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Matched Legal Cases: ['art 1', 'art 2', 'art 3', 'art 4', 'art 3', 'art 4', 'art 1', 'art 2', 'art 1', 'art 2', 'art 3', 'art 4', 'art 1', 'art 2', 'art 3', 'art 4', 'art 6', 'art 1', 'art 2', 'art 4', 'art 3', 'art 5']

standby_rates | Cogeneration | Kilowatt Hour
standby_ratesUploaded by Ignacio Vicencio ArriagadaRelated InterestsCogenerationKilowatt HourDistributed GenerationElectrical GridDemandRating and Stats0.0 (0)Document ActionsDownloadShare or Embed DocumentEmbedView MoreCopyright: Attribution Non-Commercial (BY-NC)List price: $0.00Download as PDF, TXT or read online from ScribdFlag for inappropriate contentSTANDBY RATES FOR CUSTOMER-SITED RESOURCESISSUES, CONSIDERATIONS, AND THE ELEMENTS OF MODEL TARIFFS
U.S. Environmental Protection Agency Office of Atmospheric Programs Climate Protection Partnerships Division 1200 Pennsylvania Ave., NW Washington, DC 20460
Developed by the Combined Heat and Power Partnership
STANDBY RATES FOR CUSTOMERSITED RESOURCES
ISSUES, CONSIDERATIONS, AND THE ELEMENTS OF MODEL TARIFFS
Prepared for: U.S. Environmental Protection Agency Office of Atmospheric Programs Climate Protection Partnerships Division 1200 Pennsylvania Ave., NW Washington, DC 20460 Prepared by: Regulatory Assistance Project 50 State St., Suite 3 Montpelier, VT 05602 ICF International 1655 N. Fort Myer Drive, Suite 600 Arlington, VA 22209
List of Figures ............................................................................................................................... ii List of Tables................................................................................................................................. ii List of Acronyms and Abbreviations.............................................................................................. ii Acknowledgements....................................................................................................................... ii
Executive Summary .............................................................................................. 1 Introduction ........................................................................................................... 2 Electric Rate Structures and Economics of Distributed Generation ................ 3
3.1 3.2 3.3 Elements of Electricity Rates.......................................................................................... 3 Standby Service ............................................................................................................. 4 The Economics of Distributed Generation...................................................................... 5
Tariff Designs, Supplemental Service, and Economics of Distributed Generation Systems.............................................................................................. 7
4.1 4.2 4.3 4.4 Analytical Approach........................................................................................................ 7 Example 1—Portland General Electric........................................................................... 9 Example 2—Orange & Rockland ................................................................................. 12 Example 3—NSTAR..................................................................................................... 14
Conclusions......................................................................................................... 17 Notes .................................................................................................................... 18
Appendix A: Additional Analyses of Specific Standby Tariffs ............................. A-1
A.1 A.2 Hawaiian Electric Company—Unbundled Rates and Daily Demand Charges........... A-1 Consolidated Edison—Daily As-Used Demand Charges........................................... A-2
Appendix B: Principles of Rate Design .................................................................. B-1
B.1 B.2 B.3 Basic Principles of Rate Design ................................................................................. B-1 Pricing the Components of Electric Service ............................................................... B-4 Notes .......................................................................................................................... B-7
Appendix C: References.......................................................................................... C-1
...................................................................... A-3
CHP DG FERC kW kWh MW combined heat and power distributed generation Federal Energy Regulatory Commission kilowatt kilowatt-hour megawatt
This document was prepared by Rick Weston of the Regulatory Assistance Project and Joel Bluestein.....
................. Hawaiian Electric Company Tariff Summary ........................ Their thoughts and recommendations have been incorporated where appropriate................................ 13 Table 5............................................ 7 Table 2.... provided copyediting and production services...................... Orange & Rockland Tariff Summary ........List of Figures
Figure 1....... however........... NSTAR Tariff Summary ............ Portland General Electric Tariff Provisions . Consolidated Edison Tariff Summary ............ 15 Table 7.................................................................. a few............ 14 Table 6.............................. Prototype CHP Facility....... 16 Table 8........ Orange & Rockland Cost Comparison.......................... Portland General Electric Cost Comparison ........... and Joseph Orlando for taking the time to review and comment on the initial draft of this paper..... NSTAR Cost Summary ................................... Bruce Hedman...... The authors would like to thank Calvin Timmerman............................................. A-1 Table 9.................................................................................... Eastern Research Group.................. Eric Wong............ and Rod Hite of ICF International................. 9 Table 3...... 10 Table 4........................ Their feedback was incisive and very helpful......................... Christopher Young........................................................ were beyond the scope and resources of the project.............. Prototype Demand Profile ........................ Inc.............. 8
Table 1..................
these tariffs are marked by some or all of the following features:
Contract demand or reservation charges are small in relation to the variable charges for peak demand and energy. The review of selected rate tariffs suggests that the better rate designs share common and central characteristics: they are designed to give customers a strong incentive to use electric service most efficiently. provide appropriate savings to the clean. but also on the level and structure of the otherwise applicable full requirements tariff (e. given the costs and benefits of DG. Specifically. The rate structure yields a significant retail rate savings per kilowatt-hour (kWh) produced on site instead of purchased from the grid.
These findings are consistent with the understanding that the economics of onsite generation are based on reduced electricity purchases. clean. Importantly. daily as-used demand charges are the next best solution. This paper focuses on one of those policies: the structure of prices for standby service. The report identifies approaches that. The economic viability of clean.
. combined heat and power (CHP) facilities. but how a particular rate is structured along these lines will depend on the levels of the various rate elements. at worst. This depends not only on the standby tariff itself. These examples also suggest that such rates can apply to DG while also fairly compensating utilities for the services they provide to onsite generators. customer-sited resources comes increased interest in the regulatory policies that affect their deployment. and these reduced purchases must benefit the customer to make DG viable. As such. heavily depends on the regulatory policies that determine how they are treated by the electricity network. This means that they reward customers for maintaining and operating their onsite generation.g. there are no more than monthly as-used demand charges).. distributed generation (DG) and. and to avoid charges when service is not taken. the tariff that would apply in the absence of DG). they also serve to remind regulators of the need to pay close attention to ensure that the design of partial requirement rate structures captures the economic and environmental benefits of reduced energy consumption. Peak demand charges are not ratcheted or. in particular. Energy-based charges to collect capacity costs would seem to offer the greatest promise in this regard.1:
With increased interest in efficient. DG system owner and appropriate cost recovery to the utility. but utilities and their regulators do not appear to be prepared to entirely abandon some form of peak demand charge. have 30-day ratchets (that is. to minimize the costs they impose on the system.
boiler) energy consumption. tariffs can affect prime mover selection. Today.2:
Interest in clean. Not all tariffs result in the most efficient system design or operating strategy. when it is sized to match the thermal loads of the facility and operates an extended number of hours on an annual basis. in particular CHP systems. This paper identifies the elements of rate structures that will appropriately charge customers with DG for the services they take. The degree to which customers’ charges are adjusted under a certain tariff by generating their own electricity from DG will determine whether or not this is the case. CHP is most efficient. This avoidance of cross-subsidization cannot. and lower total system energy consumption. costs. and emissions. fuel. and operating strategy. be directly judged. These rates should also fairly compensate the utility for the costs of serving customers with DG in order to protect other customers from being charged unfairly high rates. there is little evidence of a standard approach. Customers primarily install onsite generation in an attempt to reduce their overall energy costs. policy-makers. With these benefits in mind. it is likely the result of a state’s failure to adopt appropriate rules. The analyses in this paper presume that rates that are in effect or proposed by utilities are meeting cost-recovery (or revenue-burden) goals. and maintenance expenses with a decrease in the amount and therefore the cost of purchased power. improved operational efficiencies.
