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HomeMy WebLinkAbout20030130 DSM Report.pdf-- 19:V' .r- '1' t:.lr!:. V IDAHO POWER COMPANY O. BOX 70 BOISE, IDAHO 83707 ! LED An IDACORP Company '1nn 1IHj "'" qf."LiJUJ ..,)--\\"1 U i"1 '-!. I MAGGIE BRILZ UTILIT IE SCOfit'jj S S I Dt45t! (208) 388-2848 FtU( (208) 388~449 mbrilz i1IJ idahoDower.com Director, Pricing January 30 2003 Ms. Jean D. Jewell, Secretary Idaho Public Utilities Commission P. O. Box 83720 Boise, I D 83720-0074 RE:Annual DSM Report IlL E -1J.2-.1/ Dear Ms. Jewell: Please find enclosed an original and seven (7) copies of Idaho Power Company s Annual DSM Report as required by Order No. 29026. I would appreciate it if you would return a stamped copy of this transmittal letter for our files. Sincerely, m~ .-6~ Maggie Brilz MB:mb Enclosures Ric Gale Bill Eddie ~t=R An IDACORP company F:ECEIVEO FILED znil3 JPJ'~ 30 Pi'i 4: L YJ r~!::;;Uc U T IL r(iE SCOl"iI1! S S ION ,"--",_., ,~"F"" - . Annual Demand Side Management Report January 30 , 2003 2002 DSM Tariff Rider Report In Order No. 29026, the Idaho Public Utilities Commission (IPUC) directed Idaho Power to "file an annual written report to the Commission detailing: the Advisory Group s recommendations, the Company s response to those recommendations, the associated program costs, the DSM accounting numbers, customer response data and information on new DSM opportunities This report reviews those issues in three sections. Section I addresses program description, costs and customer response as well as the Advisory Group s recommendations for that program and Idaho Power s response. Section IT reviews the rider funding and expenses and Section III provides information on Idaho Power s efforts to look at new DSM opportunities. I. Program details, Advisory Group recommendations and the Company s response to those recommendations Since the formation of the Energy Efficiency Advisory Group (EEAG) in spring, 2002, the group has met five times. The results of the first meeting, which was held on April 30, 2002, were reported to the Idaho Public Utilities Commission (IPUC) in a report filed May 2, 2002. Subsequent meetings were held July 11th, September 5 November 14th and January 9th, 2003. The EEAG consists of 13 customer state agency and special interest representatives and two representatives from Idaho Power. Meeting minutes and other meeting materials are provided to all EEAG members, including IPUC staff, and are available upon request. As of January 2003 the EEAG has recommended implementing three specific customer DSM programs that have a combined total estimated budget of $1 710 000. These programs and the timeframe for their implementation are: Program Lighting Coupon Program School Operator Training Budget $850 000 $50 000 Timeframe September 2002 - April 2003 November 2002 - December 2002 Page 1 Air Conditioner Cycling Pilot Program $810 000 March 2003 - December 2004 The major activity for the Lighting Coupon Program was conducted during the fall, 2002; however, several aspects of the Program will continue until April, 2003.The classroom component of the School Operator Training Program was implemented in November, 2002. Idaho Power filed an application with the Commission on December , 2002, requesting approval to implement the Air Conditioner Cycling Program (Case No. IPC-02-13). Lighting Coupon Program Program description Starting October Idaho Power sent a brochure and two $3 coupons 359,465 residential and small commercial customers. These coupons could be used toward the purchase of Energy Star labeled compact fluorescent light (CFL) bulbs from participating retail stores. Ecos Consulting was hired to coordinate coupon redemption and to work with the participating retail stores. Idaho Power staged a fairly aggressive public relations campaign designed to educate our customers about the characteristics of CFL bulbs and to let our customers know of the coupon availability. Prior to the coupon mail-out , " ticklers" were inserted in customer bills, articles were printed in the Consumer Connection and messages were printed on the bill envelopes. Through these various means of communication, the Company attempted to alert customers to the presence of the coupons in their bills so they would not throw them away or destroy them. The program campaign kicked off with an announcement during the Alexander House Energy Star Open House with Governor Kempthorne on August 20, 2002. During October and early November Idaho Power sponsored three launch events at community shelters to help upgrade the lighting in the facilities and provide a forum for local news coverage. Launches were held at the Ike Kissler Safe House in Twin Falls, the Bannock House in Pocatello and at City Light Home For Women and Children in Boise. Radio ads were placed starting mid-October through mid-December and print ads were placed Page 2 in 18 newspapers across the service territory. Idaho Power was able to place two large educational information articles in the Idaho Statesman discussing bulb selection placement, characteristics and disposal, and all print ads had an educational message. Idaho Power worked with retail stores across the service territory to sell Energy Star CFLs and accept the coupons. Customers could look up information about the program on the Idaho Power web site and locate participating retail stores near them. In addition, there was a toll free phone number available for customers to use for assistance in locating participating retail stores. During the campaign, program field personnel manned information booths at stores to answer questions and promote the program. These booths were a successful way to understand customer concerns and promote sales. Idaho Power offered co-op advertising to retail stores to promote the program and several stores ran their own ads. Idaho Power distributed extra coupons to customers who called our Customer Service Center and requested extra coupons. Meter readers and linemen handed out coupons to customers they encountered during their workday. Coupons were included in high bill packets, and extra coupons were delivered to senior centers and community centers. The coupons expired December 31 , 2002. Savings estimates are based on regional evaluations and indicate an annual reduction of 67.5 kWh per bulb when compared to an equivalent incandescent bulb. Program costs and customer response Preliminary results as of January 15 , 2003, show over 32 000 coupons redeemed. The budget for this program is $850 000. Actual expenditures to date are approximately $321,471. Final participation numbers for the coupon program will be available in February 2003 , but appear to be well below the desired target penetration of 15% (or 108 000 coupons). considered. Therefore, a second phase of promotions is currently being Program numbers thus far show that of the coupons redeemed, 9% were redeemed by small commercial customers and 91 % were redeemed by residential customers. This breakdown is roughly the same ratio of those mailed out and indicates that both residential and small commercial customers redeemed the bulbs at roughly the same rate. Page 3 Over 128 retail stores that sold lighting products signed up to be participating retailers. The vast majority of coupons were redeemed at larger corporate stores that don t break down redemption rates by region. However, for the smaller retail stores there is data that show excellent participation across the service territory. For example customers in the western part of the service territory submitted 20% of the coupons redeemed at smaller retail stores; customers in the southern area, 26%; customers in the eastern area, 22%; and customers in the central Boise area redeemed 32% of the coupons redeemed a small retail stores. Energy Efficiency Advisory Group recommendations Idaho Power presented the proposal for a Coupon Lighting Program to the EEAG during the July 11 th meeting. Idaho Power received the following recommendations. The general consensus of the EEAG was that Idaho Power should implement the CFL program Idaho Power initiated implementation of the program The EEAG suggested that the program be offered to both residential and small commercial customers Idaho Power included small commercial customers in program The EEAG wanted Idaho Power to track the small commercial participation. Tracking of the small commercial participation would assist in the allocation of program costs to each sector. Coupons were coded so that the redemption by each customer group could be tallied The EEAG suggested a marketing and education component be included as part of the program. Idaho Power included an extensive marketing and education plan in the program implementation The EEAG was evenly split between offering customers 1 coupon with a face value of $4, or 2 coupons with a face value of $3. Page 4 Idaho Power choose to offer 2 $3 coupons because of the potential for this design to provide more energy savings and increased cost- effectiveness The suggestion was also made to provide a means of delivering CFLs to lower income customers. Idaho Power added a component to the program that distributed CFL bulbs free of charge to low-income customers through the Community Action Agencies ' Low Income Weather Assistance (LIWA) program. Additionally, there was some concern expressed by the EEAG that there might be a large number of people who have already purchased CFL bulbs. In response to this concern, Idaho Power commissioned a short telephone survey, fielded in August, that indicated 61% of Idaho Power customers had purchased CFLs in the past 12 months. This finding was shared with the EEAG during the September 5th meeting and after discussing the issue, the EEAG still felt Idaho Power should proceed with the program. Next steps Idaho Power is pursuing a second phase of the CFL program with other kinds of program promotions. The objective is to leverage the high awareness of the program established in the first phase with lower-cost promotions to increase penetration and reduce overall program cost per bulb. School Building Operator Training Program description In order to help school districts manage their energy costs, and in recognition that a key to energy savings is a well trained operations and maintenance staff, Idaho Power joined with Idaho Department of Water Resources, Energy Division and the Northwest Building Operators Association (NWBOA), to offer technical operator training. Page 5 NWBOA has a five-day level one training that has been supported and evaluated by the Northwest Energy Efficiency Alliance. A letter of invitation was sent to all K-12 school districts in the Idaho Power service territory. Training was scheduled for November 13- 15 and November 20-, 2002. The training was included as part of the annual Idaho Energy Conference so that participants could attend the sessions and activities with other people who are focusing on energy efficiency. The cost of the program included operator training ($400 per participant), conference registration and meals and lodging for out-of- town attendees. In addition, attendees received a year membership in NWBOA and, if they passed the course tests, were awarded a certification. Because this program was exclusively education and training, there are no specific installed measures for saving electricity. However, the Northwest Energy Efficiency Alliance conducted an evaluation of the NWBOA training several years ago and found that on average attendees save 55 000 kWh per year by applying the lessons learned in this training. Program costs and customer response Thirty school building operators from throughout Idaho Power s service territory attended the training and most were awarded Level I certification at the Idaho Energy Conference. There was excellent representation from small and large schools and there was broad geographic representation. The budget for this program was $50 000; $33 538.52 has been expended to date, with $10 000 set aside for further development. Energy Efficiency Advisory Group recommendations On September 5th, Idaho Power presented to the EEAG the proposal for the K- building operator training program and received the following recommendations. Strong