Demand Commodity Rates

These rates consist of two basic components: a demand charge and a commodity charge. The demand charge is typically based on the peak hourly or daily volume in the billing period. The commodity charge is based on the units of energy consumed. In many cases, a ratchet penalty is used. As previously discussed, the ratchet penalty is typically based on a certain percentage of the peak demand incurred within the previous year on an 11 or 12 month rolling basis. This type of rate somewhat more accurately reflects the cost to serve than flat commodity rates because it takes into account peak-day requirements. Such rates encourage customers to maintain a high load factor.

In many cases, a sliding block rate structure is used to blend demand and usage charges into stepped rates based on utilization (or load) factors. Usage is billed at varying rates based on hours of use of demand. For example, a 30 day billing cycle has 720 hours. If the peak demand on an electric utility bill is 1,000 kW, a 100% load factor would represent 72,000 kWh, or 720 hours of use of demand. A 25% load factor would represent 18,000 kWh, or 180 hours of use of demand. This type of rate schedule breaks the hours of the month into different blocks. With a declining block rate structure, in each subsequent block or hours of use of demand, the rate is lower. For example, the first 180 hours of use of equivalent full-load demand (18,000 kWh) would be billed at a certain rate per kWh. The next 180 hours of use of demand (from 18,000 kWh to 36,000 kWh) would be billed at a lower rate per kWh, and so on. This type of rate rewards high load factor customers. If the customer's peak demand increases, more kWh are billed at the higher rate and vice versa.

Time-of-Use Rates

TOU rate structures are often designed to differentiate among months of the year (seasonal rates), days of the week, or hours of the day. These rates assign greater costs to peak usage periods, to discourage consumption, and lower costs to off-peak periods. Commodity cost differentiation may be augmented by peak demand charge differentiation. These TOU rates are more reflective of the cost to serve than standard block rates and provide price signals that direct consumers toward off-season or off-time usage. The level of differentiation will often be greater for utilities with poor annual load factors, such as those with loads that are predominantly heating or cooling. Typically, higher summer rates will be used by electric utilities and higher winter rates will be used by gas utilities.

• Seasonally Differentiated Rates. These are a type of

Fig. 21-4 Representative Natural Gas Inverted Block Service Rate.

gas service, but they do show up with electric services. They are used by utilities that are supply-constrained, or used for conservation purposes to discourage increased consumption. Figure 21-4 illustrates a natural gas inverted block service rate.

• Sliding block rates. These rates use a peak demand value times a multiplier to determine the first-step size. They encourage greater load factors or, in other words, more constant levels of energy usage by the customer. This type of rate is common today in the electric industry for C&I customers. Figure 21-5 illustrates a natural gas sliding block service rate.

In some cases the utilities charge the same unit price regardless of the level of consumption, meaning there is only one block. This is somewhat common for residential customers.

Many utilities use a combination of block-pricing structures. They are often used to reflect a seasonal energy-cost differential. A utility may use an inverted block rate in the season of highest consumption and a flat or declining rate in the off-peak season.

900 MCf/Day

900 MCf/Day

600 MCF^ay 300 MCF/Day

600 MCF^ay 300 MCF/Day

0 500 1,000 1,500 2,000 4,000 6,000 8,000 10,000 MCF/Month

Fig. 21-5 Representative Natural Gas Sliding Block Service Rate.

TOU rate designed to assign greater cost to consumption, on a per-unit basis, for corresponding rate blocks in peak usage months. Commodity cost differentiation may be augmented by peak season demand charges and ratchets. These rates provide price signals that influence the consumers toward off-season usage.

• Off-season rates. These services are provided to customers in specific non-peak months. They are designed for customers who do not require gas service in peak months, but do not have the alternative energy sources typically required for standard interruptible sales service. Similar to interruptible rates, which are discussed later, these rates provide lower cost gas, because they do not contribute to the high cost of maintaining peak facilities. These rates may also be attractive to customers that have alternative energy sources, but cannot use them in certain months because they must meet seasonal emissions standards.

End Use Rates

End use rates are designed to provide incentives to customers to install and operate specific equipment that uses the utility's energy. This usually includes space heating, water heating, and cooling equipment. These rates generally have some basic equipment requirements and often need separate metering. Specialized heating rates are generally used by electric utilities. These are sometimes combined into an all-electric rate that is offered to customers using electric heating, water heating, air conditioning, cooking, etc. Specialized cooling equipment rates are more commonly offered by gas utilities.

End uses selected for specific rates can often be placed in given rate periods or seasons. In some cases, end use rates are combined with TOU rates. The lowest rates typically are offered for end uses employed during the off-peak season or off-peak time of day or week. More moderate rates may be offered for baseload process end uses, such as water heating, cogeneration, or year-round industrial processes.

Many PUCs prefer that price signal tools be applied uniformly to usage characteristics rather than to specific end uses. However, some utilities feel that their typical rates already accomplish this and that further distinctions are needed to attract (or discourage) certain loads.