. and cost effective.. States are innovating. reduced thermal (e. In general. in the absence of company-specific cost data. avoided investments in generation and delivery capacity. Although an increasing number of states have begun to address the question of whether the lack of appropriate statewide rules on retail tariffs might also present a barrier to onsite generation. and there are now several approaches to the design of rate structures for DG that warrant closer analysis. The many benefits accrue both to the owners of the onsite resources—through cost savings from avoided purchases of grid-supplied power. if interconnection remains a barrier to onsite generation.2 continues to grow as appreciation likewise grows for the value that these resources can provide. without creating economic barriers to DG. and lower overall energy costs—and to the electric system as a whole— through reduced demands for power. can have a significant impact on CHP economics by affecting the amount of actual savings resulting from reduced electricity purchases from the grid. and system operators have begun to address the challenges of integrating these systems into the electric transmission and distribution networks. CHP further enhances the customer economics because of additional savings from combining thermal and electric generation into one process. improved reliability. The decision to generate one’s own power balances additional capital. Onsite generation typically reduces the amount of electricity purchased while increasing onsite capital and fuel costs. system sizing. utility representatives. Much work has been done at the state and federal levels to develop and standardize technical and regulatory rules for interconnection of the onsite generator to the electric grid. particularly standby and backup rates. As such. customer-sited. Electric rate structures. and not the consequence of unresolved technological or operational challenges.g. 1 non-emergency generation. increased system reliability.
billing. to serve those peaks.5 In addition. For residential and small commercial rates. Because the electric service is to be provided on demand. For larger volume users. and energy charges. these can be ignored. Capacity is measured in kW or megawatts (MW). they may be differentiated by time-of-use. the system must be designed to meet a variety of peak loads: that of the system as a whole. They are deemed to give the
. The costs of capacity can be included in per-kWh energy charges. or by some other means. those of customers served by individual parts of the network. and service drop facilities. by season. higher energy charges might apply during on-peak time periods as opposed to off-peak time periods. recurring charge (monthly or daily). there may be adders or surcharges to cover related costs and risks of operation. and it represents the ability of a facility (or the grid in the aggregate) to deliver the service desired at any instant. of course. larger facility rates (e. but for the purposes of this paper. but more likely 500 kW and greater. or the energy charge might decrease as more energy is purchased. energy charges may be the only category of rates. and those of individual customers. typically 1 month. While this discussion applies to rate design generally.1
Elements of Electricity Rates
Electricity rates have three main components: customer charges. commercial and industrial) typically include both energy and demand charges. which must be recovered by the utility even if no electric service is taken.. it can be seen as a flat fee that provides access to the grid. high-volume commercial and industrial users for whom DG capacity would be at least 200 kilowatts (kW). Energy charges are the charges for consumption of the electricity commodity applied on a perkWh basis.4 The customer charge is a fixed. Demand charges are a means of allocating and recovering the costs of the capacity. For example. measured and priced in dollars per kW per time period. in a declining block structure. be other charges as well. there may be multiple commodity charges associated with different categories of usage charges. as they often are for lower volume residential and small commercial consumers. typically intended to cover the constant costs of metering.3:
Electric Rate Structures and Economics of Distributed Generation
This section provides a brief primer on the basics of electric service and rate design to provide a context for the later discussions of standby rates.g.
3. demand charges. Demand charges are used to recover the capital costs of the capacity necessary to meet customers’ peak loads. such as taxes or special assessments. In some cases. by consumption block. standard practice is to separate the charges for capacity and energy. this paper focuses on rate structures for customers that are most likely to be suited to onsite generation—that is. However. Demand charges are based on the peak electricity demand (kW) during a given period. Customers purchase energy at the tariffed rates or from third-party suppliers at negotiated rates. There could.3 Appendix B provides a more detailed discussion of these topics. In this sense.
Some differentiate only between standby and supplemental. The significance of the two components for a customer depends heavily on the customer’s load factor. This is an advantageous situation for the utility because its facilities are always being fully utilized. non-emergency generation typically desire. which includes continuing electricity service for the portion of usage that is not provided by the onsite generator. Many of the utilities that provide these services distinguish in their tariffs among three types of partial requirements service: supplemental. In this report. This service could be a tariff that replaces the standard full requirements tariff or an additional tariff that applies on top of the standard tariff for certain special types of service.larger utility users stronger incentives to manage their peak demand most efficiently. The relative level of each is determined by the characteristics of the local grid. thus minimizing the investment in physical infrastructure that the utility must make on the customers’ behalf. because demand and energy charges are fully linked. and maintenance. then the demand would never change and the load factor would be 100 percent. it might be appropriate for the customer to provide payment in this structure or alternatively to be driven by this structure to modify their operation to improve their load factor. they link customer charges to the longer term nature of the capacity obligations of the utility—they nevertheless can be a financial barrier for customers looking for more efficient means of meeting their energy needs (even as they have the effect of lowering the cost of off-peak power).6 Ratchets turn a fee that would otherwise vary with changes in demand into something more like a fixed charge that locks a customer into a minimum monthly payment for the duration of the ratchet. backup. supply mix..7 Most large customer electric rates include both an energy and a demand component. Customers with onsite generation typically require a different set of services. and long periods when consumption is much lower. and other local market factors. “Partial requirements” is the more precise name for standby or backup service: the set of retail electric products that customers with onsite. there would be little need to apply a demand charge.2
Customers who receive all of their electricity from the utility or via the grid are known as “full requirements” customers. In this case. as well as service for periods of scheduled or unscheduled outages. which apply a peak demand value to the bill for anywhere from several months to a year after its occurrence. then the load factor can be much less than 100 percent. In this case. a utility would want to apply a demand charge to recover the costs of supplying the peak capacity that is not recovered by the lower level of consumption during nonpeak times.
3. we recognize the following as the most common components of service for partial requirements customers:
. there can be brief periods when supply facilities are heavily used. Although there is a certain logic behind ratchets—i. This incentive is further promoted by the common use of ratchets.e. Because this load profile is in some respect related to the underlying operations of the customer. The load factor is the total energy consumption divided by the peak demand multiplied by the number of hours in the month. In this situation. If the customer always consumed the same amount of electricity every hour of the month. Their electricity is provided under rates that are primarily some mix of the components discussed above. If the demand is highly variable.
This can cause some confusion when comparing different rate elements and. the separation of these functions in restructured states has also led to a separation of the charges for them. in certain cases.
Electric industry restructuring and the unbundling of the electric system’s components (generation. The complication with respect to electricity rates comes when reduced consumption does not result in reduced electricity bills. Economic Replacement Power. reservation charges or ratchets. etc. because this service can be scheduled for nonpeak times.) has. during unscheduled outages of the onsite generation.g. in a restructured state the question of partial requirements service is limited to the remaining monopoly services that are only provided by the local incumbent utility—distribution and.e. there are also increased efficiency and operating cost savings because of the combined generation of thermal and electric energy. in particular. Supplemental service provides additional electricity supply for customers whose onsite generation does not meet all of their needs. transmission—but there might also be default service offerings for energy charges. and distribution charges. transmission. These costs must be offset by reduced electricity purchases for the system to be economical. it is considered to create few additional or marginal costs to the utility’s system. the basic economic underpinning of a DG system is a tradeoff between reduced electricity purchases and the increased capital and operating costs for the DG system.. At this level. added complexity to rate design (i.
Supplemental Service. in some states. a rate that includes only a commodity charge would provide the most direct recognition of the benefit of the DG system. Scheduled maintenance service is taken when the customer’s DG is due to be out of service for routine maintenance and repairs. This can result depending on the structure of the tariff—electric rate demand versus energy charges.
. For a CHP system. Backup or standby service supports a customer’s load that would otherwise be served by DG. In many cases it is provided under the otherwise applicable full requirements tariff. Backup Service. An 80 percent reduction in energy purchased would result in an 80 percent reduction in electricity cost. their ratchets and exemptions.
