PASADENA WATER AND POWER

DDR PASADENA WATER AND POWER FINAL ENERGY POLICY ACT OF 2005 Requirements and Impacts for Pasadena Water & Power May 2007

Contents Introduction...1 Interconnection...2 Net Metering...4 Time-Based Rate Schedules...7 Smart Metering...14 Fuel Diversity and Generation Efficiency Standards...20 Procedural Considerations...23 Summary and Conclusions...26 Bibliography...29 PASADENA WATER AND POWER ENERGY POLICY ACT OF 2005 i

Introduction EES Consulting (EESC) was retained by the City of Pasadena Water and Power (PWP) to review the Energy Policy Act of 2005 and compare its requirements with the current provisions of PWP. The Energy Policy Act of 2005 (EPAct 2005) amended the Public Utility Regulatory Policies Act of 1978 (PURPA) to require state regulatory commissions and unregulated utilities with annual retail sales in excess of 500,000 megawatt-hours to conduct assessments regarding the implementation of time-based meters and rates. Specifically, EPAct 2005 added language to PURPA which effectuates the following actions: Utilities are required, upon request by any customer it serves, to interconnect onsite generation facilities to the local distribution facilities. Utilities are required to make net metering available to electric customers, upon request. Utilities are required offer time-based rate schedules that reflect the variance, if any, in the utility s cost of generating and purchasing wholesale electricity. If utilities offer time-based rate schedules, utilities must then offer smart meters to customers who request them. Utilities must consider developing a fuel sources plan that minimizes dependence on one fuel source and ensures that the energy sold to customers is generated using a diverse range of fuels and technologies. The PURPA language states that the utility must consider each of these actions and then make a determination concerning whether or not it is appropriate to implement the standard. Therefore, unregulated utilities and state commissions are not required to adopt the standards, only consider them. However, if declined, the utility must state in writing their reason for the decision in a public document. PWP must make a determination on whether implementation of the new PURPA (EPAct) standards is appropriate. PWP may implement any standard or decline to implement any standard. However, if PWP declines, it is required to state in writing the reason for the decision and make that statement available to the public. PWP could chose to adopt all, part, or a modified version of the standard. EES Consulting was asked to provide a gap analysis of each of the areas to determine the EPAct 2005 requirements, the current PWP status for each item and any required action needed to comply with the EPAct 2005 requirements. PASADENA WATER AND POWER ENERGY POLICY ACT OF 2005 1

Interconnection Based on a review of PWP interconnection agreements, it is EESC s opinion that PWP can meet the requirement of EPAct 2005 regarding interconnection standards without any changes to the Interconnection agreements in place. EPACT 2005 Requirements Section 1254 of the EPAct 2005 requires public utilities to offer customers with on-site generation interconnection to the power grid. The EPAct 2005 added language to PURPA which states that utilities must, upon request, provide interconnection service to any customer that it serves. Interconnection service refers to service to any customer with an on-site generating facility that is connected to the distribution system. The Act specifies that the interconnection service must be offered based on the IEEE Standard 1547. The group that developed IEEE 1547 is still active and will continue to review and revise the standard. The Act recognizes this and is intentionally flexible indicating that Standard 1547 may be amended from time to time. Standard 1547 itself is designed to protect all parties connected to the grid, from small residential applications to the grid as a whole. Standard 1547 also addresses product quality, interoperability, design, engineering, installation and certification. Current PWP Interconnection Standards PWP currently has in place the following interconnection standards: Distributed Generation Interconnection Requirements Regulation 23 (Manual) The DG Interconnection Requirements manual, Regulation 23, was adopted by Council Resolution #8304 on October 12, 2003. The document describes the interconnection, operating and metering requirements for DG units to be connected the electric grid. This 30+ page manual describes the regulations, process, requirements, cost responsibilities, metering requirements, dispute resolution, application review process, and testing and certification criteria. In the manual s Scope and Purpose section it states that the requirements of Regulation 23 are intended to be in accordance with the latest revision of the following regulation, but are not intended to be a substitute for said regulations: Rule 21, Generating facilities Interconnections Underwriters Laboratory (UL) 1741 Institute of Electric and Electronic Engineers (IEEE) P1547 Regulation 23 is specifically written to meet or exceed IEEE 1547, Rule 21, and UL 1741. PASADENA WATER AND POWER ENERGY POLICY ACT OF 2005 2

