly Electricity Charges.

rate-case proceedings. Common terms used to express EAC are: fuel cost adjustment (FCA), fuel adjustment charge (FAC), purchased power adjustment (PPA), purchased gas adjustment (PGA), and levelized gas adjustment (LGA). Figure 21-2 is an illustration of a fuel adjustment charge to monthly electricity charges.

• Other adjustment charges. A utility bill may also include additional adjustment charges. Many electric companies have a nuclear capacity adjustment or nuclear plant decommissioning charge. Some companies also have conservation adjustment mechanisms or sales adjustments. Gas utilities have shrinkage or retainage charges. These are applied as a percentage increase to transported gas volumes at delivery points for transportation customers. This charge reflects lost or unaccounted for gas volumes that arise from the transportation of gas over the LDC's pipeline network.

• Taxes and fees. These are added charges that the utility bears as operating expenses and passes on to individual customers. These may include gross receipt taxes or sales taxes. They may also include surcharges for special regulatory commission approved programs that are added to the bill. Such charges may be shown on the bill as itemized charges, or they may be embedded in the derivation of other utility charges and are thus not easily spotted on the bill.

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