3. Because DG reduces the purchase of energy (kWh).3
As noted above. Some utilities offer economic replacement power— electricity at times when the cost of producing and delivering it is below that of the onsite source. In general.8 Scheduled Maintenance Service. there is a simple economic tradeoff between savings from reduced electricity consumption and the cost of additional fuel for onsite generation and levelized cost of increased capital investment. for either generation or delivery). The facility operator invests in capital equipment and must pay operating and fuel costs. and tariffs are typically structured to exempt the customer from capacity-related costs (e.. Whereas the electricity prices of vertically integrated utilities that have not been unbundled often include generation. In general. distribution. the Federal Energy Regulatory Commission’s [FERC’s] no action policy on states if deregulated). transmission.
the one outage would cause the system to forgo any savings for the entire year.Although the reduced consumption theoretically translates into a commensurate reduction in demand. determining the appropriate rate structure of DG facilities requires a different analysis than that applied to conventional facilities. causing the DG system to achieve no savings at all in that month. Under these circumstances. standby. One cannot identify a unique structure that fits all customer and market characteristics. in reality. Thus. every system has some number of planned or unplanned outages during the year. If the rate has an annual ratchet. Planned outages can be scheduled for off-peak hours when they place minimum stress on grid facilities. Unplanned outages might be extremely rare and might not coincide with other system outages. emergency. and economic replacement rates. however. if the rate has only a demand charge and no energy charge. recognizing the costs and benefits of DG. an outage would cause the facility to reach its peak demand during the month for a brief period. Thus. during which facility demand can reach the non-DG level. The rates applied to DG facilities can be many different combinations of standard. the goal of this paper is to identify basic structures that provide appropriate savings to DG facilities and appropriate cost recovery to utilities.
. supplemental service. the profile and timing of outages can be a major determinant of DG cost and system economics.
Prototype CHP Facility
Plant Consumption Details Operating hours Annual power consumption.1
The subsections that follow identify and analyze several approaches to standby rates using actual tariffs. kWh Generated power.616 Gas Turbine CHP 49.760 92.451 kWh. kW System availability. As shown in Figure 1.489. This analysis compares annual bills of a DG customer with specified usage and production characteristics against the bills that the customer would otherwise pay as a full requirements customer. it is assumed that customers are billed monthly.000
The modeled DG customer has a peak annual demand of 13. so no attempt to characterize its costs and its thermal energy benefits was made. kW CHP System Prime mover CHP electric capacity.260 8. This section employs such a detailed assessment to evaluate the effect of partial requirements charges on a prototype DG (CHP) facility and to identify beneficial rate structures.762.000 kW CHP system is baseloaded and provides about 47 percent of the customer’s annual power needs.000 kW and annual consumption of 92. Supplemental Service. The peak demand is set in August. and Economics of Distributed Generation Systems
Evaluating the economic effect of rate design on DG systems requires a detailed assessment of the time-dependent effect of both components of the rate structure.000 98% 8. kWh Base System 92.451 13. Table 1.762. Because the purpose of these analyses is to determine only the annual electric bill savings that a DG system would yield under the various tariffs given specified load and operating characteristics.
4. the 5.762. This section discusses three tariffs. and Appendix A describes two additional examples.273. The tariffs were evaluated for a mid-sized (5 MW) CHP project with characteristics summarized in Table 1.191 43. % System hours of operation Electric Consumption Purchased power. In each example.451 Gas Turbine CHP 5. the economics of the DG system were not being evaluated. kWh Peak demand.
Tariff Designs.
The tool calculated several annual average cost figures based on the total energy consumption. the reduction in electricity price should be commensurate with the reduction in purchased electricity.000 12.In order to evaluate the impact of outages on savings under different tariff structures. In these months. the peak billing demand is equal to the total demand of the facility. This was calculated as the annual bill divided by the annual electricity consumption or purchases.000 0
Peak Monthly Plant Demand Peak Monthly Billing Demand
pr M ay
ug Se p
The rate impacts for the system for each tariff were calculated for each month of the year for the DG and non-DG cases. of the avoided gridsupplied electricity. This was calculated as the bill savings divided by the avoided consumption (or generation). If the onsite system reduces consumption by 80 percent. Figure 1. the CHP system reduces the customer’s monthly peak billing demand by 5.000
10.000 kW. per kWh. The higher the ratio of avoided costs
. the cost of electricity purchases would also be reduced by 80 percent. This is the annual utility bill divided by the annual electricity purchases. the tool calculated the value. This avoided cost percentage is an important concept for evaluating the treatment of onsite generation by partial requirement tariff structures. The economics are severely impacted if partial requirements rates are structured so that only a small portion of the electricity price can be avoided.000 2. The first is the average cost per kWh for grid-supplied electricity under the full requirements tariff. A spreadsheet tool was developed to calculate these monthly values and summarize them for the year. Ideally. the CHP system was assumed to experience unplanned outages during 2 months out of the year. One of the key economic values of onsite generation9 is the displacement of purchased electricity and the avoidance of those costs. Prototype Demand Profile
14.000 6. the tool compared the value of the avoided purchases with the value of the full requirements electricity on a per-kWh basis. The second is the average cost per kWh for grid-supplied electricity under the partial requirements tariff. Next.000 8. Last.000 4. except during July and November when the outages occurred. As shown in Figure 1.
Portland General Electric Tariff Provisions
Unbundled Service for Partial and Full Requirements Customers (>1 MW) With Monthly As-Used Demand Charges Portland General Electric Full Requirements Rate 89 Part 1: Customer charge Customer charge Part 2: Transmission charges On-peak demand Part 3: Distribution charges Sum of A + B A.57/kW-month $2. demand. as compared with the full requirements tariff 89. The rate is a fairly standard structure with customer.01/kW-month $0. Thus. however. Facility capacity First 1.
.57/kW-month $2.000 MW Over 1.2
Example 1—Portland General Electric
The first example is the Portland General Electric partial tariff 75.000 kW) B.000 kW) System usage charge Energy charge Average on/off peak N/A N/A $0.0039/kWh Wholesale market price/kWh $0..01/kW-month $1. the assumed outages only affect the demand charge in that month and do not reduce the savings in other months. is that this rate has monthly as-used on-peak demand charges (i. partial requirement rate tariffs that result in avoided costs that are above 90 percent of the full service retail rate percentage generally provide adequate savings to support onsite generation.70/kW-month $150/month $150/month Partial Requirements Rate 75
Source: Portland General Electric. and energy charges. A critical feature. summarized in Table 2. As an evaluation measure.90/kW-month $0. Spinning (>2.70/kW-month $0.0626/kWh $0.
4. the higher the user’s savings.10 Table 2.0039/kWh $1.000 MW B. no ratchet).0626/kWh $0.2340/kW-month $0. Supplemental (>2. On-peak demand Part 4: Generation charges Generation contingency reserves Sum of A + B A.e.2340/kW-month $0.to the full retail average price.90/kW-month $0. Rate 75 (partial requirements) and Rate 89 (full).
Second. Finally.0714 N/A
Partial Requirements 49. as mentioned above. this rate does not have a demand ratchet.0694
97.621. the cost savings are more than 97 percent of the electricity savings. indicating that the tariff does a good job of recognizing the value of DG.800 $153.170. Because DG affects energy consumption.11 Table 3.000 adder compared with the $3-million savings provided by the CHP systems.601 $88.
Overall.191 $1.826 $0 $6.589 $3.The partial requirements tariff is in most respects the same as the full requirements tariff.277. so the outages do not have an exaggerated effect on the cost. The primary difference is a contingency reserve and a spinning reserve charge applied to the onsite generator capacity. though fixed. the standby demand charges.273.
Full Requirements 92.347 $3.493 $28.289 $53.439 $6. this is an initial indicator that these rates will be favorable for DG economics. There are three key elements:
The first thing to notice is that the energy charges constitute more than 90 percent of the total cost in both cases.404 $88.056 $105. are only a $28.120 $0. but their rates are low enough that they do not significantly change the electricity cost for the CHP system. Table 3 shows the breakdown of costs for the fuel requirements and partial requirements cases.524 $0. Portland General Electric Cost Comparison
Comparative Annual Bills Purchased electricity. These contract demand charges are fixed.2%
.800 $255.603.451 $1. kWh Facilities charges Distribution on-peak demand charges Facility capacity demand charges Transmission on-peak demand charges Standby demand charges Energy charges Total electric charges Average rate for purchased power Average avoided rate Average avoided rate as a percentage of average retail service rate
Source: EPA analysis using Portland General Electric tariff.762.0731 $0.