Non-Firm Service Rates

Non-firm rates include interruptible rates, standby rates, and load management rates. With multiple energy source options increasingly available, non-firm service is becoming increasingly popular:

• Interruptible rates. These rates, which are commonly offered to CI&I customers, are designed for customers whose entire load, or large blocks of load, can be dropped at virtually any time. The primary benefit to utilities is that it reduces the need to guarantee service during peak demand periods. The utility can pass on savings, which come predominantly from reduced fixed-capacity costs, to customers. These rates are also used to attain a competitive advantage and/or attract loads based on lower costs. Interruptible service may involve commodity or distribution components.

There are many conditions under which a facility can withstand such interruptions. Examples include:

— Customers with dual-fuel burners capable of operation on natural gas and alternative fuels, such as propane or oil, or distribution systems supplied by propane-air mixtures can easily withstand interruption of natural gas service by switching over to their alternative burner fuel.

— Customers with on-site electric power generation capacity can go off line and generate their own power to serve the entire facility or selected circuits within the facility.

— Customers with equipment that can operate on either electricity or fuel or steam, can simply use the non-electrical equipment during periods of interruption. This would be the case with a dualdrive mechanical service device that had both an electric motor drive and a prime mover drive, or with mixed energy source (hybrid) multiple unit systems that feature both electrical and non-electrical powered units.

Electric utility interruptible rates are often referred to as utility-controlled peak shaving. Customers are required to reduce their demand on the utility system completely, or to some predetermined level when necessary. Contracts may be designed with a set rate-break on demand or usage, a flat annual or monthly fee paid by the utility, or a specific payment rate for each period of interruption. Significant penalties for failure to interrupt are also common. LDC interruptible rates are typically based on the customer's ability to use an alternative fuel such as oil or propane with the natural gas commodity charge set or negotiated based on the price of the alternative fuel. Natural gas distribution services (in cases where a customer purchases gas from a seller other than the LDC) may be purchased on a non-firm basis. Pricing by the LDC may be based on competitive alternatives similar to interruptible commodity pricing or may be offered at a firm cost-of-service based price.

• Load control, or load management, rates. These rates are a type of interruptible rate that gives the utility direct control over specific loads (sometimes via radio wave signals) during system peak periods. This strategy is most commonly used by electric utilities for residential water heating and air conditioning customers, but can be used for commercial, industrial, and agricultural customers. Load control is intended to minimize customer inconvenience by selecting loads that can most easily be eliminated or cycled.

• Standby rates. Utilities offer these rates to customers that have their own source of energy but require service from the utility on an intermittent basis. These rates are more common to electric utilities and may be categorized as: maintenance rates for power supplied by the utility when the customer prearranges downtime for generation equipment maintenance; supplementary rates used by self-generators that regularly require additional power from the utility; and backup rates used by self-generators in the event of an unexpected system outage.

Negotiated and Specialty Rates

Negotiated rates may be cost-based, designed to allow the utility to compete with alternatives, used to support economic development or business recovery, or implemented to permit unique arrangements, such as inter-ruptible service.

Cost-based negotiated rates are designed for customers whose usage and characteristics vary considerably from the average of the rate class or have realistic competitive alternatives to the utility offering the rates. Most commonly, this is only done with large CI&I customers. In many cases, the utility has the ability to negotiate rates down to a level equal to or, more commonly, slightly above its short-term marginal cost. The regulatory justification is that the rest of the utility's customers will benefit from such contracts as long as the negotiated rate charged to the particular customer covers the incremental variable cost of service and provides some contribution to fixed costs. These rates provide the utility with a maximum degree of flexibility to market their product to customers with special needs or with competitive alternatives. Sometimes, particularly when the contract period is longer than five years, these rates may be designed to recover long-term marginal costs. With these rates, a larger minimum demand charge is required.

• Economic development rates. Utilities commonly offer these rates to provide economic incentives for businesses to locate or expand into their home service territory and/or into economically depressed areas. They are often based on a schedule in which rates are initially discounted and then phased into a standard rate over a period of several years.

• Business retention rates. These rates are designed to retain customers with either competitive options from other energy sources, self-generation capabilities, or an interest in moving to another state or service territory. Business recovery rates are designed to retain customers in financial difficulty.

• Conservation and load management rates. Many utilities offer these rates to customers that meet certain equipment or building envelope thermal efficiency standards and/or operating standards. These rates may be designed with a simple percentage rate break on usage based on achieving a certain level of conservation and efficiency. They may also involve a reduction in charges based on some type of load-control incentive, or they may be based on a combination of both. Rate design also may include incentive mechanisms for shifting load from peak to off-peak periods.