support was expressed from the EEAG for sponsoring the training. Idaho Power initiated this program The EEAG suggested that a survey be conducted with the participants after the training to determine if changes to building operations are made as a result of the training. Page 6 Idaho Power plans to conduct a survey of participants in the first quarter of 2003. The EEAG supported paYIng hotel and meal costs for out-of-area attendees in order to encourage participation by building operators that would need to travel. Funding was provided for lodging and meal expenses for this training Next steps A survey of attendees is planned for the first quarter of 2003. This survey will ask participants what activities and measures they implemented because of the information provided in the workshops. Idaho Power would like to make this training information available to school districts that were not able to attend the training. Therefore, Idaho Power has set aside $10 000 to work with NWBOA to provide the training and certification process in a distant learning setting. NWBOA is currently developing a CD that contains the material provided in the Level I training. It is anticipated that Idaho Power will sponsor a number of operators to test this training method. Residential Air Conditioner Cycling Pilot Program Program description On November 14th, Idaho Power presented a proposal for a Residential Air Conditioner Cycling Pilot Program. In the program, Idaho Power will install, free of charge, an intelligent programmable thermostat in participants homes. The Company will then be able to send a signal to the thermostat to cycle the air conditioner off when resources are needed for peak load reduction. The pilot will target 200 participants the first year and 300 participants in the second year. All participation is voluntary. This program will be offered to residential homeowners in Boise and Meridian who have central air conditioning. Page 7 Energy Efficiency Advisory Group recommendations Group discussion centered around three areas of the proposed program design: 1) the ability to "opt out" of a cycling event; 2) the need for an incentive to participate in the program in addition to the free programmable thermostat, and 3) the number of days in a month and hours in a day that cycling may occur. The EEAG suggested that some provision allowing customers to "opt out" of the program, especially in emergency situations, was necessary. Idaho Power is allowing participants to opt-out with notification by pm of the day prior to the day they wish to opt out. This notification time is needed in order to pre-schedule this resource into our overall resource mix. The group also suggested that some incentive in addition to the programmable thermostat would be necessary in order to entice customers to participate.The potential to start with a small incentive and then increase it if necessary was discussed. Along with the incentive of a new programmable thermostat, a $5/month incentive was added for program participants for the three months per year of program operation It was also suggested by the EEAG that any incentive paid to participants be paid only after the customer had completed participation in the program for the duration of the program. Idaho Power examined whether this was possible and decided not to structure the incentive in this way. Because of the characteristics of the Idaho Power billing system it is necessary to credit the incentive on a monthly basis. Several members expressed the sentiment that in order to help customers feel comfortable about joining in the pilot program, some description of when the cycling might occur was necessary. Idaho Power will provide this information during the participation solicitation process. Page 8 The EEAG in general felt that the number of days and hours per day that cycling could occur could be expanded from the proposed ten days and four hours per day without decreasing interest in the program. The hours of the day that the program can operate was expanded to include the eight hours between pm and 9pm. The EEAG was asked if they supported Idaho Power pursuing this program and there was unanimous endorsement. Based upon the support of the EEAG, Idaho Power pursued the implementation of this program. DSM Small Projects and Education Fund Proposal Description During the January 9 , 2003 EEAG meeting, Idaho Power proposed that starting January 1 , 2003 , two set-aside funds be established. One fund will provide a small amount of money for very small project requests and a second fund will provide a similar amount for education efforts. The amount of money set aside each year for each fund is 2% of the total annual DSM tariff rider funding. Energy Efficiency Advisory Group recommendations The EEAG endorsed the proposal to create the two set-aside funds. small amount of discretionary funds will allow Idaho Power to respond to small requests in a timely manner. In accordance with the EEAG discussions, Idaho Power has established these funds The EEAG did not want these small project and education funds to be viewed as "secret" funds and suggested that Idaho Power let customers know of their availability in some way. Idaho Power is exploring ways to put notification of the availability of these funds on the Idaho Power web site In addition, the EEAG desired that all customer segments have access to the funds. Page 9 Idaho Power will monitor the allocation of these funds to ensure all customer sectors have access . The activities funded by these set-aside funds will be reported to the EEAG at the regular meetings. DSM Comprehensive Study Description As directed by Order No. 29026, Idaho Power consulted with the EEAG regarding the need to initiate a comprehensive DSM assessment study. Because Idaho Power s primary resource need in the near future is for summer peak reduction and because most of the regional data available does not address summer demand reduction DSM options, Idaho Power suggested that if a study were undertaken, it should focus on residential and commercial summer demand reduction potential on Idaho Power system. Various study design options were discussed. It was suggested that the cost for a comprehensive study could range from $100 000 to $150 000. Energy Efficiency Advisory Group recommendations A suggestion was made by the EEAG to have Idaho Power come forward with a specific recommendation for a study that would provide the most value, present the recommendation to the EEAG, and then gather input specific to the recommendation. Idaho Power evaluated options and presented a study design to group The group generally supported an abbreviated study, although there was some support for a larger study. Idaho Power proposed a study limited to identifying summer peak demand reduction programs The suggestion was made to expand the list of potential RFP recipients. Idaho Power added some suggested consultants to the list of consultants to receive the RFP Page 10 Idaho Power has a final draft of the RFP incorporating suggestions by the EEAG. Residential Time-of-Use Pricing Prior to submitting its Residential Time-of-Use Pricing Viability Study (Study) to the Commission on September 12, 2002, Idaho Power solicited input on time-of-use pricing for residential customers from the EEAG. A copy of the Company s Study is attached as Attachment 1. DSM Screening Criteria Description During the January 9, 2003 EEAG meeting, Idaho Power proposed the following set of screening criteria for use in selecting DSM programs funded by the tariff rider. First, programs will be cost-effective. From a total resource perspective estimated program benefits must be greater than estimated program costs. As shown by the last Integrated Resource Plan, programs that decrease summer peak demand will be valuable because they reduce the need for peak resources. Programs that capture cost- effective, lost-opportunity DSM resources will be encouraged. Second, programs will be customer-focused. From the participants ' perspective programs will offer real benefits and value to customers. Third, programs will be as close to earnings-neutral as possible. From the utility's perspective, programs will be selected to minimize the negative impact on shareowners. Energy Efficiency Advisory Group recommendations The EEAG generally endorsed the overall screening criteria proposed by Idaho Power. The EEAG suggested adding another criteria to ensure that there is equity between customer sectors when it comes to spending rider funds and that attention paid to equity within a sector. Page 11 Idaho Power added a fourth criterion: Programs will be equitably distributed. From the customer s perspective, programs will be selected to benefit all groups of customers. Over time, programs will be offered to customers in all sectors and in all regions of the Company s service territory. The EEAG felt there should be flexibility when project eligibility is determined. For example, there is support for funding of instruments for measuring electricity use in the industrial and commercial sectors. Idaho Power will try to build flexibility into the screening process The EEAG suggested looking for ways to leverage the funds, like initially offering rebates at only 10% of project costs instead of starting at 50%. Idaho Power is pleased with the overall process and finds value in the recommendations and feedback received by the group. II. Rider funding and expenses 2002 DSM tariff funding 592 049 Expenditures EEAG meeting costs Lighting Coupon Program School Building Operator Training * Includes January 2003 expenditures $ 1 825 $ 321 471 * $ 33 539 * III. New DSM opportunities The primary work in 2002 was forming the Energy Efficiency Advisory Group and implementing the first set of programs. Now Idaho Power, along with input from the EEAG, is establishing a long-term look at the DSM activities. The first step in this process has been completed with the development of the high-level program screening criteria. These criteria will be used in selecting new programs funded through the DSM tariff rider. The Company is now establishing the process to apply the screening criteria to specific program options. Page 12 In addition, Idaho Power has two efforts that are in the process of examining new DSM opportunities. It is anticipated that the DSM study reviewed earlier will provide suggestions for programs appropriate to Idaho Power s system that will reduce demand during the summer peak load. Since this is a specialized study and since there is no solid regional data to draw from, Idaho Power plans to hire a contractor to complete this study. The study has not been awarded at this time. On a parallel path, where there is information and data available, Idaho Power is compiling a list of program options in the service territory. This list includes developing local delivery options of market transformation programs offered by the Northwest Energy Efficiency Alliance. It also includes irrigation and industrial program options developed with internal staff. Page 13 /ltI/1c mtNt I r' ; ~ , , r- '\' r- !\. ~ l, t:..; ,:: L~J FiLED "'", j L-- nY'r;;cJ'illJ.dJ,-, ;.) ' rd '. 0 UTI LIT itS COI'\i"jiSSION Residential Time-at-Use Pricing Viability Study Report to the Idaho Public Utilities Commission ..