Consideration To further the development of Distributed Generation resources, EPAct 2005 requires utilities to consider offering its customers the ability to interconnect onsite generation to the grid in accordance with the Institute of Electrical and Electronics Engineers: IEEE 1547. One of the significant issues facing a customer planning to install a Distributed Generation (DG) technology it the interconnection of the device to the electric utility system. The lack of common standards for interconnecting DG devices into the utility system is considered an important barrier to the wide acceptance and installation of DG technologies. In addition, if the interconnection policy is not tailored to different sizes and types of generators, the requirements may be too difficult for a customer to implement. Interconnection policy should, in general, address interconnection issues in a balanced manner to address the size of the generation facility and the unique capability of DG. The current PWP interconnection requirements accomplish this objective by allowing simplified interconnection for qualifying DG facilities. Summary and Conclusions It is EES Consulting s opinion that PWP already complies with the interconnection portion of EPAct 2005 through Regulation 23 by requiring its customers to adhere to PWP s interconnection agreement which meet or exceed IEEE 1547. PASADENA WATER AND POWER ENERGY POLICY ACT OF 2005 3

Net Metering Based on a review of PWP net metering policy, it is EESC s opinion that PWP can meet the requirement of EPAct 2005 regarding net metering without any changes to the policy in place. The following section outlines the EPAct 2005 requirements and further provides a discussion of typical net metering issues and policies. EPACT 2005 Requirements The EPAct 2005 states that utilities must make net metering service available to any customer that makes a request. Net metering is required when energy generated by a customer from an onsite generating facility is delivered to the distribution system and used to offset energy provided by the utility to the customer. Current PWP Net Metering Rules PWP offers mandatory net metering to all customers with self-generation or cogeneration through rate schedule SG: Self-Generation Service, as referenced under the Pasadena Municipal Code 13.04.178 - Section B. In August 2006, California SB 1, Section 6 amended the California Public Utilities Code Section 2827 (c) (1) to state the following: Every electric service provider shall develop a standard contract or tariff providing for net energy metering, and shall make this contract available to eligible customer-generators, upon request, on a first-come-first-served basis until the time that the total rates generating capacity used by eligible customergenerators exceeds 2.5 percent of the electric service provider s aggregate customer peak demand. PWP provides the net metering requirement through a separate rate class for self-generators of all sizes to facilitate the interconnection and billing of these customers. Conditions of the rate class specify customers shall sign an interconnection agreement with PWP and customers shall comply with Regulation 23. At this time, PWP has approximately 45 residential solar customers and 5 commercial solar customers, 6 Distributed Generation customers, and 1 cogeneration customer on schedule SG: Self-Generation. PASADENA WATER AND POWER ENERGY POLICY ACT OF 2005 4

Net Metering Issues and Considerations Net metering allows small customers to offset their electricity consumption by sending extra energy generated to the interconnected utility. A bi-directional meter registers electrical flow in both directions. This type of metering enables a monetary exchange based on net customer generation and consumption. A net metering customer uses distributed generation to generate part of their load and the utility for the remaining load requirements. However, issues arise with the possibility of the customer generating more electricity than they use. The primary question is how this excess energy should be valued if it is returned to the interconnected utility. Opinions range from a minimum rate based on the cost for the utility to purchase wholesale power to a maximum rate based on the full retail energy rate to the customer. Issues associated with net metering, include: The energy portion of the utility tariff may contain fixed charges and costs. If so, the full retail rate may over-compensate the customer for the energy delivered back to the utility and, in turn, hurt the utility s non-participating customers. The energy rate is an average rate over the whole year; therefore it may not correctly value the energy. Wholesale energy rates vary throughout the year and the retail energy rate accounts for these fluctuations. This means that the customer could be providing power to the utility during high or low value times. PWP has already addressed these issues in rate schedule SG, but may want to clarify some of these issues in detail, if any future amendments are made to rate schedule SG. Compatibility with SB 1 PWP has a net metering agreement, Interconnection and Metering Agreement that enables net metering for customers with solar or wind generating devices on their properties. This agreement, however, was developed prior to the passage of SB 1 in 2006. The primary change in SB 1 was to increase the allowable capacity of net metering from 0.5% of peak to 2.5% of peak. Table 1 below shows a comparison of selected stipulations of SB 1 and compared with the requirements of PWP through Regulation 23 and the Interconnection and Metering Agreement. PASADENA WATER AND POWER ENERGY POLICY ACT OF 2005 5