The generation charges cover the costs of generation capacity necessary to serve unplanned outages of the DG. yield the same result): 1. hourly) to reflect the variable costs of production or a market-based approach.g.e.). theoretically at least. The customer charge is typically a fixed.. As a share of the contingency reserves required to serve load in the event of an unplanned outage.g. The ratchet will depend in part on the nature of wholesale capacity and energy markets and the obligations of participants. The charges might differ. within these categories.12 This might also be true of the generation rates.. off-peak. one for dedicated facilities and a second for shared facilities. 2. whether full or partial requirements:
Transmission. a ratchet should reflect the timing and duration of capacity purchase requirements.. when other units are suffering unplanned outages). and generation charges are separated and.13 Energy charges are rendered in dollars per kWh and can be differentiated by time (on-peak.m. but it could depend on the existence of competitive alternatives.m. billing. It goes without saying that charges should not be duplicative—for example.
. At most. and distribution rates are the same for full and partial requirements customers.This rate structure illustrates a number of rate design features that could be appropriate for large users.. The transmission charge is applied to kW of monthly on-peak demand (no ratchet).
The facilities (or contract demand) charge is a per-kW fee applied to the customer’s maximum noncoincident peak demand (or contractually agreed-on maximum) of required capacity for dedicated facilities. primary. It should cover at most the costs of metering. periodic (daily or monthly) charge. the rates are further unbundled as justified by their cost characteristics. The charge for shared facilities is also a per-kW fee. to 11 p. sub-transmission). These per-kW charges can be calculated in one of two ways. distribution. There are two categories of distribution charges. The customer charge.e. in recognition of the DG’s diversity benefits (they should. but should also be reflective of the other uses to which that capacity can also be put (i. transmission rate. but applied to the customer’s maximum monthly demand during the on-peak periods (e. season. As a function of the probability of the occurrence of an unplanned outage coinciding with a system peak or other times of capacity constraint (e. depending on the voltage level at which service is taken (i. and customer service that do not vary with usage. the diversity of the loads it will serve). secondary. subject to an 11-month ratchet or similar mechanism. a partial requirements customer should not pay a customer charge for standby service and a second one for supplemental service. 8 a.
4. Note. see Appendix A. which describes the Hawaiian Electric standby tariff).. that a customer has the option to segregate a portion of its load so it might indeed be billed under the applicable full requirements tariff. This means that the contract demand charge applies to the customer’s total maximum demand. not merely that portion necessary to backing up its generator. supplemental)—is taken under the partial requirements tariff.e.
.e. as compared with its full requirements tariff SC-9. Table 4 summarizes Orange & Rockland’s standby service tariff SC-25. onpeak demand charge. standby) and that needed to serve the customer’s demand in excess of the capacity of its onsite generation (i. a daily demand charge with a 30-day ratchet. An alternative to a monthly demand charge for shared facilities is a daily as-used. As suggested earlier. In its other aspects. A unique feature of this standby service tariff is that all service—both that needed to serve the customer when its onsite generation is offline (i. in effect. providing incentive for increased onsite generation. a monthly demand charge is. In this respect it differs from other tariffs with daily as-used demand charges (for instance. It reduces the costs of partial requirements service for those customers whose need for backup is infrequent. however.. this type of rate design looks very much like the previous design.3
Example 2—Orange & Rockland
Orange & Rockland is an investor-owned utility in New York State.
The contract demand charges and delivery charges in the partial requirements tariff are much higher than in the previous example.64/kW-month $450/month $371/month Partial Requirements SC-25
Source: Orange & Rockland. demand A. all kWh Period B. these charges are in lieu of higher demand and delivery charges included under the full requirements tariffs. Period A B. commodity Commodity charge $3. However.0795/kWh $0. Period B As-used demand charge Daily summer as-used Daily non-summer as-used Part 3: Delivery charges.4210/kW-month $0. energy Period A. and. accounting for almost $1 million. all kWh Standby Contract demand charge Part 4: Energy. all kWh Period C. so the result is a net savings. ancillary service. accounting for slightly more than 80 percent of the total cost. Orange & Rockland Tariff Summary
Unbundled Service for Full and Partial Requirements Customers (>1 MW) With Daily As-Used Demand Charges Orange & Rockland Full Requirements SC-9 Part 1: Customer charge Customer charge Part 2: Delivery charges.01103/kWh $0. though not as much. standby charges that replace rather than add to the demand and delivery charges in the full services tariff.89/kW-month $4.09/kW-month Energy.
. The key factors again are a tariff dominated by energy charges. in this case. the energy charges predominate.2769/kW-month $9.0041/kWh $0. again showing a good recognition of the value of DG in the tariff.
Table 5 shows the calculated cost for the conventional and CHP systems under Orange & Rockland’s two tariffs.0795/kWh $0. The reduction in cost is more than 95 percent of the reduction in consumption.01103/kWh $0. no demand ratchet. capacity at wholesale market prices $0. general service Tariff SC-9 and standby service Tariff SC-25. As in the previous example.Table 4.
880 $489.457 $0 $0 $484.311 $0 $0 $7.374.273.744 $667.615 $8.69%
.896.0957 N/A
Partial Requirements 49.451 $5.Table 5.398 $832.518 $0.4
Example 3—NSTAR
NSTAR has a standby rate design that calls for contract demand charges only. kWh Facilities charges Delivery demand charges Delivery energy (usage) charges Contract demand charges Daily as-used demand charges Commodity energy charges Total electric charges Average rate for purchased power Average avoided rate Average avoided rate as a percentage of average retail service rate
Source: EPA analysis using Orange & Rockland tariff.0994 $0.961 $3. as compared with its full requirements T2 tariff. Orange & Rockland Cost Comparison
Comparative Annual Bills Purchased electricity.191 $4.762.0916
95. either monthly or daily.068 $0.880.219 $4. Table 6 summarizes NSTAR’s partial requirements SB-T2 rate.
Full Requirements 92. there are no variable demand charges.917.
. it cannot be reduced through the generation of more power. It therefore represents an unavoidable cost which is larger than in the previous examples.75/kW-month
$375/month $19. The standby charge is a contract demand charge. which is lower than in the previous examples. but it represents only 70–75 percent of the total.03/kW-month $0. there is no demand ratchet.67/kW-month $8.5/kW-month $11.11678/kWh
Source: NSTAR.03/kW-month $0.
Partial Requirements Rate SB-T2 $375/month $19. This suggests a less favorable outcome for DG.01371/kWh $4. demand Summer peak Winter peak Energy charge Transmission charges. NSTAR Tariff Summary
Unbundled Service for Full and Partial Requirements Customers (>14. and. accounting for more than 7 percent of the total electricity cost in the DG case compared with $6 million in savings.000 Volts) Contract Demand Charges for Partial Requirements Monthly As-Used Demand Charges for Full Requirements NSTAR Full Requirements Rate T2 Part 1: Customer charge Customer charge Part 2: Distribution charges.11678/kWh $0.01371/kWh $4.Table 6. commodity Default service. however.50/kW-month
Table 7 summarizes the cost analysis for this NSTAR example. The energy charge is the largest cost component.50/kW-month $14. demand Summer Part 3: Other charges. all kWh $0. Rate SB-T2 for partial requirements customers and Rate T2 for full.5/kW-month $11. as such. standby Summer contract demand Winter contract demand Part 4: Energy. This accounts for a large part of the difference between the average retail rate before DG and the average avoidable rate.
456 $675.125 $649.
