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HomeMy WebLinkAbout20030203_377.pdfDECISION MEMORANDUM TO:COMMISSIONER KJELLANDER COMMISSIONER SMITH COMMISSIONER HANSEN COMMISSION SECRETARY COMMISSION STAFF LEGAL FROM:LISA NORDSTROM DATE:JANUARY 31, 2003 RE:IN THE MATTER OF IDAHO POWER'S REPORT ON TIME-OF-USE PRICING. CASE NO. IPC-02-12. In Case Nos. IPC-02-2 and -, the Commission directed Idaho Power and the Energy Efficiency Advisory Group (EEAG) to "evaluate and report to the Commission on the viability of a Time-of-Use residential metering program by September 12, 2002.Order No. 29026 at 22. In compliance with this Order, Idaho Power submitted its "Report on Residential Time-of-Use Pricing" (Report) on September 12, 2002. IDAHO POWER'S REPORT ON TIME-OF-USE PRICING To assist in evaluating the feasibility of residential time-of-use metering, Idaho Power engaged the services of Christensen Associates. The Company described Christensen Associates as "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 for its work with time-of-use and real-time pricing and market-based interruptible load programs." Report at A. Analysis Conventional TOU Pricin2::Traditional Time-of-Use (TOU) pncmg 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). fd. at 5. If applied on a mandatory basis to residential customers, conventional TOU pricing would produce "very modest potential benefits.fd. at 23. The Report attributed this to the relatively small differential between average peak and off-peak wholesale costs (and resulting retail TOU prices), as well as the general lack of correspondence between average peak costs and the day-to-day variations in those costs. Although making TOU pricing voluntary would produce "somewhat higher DECISION MEMORANDUM consumer benefits " this would also result in "net revenue losses to Idaho Power due to customers self-selecting the TOU rate whenever it offers immediate bill (and revenue) reductions.!d. 2. Critical Peak TOU pricin2::This type of pricing allows the peak-period price to be increased to a higher than normal "critical" level in response to high-cost conditions in the wholesale market. ld. at 9. According to the Report , " Critical peak TOU pricing has the potential to produce substantial benefits.ld. at 14. Not only would it produce much larger demand reductions during the most important high-cost hours than does conventional TOU critical peak TOU pricing would allow higher net customer benefits due to the greater opportunity for benefits from load reductions during critical price periods. ld. at 23. The Report indicated that if made mandatory, critical peak TOU pricing could result in an annual customer benefit of more than $1 million. ld. More importantly, Idaho Power has the potential to avoid $12 million per year in carrying charges for capital investments in peaking facilities. !d. at 22. If offered on a voluntary basis, the Report stated that "careful rate design would be required to limit the extent of revenue losses from customer self-selection.ld. Under the assumptions used in Christensen Associates' analysis , a market share of 25% would produce load reductions of approximately 40 MW during critical price conditions. ld. at 23-24. A key factor limiting these potential benefits is the nature of the costs that would be avoided by customers' load reductions. Under the Report's base cost scenario, cost reductions fall short of revenue reductions - yielding a large net revenue reduction. ld. at 23. However cost reductions under the high-cost scenario exceed the revenue reductions, producing net gains to the utility. ld. B. Metering Capabilities According to the Report, Idaho Power s cost of installing advanced interval metering equipment and modifying its billing systems to account for TOU pricing must also be considered. ld. at 32. The analysis performed by Christensen Associates did not include any cost component for the metering equipment necessary to record usage by time period. During its standard monthly meter-reading process, the Company would retrieve consumption data for the time-of-use periods from the standard time-of-use meter. The alternative, an automated meter reading (AMR) system, is read remotely via the power lime or radio frequency and can be collected at will, allowing customers to receive more timely information. DECISION MEMORANDUM According to the Report, 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. ld. As compared to the standard meter now installed for residential customers, the incremental cost of the TOU meter would result in an increased charge to customers of about $1 a month. ld. The Report indicated that the latest cost estimate to install an AMR system across Idaho Power s service territory is approximately $72 million. ld. C. PCA Implications The Report advocated that 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. Assuming that a time-of-use scenario that successfully addresses the potential revenue attrition problems 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.!d. at 32-33. Under the current PCA methodology, 90% of the reductions in power supply costs that would 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. Thus, Idaho Power would retain only 10% of the benefit but absorb 100% of the reduction in revenue. The Report stated that PCA treatment of benefits resulting from reduced power supply expenses "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.ld. at 33. D. Energy Efficiency Advisory Group According to the Report, input from the Energy Efficiency Advisory Group indicated support for implementing pricing that requires customers to pay what it costs to receive service. ld. at 34. 