- DAHO POWER September 12 , 2002An IDACORP company BACKGROUND In Order No. 28894 the Idaho Public Utilities Commission ("the Commission directed Idaho Power Company ("the Company ) and the Energy Efficiency Advisory Group ("the EEAG") to consider implementing a time-of-use metering pilot program. In Order No. 29026 the Commission reaffirmed its directive that Idaho Power and the Energy Efficiency Advisory Group "evaluate and report to the Commission on the viability of a Time-of-Use residential metering program by September 12 , 2002" To assist in evaluating the feasibility of residential time-of-use (TaU) pricing, Idaho Power engaged the services of Christensen Associates. Christensen Associates is an economic consulting firm that has been providing consulting services to the energy industry for more than 25 years and is well known in the industry tor its work with time-ot-use and real-time pricing and market-based interruptible load programs. This report is comprised ot the following sections: An overview ot residential time-ot-use pricing provided by Christensen Associates An analysis performed by Christensen Associates assessing the potential benefits of residential time-of-use pricing for Idaho Power Issues relating to the implementation ot time-ot-use pricing which are specific to Idaho Power Input from the Energy Efficiency Advisory Group Conclusions on the viability ot residential time-ot-use pricing at this time Christensen Associates Overview An Overview of Residential Time-of-Use Pricing - Problems and Potential Steven Braithwait Christensen Associates July 15, 2002 The Idaho Public Utility Commission has asked Idaho Power to investigate the viability of time-of-use (TOU) pricing for its residential customers. This memorandum serves as the first step in assisting Idaho Power to conduct that assessment. It provides an overview of residential TaU pricing, including the following topics: an historical perspective a discussion of potential problems that can limit the benefits of residential TOU to utilities a description of new types of TOU pricing that show promise in addressing some of those problems, and a summary of evidence on customer price responsiveness. 1. Background and historical perspective The issue of market design , and the current disconnect between wholesale and retail power markets, has been the focus of intense discussion in recent months. It has been generally acknowledged that hourly wholesale power costs vary substantially across hours, days and seasons , while most customers face fixed retail prices. Thus, customers have no incentive to cut back usage during periods of high wholesale costs, which would provide needed relief from wholesale price pressures. As a result, various demand response mechanisms have been suggested to remedy this problem. One category of demand response mechanisms is dynamic pricing, in which customers face retail prices that directly reflect conditions in the wholesale market. The most common example of dynamic pricing is real-time pricing (RTP) for large commercial and industrial customers. However, interest in the general topic has renewed discussion of the potential value of TOU pricing for residential customers. Tau pricing has been studied in some detail, in a variety of pilot and permanent programs , over the past twenty-five years, but has never achieved widespread use for small customers. Over that time , utility rate designers, regulators, academics, and consultants have debated the fundamental principles of retail electricity rate designs. Traditional utility rate design has focused largely on recovering allowed costs , and on methods for allocating those costs fairly across various customer types. A relatively low priority has been given to establishing prices that reflect differences in the incremental, or marginal cost of generating and delivering electricity in different time periods. The principal argument in favor of Tau pricing has always been economic efficiency TaU prices reflect differences in the average cost of generating and delivering power during particular time periods, thus providing more appropriate price signals to customers than do flat rates. Customers can achieve benefits under TaU pricing if they can shift sufficient consumption from peak-period hours in which the price exceeds the standard flat price, to lower-price off-peak hours. Utilities can realize net gains from those same load shifts by avoiding some peak period sales whose cost exce~ds the revenue generated, and selling more during low-cost off-peak periods. However, these TaU benefits must be traded off against higher metering and administrative costs. Estimates of that benefit-cost tradeoff have generally not been favorable. Two main factors have weighed against the benefits of TaU pricing for residential customers. First , TaU prices do not reflect the variability of wholesale power costs with sufficient accuracy. For example, peak period prices (e.12/kWh) are generally designed to represent an average across expected wholesale costs during peak- period hours in a given season (e.summer).1 However, wholesale power costs can range widely from moderate to very-high levels , depending on actual load levels and supply conditions. In many hours. TaU peak period prices substantially exceed the actual cost of power (e.a Tau price of $.12/kWh versus a wholesale cost of $.04 to $.06/kWh). However, in the very hours in which costs reach their highest levels, the peak period price is likely to fall far short of that level (e. 12/kWh versus costs of $1.00/kWh or more). Thus , while TaU prices do a better job than a flat price of reflecting cost differences on average, the price signal is still not very accurate. When TaU customer reduce load during those peak hours in which costs are actually low , utilities' revenue can be reduced by more than their costs. Second , the relatively low usage level of residential customers, combined with the first factor of inaccurate prices , limits the overall magnitude of potential benefits from customer response to TaU prices. These benefits must be traded off against the additional cost of metering and billing. Tau rates have generally not been mandated, or established as the default tariff for residential customers. Most Tau programs have been offered as voluntary programs, typically targeted at customers with high usage levels , or ownership of major appliances such as central air conditioning or pool pumps. As a result, most residential TaU tariffs have relatively few customers. Two recent programs promoted by Puget Sound Energy (PSE) in Washington State, and Gulf Power in Florida , provide indications of potential renewed interest in 1 To cover expected costs, Tau prices actually need to reflect a load-weighted average of hourly wholesale costs, where the weights represent the load pattern of the customers expected to take service under the rate. residential TaU. PSE has undertaken an ambitious program to install advanced interval meters for all of its residential customers, along with software and communication devices that give customers the ability to monitor their energy usage and PSE's wholesale power costs online. PSE has assigned all customers with the new meters to a TaU rate , although customers have the right to opt out and return to a flat rate. PSE claims that a large share of the cost of the metering and communications system may be covered by improved meter reading and billing efficiency, even before accounting for the benefits associated with customer load response to TaU prices. PSE has also discussed a range of potential advanced pricing approaches that they may consider offering to take advantage of the metering and communications capabilities. Gulf Power has recently announced a planned expansion of their pilot. Residential Service Variable Price (RSVP) program , which combines advanced interval metering, and communication and control technology with a TaU rate that includes a dispatchable "critical peak price." This program, described in more detail in section 3, has the potential to solve a number of the problems with traditional TaU pricing. 2. Problems with traditional residential TOU pricing Traditional Tau pricing has typically been characterized by two or three fixed price levels (e.peak, shoulder and off-peak) for two seasons (e.summer and non- summer). The prices are designed to represent the average cost of generating and delivering power to a class of customers during those periods. Potential problems associated with traditional TaU pricing include the following: inaccuracy of TOU prices; revenue attrition due to overall reductions in consumption; revenue attrition due to customer self-selection in voluntary rates; and inadequate benefits relative to costs. Inaccuracy of TOU prices Utility planning and operations staff have always recognized the variability of electricity costs. However, prior to the deregulation of wholesale power markets these costs were largely internal to individual utilities , and not visible in public markets. As wholesale power markets have opened up, time-varying power generation costs have become reflected in wholesale energy prices. The increasing opportunities for trading power in wholesale markets make these prices the opportunity cost of power for most utilities, regardless of their mix of generation resources. In spite of the variability of wholesale power costs , traditional utility rate design has focused largely on recovery of allowed costs through fixed retail prices, using methods designed to allocate those costs fairly across various customer types. Figure 1 illustrates the resulting disconnection that can exist between varying wholesale energy costs and fixed retail prices. The curved line in the figure shows hourly wholesale prices in the PJM East region for the summer of 2000, arrayed from high to low. The flat line shows the load-weighted average of these prices which turns out to be approximately $50/MWh (or $.05/kWh). This value represents a typical flat seasonal energy price that might be offered to customers in this region. If charged in all hours , it would recover the same amount of revenue as if the actual variable costs were charged in each hour. Note , however, that in more than 70 percent of the hours of the summer, wholesale electricity costs were less than the average price (sometimes much less), while in more than 5 percent of the hours electricity costs were more than twice as high as the average. Figure 1. Disconnect Between Wholesale Energy Costs and Retail Prices (PJM East Summer 2000) $300 $250 $200 $150tit $100 $50 10%20%30%40%50%60%70%80%90%100. Cumulative Percentage of Hours -Wholesale Price Load-weighted average Competitive markets for other commodities tend to produce prices that reflect production costs. The frequent wide differences between wholesale electricity costs and retail prices suggest extensive foregone opportunities for economic gain. That is , in an important but relatively small number of hours, the cost of producing electricity far exceeds customers' value of consuming it, as reflected in the price they willingly pay. Reductions in usage during these hours would save costs far in excess of customers' forgone value of power. However, it is also important to recognize that typical retail tariffs give customers no access to the relatively low- cost power that is available in the vast majority of hours. Increased usage during these periods would produce value to consumers that exceeds the cost of generating that power. The figure above shows costs in all hours compared to a single fixed average price. Similar figures could be constructed to illustrate the distribution of costs in peak and off-peak periods. While the results would undoubtedly be less extreme, the wide distribution shown suggests that a fixed peak-period price would exceed costs in many hours, but lie below wholesale costs during the few, but important hours of highest costs. If customers reduce load in all peak periods, then during low-cost hours, utilities lose more revenue than they save in avoided costs; and during high- cost hours , utilities face costs that exceed revenues. Section 3 describes two types of innovative TOU price structures that allow closer matching between TOU prices and actual market costs. Revenue attrition due to overall reductions in consumption Under standard utility rate design methods, TOU prices are typically constructed to be revenue neutral for customers in a particular rate class at the at the average usage pattern for that class under standard rates. That is, the average monthly bill under TaU prices , at the same consumption pattern used to design the flat rate would remain the same as under a standard flat price. Customers then have an opportunity to lower their bill if they shift load from peak to off-peak periods under TaU pricing. However, one typical finding from studies of customer response to Tau prices is that in addition to shifting load from peak to off-peak periods customers tend to reduce overall consumption somewhat. This reduction can cause utilities to recover less revenue than planned. This revenue attrition is largely the result