Full Requirements 92. NSTAR Cost Summary
Comparative Annual Bills Purchased electricity.315 $0.191 $4.754.762.500 $954.512 $298.473.793.Table 7.271.1692 $0.1560 N/A
Partial Requirements 49.500 $1.44%
.832.535 $5.799 $14. kWh Facilities charges Distribution demand charges Standby/contract demand charges Transmission demand charges Distribution energy charges Commodity energy charges Total electric charges Average rate for purchased power Average avoided rate Average avoided rate as a percentage of average retail service rate
Source: EPA analysis using NSTAR tariff.336.221 $0 $571.773 $10.123 $8.273.021 $1.451 $4.252 $0.1411
but utilities and their regulators do not appear to be prepared to entirely abandon some form of peak demand charge. Importantly. but also on the level and structure of the otherwise applicable full requirements tariff. have 30-day ratchets (that is. Specifically. As such. Rate designs that reward reliable operation can encourage the development of a diversified.
. they also serve to remind regulators of the need to pay close attention to ensuring that the design of partial requirement rate structures captures the economic and environmental benefits of reduced energy consumption. Rate designs that have a reasonable balance between energy and demand or reservation charges will naturally be more amenable to the broad policy goal of encouraging clean. to minimize the costs they impose on the system. clean DG. Put another way.. daily as-used demand charges are the next best solution. These factors include the costs of the onsite DG systems and the costs (e.g. at worst.
These findings are consistent with the understanding that the economics of onsite generation are based on reduced electricity purchases. they are marked by some or all of the following features:
Contract demand or reservation charges are small in relation to the variable charges for peak demand and energy. efficient DG. the rates) for partial requirements electricity service. there are no more than monthly as-used demand charges). but how a particular rate is structured along these lines will depend (as the first bullet mentions) on the levels of the various rate elements. These examples also suggest that such rates can apply to DG while also fairly compensating utilities for the services they provide to onsite generators. Peak demand charges are not ratcheted or. more reliable electric grid. and these reduced purchases must benefit the customer to make DG viable.5:
A host of factors will affect increased investment in efficient. Energy-based charges to collect capacity costs would seem to offer the greatest promise in this regard. This depends not only on the standby tariff itself. The review of tariffs and operation on peak in this report suggests that the more favorable rate designs share common and central characteristics: they are designed to give customers a strong incentive to use electric service most efficiently. The rate structure yields a high value of retail rate savings per kWh produced on site instead of purchased from the grid. and to avoid charges when service is not taken. they reward customers for maintaining and operating their onsite generation.
which then extends for the following 11 months. coincident) peak. Of course. for a share of that peak demand or the peak in that month. A typical ratchet calls for billing the customer.. DG.C. Other simplifying assumptions having to do with the market price for the energy commodity were also made.. which further exacerbates the challenges for the customer in making the case for DG work. clean. whereas for delivery it will be a function of the customer’s noncoincident peak and its contribution to the need for dedicated and shared facilities. A relatively diverse system should have less of a need for longer-duration charges. The generic system that we model in the analyses is a high-capacity factor CHP system slightly more than 5 MW in size. EPA’s Combined Heat and Power Partnership defines CHP as follows: “CHP. This example assumes that this customer is on a calendar month billing cycle. as a function of demand or energy or according to some other measure) will be relevant to whether they pose barriers to DG and can be avoided.html>. and reliable approach to generating power and thermal energy from a single fuel source. including increased reliability and. “standby” is not differentiated from “supplemental” service. To the extent that generation and delivery charges are unbundled. particularly CHP systems with higher capacity factors. Whether this is the case depends on the probabilities and timing of outages and the overall load shapes of the relevant customer classes and the system as a whole. This is not the case in practice. Some standby tariffs allow for the conversion of the historical ratchet into the level of contract or reservation demand. the computation and application of the charges and ratchets can differ. also known as cogeneration.” even if the customer sheds load to compensate for the unplanned outage (see the discussion in Section III. Some tariffs define their consumption blocks in terms of kWh per kW of demand. is an efficient.eea-inc. in the case of CHP applications. save energy. and CHP systems. There are additional economic values provided by onsite generation. an ICF International Company.g.6:
There are a variety of terms and associated acronyms for customer-sited generation. the full requirements customer pays an energy rate that already includes the cost of the contingency reserves. In the case of generation. thus relating usage directly to levels of demand. reduced fuel use for onsite thermal needs. Whereas the partial requirements customer pays for its generation contingency reserves separately from the energy it uses. maintains a Combined Heat and Power Installation Database that contains data on CHP units in each state. By using the same energy commodity charge for both customers. If a higher peak occurs.” Energy and Environmental Analysis. unless it too is surpassed. but depending on the nature of their outages. Similarly. This is the consequence of a simplifying assumption in which the generation energy charges that partial requirements customers pay are the same as those paid by the full requirements customer. we have slightly
. all service taken by an Orange & Rockland DG customer is supplied under the partial requirements tariff. we use the catch-all term “DG” here because our analyses are concerned only with utility rates and not with the costs and benefits of different kinds of onsite facilities. At least one utility—Detroit Edison—calls the service that it provides to customers with onsite generators “backup. The tension with ratchets lies in precisely this circumstance. in each of the 11 months following their peak demand. whichever is greater. that new demand forms the basis of a new ratchet. The database can be accessed at <http://www. onsite generation.e. Onsite generation systems. some of which are synonyms and some of which refer to subsets of others: for example. the demand charge should be a function of the customer’s contribution to system (i. how these other charges are calculated (e.com/chpdata/States/MT. on physical assurance). they might have less of an impact on the need for grid-supplied capacity (both generation and delivery). For simplicity’s sake.
regulators might want to set rates that better reflect those impacts.overstated the cost of partial requirements service.
This assumes that the distribution. Mathematically.
. In the second case.and transmission-level diversity benefits (or losses) provided by DG customers do not significantly differ from those of full requirements customers. the differences between the two methods are as follows. it is the cost of the system’s generation reserves that is discounted (that is. Then applied to that discounted demand is a price per kW for the generation needed to cover it. it is shared among all customer classes according to their contributions to system peak) and is then applied to the total kW that a customer is expected to incur during an unplanned outage. If they do. though not significantly enough to affect the central conclusions. the amount of load to be served in the case of an outage is discounted by the probability of that outage occurring on peak. In the first instance.
g. *Note that. As-used demand charge First 500 kW of billing demand Next 1.. serving an island. Hawaiian Electric Company Tariff Summary
Unbundled Service for Full and Partial Requirements Customers (>1 MW) With Daily As-Used Demand Charges Hawaiian Electric Company Full Requirements Rate PS Part 1: Customer charge Customer charge Part 2: Delivery charges.66/kW-day $230/month $230/month Partial Requirements Rate SS
Source: Hawaiian Electric Company.26/kW-month $0.Appendix A: Additional Analyses of Specific Standby Tariffs
A.500 kW of billing demand Part 3: Delivery charges.1 Hawaiian Electric Company—Unbundled Rates and Daily Demand Charges
This is an additional example of a standby rate that makes use of daily as-used demand charges. Reservation demand charge* B.00/kW-month $9. is faced with particularly high costs. commodity $0. demand Sum of A + B A. Hawaiian Electric Company’s reservation demand charge applies only to the amount of demand associated with backup service (e. Table 8. full requirements Rate PS and partial requirements Rate SS.50/kW-month $8.15/kWh $0.064104 $0. unlike the Orange & Rockland contract demand charge.124/kWh $10.061010 $0.15/kWh $0.000 kW of billing demand Over 1.
.072087 $0. Its rates are provided in Table 8.50/kW-month $7. Hawaiian Electric Company. energy All kWh First 200 kWh/month per kW of billing demand** Next 200 kWh/month per kW of billing demand Over 400 kWh/month per kW of billing demand Part 4: Energy.
a preferred approach to standby rate design. Of interest is the fairly high per-kWh charge ($0. Consolidated Edison. enables the 42 percent reduction in the customer’s annual bill and results in the fairly high value of avoided retail purchases. shifts part of the revenue burden for partial requirements customers from an unavoidable delivery demand charge to a “pay as you go” energy charge. as a general matter. this charge could be much larger.3 percent of the average retail rate. in combination with the daily as-used demand charge. What matters are the relative shares of the total bill to which the various rate elements contribute.