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 making time-of-use mandatory. ld. The Report stated the EEAG believed it would be "more sensible to pursue a demand response program than a time-of-use program at this time given the investment in metering equipment that would be necessary to accommodate a wide-scale time-of-use program.ld. The EEAG did not support mandatory time-of-use pricing for new subdivisions and housing DECISION MEMORANDUM developments, nor did the EEAG support cost shifting of additional meter-related costs to non- participants. !d. E. Conclusions of the TOU Report Some 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 point in the future. The cost of installing standard time-of-use meters, which would not allow for the "critical peak" design, 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 native impact on 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. ld. at 35. PUBLIC COMMENTS The Commission received four comments from private citizens in this case. A Kuna resident concluded that the opportunity for concerned customers to help themselves via TOU pricing should not be withheld just because the utility does not see any financial benefit. A commentor from Boise was disappointed in the Company s position because "these meters would give the consumer a proactive change to manage their consumption in collaboration with Idaho Power to lower consumption during peak, high cost use times. Another Boise resident supported voluntary time-of-use meter installations with a rate structure that supports the advantageous use of the information given by the meters. However TOU metering should be used in conjunction with "substantial" conservation programs, like those promoting efficient appliances and construction, to minimize the peak power Idaho Power must purchase. While this commentor indicated that net profits or return on investment is the measure by with Idaho Power and the PUC should determine program validity, he noted that Idaho Power s revenue loss would be offset by "lower power and capital costs and higher company image.If this program is adopted, this individual stated there should be no predetermined method for make-up of revenue losses until they are proven to exist. A fourth commentor from Idaho City noted that the time-of-use pricing matter is in the wrong place at the wrong time" for Idaho Power customers, who would lose no matter how rates were structured. Furthermore, the program would be of substantial cost and minimal DECISION MEMORANDUM benefit to customers, many of whom cannot shift power usage to other times. This commentor also argued that other companies who have tried TOU pricing now consider it a failure and it would be of minimal benefit since Idaho Power s power costs only rise during a few hours on a limited number of days in the summer. ADVANCED ENERGY STRATEGIES COMMENTS Jeffrey C. Brooks of Advanced Energy Strategies, Inc. (AES) also filed comments in this case. These comments generally supported the comments of the NW Energy Coalition with several amendments and caveats. AES argued that time-of-use rates are best suited to medium and large commercial and industrial customers. AES Comments at 1. The residential customer group is intrinsically the wrong target market for TOU applications and is unlikely to enjoy the economies of scale necessary to outweigh the necessity of personal convenience for the average customer. Unlike commercial and industrial customers, residential and small commercial are unlikely to provide the magnitude of benefit necessary to impact utility-scale needs. Commercial and industrial customers represent the most fertile application of time-of-use rates, which should work in conjunction with efficiency improvements, load management, and load shedding strategies to provide an integrated portfolio of DSM load shaping tools. ld. at 2. AES first recommended that the Commission order Idaho Power to begin formulating time-of-use rate designs for application to various commercial and industrial customer size groups, such as; 26 kW up to 49 kW demand; 50 kW up to 499 kW demand; 500 kW up to IMW demand; and :;:. I MW demand customers. ld. at 3. However, small commercial (.::: 25kW demand) and residential customers should be exempted from TOU rate participation. AES believes the Commission need not wait until another study is completed before ordering Idaho Power to do this. !d. Second, AES recommended that Idaho Power formulate TOU demand and energy rates in a revenue neutral fashion to the utility. ld. This would provide