of bundled tariffs that are designed to recover transmission and distribution costs, as well as energy costs , through a volumetric (per kWh) price. That is, overall reductions in energy consumption lead to corresponding reductions in the cost of energy, though not in T & D costs, which are largely fixed. One potential solution to this revenue attrition problem is to redesign TaU tariffs to recover a larger portion of T & D costs through monthly customer charges , where the size ofthe charge may vary by customer size. Revenue attrition due to customer self selection under voluntary rates Calculating appropriate TaU prices is a reasonably straightforward exercise if the rate is mandatory for a particular customer class, or group of customers (e.all residential customers with both electric space heating and water heating). In that case , the expected loads , and thus the expected load-weighted energy costs, can be calculated based on existing load research data and information on expected power costs. However, the situation is more complicated in the case of an optional TOU rate. The problem is caused by two factors - the diversity of customers' usage patterns and a lack of hourly or TOU metered data for all customers. Regulated electricity prices for residential customers are typically fixed across a broad range of customers. The prices are set to recover the costs to serve the customers in the class, based on metered usage data for a load research sample of customers. However, the actual cost to serve different types of customers in the class can vary widely, depending on the percentage of their usage that occurs in the relatively high-cost peak period. The average cost to serve some customers may be substantially lower than the tariff price, while the cost to serve others may be much higher. However, without metered data , the energy supplier cannot easily distinguish between the costs to serve individual customers. Two possible approaches for setting the regulated prices of an optional TaU rate illustrate the potential problems involved with traditional designs. In the first approach , TaU prices are set to be revenue neutral to the standard tariff for the average customer in the class (i.the TaU prices are set to recover the same revenue as under the standard tariff, at the class-average level of usage). In the second approach, the TaU prices are designed to be revenue neutral for those customers that the utility expects are most likely to select the TaU rate (i,the TOU prices are set to recover the same revenue as under the standard tariff, after accounting for the lower-cost usage patterns of the customers most likely to accept the TaU rate). In the first case, the customers most likely to choose the TaU rate are "instant winners" who would see lower bills than under the standard tariff, even without changing their usage pattern, since their peak-period usage is less than average. This outcome , however, would leave the utility with less revenue than before, and is thus not revenue neutral across both the standard and TaU tariffs, In the second case, the customers most likely to choose the TaU rate are those with peak-period usage that is lower even than the average of those customers targeted'for the rate. As a result, relatively few customers are likely to choose the TaU rate , and those that do are still likely to see lower bills (and hence lower revenue to the utility) than if they had remained on the standard tariff, even before any load shifting, Possible solutions to self-selection problems One solution to the revenue attrition dilemma posed by these two approaches is to treat both the TOU rate and the standard tariff as optional once TaU is offered. Each rate is then priced to reflect the expected cost to serve the customers likely to select it. That is , the TaU prices are set to recover the 'lower expected cost of serving the customers most likely to accept the TaU rate , and the standard tariff prices are set to reflect the higher expected cost to serve the remaining customers. With such designs, the utility is more likely to recover its allowed revenue, while achieving greater participation in the TaU rate.2 This is also the natural approach and outcome that will be followed by competitive energy suppliers offering alternative pricing options to customers in a broad market. 2 This design is arguably more fair in that it produces less intra-class cross subsidy than a single flat rate. Another approach to addressing the revenue erosion problem is to attempt to limit the applicability of the TaU rate to particular customer types whose readily identifiable characteristics are likely to imply costs to serve that are lower or higher than average (e.customers with electric space heat and water heating). Yet another approach is to use a two-part pricing mechanism, with a customer-specific baseline level of usage, similar to the method used in two-part real-time pricing programs. This approach maintains revenue by billing each customer s baseline usage level at their standard rate, and applying TOU prices to differences between their actual and baseline usage. It gives each customer an incentive to respond to the TaU prices , but provides bill stability if they maintain their usage at baseline levels. Two potential weaknesses of this approach for residential customers are a lack of information on individual customers' baseline usage patterns , and a perception of greater complexity compared to a standard TOU rate. A final solution is to install advanced interval meters for all customers, and charge prices , either flat or TOU , that reflect each customer s actual costs. 3. Innovative new types of residential TOU pricing As noted in Section 2 , a fundamental problem with traditional TOU pricing is the inaccuracy of TOU prices in reflecting wholesale power costs. Two new types of TOU pricing designs show substantial promise for addressing this problem. Both designs involve some form of variable , dispatchable pricing, in which one or more of the TaU prices may be modified on a day-ahead, or shorter notice basis to reflect expected wholesale market prices. One version , sometimes called "critical-peak" pricing, involves a feature in which the peak-period price can be increased to a higher than normal "critical" level in response to high-cost conditions in the wholesale market. The other, exemplified by Electricity de France s (EdF) Tempo tariff, consists of multiple sets of TOU prices that apply to different day types , which are designated and announced a day in advance. Recent examples of the critical price TOU approach have combined variable pricing with communication and control technologies. The communication device allows the utility to signal a different price depending on wholesale price conditions. Rate structures of this type have typically taken the form of a standard three-tier TaU rate (e.peak , off-peak and shoulder periods), with the addition of a critical price that applies only occasionally when wholesale prices or reliability conditions reach certain critical levels (critical price levels appear to have ranged from approximately 25 to $.50/kWh , and many programs limited the number of critical price hours to no more than 2% of all hours). Under this approach, the standard peak period price may be set at a level substantially below typical TOU peak-price levels, because it does not have to cover the relatively few , but high-cost hours in which the critical price applies.3 The lower peak price and occasional critical price allow a better match between TOU prices and wholesale costs. This feature may be particularly valuable to utilities in the Pacific Northwest, where extensive hydroelectric 3 For example, Gulf Power Company s standard peak period price is $.O87/kWh, which contrasts with values of $.15 to .20/kWh for traditional TaU programs at other utilities. resources keep costs low much of the time , but where infrequent tight reserve conditions can drive wholesale market prices much higher than normal. In addition to the communication feature of the technology, a control device gives customers the ability to pre-set their response to both the standard and critical prices. This feature , similar to a programmable thermostat, has been shown to amplify the degree of customer price responsiveness, which adds to the potential benefits of this type of TaU rate structure. Gulf Power Company in Florida has tested a pilot critical price TaU tariff (Residential Service Variable Price, or RSVP), and has received approval to expand the program to a target of 50,000 customers. EdF's Tempo tariff consists of three sets of peak and off-peak TaU prices for three day-types (e.low, moderate, and high-cost), in each of two seasons. Customers are notified of the next day s day-type by eight p.m. (through the meter). The utility allocates a limited number of high (22) and moderate (43) days throughout the year. Like the critical price approach , this type of rate design allows lower peak period prices on the low and moderate-cost day-types than under typical TaU rates , and provides strong incentives for customers to reduce load during the relatively few high-cost peak periods (see Section 4 for empirical evidence). 4. Evidence of TOU price responsivenessTraditional TOU Numerous studies have investigated how residential customers respond to TaU prices. Many of the studies were conducted in the late 1970s and early 1980s as part of a series of Tau experiments at a number of U.S. utilities under sponsorship of the predecessor of the U.S. Department of Energy. Faruqui and Maiko (1983) reviewed the findings from a variety of studies arising from these experiments. A useful synthesis of the findings on customer response to Tau pricing can be found in Caves et al (1984), which reports on an EPRI study of the consistency of price response across experiments. Caves et al found a striking consistency across the TaU experiments in the estimated value of one typical parameter used to measure price responsiveness - the elasticity of substitution with average values centering on approximately 0.14.4 The estimated values also varied in sensible ways with certain household characteristics. For example , price responsiveness was smaller (0.07) for customers with no major appliances, and larger (0.21) for customers that had all major appliances, and thus a greater incentive and ability to respond. In a related study, Caves and Christensen (1980) showed that an elasticity of substitution of 0.17 was consistent with partial and total peak-period own-price elasticities of approximately -0.5 and -0.3 respectively. Analysts at the Salt River Project in Arizona estimated a peak-period own-price elasticity of approximately -30 for a Tau experiment in the late 1980s (see Kirkeide (1989)). This estimate focused on the response of relatively high usage residential 4 See the appendix for a definition of various price elasticity concepts. customers during the few hours coincident with system peak demands during the summer months. Voluntary TOU Two more recent studies reported findings of customer responsiveness to voluntary TaU rates. First, Caves et al (1989) found a relatively large substitution elasticity of , 0.37 among customers who volunteered for a TaU rate at Pacific Gas and Electric Company. In contrast, Baladi et al (1998) found that the volunteers for an experimental TaU rate at Midwest Power responded quite similarly (0.17) to . customers in the original non-voluntary TaU experiments. Variable-price TOU A few studies have reported price response findings for TaU programs in which the utility may dispatch different TaU prices depending on market conditions. American Electric Power (1992) reported significant load shifting from the "high" and "critical" price tiers to the "low" and "medium" tiers, but did not estimate formal price elasticities. They also reported peak demand reductions ranging from 2 to 3 kW per customer at high" prices, and 3.5 to 6.6 kW at "critical" prices. The latter values represented as much as 60% of customers' peak load during a winter period. AEP also reported overwhelming customer satisfaction with the program. Braithwait (2000) analyzed a similar pilot program at GPU