Common Electric Rate Schedules

Electric rates use a mix of various rate components, and rate schedules include one or more of the rate design strategies discussed earlier. These components typically consist of an energy charge, a demand charge, a ratchet clause, a fuel adjustment charge, surcharges for factors such as conservation or nuclear plant decommissioning, power factor charges, and taxes. Often, rates are offered to customers who meet specific criteria, such as type of facility or type of equipment used. Some of the most common non-residential electric rate schedules include:

• General service (GS) rates. GS rates are typically used by most small commercial customers. Rate design may include block rates, seasonally differentiated rates, and demand charges. Generally, these rates place a greater emphasis on usage than on demand and are less differentiated than large customer power rates. In some cases, these rates are available without demand metering, using higher usage charges instead. Typically, availability of GS rates is limited to customers whose demand does not exceed a particular specified level.

• General service TOU (GST) rates. GST rates are generally used by small C&I customers with multiple shift operations. They commonly consist of peak and off-peak periods and often register peak demand only during the peak period. They are not time-differentiated as much as are large customer power TOU rates, but they do allow customers to benefit from lower costs for extended use in off-peak periods. They also are often used by customers with electric heat or some type of thermal storage. Rate design may include block rates and seasonally differentiated rates.

• General service heating (GSH) rates. GSH rates are common end use-specific rates. Typically, they are general service rates that are available only to electric heating customers whose heating related usage makes up a certain minimum portion of total usage. They are often used by summer-peaking utilities to build winter load. They have a greater degree of seasonal differentiation than standard general service rates, with depressed winter rates compensating for extensive usage. They also may have a TOU component to allow for the use of domestic hot water or heating thermal storage.

• Street lighting (SL) rates. SL rates are end use-specific, typically offered to states, cities, or other municipalities, and sometimes to large campus-type facilities.

• Large power (LP) rates. LP rates are the traditional rates offered to larger CI&I customers and virtually always include monthly or fixed-contract demand charges and may use rate blocks and seasonal differentiation. Typically, the design is somewhat similar to general service rates, except that there is usually increased emphasis on demand charges.

• Large power TOU (LPT) rates. These rates are becoming more predominant for large CI&I customers. Typically, they consist of two, three, or four rate periods, such as peak, shoulder, or off-peak. They may register demand only during peak or all rate periods or have fixed-contract demand charges. Off-peak usage may be handled with varied charges or as peak usage with charges in the off-peak periods only for demand in excess of peak demand. Usage charges are varied by rate period. Rate design may include block rates and seasonally differentiated rates.

These rates are more stratified than traditional large power rates. They are advantageous for facilities with high load factors and extended hours of operation, which can offset costly peak usage with inexpensive off-peak usage. They also are attractive for facilities that use thermal storage or some type of peak-shaving technology.

• Real-time pricing (RTP) rates. Typically, RTP rates do not have a demand component. Instead, kWh may be priced by the individual hour or, in some cases, charges may be fixed, but the hours in which different charges are applied will vary. In either case, the utility communicates these varying costs or hours of application on an hourly, daily, or weekly basis to customers. Often, these rates are used by facilities with alternative energy sources in place or with the ability to shed loads on a regular basis. RTP rates may become increasingly common as electric rates become even more sensitive to market competition. As opposed to demand-based TOU rates, RTP rates are thought to more closely reflect the actual discrete price of power at a given hour or even minute.

• Transmission (T) rates. Currently, T rates are typically used for special cases, such as wheeling, in which power is either bought from or sold to a party other than the local utility. Rate design is based on the use of the utility's transmission facilities only. Under the National Energy Policy Act of 1992 (EPAct 92), electric utilities are required to more clearly define transmission rates, as well as identify available capacity and known restraints. Over the long term, it is anticipated that the advent of retail wheeling and the further unbundling of electric rates will result in transmission/distribution rates being available to all customer classes.

• Interruptible rates (IR). These rates and rate riders are designed for customers that have blocks of load (or all of their load) that can be dropped at any (or almost any) time. Commonly, this includes the use of standby generation as a load-shedding technology. Interruptible rates may be designed with a set rate break on demand or usage, or may consist of a flat annual or monthly fee paid by the utility to the customer with a specific payment rate for each period of interruption. Rate design includes different steps, or levels, of availability, with 100% availability receiving the most beneficial treatment. Rates also vary with notice period. The shorter the notice needed for an interruption, the higher the rate discount.

Further refinement of interruptible rates involves differentiation of services between non-firm electricity sales and non-firm transmission/distribution services. Facilities with on-site energy alternatives can benefit from the ability to withstand sales and transmission interruptions. Facilities with alternative electricity purchase options, via retail wheeling, can benefit from the ability to withstand sales interruptions, but may still require firm transmission/distribution services.

• QF rates and rate riders. Many utilities have special QF rates or rate riders for self-generators. In some cases, these are elective rates (or riders), while in other cases, they are required. These riders often include rate designs that emphasize high peak demand charges, such as TOU rates. These special QF rates also usually include mandatory provisions that require the self-generator to purchase a form of backup services to provide a payment stream to the host utility for providing a reliability service by virtue of the physical connection. The provision of backup service is generally desired by the customer to prevent interruptions. The charge for backup is supported by the argument that a rate recovery mechanism is needed to prevent self-generating facilities from taking advantage of utility capacity supported by other rate-paying classes, in the event of an outage of self-generation equipment, or during periods of planned system maintenance or for purchasing supplementary power.