appropriate customer price signals, which simultaneously promotes improved energy efficiency options and/or load shifting, load management, or load shedding techniques. !d. Third, AES recommended that the Commission order Idaho Power Company to integrate TOU and other rate design options into an overall Demand Side Management strategy for inclusion in an Integrated Resource Plan and in the next general rate case proceedings rumored to commence in the fall of2003. ld. at 4. DECISION MEMORANDUM NWEC AND LAW COMMENTS Following its involvement in the pilot time-of-use (TOU) rates program operated by Puget Sound Energy (PSE), the NWEC has several concerns about TOU programs. First NWEC believes that TOU programs are not a substitute for energy efficiency programs and may divert utility, consumer, and regulator attention away from cost-effective efficiency programs that produce durable economic and environmental benefits. NWEC and LAW Comments at 2. NWEC's second concern is that the PSE program data collected to date suggests that the cost of the TOU program is approximately 10 times the economic benefit. The first of the required quarterly reports released in October showed that 94% of customers were not able to save enough with TOU to offset the $1.00 incremental meter reading charge. !d. PSE submitted a request to the Washington Utilities and Transportation Commission in mid-November to end the pilot-program nine months prior to the original pilot completion date, which the WUTC approved. NWEC noted that the cost threshold would be higher for Idaho Power since the cost ofthe AMR system was not included in the assessment ofPSE incremental costs. Third, NWEC is concerned that TOU pricing and associated load shifting may have adverse environmental impacts. If TOU pricing is effective at shifting loads from on-peak periods to off-peak periods, coal-fired generation may increase in the west since it has a lower variable off-peak running cost than natural gas. !d. at 3. Since coal generation produces 2 - 3 times as much CO2 as gas generation, as well as emitting much larger amounts of oxides of nitrogen (NOx), sulfur dioxide (SOx), particulates, mercury, and other pollutants, a shift from gas to coal carries significant environmental consequences. !d. NWEC also believes that alternative programs, such as critical period pricing and energy efficiency, can provide deeper benefits. The economic value of load shifting on a hydro- based grid is very modest. Data presented in the PSE rate proceeding suggested that the on-peak off-peak power cost differential was about a half-cent per kwh over the next five years. !d. During the few hours per year when the differential gets much larger, creative pricing may help to contain market price spikes and should be examined. Furthermore, NWEC and LAW stated that a strategy to reduce loads on Idaho Power s hydro-based grid during droughts would seem to be more important than TOU pricing. ld. Research done by the Northwest Power Planning Council's Regional Technical Forum indicated that investments in residential weatherization can produce up to 5 kilowatts of DECISION MEMORANDUM peak load reduction for each average kilowatt of energy load saved. ld. at 4. These savings benefit generation, transmission and distribution capacity requirements. Similarly, investments in new construction energy efficiency, industrial motors, and other measures produce significant peak load savings. Simply put, efficiency provides double benefits - both peak AND energy, while TOU programs typically benefit only one aspect of the equation. ld. . Although the NWEC and the LAW Fund recognize that they have largely favored exploration of TOU strategies in recent proceedings, they now recommend the Commission defer any further consideration ofTOU pricing for Idaho Power s residential customers until the economic and environmental impacts are better understood. !d. They hesitate to support such programs, even for industrial and large customers, until more information is available on the environmental consequences of load shifting. However, they do encourage the Commission and Idaho Power to explore a critical peak pricing strategy as one response tool for drought and high energy cost periods. ld. DRAM COMMENTS The Demand Response and Advanced Metering Coalition (DRAM)l is a policy organization comprised of utilities, public interest groups, metering and communications companies and demand response providers. DRAM believes that the proceeding to date has been a good start in identifying the cost and benefits of dynamic pricing. However, DRAM also believes the costs of the enabling technology, in this case advanced metering, may have been overestimated and that some of the benefits from deployment of advanced metering may not have been accounted for. Dram Comments at 12. Types of Meters Dram argued that the key to addressing metering choices is understanding the objectives being pursued and also the benefits that each choice provides. ld. at 4. Standard time- of-use meters enable time-of-use rates due to their ability to record usage in a specific pre-set