Energy. Analysis of participant and control group load data indicated that customers modified their usage patterns substantially in response to the TaU prices reducing consumption during peak periods and some shoulder periods , and increasing consumption during certain off-peak and shoulder periods. Summer peak-period load reductions averaged about .5 kW, or 25% of control group loads , while response during critical price periods ranged from .6 to 1.24 kW. Estimated elasticities of substitution exceeded those in most previous studies of traditional TaU programs, indicating strong customer price responsiveness. Specifically, the study estimated an elasticity of substitution of 0.31 for a constant elasticity of substitution (CES) demand model while substitution elasticities between peak and off-peak periods of as large as 0.40 were found using a more flexible Generalized Leontief model. These results illustrate the importance of two key factors that influence the degree of customer response to time-varying prices. First, relatively high peak period and critical prices ($0.25 and $0.50/kWh , respectively) provided strong incentives respond. Second, the interactive communications equipment provided the ability respond easily, without customers having to remember to make manual adjustments. Finally, Aubin , et al (1995) reported finding strong price responsiveness and substantial net economic benefits in the experimental phase of the EdF Tempo tariff, which they referred to as residential real-time pricing. The overwhelming evidence from the literature is that residential customers do respond to TaU prices, in a significant, and reasonably consistent and predictable manner. The primary question is whether the net benefits to customers and utilities from this load response are sufficient to outweigh the additional metering costs. References American Electric Power , " Report on the Variable Energy Pricing and TranstexT Advanced Energy Management Pilot " 1992. C. Aubin , D. Fougere, E. Husson , and M Ivaldi , " Real-Time Pricing of Electricity for Residential Customers: Econometric Analysis of an Experiment,Journal of Applied Econometrics Vol. 10, S171-S191, 1995. M. Baladi, J.A. Herriges and T.J. Sweeney, "Residential Response to Voluntary Time- of-Use Electricity Rates Resource and Energy Economics 20:225-244, 1998. S. Braithwait , " Residential TaU Price Response in the Presence of Interactive Communications Equipment " in Pricing in Competitive Electricity Markets edited by A. Faruqui and K. Eakin, Kluwer Academic Publishers, 2000. W. Caves and loR. Christensen , " Econometric Analysis of Residential Time-of-Use Electricity Pricing Experiments Journal of Econometrics, 1980. W. Caves, loR Christensen, W.E. Hendricks and P.E. Schoech , " Cost-Benefit Analysis of Residential Time of Use Rates: A Case Study for Four Illinois Utilities Electric Ratemaking, Vol. 1 , No., 1982. W. Caves, loR. Christensen and J.A. Herriges , " Consistency of Residential Customer Response in Time-of-Use Electricity Pricing Experiments,Journal of Econometrics 1984. W. Caves, J.A. Herriges and K. Kuester , " Load Shifting Under Voluntary Residential Time- of-Use Rates The Energy Journal 10(4), 1989. A. Faruqui and J.R Maiko , " The Residential Demand for Electricity by Time of Use: A Survey of Twelve Experiments with Peak Load Pricing,Energy, Vol. 8, No. 10, 1983. RR Johnson, "Residential Meters: Adoption At Last?"Fortnightly s Energy Customer Management Fall 2001. lo Kirkeide , " Reducing Power Capacity Requirements Using Two-Period Time-of-Use Rates with Ten-Hour Peak Periods," Masters Thesis, Arizona State University, 1989. Levy, "Advanced Metering Scoping Study," California Energy Commission, August 2001. Christensen Associates Analysis Assessing the Potential Benefits of Residential Time-of-Use Pricing at Idaho Power Company Steve Braithwait Christensen Associates September 11 , 2002 The Idaho Public Utility Commission has asked Idaho Power Company (IPC) to investigate the viability of time-of-use (TaU) pricing for its residential customers. a July 15 , 2002 memorandum , Christensen Associates provided an overview of residential TaU pricing, including the following topics: an historical perspective on TaU pricing, a discussion of potential problems that can limit the benefits of residential TaU to utilities and their customers a description of new types of TaU pricing that show promise in addressing some of those problems, and a summary of evidence on customer price responsiveness. , This report describes the results of a quantitative analysis designed to estimate the potential benefits to Idaho Power and its customers of offering alternative types of residential TaU pricing. Summary The fundamental principle of time-of-use (TaU) pricing is to charge retail prices that vary by time period (e.summer peak and off-peak) to reflect differences in the average cost of generating and delivering power during those periods. Billing customers for their consumption under TaU pricing requires the installation of meters that record energy usage during specific blocks of time. As metering technology has advanced and become less expensive, a number of utilities are considering the installation of advanced interval meters that record hourly usage and thus allow more refined pricing strategies that send high prices only during infrequent periods of high power costs (e.extremely hot summer afternoons on which transmission constraints limit Idaho Power s access to wholesale power from outside of its service area). This study assessed the potential benefits to Idaho Power and its customers of both conventional TaU pricing and a form of "critical peak" TaU pricing that would involve interval metering, and communication and control technologies that would allow Idaho Power to send occasional critical prices to residential customers. This assessment involved the use of data on Idaho Power s residential customer energy use and its hourly costs of supplying power. The analysis was conducted using customer demand model software that simulates customers' load response to TaU pricing, and calculates changes in consumer and utility benefits. Our primary conclusions may be summarized as follows: Conventional TOU pricing offers relatively small potential benefits. The primary reason for this result is that Idaho Power s supply costs are generally low on most days , but they rise steeply during a few hours on a limited number of days in the summer. TOU prices that remain fixed on all days send price signals to customers that are too high on most days, but too low on the critical few high-cost days. Critical peak TOU pricing has the potential to produce substantial benefits. implemented on a mandatory basis, such a pricing strategy could produce peak load reductions on high-cost days of nearly 200 MW. Estimated benefits to customers would exceed $1 million annually. Estimated benefits to Idaho Power depend critically on assumptions about the costs that it avoids when customers reduce load during critical price periods. If avoided capital costs of new peaking capacity are considered , then the cost reductions associated with the 200 MW load reductions under mandatory CP TOU pricing could reach $12 million per year. Under mandatory TOU pricing, the wide range of usage patterns across all residential customers implies that, before accounting for load response , some customers could face bill increases of up to $20 per year, while others could face bill reductions of similar amounts. Implementing critical peak TaU pricing would require substantial investment in new metering and communication equipment, and changes to Idaho Power s billing systems. The cost of those investments has not been investigated in this study. If TaU pricing were offered on a voluntary basis , the customers most likely to switch to TOU would be those that would experience an immediate bill reduction even before changing usage patterns. This would produce a revenue shortfall to Idaho Power without rate design changes to address this "self-selection" problem. 1. Introduction The principal argument in favor ofTOU pricing has always been economic efficiency TOU prices reflect differences in the average cost of generating and delivering power during particular time periods , thus providing more appropriate price signals to customers than do flat rates. Customers can achieve benefits under TOU pricing if they can shift sufficient consumption from peak-period hours in which the price exceeds the standard flat price, to lower-price off-peak hours. Utilities can realize net gains from those same load shifts by avoiding some peak period sales whose cost exceeds the revenue generated, and selling more during low-cost off-peak periods. However, these TOU benefits must be traded off against higher metering and administrative costs. Estimates of that benefit-cost tradeoff have generally not been favorable. Two main factors have weighed against the benefits of TOU pricing for residential customers. First, TOU prices do not reflect the variability of wholesale power costs with sufficient accuracy. For example , peak period prices (e.1 O/kWh) are generally designed to represent an average across expected wholesale costs during peak- period hours in a given season (e.summer).1 However, wholesale power costs can range widely from moderate to very-high levels , depending on actual load levels and supply conditions. In many hours , TOU peak period prices substantially exceed the actual cost of power (e.a TOU price of $.a/kWh versus a wholesale cost of $.03 to $.05/kWh). However, in the very hours in which costs reach their highest levels, the peak period price is likely to fall far short of that level (e. 10/kWh versus costs of $.50 to $1.00/kWh or more). Thus, while TOU prices do a better job than does a flat price of reflecting cost differences on average, the price signal is still not very accurate. When TOU customers reduce load during the many peak hours in which costs are actually relatively low, utilities' revenue can be reduced by more than their costs. Second , the relatively low usage level of residential customers , combined with the first factor of inaccurate prices, limits the overall magnitude of potential benefits from customers' responses to TOU prices. These benefits must be traded off against the additional cost of metering and billing. TOU rates have generally not been mandated , or established as the default tariff for residential customers. Most TOU programs have been offered as voluntary programs, typically targeted at customers with high usage levels , or ownership of major appliances such as central air conditioning or pool pumps. As a result, most residential TOU tariffs have relatively few customers. Two recent programs promoted by Puget Sound Energy (PSE) in Washington State, and Gulf Power Company in Florida, provide indications of potential renewed interest in residential TOU. PSE has undertaken an ambitious program to install advanced interval meters for all of its residential customers, along with software and communication devices that give customers the ability to monitor their energy usage and PSE's wholesale power costs online. PSE has assigned all customers with the new meters to a TOU rate , although customers have the right to opt out and return to a flat rate. PSE claims that a large share of the cost of the metering and communications system may be covered by improved meter reading and billing efficiency, even before accounting for the benefits associated with customer load response to TOU prices. PSE has also discussed a range of potential advanced pricing approaches that they may consider offering to take advantage of the metering and communications capabilities. Gulf Power has recently announced a planned expansion of their pilot Residential Service Variable Price (RSVP) program , which combines advanced interval I To cover expected costs, TaU prices actually need to reflect a load-weighted average of hourly wholesale costs, where the weights represent the load pattern of the customers expected to take service under the rate. metering, and communication and control technology with a TOU rate that includes a dispatchable "critical peak" price. This program, a version of which is assessed in this report, has the potential to solve a number of the problems with traditional TOU pricing. Our understanding is that Idaho Power Company currently faces a situation of increasing demand and transmission constraints that limit access to generation resources to the west. As a result, the company is considering plans to build additional peaking capacity. Thus, a dynamic pricing program that provided load reductions during key peak demand periods could provide valuable cost savings. 