Table 1 Comparison of SB 1 and PWP Regulation 23 PWP Reg. 23 & Net Metering California SB 1 Agreement Provide Net Metering Service Solar, Wind, and Hybrid Generator Types Offered for Up to 2.5% of Customer Peak Demand N/S Residential, Commercial, Industrial, Ag Customer Classes N/S Capacity Up to 1 MW per Site N/S Located at Customer Site; Owned, Leased or Rented Covers 12-Month Time Period Single Meter Capable of Measuring Flow in 2 Directions Meter Cost Responsibility of Customer Additional Meter Cost Responsibility of utility Wind Co-Metering (>50 kw) N/S Request Processed within 30 Days N/S Time-of-use; Co-energy Metering N/S = Not specified In general, the PWP agreement covers the SB 1 provisions. The key is to allow up to 2.5% of PWP s capacity be made available for net metering. This limitation is not specified in the documentation and may not need to be. Another requirement of SB 1 is to have the net metering request processed within 30 working days of submittal. A couple other items include the customer class and the unit size limitation, which are indicated in SB 1, but not currently in the PWP agreement. However, as long as these items are part of PWP policy, they do not necessarily need to be identified in the agreement. Summary and Conclusions The EPAct requires that the utility consider making net metering available to all customers. PWP is in compliance with this standard, as it offers interconnection and net metering for all customers with cogeneration or self-generation. As such, no change is recommended for PWP net metering program. PASADENA WATER AND POWER ENERGY POLICY ACT OF 2005 6

Time-Based Rate Schedules PWP has already implemented time-based rates for most customers. As such, PWP already meets some of the EPACT 2005 requirement for considering time-based rates. The following section outlines the requirement for time based rates stated in EPACT 2005 and describes the additional options that PWP may decide to consider. EPACT 2005 Requirements EPAct 2005 requires regulatory entities to conduct an investigation and issue a decision on whether or not utilities should offer each of its customer classes, and provide individual customers upon customer request, a time-based rate schedule under which the rate charged by the electric utility varies during different time periods and reflects the variance, if any, in the utility s cost of generating and purchasing electricity at the wholesale level (EPAct 2005 Section 1252). The time-based rate options mentioned in EPAct 2005 include traditional time-of-use (TOU) pricing, critical peak pricing, real-time pricing, and load management credit. Each of these is described below: Two Period TOU Pricing - Rates are set in advance and broken into two or three time blocks corresponding to peak, intermediate and off-peak periods. Prices are highest during the peak and lowest during off-peak. Critical Peak Pricing (CPP) Under CPP, TOU Rates are in effect for approximately 95 percent of the hours in a year. However, in the remaining 5 percent of hours of the year which correspond to extreme peak hours of each month, prices are increased substantially to signal the increased value of energy and therefore increased benefit of reducing demand during the extreme peak period. Real Time Pricing (RTP) Rates are set in advance based upon a forecast of hourly real-time wholesale prices. These real-time prices may be updated as frequently as hourly to reflect the actual cost of electricity at the wholesale level in real-time. Load Management Credit Credits for pre-established peak load reductions (customers with large loads) that reduce a utility s capacity obligations. The objective of this section of the EPAct 2005 is for regulating entities to determine, taking into account special circumstances in their area, if additional time based rate structures should be offered to customers, in order to promote conservation, encourage efficiency of resources and implements equitable rates. PASADENA WATER AND POWER ENERGY POLICY ACT OF 2005 7

PWP Current Status PWP currently offers TOU rates to all residential, commercial and industrial customers based on the availability of advanced meters. As such, PWP is ahead of many utilities in the U.S. The PWP TOU rate is designed as an option in the regular rate schedule. For example, Residential Single-Family Service, SCHEDULE R-1, offers two options for energy services charges: Option A Seasonal Flat Rate, or Option B Time-of-Use Rate. Option A offers different rates by season only, while Option B offers rates that differ by summer on and off peak and winter on and off peak. Option B is the one that complies with the EPAct 2005. The time periods used for the TOU rate are defined as follows: Summer months are defined as June through September Summer On-peak hours: 12:00 noon to 8:00 p.m. Summer Off-peak hours: 8:00 p.m. to 12:00 noon Winter months are defined as October through May Winter On-peak hours: 6:00 a.m. to 10:00 p.m. Winter Off-peak hours: 10:00 p.m. to 6:00 a.m. Weekend and holiday hours are all off-peak The TOU program was first implemented in July 2002 and to date only 169 commercial and industrial customers have chosen to participate. According to PWP staff, meter availability has not been an issue. Issues and Considerations Related to Time Based Rates The primary goals of time of use rates are (1) to reflect the time variation in the wholesale cost to produce electricity, (2) to more accurately match costs with the service being provided to the customer and (3) to encourage customers to eliminate consumption during on-peak periods or shift energy use to off-peak periods allowing utilities to operate more efficiently. Design of Time Based Rates As discussed, PWP already has in place a TOU rate for all customer classes. EPAct 2005 discusses two additional time based rate structures CPP and RTP. For all three time based rate designs, PWP s hourly power cost needs to be explored and analyzed to determine the appropriate rate design and pricing. Evaluation of Time Based Rates (TOU, CPP and RTP) The resulting benefits of a successfully designed TOU program are twofold. First, the electric system load shifts over time, allowing for the potential deferral of capital investments in the distribution system. Secondly, customers and utilities realize reduced power costs due to shifting of consumption. Conversely, implementing TOU rates increase expenditures due to the costs associated with replacing or upgrading metering and billing infrastructure. The costs of these investments vary depending on the TOU program selected by the utility and the current capability of the existing system. PASADENA WATER AND POWER ENERGY POLICY ACT OF 2005 8