period for billing purposes. Depending on the meter, however, this may simply be an accumulation of data in several time-based registers and not include data collection in hourly 1 DRAM members participating in these comments include: eMeter, SchlumbergerSema, Landis + Gyr, MeterSmart, DCSI/TW ACS, Echelon, Puget Sound Energy and the Alliance to Save Energy. More information on DRAM can be found at www.dramcoalition.org DECISION MEMORANDUM intervals. While simple TOU rates can be implemented, other options like Critical Peak Day Pricing cannot be. An automated meter reading (AMR) system, per say, does not enable TOU pricing/rates. The functional objective of AMR is to automate and streamline the meter reading operation so as to reduce meter-reading costs. ld. at 5. An AMR system does not necessarily provide the interval measurement necessary for dynamic pricing and, in most cases, a basic AMR system does not increase the frequency of data access and presentation to the utility or the customer. Important to note, however, is that with either a standard or advanced AMR system the benefit to a utility whose existing meters are of the older, conventional, non-AMR type can be great. ld. Several utilities in recent years have undertaken AMR deployments based on a business case supported by savings in meter reading operations. The type of meters most closely associated with demand response is referred to as advanced meters. These meters provide automated meter reading functionality but do so by way of a fixed communications network which provides flexible two-way communications capability. These meters record and measure data on at least an hourly interval basis, transmit data to the utility on at least a daily basis, allow customer access to usage data on at least a daily basis (via a free website), and provide interval-based usage and pricing data to customers on at least a monthly basis (via the monthly bill). !d. at 6. Costs of Meters Although Idaho Power quoted the average meter cost per customer for a standard time-of-use meter to be $145 , DRAM submitted that an average cost of$100 is more appropriate for an advanced meter capable of allowing TOU pricing. ld. at 7. Based on a cost estimate of $100 per customer, which may be at the high end of the applicable cost range, the total cost for providing advanced metering to all 300 000 of IPC'residential customers would be approximately $30 million. ld. at 9. While this estimate could conceivably rise due to special circumstances present in the IPC service territory, DRAM found that the estimate of $72 million for an AMR system as presented in the report is substantially too high based on commercially available technologies installed on millions of customers in the U.S. ld. DECISION MEMORANDUM Benefits DRAM believes that other advanced metering benefits were not addressed in the Report and warrant further examination. These include: outage management and response (i. trip avoidance, crew optimization), more timely and efficient response to customers, reduced meter reading costs (i., reduced labor costs, avoided vehicle and equipment costs), improved meter reading accuracy, and a reduction in estimated bills. The Company would also acquire two-way communications ability and interactive messaging ability, load control and management capabilities, the acquisition of new and different data, and improved forecasting. Advanced meters would also optimize the planning, expansion and operation of the distribution system. Individual customers would benefit from enhanced usage information (resulting in enhanced ability to practice energy management) and additional rate options (customer choice of different product from same provider). The system would benefit from faster wholesale power cost settlements, improved data, improved forecasting, system optimization, and system planning and expansion. ld. at 10-12. STAFF COMMENTS Staff split its comments into three sections. The first portion advocated implementing AMR with or without TOU pricing while the second discussed TOU pricing in generaL The third section outlined Staffs recommendations to the Commission regarding this case. Automated Meter Reading and Time of Use Pricing Although Idaho Power s Report concluded that residential time-of-use pricing was not economically viable "until such time as an AMR (automated meter reading) system is available on Idaho Power s system and a PCA (power cost adjustment) methodology is devised to remove the negative impact to Idaho Power s earnings " Staff did not agree. Staff Comments at 2, quoting Report at 35. In support of its position, Staff noted Christensen Associates analysis that mandatory, critical peak time-of-use retail pricing provided the potential for benefits exceeding $1 million annually and the potential for another $12 million annual benefit by avoiding the capital costs associated with 200 megawatts of new peaking facilities. !d. Even without consideration of TOU pricing, the Report indicated that an AMR system has a positive net present value of $32 million over the life of the equipment as compared to the current