2. Overview of Quantitative Assessment This report describes the analyses that we have conducted to assess the viability of , residential TOU pricing at Idaho Power. We have analyzed variations on two general types of TOU pricing strategies - a conventional TOU tariff and a "critical peak" (CP) TOU tariff which consists of a standard TOU rate plus the ability of the utility to send a "critical" price on a limited number of days during the peak period, with day-ahead notice. We considered mandatory and voluntary versions of these two general TaU pricing strategies. Analytical Tools and Data Calculating the benefits of TaU pricing requires certain types of analytical tools and data. The principle benefits from TOU pricing result from customers' demand response to the TOU prices relative to their former flat price. Thus, developing estimates of TOU benefits requires an analytical model of customer demand for electricity by time period. In this study, we have calculated the benefits to customers and the utility using customer demand model software (implemented in Excel spreadsheets) that characterizes customers' hourly demands for electricity (relative to a reference load) as a function of TOU prices relative to prices from a reference period.2 The model first calculates hourly changes in loads in response to changes in TaU prices , then calculates the changes in customer benefits (technically, consumer surplus) and utility net benefits (changes in revenue less changes in cost) associated with those load changes, and finally adds up the changes over all hours in the period of analysis? In cases where TOU pricing is' voluntary, customers may choose the TOU tariff if they believe that they would be better off facing TOU prices. To simulate this choice , the demand model contains a simple choice model, in which customers' probability of selecting the TOU rate depends on their estimated benefits from TOU pricing, scaled as the percentage change relative to their base bill under the flat rate. The demand model requires several types of input data and behavioral parameter assumptions. The data include historical hourly customer loads and wholesale 2 A technical description of the customer demand model is provided in an appendix. 3 In the case of regulated utilities such as Idaho Power, the benefits to the utility may largely be thought of as benefits to all of the utility's customers. For example, load reductions that produce avoided costs that exceed foregone revenue imply that retail rates in the future will be less than would otherwise be the case. costs, and forecasts of wholesale costs for the period of analysis. The parameters include price elasticities that characterize the extent to which different types of customers respond to time-varying and overall electricity prices , and parameters that represent customers ' likelihood of accepting TOU pricing if offered on a voluntary basis. Christensen Associates has extensive experience in both estimating price response parameters for customers facing TOU pricing, and in compiling literature reviews of parameter values estimated in other studies. Historical load and wholesale cost data For purposes of this analysis , we used historical data from 1999 on customer loads and wholesale costs. This was the most recent year that was not "contaminated" by the extreme conditions that held in the West due to the California crisis of 2000- 2001. Idaho Power provided hourly load research sample data for 1999. After exclusions for missing data , we were left with high quality data on hourly loads for a random sample of 94 customers that represented the wide range of usage patterns of Idaho Power s residential customers. Constructing historical wholesale cost data required several steps. In principle , we wished to represent Idaho Power s hourly opportunity cost of generating, purchasing or selling power. IPC staff suggested using Mid-Columbia wholesale prices to represent those values. However, IPC only maintained historical records of the daily average peak and off-peak prices for 1999. To allocate those prices to hours of the day. we applied hourly patterns of the California day-ahead PX prices for each day in 1999. Finally, we decided that it was appropriate to smooth out certain uncharacteristic seasonal price patterns in the historical data by using expected seasonal patterns from wholesale price. forecasts provided by IP. Figure 1 illustrates the variability of IP's power costs. The curve shows the distribution of daily (weekday) five-hour peak average wholesale costs during June through September 1999 (e.the average cost for hours 14 through 18). The solid flat line shows the overall average summer peak-period cost, which would normally serve as the basis for a peak period TOU price. The classic asymmetric shape of the price distribution illustrates one of the typical problems of TOU pricing - a TOU peak price based on the average cost across all days exceeds the actual cost of power on more than two-thirds of the summer days, while on the dozen days of the highest costs , the actual cost of power exceeds the average cost by more than fifty percent. When customers reduce load in response to peak TOU prices on days of relatively low costs , the utility loses more in revenue than it avoids in cost. Only on the relatively few high cost days does the utility save more in avoided cost than it loses in revenue from the load reductions. 4 The utility also potentially loses revenue from the non-energy portion of the rate if consumers reduce load by more in the peak periods than they increase usage in off-peak periods. This suggests that a larger portion of non-energy costs be recovered through customer charges rather than energy charges, particularly to the extent that the costs are fixed and not affected by changes in energy consumption. The potential value of the CP TOU pricing approach can be seen in the dashed flat line , which shows average costs after excluding the twelve highest-cost days. that case , the peak price provides a better approximation of normal peak-period costs, and the higher critical peak price on the highest-cost days encourages greater load response on those days. Wholesale cost scenarios We produced results for two alternative wholesale cost scenarios. One used the actual costs that occurred in 1999. The other was designed to represent a high- cost scenario, in which the costs for the 100 highest-cost hours were increased by gradually greater amounts such that the highest price equaled $500/MWh, rather than the actual historical maximum of approximately $200/MWh. Customer price responsiveness The customer demand model represents customers' price responsiveness by two main types of parameters elasticites of substitution that represent customers willingness to shift load from high-price to low-price time periods, and an overall price elasticity that represents customers' propensity to change their overall electricity consumption due to any change in the overall average price of electricity. Since the focus of this study was on customer response to time-varying prices, we set the overall price elasticity equal to zero. We applied a range of elasticity of substitution values across the customers in the load research sample , where the values were based on two key factors that have been observed in previous analyses. First, reasonably consistent values of these elasticities have been found in a variety of conventional TOU pricing studies, with average values ranging from approximately .05 to ., and higher values typically estimated for customers with major electricity-consuming devices such as central air conditioning, and electric space and water heating. Second , we have found substantially greater price responsiveness among customers facing critical price TOU programs, particularly for those in which the program involves communication and control technology that allows customers to pre-specify their response to TOU and critical prices , as in raising air conditioning thermostat settings. In one study, we found elasticities of substitution that approximately doubled the estimates under conventional TOU pricing. We incorporated these findings in the following way. First, we assigned elasticities to the sample customers in a random fashion , after adjusting each customer probability of receiving a given value such that customers with greater (less) than average annual usage had a greater (less) chance of receiving a larger elasticity parameter. Second , the parameters assigned for the CP TOU case were approximately double those of the Base TOU case. For the latter case, the assigned values ranged from .05 to ., while for the CP case, they ranged from . to .30. TOU Pricing Strategies The TOU prices were calculated according to two principles. First, the ratio of peak to off-peak energy prices was set to reflect the ratio of the load-weighted average wholesale power cost in those time periods. Second , the actual price levels were calculated so as to generate the same revenue as under the standard flat tariff price , at the customers' baseline level of consumption. Only the energy portion of the standard tariff price (i.the unbundled power supply and PCA rate component) was adjusted to reflect time-varying costs; the remaining portion of the tariff price which represented about half of the total price, remained constant across time periods. For the CP TOU strategy, we assumed a CP energy price of $.20/kWh , and assumed that it would be implemented on average during 60 hours of the year.5 To calculate the TOU prices that apply during the remaining hours of the year , we first subtracted the revenue generated in the assumed 60 critical hours, then calculated the price ratios and revenue-neutral prices for the remainder of the revenue requirement. For purposes of this relatively high-level analysis, we felt that it was appropriate to focus only on peak and off-peak pricing periods. A more comprehensive analysis could examine a third set of "shoulder" period prices as well. Analysis of the wholesale power costs across hours suggested that the optimal peak period for the June through September summer period was the five hours of 1 p.m. to 6 p.m. (i. hours ending 14 through 18), while for the remaining months it was 14 hours from 7 m. to 9 p.6 Table 1 summarizes the relevant prices. Table 1: TOU Prices Winter Prices Summer Prices (cents/kWh)(cents/kWh) Peak Off-peak Critical Peak Off-peak Flat 5.12 Base TOU Critical Price TOU 22.45 For reference, GPU Energy used a critical price of$.50/kWh in a pilot CP TaU program in 1997, and Gulf Power has set its critical price at $.29/kWh. We used a somewhat lower price in view ofIPC's generaIly lower costs.6 The optimal peak periods minimize the variability of prices within the period, while maximizing the difference between the average variability between the two periods. 