Rate restrictions are often put in place to limit rate options available to self-generators. A self-generator forced to be on a highly demand-sensitive rate with a ratchet penalty clause could end up with nearly a full year's worth of demand charges for a single outage. This is often considered excessive recovery. On the other hand, a self-generator allowed to be on a low-demand, highly usage-sensitive rate may pay a minimal amount, which is often considered insufficient cost recovery.

• Standby rates. These rates are offered to self-generators requiring power from the utility when their own or alter native energy supply is inadequate or unavailable. Standby rates are often riders which affect several rates offered by a utility. Many utilities have special rate recovery treatment for providing standby (QF backup) power to self-generators when their own or alternative supply is inadequate or unavailable. Standby charges are a type of demand (or insurance) charge paid to the utility to reserve replacement capacity and energy if a system failure or normal maintenance interval takes the on-site generator out of service. These standby rates may be offered as separate rates or rate riders.

There are three general types of standby rates offered by electric utilities: backup rates, maintenance rates, and supplementary rates. Backup and maintenance rates are offered to provide power when a self-generator's system is fully or partially out of service. Maintenance rates are offered for use during pre-arranged downtime and backup rates are offered for unanticipated downtime. Supplementary rates offer power for regular use and are offered to partial-requirements customers that may require purchased power in addition to their own self-generated power. Standby rates for backup and maintenance are usually based on a monthly charge per kW of capacity reserved. There is also a commodity charge for actual energy usage during the down-time period. These standby demand charges are less costly per kW than the actual demand charges on a given full service rate, but are paid for on a take-or-pay basis, regardless of whether additional power is ever required.

Maintenance service rates provide convenience in that they allow self-generators to perform routine service and overhaul during peak demand setting periods. An alternative is to perform maintenance in off-peak periods. However, this is not always possible, particularly for lengthy overhauls. Backup service rates are somewhat like an insurance policy. By purchasing this capacity insurance for a given amount of kW on a monthly basis, self-generators avoid ratcheting and/or full demand charges that might otherwise result from outages.

Consider an example in which the full service rate demand charge is $18/kW/month and the standby charge is $8/kW The facility pays this charge regardless of whether backup power is used. In this example, the annual fee of $96/kW would be a wise investment only if the facility experienced peak setting outages more than 5 months per year, since 5 months' demand charges would only cost $90/kW.

The cost of standby service varies widely. Some utilities require self-generators to purchase standby insurance. Other utilities offer it as an option, while some have no provision for standby power at all. The alternative is the use of standard rates. Key questions in cost allocation are: "What are true costs?", and "What is a fair and reasonable price for such capacity insurance?" The logic behind this particular cost allocation is that the utility must stand ready to serve these loads when needed. Cost allocation is based on a determination of the impact on generation and distribution capacity requirements. The cost-of-service analyses take into account all self-generators and the real probabilities of peak demand impact resulting from random system outages. If, for example, each of 100 self-generators were to set a peak once a year at different times, what would the real impact be on the capacity requirements of the utility?

For cases in which standby service is not mandatory, but offered as an option, customers must make the determination whether to take this type of insurance or take their chances on standard rates. Customers may also elect to secure standby power for a portion, rather than all, of their self-generation load.

In cases where standby charges are mandatory and very high, the cost may be sufficient to make projects uneconomical. In some cases, a change to mandatory requirements, resulting from rate case proceedings years after a system has been installed, may provide sufficient incentive to abandon a project due to the evaporation of savings critical to successful economic operation.

One hypothetical example of such prohibitive effects is a system with three generation units with required standby charges for the full connected load at 66% of the standard demand charge. In this case, the cost of standby service is equivalent to the system operating on a standard rate and experiencing the highly unlikely occurrence of a peak-setting outage in every single month for two of the three units. Add to this the potential of being forced onto an uneconomical rate, and a self-generator could end up with no savings at all. While this example is extreme, it helps to explain why self-generation has been underdeveloped in certain utility service territories.

RTP rate structures may offer an effective means of allocating costs for standby power. RTP is an attempt to reflect short-term costs so that consumers may make short-term purchase decisions. These same varying short-term prices could be made available to QFs. California, Florida, and Virginia are a few of the states that currently have QF purchase power pricing tied to variants of RTP. For example, one rate structure on file with a state commission provides payment for a QF's energy sales at the corresponding marginal cost (i.e., system lambda, $/MWh) of power the host utility experiences. In California, a forecast of marginal costs are the primary input in determining an RTP pricing structure for as-available energy.

Renewable Energy 101

Renewable Energy 101

Renewable energy is energy that is generated from sunlight, rain, tides, geothermal heat and wind. These sources are naturally and constantly replenished, which is why they are deemed as renewable. The usage of renewable energy sources is very important when considering the sustainability of the existing energy usage of the world. While there is currently an abundance of non-renewable energy sources, such as nuclear fuels, these energy sources are depleting. In addition to being a non-renewable supply, the non-renewable energy sources release emissions into the air, which has an adverse effect on the environment.

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