metering system. !d. In addition, Staff noted that the AMR study listed many customer service DECISION MEMORANDUM benefits, cost savings, and revenue enhancement opportunities for the Company that would result from implementing an AMR system. !d. According to Staff, the most effective TOU rates (i., critical-peak TOU) can be implemented only if an AMR system is in place. ld. at 4. With AMR, retail prices can vary as necessary to track costs while treating all customers the same regardless of billing cycle because the monthly meter-reading schedule is no longer a limiting factor. Idaho Power tested an AMR system in the Idaho City area in 1999 and concluded that the AMR system was deployable and met the Company s technology requirements. !d. at 3. Although Idaho Power estimated the initial cost of an AMR system to be $72 million, or about 50% more than that required for traditional TOU meters, the entire cost of the AMR system is more than offset by savings in meter reading costs and improved customer service. ld. at 4. More specifically, Idaho Power estimated the annualized cost of an AMR system to be about $4 million, but that AMR would save nearly $6 million per year in monthly meter reading and customer movement costs. ld. at 5. With this in mind, Staff believes that consideration of TOU pricing should first focus on planning and installing an AMR system. !d..at 4. After Idaho Power has begun AMR installations, the Commission could then consider whether TOU pricing, either mandatory or optional, is an appropriate rate design. Staff believes that determination of TOU rates would be best considered during Idaho Power s next general rate case. ld. Once some ofthenew meters are installed, the Commission and Idaho Power will be able to test alternative TOU rate designs to more precisely estimate Idaho customers' price elasticity of demand. Although Staff believes AMR is justified without implementation of TOU pricing, AMR is just the first step in establishing the TOU pricing. Staff Analysis of Idaho Power s TOU Pricing Report Staff was unclear why Idaho Power believes that the PCA mechanism and TOU pricing will necessarily result in lost revenue. To the extent that TOU prices are established to cover costs, Staff does not believe that reduced revenues would result from rate design. ld. at 5. However, if necessary, Staff noted that the Company may file an application with the Commission for a regulatory ruling to accommodate new technology or innovative rate design that results in lower rates, better service to customers, or to allow the Company to earn its authorized return. ld. at 6. DECISION MEMORANDUM Staff did not believe that the EEAG, as a whole, would agree with Idaho Power assessment of the Group s conclusions. ld. Staff has participated in all of the EEAG meetings and agreed that these issues were discussed. However, Staff stated that no vote was taken on these issues and no conclusions were reached on the TOU issue. ld. Although Puget Sound Energy (PSE) recently sought early termination of its voluntary TOU pricing program, Staff believes this should have little impact on the Idaho Commission s consideration of either an AMR system or a critical peak TOU pricing for Idaho Power. ld. PSE serves customers in a more temperate climate and does not experience the extreme summer peak demand that Idaho Power does. !d. PSE's TOU program offers an optional tariff to customers, which as described in the Report, results in less than optimal benefits when compared to a mandatory TOU tariff. In addition, Staff argued that PSE serves primarily an urban area where costs to manually read meters are presumably much lower than Idaho Power s per customer meter reading costs. !d. Staff Conclusion Based on Christensen Associates' conclusion that mandatory, critical peak TOU pricing has the potential to trim 200 MW from Idaho Power s peak demand, Staff believes that this is an option that should not be easily dismissed or unnecessarily delayed given the future capacity deficit forecasted by Idaho Power. !d. TOU pricing, combined with other demand side management programs, may cost-effectively supplant the need for acquiring capacity from peaking plants and transmission upgrades for many years. Staff recommends that Idaho Power submit a plan to the Commission in early 2003 for installation of new meters capable of AMR and critical-peak TOU pricing. ld. at 7. Staff believes the Company should begin implementing AMR in those areas and for those customers where the benefits to Idaho Power and its customers are the greatest. ld. IDAHO POWER REPLY COMMENTS The Company s reply comments agreed with the several conclusions of the NW Energy Coalition and the Land and Water Fund. Specifically, the Company agreed that the economic value of load shifting on a hydro-based grid is very modest. Reply Comments at 5. The Company also agrees with their recommendation that further consideration of TOU pricing for Idaho Power s residential customers be deferred until its impacts are better understood. !d. DECISION MEMORANDUM 6. With regard to Staff s comments, Idaho Power addressed