The standby rate customer. This. The average cost of a grid-supplied kWh under the partial requirements tariff is approximately 5 percent greater than under full requirements. Obviously. if the recurring charges (customer and reservation or contract demand charges) are themselves set at disproportionately high levels. and the customer will reduce its utility bill by 42 percent. the delivery charge constitutes a relatively small portion of the total annual bill (approximately $90. An energy-based delivery charge is. The value of the average avoided kWh is 94. will avoid the purchase of 47 percent of its grid-supplied energy. In this example.124/kWh) for delivering energy to the partial requirements customer when the DG is offline. Table 9 compares this utility’s full and partial requirements tariffs. even a rate structure that makes use of avoidable charges might still impose relatively high bills on the customer with DG.000) because the onsite generation operates at a fairly high capacity factor. A similar charge is not imposed on full requirements customers. Any demand in excess of that amount is paid for under the otherwise applicable full requirements tariff.
Consolidated Edison—Daily As-Used Demand Charges
This analysis shows the full and partial requirements tariffs of an additional New York utility. but they pay delivery demand charges that range from 17 percent to 37 percent higher than partial requirements customers. But. for a less well-performing DG system. **Energy charges in kWh/month per kW of billing demand denote a declining block structure where the number of kWh under each block rate is a function of the monthly kW billing demand. in effect.the nameplate capacity of the onsite generation or a contractually agreed-on demand). This tariff. as in the other examples discussed in this report. in that it gives the customer a strong and direct incentive to ensure that their DG is properly maintained and operating.
demand June–September: sum of A + B + C A. Rate II.–6 p. energy All hours/days Part 6: Energy. partial requirements tariff SC-14RA and full requirements tariff SC-9. as-used demand
Source: Consolidated Edison. The average cost of a grid-supplied kWh under the partial requirements tariff is 6 percent greater than that under full requirements. 8 a.
The partial requirements customer.2 percent of the average retail rate.m. ancillary service.0018/kWh Energy. M–F. all hours All other months: sum of B + C B. energy M–F.Table 9.
. M–F. M–F.m. Rate II Part 1: Customer charge Customer charge Part 2: Delivery charges.–10 p. will avoid the purchase of 47 percent of its grid-supplied energy.m. Jun–Sept 8 a.–10 p. All days.m. and will reduce its utility bill by 43. other months Part 4: Delivery charges.0018/kWh $0.5 MW) With Daily As-Used Demand Charges Consolidated Edison Full Requirements Tariff SC-9. capacity at wholesale market prices $0. 8 a. B.m. Consolidated Edison Tariff Summary
Unbundled Service for Full and Partial Requirements Customers (>1. all hours 8 a.m.–10 p.m. C.0058/kWh $0.6910/kW-day $0.54/kW-month $0.m.86/kW-month $11.7 percent..14/kW-month $3.41/kW-month $0 $908 Partial Requirements Tariff SC-14RA
Part 3: Delivery charges.3423/kW-day $0. All other hours/days Part 5: System benefits charges. Jun–Sept 8 a. 8 a.m.m.m.m..0058/kWh $8.–6 p.94/kW-month $5.m. All days.. in keeping with the other examples. C.m.09/kW-month $10.–10 p. commodity $0. 8 a. The value of the average avoided kWh is 93.–10 p.5200/kW-day $5.
1999.11. This is called “natural monopoly. the long-run marginal costs of production. 94–95). In light of the economic and public welfare characteristics of utilities. The first is the widely held belief that this sector’s outputs are essential to the well-being of society—its households and businesses. Kahn. Competition cannot thrive under these conditions and. Prices should also be fair to competitive providers or. 25–41. while still enabling the utility to generate enough revenue to cover necessary expenses and investment and to provide a reasonable return on that investment.2 Thus. Pierce. environmental protection. all firms but one exit the market. They can be generalized in the two goals of economic efficiency and fairness (or equity). the markets by themselves will go a long way toward meeting these goals. Non-discriminatory access to service for all consumers. Economic regulation is seen then as the necessary and explicit public or governmental intervention into a market to achieve a public policy or social objective that the market fails to accomplish on its own. 243–246). Vol. 69–70. low-income support. 1999.1 Fair prices for consumers and investors. 20–25.” and.g. p. more accurately. and
. certain purposes for price regulation emerge. p. it can be said that economic regulation is intended to achieve outcomes that competition. The second is that its technological and economic features are such that a single firm often can serve the overall demand for its output at a lower total cost than can any combination of more than one firm.Appendix B: Principles of Rate Design
B. Vol. if it were possible in the market for electricity. I. p. pp.
For goods and services that competitive markets can provide. 372. prices in regulated industries naturally affect prices in competitive ones. 1961. They should also minimize any distortional effects on the economy—changes in how the economy and customers would act if there were perfect competition with no regulation and no monopoly. and Vol. energy efficiency) (Bonbright. universal service. Price regulation is intended to guard against the reaping of unjustifiably high profits (called economic “rents”). To achieve this objective. II. like monopoly power in general. it gives the surviving firm the power to restrict output and set prices at levels higher than are economically justified. would otherwise achieve (Kahn.. pp. the competitive process. pp. regulation sets rates that reflect. Other stated public policy objectives (e. Because electric utilities generally do not operate in competitive markets that would impose cost discipline on them. Pierce. 2. 17. 1961. eventually. 1988. regulation must fulfill that function. I. reliability is critically important. Adequate quality and reliability. pp.1 Basic Principles of Rate Design
There are two broad. 1988. fundamental justifications for governmental oversight of the utility sector. Because electricity is an essential service. which can then be further broken down as follows:
Economic efficiency. Bonbright. to the greatest extent possible. 47– 48. Also.
Cost-Related Objectives:
Rates should be set so as to promote economically efficient consumption. The need to cover historical costs. given the restraints (static efficiency).
Rates should be simple. set economically efficient prices. where the wellbeing of both the utilities and consumers is maximized. understandable. payable conveniently. Rates should promote innovation in supply and demand (dynamic efficiency).
. but these costs may only bear a passing resemblance to the marginal costs—what a customer must pay to receive one more unit of energy—that form the basis of economically efficient prices. all internalities and externalities). Undue discrimination should be avoided. and on. It remains today the comprehensive compilation on which regulators rely. Rates themselves should be stable and predictable. 291): Revenue-Related Objectives:
Rates should yield the total revenue requirement. certain. Bonbright’s principles are (Bonbright. acceptable to the public.vice versa.. and then meet other objectives of regulation requires careful judgment. beginning with a catalogue of the several and sometimes competing objectives of rate design. 1961. and easily administered. More specifically. James Bonbright (1961) dedicated five chapters and 120 pages to the subject. Rates should be apportioned fairly among customers and customer classes. The general goals of economic regulation inform the rate design process. The particular problem faced by regulators in this exercise is that the legitimate historical (accounting or “embedded”) costs that a utility incurs are to be recovered in rates.e. Rates should provide predictable and stable revenues. its investment. Rates should reflect the present and future private and social costs and benefits of providing service (i. the object is to set economically efficient and fair prices. p. while simultaneously giving the regulated firm a reasonable opportunity to recover its legitimate costs of providing service—including return of. Paraphrased. and therefore affect the overall efficiency of the economy—all the more reason to adopt utility rate designs that most closely resemble price structures in competitive markets and therefore do not create excessive distortionary effects on the economy.
in the long run. Proponents of DG make two fundamental arguments: (1) customers with onsite generation should be no more obligated to pay unavoidable charges than full requirements customers (in fact less so.3 This logic might suggest that the economist’s preferred price unit for electric service is the kWh charge (differentiated by time and. but they avoid costs when they do not use the good. given their asserted lower probabilities of needing service at times of peak).