The Energy Policy Act of 2005 (Act) requires that non-regulated and regulated utilities analyze the costs and benefits of implementing retail rates that are designed to reflect the utility s variation in wholesale power costs. The Act also directs utilities to determine a framework for calculating the benefits and the costs that reflect the major sources of benefits that may be realized by a utility and the major sources of costs that a utility is likely to incur. The remainder of this section will lay out a framework for analysis that can be used by PWP to further evaluate time based rates. Any analysis of time-based rate schedules will need to be performed separately for each rate schedule. Different time-based rates may be appropriate for different customer classes depending on usage patterns and power supply costs. Therefore a separate analysis for each combination of time based rates (TOU, CPP, RTP) and rate schedules (R-1, R-2, S-1, M-1, M-2, L-1, and L-2). Since PWP already offers a TOU rate for all rate schedules, the additional analysis could be limited to the CPP and RTP options. As part of the analysis of time based rates, PWP would also need to determine if the rate structure is mandatory, i.e. required for all customers in the customer class, or voluntary, as is the case with the current TOU rate offered to PWP customers. The first step in the analysis of time based rates is the estimation of the gross benefits of implementing the rates. The major benefits of time-based rates to the utility are twofold. Following the implementation of time-based rates, customers will experience higher rates in onpeak periods and lower rates in off-peak periods. This price signal may cause consumption of energy to shift from peak to off-peak periods if the following occurs: (1) customers are capable of shifting load, (2) the price differential between the on-peak period and off-peak period is large enough to provide sufficient benefits for the customers to shift load, and (3) the customers have adequate information about their loads to assess the impact and benefits of shifting their loads. If customers are able to shift energy consumption between the on-peak periods to the off-peak period, the utility could potentially reduce its power costs and transmission costs. Secondly, as customers reduce on-peak consumption it may be possible for utilities to defer future capacity investments in the distribution system. Both of these benefits need to be accounted for in the benefit-cost analysis. In the calculation of the gross benefits to PWP, the following methodology can be utilized: Determination of Net Savings in Power and Transmission Costs Determination of incremental power and transmission cost by on-peak and off-peak rate periods for the TOU rate design, by critical peak, on-peak and off-peak rate periods for the CPP rate design and on an hourly basis for the RTP rate design. Determine the potential shift of usage under new time based rates based on the assumed price elasticity of substitution for PWP customers. Adjust power cost as a result of customers shifting load from on-peak periods to off-peak periods. PASADENA WATER AND POWER ENERGY POLICY ACT OF 2005 9

Because retail rates are designed to reflect power costs, reduce retail customers average rate because it reflects the reduction in average power costs. Assume that the retail customer would respond to this reduction in its average retail rate by increasing its overall consumption. This increase in overall consumption offset or reduced some of the calculated benefits achieved from shifting consumption from peak to off-peak. Based on the reduction in on-peak energy, calculate the reduced demand consumption. Determine transmission cost savings due to reduction in customer demand. Determination of Net Savings in Future Distribution System Capital Additions Based on discussions with PWP engineers, determine potential savings in future distribution system capital additions due to reducing the magnitude of peak loads. Determine the expected shift in demand from on-peak to off-peak based on the projected reduction in peak loads. Determine average distribution capital investment costs per kw either based on PWP historical data or based on a survey of neighboring utilities. The avoided distribution cost can be calculated as the estimated kw reduction times the projected cost savings per kw. Once the gross benefits per customer are determined, the potential savings can be extrapolated to determine total program savings for both a mandatory and a voluntary rate program. The second step in evaluating time based rates is the estimate of the additional costs of implementing rates. Implementing a time-based rate requires special metering and capability of the Customer Information System to handle multiple rates per period. If only a small number of customers participated in a time-based program, the utility could calculate bills manually for these customers. On the other hand, if more than a handful of customers take service under a time-based rate schedule, major changes to a utility s infrastructure may be required. As part of the analysis of time based rates, PWP needs to examine the potential costs of implementing additional time-based rates. Many of these additional costs have been discussed in the Smart-Meter section, but a summary of the cost components is provided below: Evaluation of the Customer Information System Assess the capabilities of the current CIS and billing system. How many billing periods can the system handle? Is it possible to bill for RTP and CPP rate designs? PASADENA WATER AND POWER ENERGY POLICY ACT OF 2005 10