• Special contract rates. In cases where it is in the best interest of all parties (i.e., the utility, the customer, and the rest of the utility's customers) and where the unique conditions of the situation cannot be met under standard rules, utilities may develop special contracts with individual customers. Examples are a very large cogeneration application or a customer who makes year-round third-party gas purchases and is willing to make volumes available to the utility for resale during peak periods. These contracts often require individual PUC approval, which can be a lengthy process.

Examples of other types of specialty rates are compressed natural gas rates for natural gas-fueled vehicles and rates that support the introduction of new technologies.

Competitive Energy Rates

Competitive energy rates give utilities the maximum flexibility to sell power or natural gas in competitive situations. For example, customers considering a gas or steam technology application, such as cogeneration, are often presented with some type of competitive energy rate by their electric utility in an effort to keep the full load on the utility system. Competitive pricing may be offered down to some small level above the incremental avoided cost.

This pricing structure is also used for peak usage by utilities with some excess system capacity. There is some concern that this practice skews market choices, keeps load at the expense of conservation opportunities, discounts opportunity costs, and, in the long run, leads to additional capacity needs at the expense of the rest of the rate payers.

Wholesale (Off-System) Sales

Another area for incremental-cost commodity sales is on the wholesale market. This market, while often less stable than on-system sales, can be very profitable for utilities if the plant supplying power or the reserved gas pipeline capacity is in the rate base. A utility with excess capacity in a given period can sell gas or electricity to other utilities or, in some cases, to customers outside of their service territory. The prevailing logic is that excess capacity should be marketed whenever possible as long as variable costs are recovered and some contribution, however small, is made toward fixed cost recovery. With the potential for capacity release, however, LDCs can instead sell excess capacity rights to others rather than use the capacity for the purpose of off-system sales.

Real Time Pricing

Real-time pricing (RTP) is an emerging utility rate strategy that goes a step further than demand charges and varying usage charges in allowing for differentiation of costs that better reflect the utility's actual incremental cost. RTP rates typically do not have a demand component. Instead, kWh, or Mcf, consumption is priced by the hour. For example, an hourly RTP structure may charge $0.90/kWh at noon on a Wednesday in August and only $0.02/kWh at midnight on a Sunday in March. Currently, RTP is being used by numerous electric utilities.

The theory behind RTP is that if customers are told in advance of the utility's anticipated system and price conditions, customer demand will respond most directly to price changes. That is, a decrease in consumption as the price rises and an increase in consumption as the price falls. Typically, customers are given a schedule of hourly prices one day in advance. In some cases, the cost per kWh is fixed for several categories (i.e., off-peak, utility-peak, or regional power pool-peak), but the hours during which they are applied are varied and communicated by the utility to customers on an hourly, daily, or weekly basis.

The procedures used to design rates that differentiate usage and demand charges by time and season of use come close to approximating what the utility determines is proper hourly cost allocation. RTP accomplishes this with greater certainty and fewer complications. Taking the example of a TOU rate with a peak demand period of the typical 9-to-5 workweek, a peak demand may be set at 9 a.m. by a facility. This peak may have no impact on the utility peak, but is charged as if it were set at the utility system peak hour. With RTP, if in fact this peak had no impact on the utility peak, it would be priced at a far lower level than a peak that did have an actual impact on the utility peak.

The concept behind RTP is that pricing reflects real, almost instantaneous, market conditions instead of predicted market conditions. While TOU rate blocks are bins which approximate what actual costs are in different periods, RTP more closely reflects the actual value of electricity (or gas) at any given point in time. Non-RTP rates are, therefore, based on probability of occurrence, rather than occurrence.

Another type of pricing that more closely represents real events is ambient temperature based pricing. For example, when the outside temperature falls below 30 or 20°F (-1 or -7°C), natural gas pricing could automatically shift to a higher rate. Currently, there are many interrupt-ible gas rates that base interruptions on temperature. A similar strategy could be employed for summer electricity pricing, based on rising temperature. While this is not an instantaneous pricing mechanism, it is one based on real events as opposed to predicted events. When the event occurs, the pricing schedule is in effect.

Electric utility dispatch modeling has become an increasingly precise process. Utilities can identify where each incremental kWh comes from and its value. Large facilities can then perform the same modeling of in-house usage. Furthermore, the cost of telemetry is decreasing, while capabilities are increasing. As alternative electricity purchase options become available, RTP may become a mainstream sales pricing tool. Consumers may elect to purchase certain blocks from the utility, generate certain blocks on site, and purchase certain blocks from other sources through retail wheeling, all based on real-time price signals.

Rate Riders

In additional to various rate design options, rate riders are special charges or programs integrated into rate schedules that modify the structure based on specific customer qualifications. Riders are used to account for unique conditions or to give the utility added flexibility to apply rates without dozens of additional tariffs. Riders may include: negotiated competitive-energy riders, interruptible riders, standby riders, buy-back riders, conservation and other load-control riders, end use riders, and other types of discounts, such as an electric utility discount for customers receiving service at a voltage above the standard voltage.

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