Rates should be. regulators are rightly limited to consumption-based prices. but its practical application is difficult. are another approach.5 A customer’s guarantee that demand for standby service will not exceed a specified level (accompanied by facilities or equipment to make good on the guarantee. and ratcheted charges. drives its costs—and in the long run all costs are variable. to be paid regardless of whether. but also on the use of fixed. for the most part. and (2) their charges should be discounted in relation to those of full requirements customers. to account for (or reward) highcapacity factors (reliability) of onsite generation. But there are other objectives of rate design. and remind customers as well that their right to call on the system at any time depends in part on the availability of otherwise idle capacity. Price discounts or ratchet adjustments. passing along the way from as-used demand charges to ratcheted ones. because it is demand for units of the good. service is taken. because they provide diversity benefits to the system as a whole. But because prices should. might threaten the financial integrity of the utility and the overall reliability of the grid. that. The longer duration charges. In this way. As a principle. which. to the extent possible. arguably. This diversity benefit obviously depends
. they look very much like access fees. Debate focuses not only on the level of rates. it can be easily agreed on by all. the essential differences among them are their time denominations. if unmet. reflect the long-run marginal costs of production. known as “physical assurance”) is another tariff feature that allows for alternative rate treatment of CHP. and the costs to society of the resources allocated to that good (externalities) are fully covered. and the level at which.4 It certainly has its appeal. extends from the energy charges to the recurring customer charge. Unavoidable charges are inconsistent with the objectives of economic efficiency. geography). give the utility some greater measure of revenue predictability.6 The degree of diversity that customers with onsite generation bring to a system appears to be most often the thorniest issue that regulators deal with. Fixed and ratcheted charges might. consumers must pay to use the good. its rate design should reflect these differences. though supposedly still avoidable. arguably. measured by customers’ ability to avoid paying charges. The justification for demand charges lies in this balancing act. there is no reason why they cannot be extended to full requirements customers as well). To the degree that the characteristics of demand for standby service and therefore its costs differ significantly from those of the rate class to which the DG customer would otherwise belong. Daily as-used demand charges are one example of this (although. be designed to satisfy this principle—they cover the long-run costs of service and can be avoided by taking no service at all—but as a practical matter. recurring. electricity in this case. As pointed out earlier. free from controversies about proper interpretation
The tension among these sometimes competing and always challenging goals gives regulators a good deal of discretion in designing pricing structures. perhaps. The succession of rate structures.
and this will go a long way toward fairly allocating the costs of
.. but it can also be expressed in energy terms (per kWh) given assumptions about a plant’s operating characteristics. restricted to that component of service. any more would be wasteful and any less would. Restructuring accelerated the movement to unbundled pricing for the various components of service (i.e. a customer class’s full or partial requirement.e. but often there are variable operations and maintenance costs that are not incurred if the unit does not run.8 As described above. Primarily this is the cost of fuel. but nothing about vertically integrated industry structures prevents a similar unbundling of rates. more precisely. the pricing elements are combined and aggregated into simpler energy-only or energy and demand charges. and distribution). Customers will choose the tariff that better serves their needs and reduces their costs more. Capacity is the cost of the plant—or. Unbundling makes the nature of costs more transparent and.. Only that amount necessary to meet peak (and reserves—otherwise unused capacity to maintain reliability in case of unplanned outages) should be acquired. If multiple competitive suppliers provide generation services. of the ability to generate power—for the period of the purchase (hour. Three broad categories of costs emerge from this approach—generation. is to make the tariff optional—that is. separate prices for the differentiable elements of service—generation. like that of full requirements service. This means that it is a customer’s or. at least in the early years of a new standby rate structure.on the operating characteristics of the generation. transmission. and distribution—which can be separately priced as consumer understanding and administrative simplicity allow. Insofar as the load-serving entity (i. without remedial action. year).e. distribution utilities will provide only delivery service and regulatory interest in standby will be. Energy is the cost to actually produce kWh— that is. The amount of generation that a system needs is a function of its overall peak demand. time-differentiated pricing can be designed to reflect the expected costs of peak demand. We note here that the structure of the electric industry in a state might affect the nature of partial requirements service. if done properly.2
Pricing the Components of Electric Service
Rate designers differentiate the major components of the system according to the drivers of their costs—i. which system operators and utilities argue is far less understood than proponents contend. While this may result in a lower aggregate level of revenues for the utility from these customers. transmission. One way to deal with this issue. greatly reduces or even eliminates the potential for the cross-subsidization of one service by another. Where the benefits of changes in usage caused by more complex rate designs are not enough to justify the added metering and billing costs to support such rates.7
B. jeopardize system reliability. variable (or marginal) cost. according to the functions of the system. the utility or competitive service provider) knows generally when peaks will occur. Generation consists of energy and capacity costs. day. contribution to the system (or coincident) peak that determines its responsibility for the costs of the required generation capacity. give customers the choice of taking service under the standby tariff or under the otherwise applicable full requirements tariff. more accurately. month.. capacity is typically expressed in perkW terms. accordingly. it will reveal a good deal about the performance that customers expect from their machines and might indeed offer a better allocation of the risks between them.
the amount of operating reserves that must be available to meet load in the event that the customer unexpectedly takes energy from the grid—that is.12 A variation on the reservation charge is a fee for contingency reserves.. is referred to as “as-used. different services suited to the needs of the classes. which can vary insofar as the plant can be redeployed (used to serve other demands). A standard practice in the design of standby tariffs is to impose more than one type of demand charge. and therefore looks very much like an unavoidable. being treated as a separate class is good or bad (that is. and for facilities shared among distribution customers (e. then the non-DG customers are benefiting from the inclusion of DG owners in the class. the amount of resources to be held in reserve is correspondingly less than the full potential load that they might be called on to serve. in effect.” This charge is generally linked to the costs of shared facilities.9 Each customer class imposes unique demands on the system. and the costs associated with that usage. maximum demand.. and it greatly reduces the amount of excess capacity that the system must have to maintain a given level of reliability. To the extent that the usage characteristics of partial requirements customers. substations. For facilities dedicated to the customer. or ratcheted). If the load factors of DG customers are for the most part better than those of other customers in the relevant full requirements service class. capturing the benefits of demand response. from the perspective of DG customers. the driving force is coincident peak demand of the customers they serve. fixed. A combination of factors drives investment in the distribution system. they are typically combined within one demand charge (or
. at the time of a system peak. feeders. or sometimes daily. in particular. entitlement to sufficient operating reserves to cover the load in cases of an unplanned outage of any of the resources serving that load. But either way. Under this approach the customer has the same obligations that other load serving entities have: namely. The next charge is a usage-related demand charge. are less than 100 percent. such customers can be seen as constituting a different class. when its onsite generation suffers an unscheduled outage. Because the probabilities of two or more generating facilities (whether central station or customer-sited) suffering an unplanned outage simultaneously and. Whether.e. Though the costs are separable.).g. and capturing load diversity from the different power generation sources. are demonstrably different from those of related full requirements customers.11 The contract demand is often based on the net capacity of the onsite generator or some negotiated or specified portion of that capacity.10 Or it might be the other way around. regardless of when it occurs) drives investment. recurring fee that gives a customer the right to take standby service. which is applied against demand associated with standby service actually taken. Typically. among other things. etc. and the tariffs drawn up to reflect those different characteristics provide. The first is the reservation or contract demand charge. even if that call is never made. the reservation charge is applied against monthly billing demand (contract. which ostensibly covers the costs of the capacity that the utility must have access to in order to cover a call for unscheduled service. This is the effect of diversity.capacity among users. a customer’s noncoincident peak demand (i. in the absence of a ratchet. the average load factor (the ratio of average electric load to peak load) of the group and its contribution to system peak. a detailed cost of service study—using reliable data on the operational characteristics of DG systems—will be needed to inform the regulators’ decision about how to treat these customers. This charge is often a monthly. maximum potential. less or more costly) depends on. price per kW used and.