If upgrades are needed, determine the cost of upgrading the system to handle RTP and/or CPP rates based on discussions with vendors. Evaluation of Metering Hardware Determination of number of meters capable of metering for TOU, CCP and RTP rates by rate class. Determination of the cost, including installation, of new meters capable of metering for TOU, CCP and RTP rates by rate class. Assessment of communications module needs for each rate option. Determination of Additional Administrative Cost Due to meter installation and implementation of time based rates. Due to additional customer education and customer service. Evaluation of Customer Impact Increase complexity on customer bills Potential increase in costs Customer inconvenience Production interruptions Once the benefits and costs have been determined for each time-based rate option and for each customer class, the analysis can be concluded by determining if each time-based rate option should be implemented on a cost-benefit basis. Evaluation of Load Management Credit Load management has generally been used for large commercial and industrial customers. These programs allow the utility to interrupt or reduce customer loads to respond to high market prices or demand costs. Various control strategies can be implemented to ensure that the load reduction actually occurs. In general, very few utilities have implemented load control for residential or small commercial customers. The most common residential load control programs include air conditioning and water heater programs. These programs are estimated to save approximately 0.1 kw to 1.59 kw per customer per event for air conditioning (depending on location and size of housing) and between 0.2 and 0.65 kw per customer for water heating cycling. Larger customers, that are able to shift or stop operations, may be able to provide more benefit to the utility and the customer, especially if a price signal is provided. The estimates savings from this program is difficult to establish, since the potential for demand reduction is dependent on the operation of the individual customer site. PASADENA WATER AND POWER ENERGY POLICY ACT OF 2005 11

For the Load Management Credit, due to the likelihood that this program would be most applicable to large commercial and industrial customers, it is likely that each agreement developed with such customers would be unique based upon the customer s circumstances and therefore a general estimate would not be meaningful. As a result, a generic quantitative costbenefit analysis is difficult to develop for a Load Management Credit. If a PWP customer is interested in a load management program, it is recommended that the specific costs and benefits for that customer are determined on a stand alone basis. Case Studies Time of Use (TOU) rates have been an area of study for utilities for many years. The success of these rate structures has largely depended on the cost of primary sources of power supply and the cost of implementation. TOU rates have been offered in California for several years and have shown some success in particular for large commercial and industrial customers. In 2004, the California Public Utilities Commission (CPUC) required that investor owned utilities analyze and develop business cases surrounding Advanced Metering Systems capable of supporting dynamic tariffs, facilitating operation and other cost reductions, and ultimately reducing peak-energy demand through load control and demand response capabilities. This analysis requires that utilities study the costs and benefits of full deployment or a mandatory program for all of its customers. For a utility such as Southern Cal Edison (SCE), this would involve developing and building an infrastructure capable of serving 5,000,000 customers spread over a 50,000 square mile service territory. In SCE s evaluation, SCE found that with current technology, even under its most optimistic or best full deployment business cases, the results yielded significantly negative net present values (NPV). As a result, SCE began to pursue development of a next generation Advanced Metering Infrastructure (AMI) technology. Since that time, SCE has observed significant potential improvement in the next generation technology. The revised estimate of business case NPV s, incorporating the assumed next generation technology improvements, have changed dramatically. While the NPV s are still negative, the improvement has lead SCE to conclude that if these major technology advancements are realized, it no longer can conclude that the full deployment is highly unlikely to result in a net benefit. Ironically, at the same time that the CPUC has ordered utilities to embark on a study of full deployment or mandatory TOU rate programs, the statewide 20/20 programs for commercial and industrial customers have been criticized for yielding insufficient load reductions for the cost. SDG&E s C&I Peak Day 20/20 program is designed to reward small-commercial and industrial customers with a 20 percent bill reduction in exchange for the customers cutting their demand by 20 percent at certain times. Unfortunately, between 2005 and 2006 the number of customers participating and the amount of load reduction achieved appears to have dropped dramatically. This program has also been criticized for going the way of the other statewide programs by achieving benefits derived from the load reductions that are less than the associated costs. PASADENA WATER AND POWER ENERGY POLICY ACT OF 2005 12