3. Effects of TaU Pricing Analysis of Changes in Energy Consumption and Benefits As described above, the customer demand model first calculates changes in customer usage patterns under TaU pricing. These load changes are then used to calculate changes in consumer benefits, and changes in utility net revenues. In the case of voluntary TaU , the changes in consumer and utility benefits are calculated only for that percentage of customers that are estimated likely to adopt TaU pricing. Before turning to the quantitative results , we first summarize the source of and method for calculating consumer benefits from TaU pricing. It is instructive to illustrate changes in consumer benefits in two stages. First , consider the bill changes induced by the revenue neutral (at average baseline usage) TaU design as shown in Figure 2. The higher prices during the peak periods, and the lower prices during off-peak periods, relative to the flat price , imply peak-period bill increases and off-peak bill reductions. For the average pattern of baseline usage, these bill changes offset each other completely, leaving no net annual bill change (i.revenue neutrality) before accounting for any load response. However, the wide range of usage patterns in the residential class implies that some customers (e.those with a greater than average share of peak period usage) will experience overall bill increases, while others (e.those with a less than average share of peak period usage) will see bill reductions even before undertaking any load response. To illustrate , Figure 3 shows the distribution across customers of annual bill changes before load response for the Base Tau pricing case. The distribution is reasonably symmetric, with relatively small bill changes ranging from approximately $20 bill reductions , to $20 bill increases per year. (Note that under the current flat price those customers with relatively less usage during the higher-cost summer peak periods cost less to serve than the average customer, and are thus effectively subsidizing customers with relatively high usage during those periods). Figure 4 illustrates how customers can benefit from load changes in both peak and off-peak periods. Economists traditionally measure changes in consumer benefits due to price changes as changes in consumer surplus which can be thought of as the difference between what consumers are willing to pay for a certain amount of a product (as reflected in their demand curve) and the market price that they actually have to pay. A conventional downward sloping demand curve reflects the value that consumers attach to a product or service; it implies that consumers are willing to purchase more of a product as its price falls, or less of it as its price rises. The right panel of Figure 4 shows that the average consumer who purchased Qoop in the off-peak period at the flat price , PF, increased consumption to QTOUop at the lower off-peak price , and experienced an increase in benefits equal to the triangular area under the demand curve and above the off-peak price, PoP. The left panel shows that during the peak period the average consumer who purchased Qop in the peak period at the flat price, reduced consumption to Q TOUp at the now higher peak price, Pp. By reducing consumption , he reduced his bill by the rectangular area bounded by the two price lines and the amount of the load reduction. However, he also lost some value from the foregone consumption (e. g., experienced some discomfort after raising the air conditioner thermostat setting on a hot day), as indicated by the triangular area under the demand curve. The net result is a gain in value equal to the bill reduction less the foregone value? Estimates of TOU Pricing Impacts Table 2 summarizes the estimated changes in various key electricity consumption financial , and customer benefit variables for each of the pricing strategies examined in this analysis. The following are comments on specific results , starting from the left-most columns. 1. Load changes. The first set of columns shows changes in demand (in MW). Two values are shown. The first is the change during the hour of maximum demand (regardless of wholesale cost) for the entire class. The second shows the change in the hour of highest wholesale cost. The Base TaU case produces the greatest impact in the coincident peak hour , while the load response for the CP TaU cases is much larger during the important high-cost hour. The mandatory version of CP TaU suggests a maximum potential of nearly 200 MW of load reductions at times that critical prices apply. 2. Utility impacts. The second set of columns shows effects on Idaho Power revenues, costs, and net revenues of the load shifting induced by the TaU pricing, under both the base and high-cost scenarios. For the two mandatory cases, the reductions in revenue occur as a result of customer load changes. Under the voluntary cases, the revenue reductions occur as a result of both instant" bill reductions for participating customers as well as their load reductions. The reductions in cost result from the energy costs avoided by customers shifting load on net from high-cost to low-cost hours. Under the base assumption of the costs that occurred in 1999 , the cost reductions in most cases are less than the revenue reductions. Under the high-cost scenario cost reductions in the two mandatory TaU cases exceed revenue losses, showing the potential net benefits to the utility and its customers. In the two voluntary cases , the revenue losses from voluntary self selection exceed the 7 The actual amounts of both bill reduction and foregone value from the load reduction include the unshaded rectangle below PF and between the two quantity levels. However, these changes cancel, leading to the focus on the shaded areas.8 The load changes and resulting impacts on utility costs were inflated by an estimate of transmission and distribution line losses. We assumed an average value of seven percent. Thus, a 1 MW load reduction measured by meters at the customer level translates into a 1.07 MW reduction in Idaho Power generation requirements. cost reductions. However, it should be pointed out that alternative TOU rate designs can be used to address the revenue attrition problem caused by customer self selection. Finally, Idaho Power may be able to count an additional benefit of the TOU load reductions to the extent that they allow the utility to avoid or postpone the need for additional peaking capacity. For example, under an assumption of a capital cost for peaking capacity of $500/kW for a unit that, is expected to run for approximately 50 hours per year, and an annual capital charge rate 12%, then a 100 MW load reduction during the same number of hours could be considered to avoid the cost of $60/kW * 100 MW * 1000 kW/MW = $6 million per year. Thus , the 200 MW load reduction of the mandatory CP TOU would produce $12 million in capital cost savings. 3. Customer benefits. The third set of columns shows changes in consumer net benefits , in both a dollar amount and as a percentage of the total base bill before load shifting. The total change in net benefits is comprised of two components. One is the "instant" bill changes that consumers see from the change to TOU prices (e., customers with greater than average energy consumption in the non-summer and off-peak periods receive an immediate bill reduction from the TOU prices). In the mandatory cases, these instant bill changes net out to effectively zero, reflecting the revenue neutrality assumption. The second component represents "load response" gains due to consumers shifting load from peak to off-peak periods. The percent of base bill value provides a useful relative measure of the magnitude benefits. In previous analyses, we have seen gains in net benefits as a percent of base bill range from less than 1 % to approximately 2 - 3%. The magnitude of net benefits depends on two key factors - the degree of price variability (e., the difference between peak , off-peak and critical prices) and customers' flexibility to change usage patterns. Total annual net benefits for each TOU option under each cost scenario may be obtained by adding the total customer net benefits to the utility s net revenue change in the relevant cost scenario. These results provide one key input to the assessment of the viability of TOU pricing at Idaho Power. To arrive at a complete assessment of the benefits and costs of the TOU pricing strategies , one would need to compare the costs of the required metering equipment to a discounted stream of annual net benefits ,such as those in the table, over a reasonable time period. 4. Participation. The next set of columns shows participation rates in the two voluntary options as a percentage of load and of the number of customers. 9 For example, once the TaU rate is offered as a voluntary rate, the standard flat rate also becomes voluntary. Thus, each should be priced to reflect the costs of the customers most likely to select each rate. This would suggest higher flat prices to reflect the relatively higher cost to serve customers that do not immediately benefit from the TaU prices. An assumption underlying the relatively small TaU participation rates is that customers have some inertia that tends to make them reluctant to change pricing options , particularly for the relatively small gains reflected in these examples , such that they do not automatically adopt a TaU option even if it appears to deliver positive net benefits. The number of customers participating in the voluntary cases may be calculated by recognizing that Idaho Power had approximately 300 000 residential customers in 1999. 5. The last column shows the percentage of customers that would experience negative net benefits under each case. Under the mandatory cases, approximately half of the customers would gain at the expense of the other half, as seen in Figure 3 above. In the voluntary cases, even some customers that experience bill increases have some probability of volunteering for the TaU price. 4. Conclusions Conventional TaU pricing applied on a mandatory basis to IPC's residential customers would produce very modest potential benefits. This result is due to the relatively small differential between average peak and off-peak wholesale costs, and thus the retail TaU prices; as well as the general lack of correspondence between average peak costs and the day-to-day variations in those costs. Making TaU pricing voluntary produces somewhat higher consumer benefits, but results in net revenue losses to Idaho Power due to customers self selecting the TaU rate whenever it offers immediate bill (and revenue) reductions. Critical peak TaU pricing appears to provide the potential for beneficial load reductions and cost savings. It would produce much larger demand reductions during the most important high-cost hours than does conventional TaU. Customer net benefits are also higher due to the greater opportunity for benefits from load reductions during critical price periods. The results for the mandatory case indicate a potential gain of more than $1 million annually. From the standpoint of Idaho Power, however, the key factor affecting potential benefits is the nature of the costs that would be avoided by customers' load reductions. Under the base cost scenario , cost reductions fall short of revenue reductions, yielding a large net revenue reduction.10 However, cost reductions under the high-cost scenario exceed the revenue reductions, producing net gains to the utility. In addition, if the load reductions can be credited with avoided capital costs for new peaking capacity, then the value of the load reductions may be substantially higher than the cost reductions shown in Table 2. A more realistic case might be that CP TaU would be offered on a voluntary basis. In this case , careful rate design would be required to limit the extent of revenue losses from customer self selection. Under the assumptions in our analysis, a 10 In actual operation, the critical prices might not be dispatched for as many days under the base cost scenario as was assumed in the analysis. This would limit the amount of net revenue losses. market share of 25% would produce load reductions of approximately 40 MW during critical price conditions. Finally, any of the above cases of estimated benefits must be traded off against the cost to Idaho Power of installing advanced interval metering equipment and modifying its billing systems to account for TaU pricing. -= 100 fI"! 80 Figure 1: Distribution of Wholesale Power Costs A verage Daily Peak-period Values (1 m. - 6 180 160 140 120 40 - - - - - - - - -------- 1 3 5 7 9 II 13 15 17 1921 23 25 27 29 31 33 35 37 39 414345474951 5355575961 6365676971 737577 79 81 838587 I-Avg-Peak.Price PeakPrice(CP)! Figure 2: Revenue Neutrality of TOU Prices at Baseline Consumption Peak $/kWh kWh $/kWh Off-Peak POP Q~p kWh Figure 3: Distribution of Bill Changes Before Load Response Mandatory Base TOU ($/year) 25. 20. 15. 