and other New York utilities use daily on-peak only (as-used) demand charges. of course.. are characterized by greater diversity than much of the distribution system.set of charges) for distribution service. Transmission investments are shared facilities and. Either way. the less diverse the system’s load. and so the fees it pays are not much different from those it would pay without the ratchet. A customer with relatively high load factors is less affected by the ratchet the closer its periodic demands are to its peak. is driven by the relevant peak demand. A number of utilities have eliminated multi-month ratchets for distribution service. it is worth examining the justification for the ratchet to determine if it is related to the nature of the costs incurred and if the capacity whose costs it covers is indeed unable to be put to alternative uses. The more diverse a system (or part of a system) is. priced on a per-kW-month basis. then the design of demand charges—specifically. Transmission costs tend to be less problematic than generation and distribution costs if only because they are typically a small portion of the bill. In many restructured states. not the prices of the distribution company. They require the customer to pay a fee related to a significant fraction of their peak demand in periods when their demand does not approach their peak. each month’s costs are determined separately and are unrelated to any previous month’s demand. their ratchets—becomes a focus of analysis. The distribution demand charge is multiplied by the customer’s billing demand. low ratios of actual usage (in kWh in a period) to maximum potential usage (the product of peak demand and hours in the period). depending on the size of the facilities in question. the greater the degree of coincidence in customer demands.e. Simplicity is one reason for this. For partial requirements customers. Portland General Electric assesses distribution demand charges on the basis of the customer’s peak in the month. a feature sometimes referred to as “physical assurance. the measure of the coincidence of customer demands. transmission charges are typically included in the prices of competitive generation suppliers. or an agreed-on contract demand. Another is the lack of a metering and data management capability that measures both customer coincident and noncoincident peaks on discrete sections of the distribution system— although advances in metering technology are changing this. its maximum potential demand. each has its own approach. it is priced on a per-kW (or per-MW) basis. which is one of several quantities (or some variation on them): the customer’s monthly noncoincident peak demand. the less impact the peak demand of any one customer or set of customers has on the overall peak of the system. Orange & Rockland. the negotiated contract demand might be accompanied by the customer’s promise not to exceed it (accompanied by special load-limiting facilities to make good the guarantee). Ratchets are most painful to customers with relatively low load factors—i.”13 Not all utilities offer these options. Conversely. This is another way of looking at the question of diversity. like distribution. If avoidability of charges is a key determinant of whether a rate structure is beneficial to DG. Because transmission.14 Rochester Gas & Electric.
environmental damage costs). however. anti-trust and anti-discrimination laws.g. given traditional metering technologies. This is not to say that competitive markets will. The relatively few instances of such fees in nonregulated markets (e. and Bonbright. a practical necessity. the rates of regulated monopolies must be sufficient to cover actual expenditures that are deemed prudent and used and useful. including real-time pricing. to the extent possible. Arizona Public Service Corporation sets a minimum number of hours per month at which standby service will be provided at base prices. 1998. do not drive their embedded costs per unit to equal their marginal costs. The problem is that utilities are natural monopolies and the economics of their industries. for instance when variable costs (e. early designs for competitive wholesale markets called only for energy pricing.) This is not to say that it is not appropriate. and financial requirements are all examples of government actions taken to assure that other highly valued outcomes (such as equity) are achieved. Regulation is intended to prevent that outcome and to ensure only the recovery of their embedded costs. for rate design generally. to set prices at short-run marginal cost. price should equal the marginal cost of the good. In addition. nor is it. health standards. because that describes the value to society of the resources that production of the good requires. easily measured. As a matter of economic theory. Early experience with these new technologies and prices has demonstrated that customer demand response. Some regulatory economists argue that the converse is also true—that when capacity is surplus. unlike those of competitive markets. and the preexisting distribution of wealth and income—to name a few factors—all affect the operations of markets in ways that often call for some form of governmental intervention into the market for the benefit of the public overall. especially where made possible by automated systems (e. satisfy all. including the external costs (e. the shutting down of one’s air conditioning when a specified price trigger is hit).g. the onsite generation must maintain a 75 percent capacity factor. 1961. or fully any. for example.. Indeed.. Tucson Electric Power’s standby tariff works in a similar fashion. Failure to stay at or below the minimum will result in penalty charges. Kahn.3
The economics literature in support of this statement is extensive. that this argument might have more appeal if all the costs of production. For example. p. Advances in metering infrastructure are enabling more dynamic rate structures.. This is not the case in the electric industry.g. performance requirements. as monopolies. consumers undervalue the good and use more of it than is economically justified. and the utility loses money. New York and Hawaii have both taken this approach. (See. for example. These are referred to as historical or embedded costs.g. which reveal hourly (or even shorter duration) changes in wholesale market prices for power. the profit-maximization imperative would cause them to set prices at levels that exceed their embedded costs. can be predictable and
. externalities. it is economically inefficient to charge greater than variable operating cost. One does not pay a toll. As a matter of law. Worse yet. Rate design aims. labor. were included in the price. the price of fuel) exceed the long-run marginal cost. they are virtually unknown in competitive markets. adjusted as appropriate to generate revenues sufficient to cover embedded costs. In that event. as symptomatic of an industry in which capacity (bandwidth) is plentiful and inexpensive. California is one state where this option is available. cellular telephone service) can be seen as exercises of some degree of market power and. An individual customer’s contribution to coincident peak is not. Content labeling. Moreover. The onsite generation is also subject to penalties for failure to do so.B. Chapters 3 and 4. based on a rolling 18-month average. in the long run. We would say. and the marginal costs of usage (in both the short and long runs) are very low. Transaction costs. to enter a grocery store. perhaps more importantly. although in New York the option was available only to customers who had onsite generation as of January 2003. by themselves. in certain circumstances. their embedded costs will exceed their marginal costs. to set rates that reflect marginal costs. of the welfare-enhancing objectives that a society embraces. lack of information. 318..
Technologies of this sort and the dynamic rate designs they support can have the effect of allocating costs more directly to those who cause them and. in effect.significant. we haven’t differentiated between the rates of vertically integrated utilities (those that are monopoly providers of generation. This. California is one state where this option is available. can more directly reward those who are able to avoid them. is a demand charge with a maximum 31-day ratchet. the state’s public utilities commission defined physical assurance “as the application of devices and equipment that interrupt a DG customer’s normal load when DG does not operate. conversely.
. but in the case of delivery-only service the charges would of course not include any generation costs. In Rulemaking 99-10-025 (1999). is true of all rate structures as a general matter: the nature of average-cost ratemaking is that customers with load factors that are below average pay less than what might be described as their “full share” of the class’s total cost of service. but should instead be limited to specified circumstances such as times of local distribution system peaks. The customers who cost less to serve than the average cover some part of the costs of those who cost more than the average to serve. The general description of typical standby rate designs applies to both.” The California Clean DG Coalition has since argued that a utility’s ability to refuse service should not be unconditional. and distribution services) and delivery-only utilities. it may result in total costs to the customer that will render most onsite generation projects uneconomic. of course. transmission.
This. If that level approximates the generation component of the otherwise applicable full requirements tariff and makes no provision for the probability that the service will be needed. and the customers with better-than-average load factors pay more than their share. What matters most under this scheme is the level of the per-kW reservation charge. And it is also true of pricing in competitive industries as well: the standard rate for delivery of a package by Federal Express doesn’t vary by distance. In this discussion. Whether this will be the case depends on the relationship between (1) the capital and operating costs of the DG system and (2) the demand and energy costs of grid-supplied power.
and E. Kahn. Inc. St. Vols. Regulated Industries. New York: Columbia University Press.
. R. 4th ed.Appendix C: References
Bonbright. I and II. Jr. A.P.. Gellhorn (1999).C.. Principles of Public Utility Rates. (1988). Public Utilities Reports. Paul. Pierce. The Economics of Regulation.J. J. (1961). MA: MIT Press. MN: West Group. Cambridge.
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