several issues regarding the Report and implementation of an automated meter reading (AMR) system. Potential Benefit of Time-of-Use Pricinq Idaho Power argued that Staffs comments on the potential benefit of TOU pricing provide an incomplete representation of the results included in the Report. Staffs commen!s blur the important distinction between the value associated with load reductions (i., the value associated with reductions in power supply costs) with the value associated with customer bill reductions. fd. at 2. The $1 million in potential benefits from mandatory, critical peak time-of- use retail pricing referred to by Staff represents the benefit customers could realize as a result of reduced bills associated with the time-of-use pricing. ld. This potential benefit to individual customers has no correlation to the value associated with reduced power supply costs attributable to load shifting. Idaho Power noted that although customers have the potential for over $1 million in immediate bill benefits under critical peak TOU pricing, the reduction in power supply costs associated with load shifting is only $370 000 (Report, p. 23; Report, Table 2, p. 29). ld. at 3. The real value of time-of-use pricing comes from a reduction in power supply costs resulting from load shifting, which in turn leads to the reduction in rates paid by all customers, not just the amount of near-term reduced rates passed on to some customers through bill reductions. A pricing mechanism that provided $630 000 more in bill reductions than are supported by cost reductions is not economically viable and will ultimately lead to overall increased rates for all customers, negating any customer benefit that might be available under TOU rates. !d. Ability to Track Market Prices with an AMR System The Company clarified that although the critical-peak TOU pncmg structure overcomes several of the issues associated with standard TOU pricing, it does not eliminate the mismatch between prices and costs. ld. at 4. Idaho Power also indicated that Staffs assertion that with an AMR system the monthly meter-reading schedule is no longer a limiting factor is incorrect. While an AMR system allows for more flexibility in obtaining usage information than a manual read system, monthly meter reading and billing schedules will still be necessary in order to generate bills manage work flows, and integrate usage information into the Company customer billing system. ld. DECISION MEMORANDUM Energy Efficiency Advisory Group Although Staff was critical of Idaho Power s assessment of the EEAG's conclusions regarding time-of-use pricing for residential customers, the Company pointed out that its representation of the EEAG's conclusions is consistent with the meeting minutes as reviewed and approved by the individual EEAG members. ld. at 4- Implementation of an AMR System The Company was surprised that Staffs comments questioned "why the Company has not yet implemented a plan to install an AMR system and apparently is not planning to do so in the near future.ld. at 5 , quoting Staff Comments at 7. In response to informal questions posed by Staff prior to the deadline for the filing of Staff comments, the Company indicated that it is currently experiencing a very tight capital market. ld. The 2003 capital budget approved by the Company s board of directors, although increased over the 2002 capital budget, is still constrained and includes funding only for those items that are deemed critical to reliable operations. While an AMR system would provide many benefits, its immediate implementation is not critical for reliability or ongoing business operations during 2003. The Company expressed to Staff its intent to request 2004 budget approval of the capital needed to begin implementation of an AMR system during 2004. ld. Conclusion Although the Company s Report to the Commission concluded that it is not economically viable to implement time-of-use pricing prior to the implementation of an AMR system, Idaho Power acknowledged that automated meter reading capability provides multiple benefits. As indicated in its reply comments, Idaho Power plans to request budget approval for the cap~al necessary to begin AMR implementation in 2004. This approval of course would be subject to the Company s financial situation, capital markets, and other resource needs. Idaho Power has been evaluating the potential costs and benefits of implementing TOU pricing for its various customer classes for several years and plans to continue evaluating it in the future. As additional information regarding the impacts of TOU pricing becomes known, Idaho Power believes it will be useful in its own evaluation. Idaho Power believes that no further action on the Commission s part regarding time-of-use pricing as it relates to the Company is necessary at this time and that this docket should be closed. !d. at 7. DECISION MEMORANDUM COMMISSION DECISION What action, if any, does the Commission wish to take on the issues of Time- of-Use metering and/or Advanced Meter Reading? /7 ~.lLJA- d". tIl~~ Lisa D. Nordstrom M:IPCEO212 In3 DECISION MEMORANDUM