10. tit 1 4 7 10 13 16 19 22 25 28 31 34 37 40 43 46 (5. (10. (15. (20. Figure 4: Customer Benefits from TaU Pricing Peak Cost of responding Q~OU Q~kWh $/kWh PoP Off-Peak Net benefit (added value) TOUOP kWh Ta b l e 2 : I m p a c t s o f TO U P r i c i n g - B a s e Ca s e C o s t s Ch a n g e i n D e m a n d (M W ) Ut i l i t y I m p a c t s ( $ m i l l i o n ) Cu s t o m e r B e n e f i t s ( $ m i l l i o n ) Pa r t i c i p a t i o n Ba s e c o s t s Hi a h c o s t s % C u s t Ho u r o f Ne g Hi g h e s t % B a s e %o f Be n e f i t s Ta r i f f Co i n . P e a k Co s t Re v . Co s t Ne t R e v Co s t Ne t R e v In s t a n t To t a l Bi l l % o f l o a c cu s t . Ba s e T a U - M a n d . 25 . 4 22 . $0 . $0 . $0 . $0 . $0 . $0 . $0 . $0 . 04 % 10 0 % 10 0 % 53 % Ba s e T O U - V o l . $0 . $0 . $0 . $0 . $0 . $0 . $0 . $0 . 13 % 16 % 14 % 17 % CP T O U - M a n . 19 8 . $1 . $0 . $0 . $1 . $0 . $0 . $1 . $1 . 51 % 10 0 % 10 0 % 46 % CP T O U - V o l . -4 3 . $1 . $0 . $1 . $0 . $0 . $0 . $0 . $1 . 53 % 30 % 25 % 11 % 1,0 Appendix: Demand Model Documentation The demand response model incorporated in the spreadsheet software is based on the nested constant elasticity of substitution (CES) demand model. The CBS functional form has been widely used to characterize customer response to time-varying prices, including both time-of-use (TaU) and hourly prices. The nested CES (NCES) is derived from a customer cost function that allocates electricity costs separately within and between days. That is , a customer overall electricity costs are represented by a function of daily price indexes which in turn are functions of the hourly (or TOU) prices on each day. Customers choose levels of electricity demand that minimize overall costs with respect to the time-varying prices, while maintaining the level of services implied by a historical usage pattern at historical prices. The model allows two levels of customer flexibility to respond to time-varying electricity prices. One level involves the flexibility of customers to shift load between hours or time periods within a day; the other level allows the flexibility to shift load between days in response to changes in the average price level between different days. The daily price index for day , Dd, is specified via the CES functional form as a load-weighted average of elasticity-adjusted hourly prices Ph in that day: d = I,a (I-aw)!cl-aw) /zed where CXhd is a load shape parameter that approximates the fraction of daily load in hour and aw is the within-day elasticity of substitution parameter. Next, the aggregate monthly price index Mm, also given as a CES function , is a load- weighted average of elasticity-adjusted daily prices Dd in that month: m ~(~PdDr~)t~.) where fJd is a second load shape parameter that approximates the fraction of aggregate monthly load that occurs in day and ab is the between-day elasticity of substitution parameter. The customer s demand for electricity may then be obtained by applying Shepard's Lemma to the above cost functions, differentiating the cost function with respect to the input price. It is most convenient to specify the resulting demand equations relative to an average reference load and in logarithm form as shown in the following: In()~(T (ln())+(T )). Edh represents electricity usage in hour (or time period) on day , Pdh is the price, and the daily and monthly price indexes are as defined above. The variables in the denominator with the super bar represent averages of the variable for the comparable time period in the reference period (e. g., the average load in hour on weekdays in a given month. The demand equations have two types of parameters. The load shape parameters (CXhd and !3d) characterize the inherent shape of the customer s load pattern and are used to construct the daily and monthly price indexes. The price response parameters (O'w and O'b) characterize how the load responds to changing hourly prices. In this study, we assumed that the two price response parameters take on the same value , O'w O'b, and refer to that value as the elasticity of substitution. Given prices and loads in a baseline period, assumptions about price response parameters, and prices in an alternative scenario , the model calculates customer demands in each time period. ISSUES SPECIFIC TO IDAHO POWER Two issues which directly affect the viability of time-of-use pricing for Idaho Power are the current status of the Company s metering capability and the PCA treatment of benefits associated with reductions in power supply costs which may result from the shifting of customer loads to off-peak periods. Any potential benefits from time-of-use pricing must be traded off against the costs of the metering equipment and billing system modifications necessary to record and bill interval usage. In addition, any power supply related benefits from time-of- use pricing should flow through the PCA in a manner that is fair and equitable to customers and the Company. Meterinq Capability. The analysis performed by Christensen Associates did not include any cost component for the metering equipment necessary to record usage by time period. Idaho Power currently does not have metering equipment in place to record usage by time period for residential customers. There are two options which could be utilized to provide the ability to record usage by time-of-use. First, standard time-of-use meters could be installed. These meters have an internal clock and calendar and are programmed to record usage during the time-of-use periods. Usage data is retrieved monthly during the Company s standard meter reading process. If the hours included in the time-of- use periods change , these meters must be physically reprogrammed through a site visit. In addition, because usage information from several registers must be retrieved when these meters are read, additional administrative costs associated with the increased meter reading time is incurred. Second , an automated meter reading (AMR) system could be installed. With an AMR system, meters are read via the power line or radio frequency depending on the application. Changes to time-of-use periods can easily be made via the remote communication capability of an AMR system. Because an AMR system reads meters remotely, updated usage information can be collected on an "at will" basis, allowing for more timely information to be provided to customers. The average cost to install a standard time-of-use meter for a residential customer would be about $145 per customer or approximately $47 million for all residential customers system-wide. The incremental cost of the TOU meter compared to the standard meter now installed for residential customers would result in an increased charge to customers of about $1 a month. The latest cost estimate to install an AMR system across Idaho Power s service territory is approximately $72 million. PCA Implications . Benefits result from time-of-use pricing when customers are able to reduce their bills and utilities are able to reduce their costs by an amount greater than the reduction in revenue. Assuming that a time-of- use scenario that successfully addresses the potential revenue attrition problems identified by Christensen Associates could be constructed, a time-of-use scenario cannot be beneficial to Idaho Power without a modification to the manner in which reductions in power supply costs which result from customers load shifting are treated in the Power Cost Adjustment (PCA) mechanism. Under the current PCA methodology, 90% of the reductions in power supply costs that accrue as a result of customers shifting load from the on-peak to the off-peak period are passed through to customers as a benefit. Idaho Power is able to retain only 10% of the benefit. However , Idaho Power absorbs 100% of the reduction in revenue. The 90/10 sharing of the benefits associated with reduced power supply costs would result in a negative impact to Idaho Power s earnings. The following example , in which it is assumed that customers' load shifting resulted in a decrease in power supply costs greater than the reduction in revenue , illustrates the situation. Impact for Utility Without PCA Mechanism Reduction in revenue due to reduced customer billings Reduction in power supply costs due to customers shifting load to off-peak time period Impact to Utility s earnings $ (90,000) $(130.000) $ 40,000 In this example, the net impact to the utility s earnings is an increase of $40,000. Impact for Idaho Power With PCA Mechanism Reduction in revenue due to reduced customer billings Reduction in power supply costs due to customers shifting load to off-peak time period $(130 000) Idaho Power s 10% share of reduced costs $(130,000*10%) Impact to Idaho Power s earnings $ (90,000) $(13.000) $(77 000) In this example , the net impact to Idaho Power s earnings is a decrease of $77 000. The PCA treatment of benefits associated with reductions in power supply expenses that could accrue as a result of customers shifting load in response to time-of-use pricing must be addressed to remove the negative impact to Idaho Power s earnings in order for time-of-use pricing to have the opportunity to be viable. Energy Efficiency Advisory Group Input from the Energy Efficiency Advisory Group (EEAG) indicates support for implementing pricing that requires customers to pay what it costs to receive service. The EEAG supported pricing that lets customers who use less energy during the on-peak period pay less and requires customers who use more energy during the on-peak period to pay more. Overall the group was more supportive of increasing the charges for the standard tariff service and making both the standard service and time-of-use service optional than it was of making time-of- use mandatory. Some concern was expressed for those who may have a difficult time paying more for energy used during the on-peak period; however recognition was made that customers should pay for the service they receive. The EEAG expressed the sentiment that it appeared to be more sensible to pursue a demand response program than a time-of-use pricing program at this time given the investment in metering equipment that would be necessary to accommodate a wide-scale time-of-use program. A demand response program that targeted a reduction in load during only those high cost hours in which the economics indicated it was beneficial to do so appeared , according to the EEAG to be an option that might have merit. Although time-of-use pricing could be offered using standard time-of-use meters, the EEAG believed that it would be important to the program s success to provide customers with the additional information that would be available through an AMR system. In addition, the EEAG indicated customers would be willing to pay more to have the additional information available. The EEAG discussed the potential of installing time-of-use meters in new subdivisions and housing developments. However, the EEAG did not support mandatory time-of-use pricing for these customers nor did the EEAG support cost shifting of additional meter related costs to non-participants. Consequently, EEAG did not support the suggestion that all new developments be equipped with time-of-use meters. Conclusions Some of the new types of time-of-use pricing, particularly the critical peak TOU structure , may have potential as viable pricing options for residential customers at some time in the future. However, any benefits that may result from time-of-use pricing must be balanced against the costs of the equipment necessary to accommodate the pricing. Idaho Power currently does not have a metering system in place to accommodate a large-scale time-of-use pricing program for residential customers. The cost of installing standard time-of-use meters , which would not allow for the "critical peak" or "day type" designs, does not appear to be economic given the potential benefits that might accrue from load shifting given the relatively small loads of residential customers. Until such time as an AMR system is available on Idaho Power s system, and a PCA methodology is devised to remove the negative impact to Idaho Power s earnings due to the unequal treatment of the revenues and expenses impacted by load shifting, residential time-of-use pricing is not economically viable.