In 2004, a survey of United States Real Time Pricing (RTP) programs that reviewed 43 utilities with voluntary RTP programs was performed by Berkeley National Laboratory. The survey indicated that despite the theoretical benefits of improved price signals to retail customers, participation in most programs is declining. It showed that the customers that were able to be most responsive to price changes were those that had on-site generation. It also concluded that while the goal to improve economic efficiency is likely to be achieved by reducing the disconnection between wholesale prices and retail prices, it also transfers the risks to customers. Unfortunately, it was found that the customers had difficulty managing exposure to such price risks. Of the 43 utilities and their associated programs surveyed, only one program resulted in a system peak reduction of 1 percent. Summary and Conclusions EPAct 2005 requires regulatory entities to conduct an investigation and issue a decision on whether or not utilities should offer a time-based rate schedule for all customers. PWP currently offers TOU rates to all residential, commercial and industrial customers based on the availability of advanced meters, however, PWP needs to consider other time-based rate options, such as CPP and RTP. The objective of the time-based rate consideration requirement is for regulating entities to determine, taking into account special circumstances in their area, if additional time based rate structures should be offered to customers, in order to promote conservation, encourage efficiency of resources and implements equitable rates. This section summarized a framework for analysis that could be used by PWP to further evaluate time based rates. Based on the experience by PWP and other California utilities, time-based rates may provide additional incentive for conservation and efficient use of resources for some large customer. However, most customers are not interested nor experience sufficient savings such that these programs are successful. Before PWP determines to proceed with the cost-benefit analysis of additional time-based rates options, the following items need to be considered: PWP currently offers a TOU rate, which is not selected by most customers. PWP should consider the potential impacts on customer participation and response in the event that TOU rates are modified as a result of an updated cost of service study. Are there any significant delays in generation, transmission or distribution infrastructure that can be realized if demand is shifted off-peak? If the CIS system needs to be upgraded, this cost often outweighs any benefits obtained by a changing rate structure. The experience with CPP and RTP programs demonstrate very limited response, except for large sophisticated customers. PASADENA WATER AND POWER ENERGY POLICY ACT OF 2005 13

Smart Metering PWP currently offers a TOU-capable meter to customers who request the TOU rate and can meet this portion of the EPAct. However, PWP is required to investigate whether or not it is appropriate to install time-based meters for all customers. More details of the requirements and issues related to smart metering are discussed in this section. EPACT 2005 Requirements The EPAct 2005 requires that the utility consider offering time-based rates to all customers, as discussed in the previous section. Then if a customer selects the time-base rate, the utility must provide the customer with a time-based meter. The actual language from Section 1252 reads as follows: (c) Each electric utility subject to subparagraph (A) shall provide each customer requesting a time-based meter capable of enabling the utility and customer to offer and receive such rate, respectively. The Act also specifies that the investigation of time-based meters must consider the impact of providing them to all customers: Each State regulatory authority shall conduct an investigation and issue a decision whether or not it is appropriate for electric utilities to provide and install time-based meters and communication devices for each of their customers Many of the issues related to smart meters are intertwined with the time-base rate schedules covered in the previous section. However, this section covers items specifically related to the meters. PWP Current Status PWP currently does meet the specific requirement by offering a Time-of-Use Rate (Schedule R- 1, Section D-3.2 Option B). However, the rate schedule includes a footnote that indicates This option is subject to meter availability. This limitation may need to be revised or removed in order to comply with the shall provide clause. PWP Current Meter Status PWP currently has 53,980 residential, and 8,255 commercial and industrial customers (total of 62,235 in 2006). PWP is currently in the process of replacing older residential meters with AMR-capable meters. This process is approximately 2/3 complete. The new meters, while capable of AMR, do not have time-of-use capability. The commercial and industrial customers PASADENA WATER AND POWER ENERGY POLICY ACT OF 2005 14

have meters with the ability for time-of-use rates. PWP currently offers the following meter types: Centron new AMR meters for residential and small commercial, no TOU Sentinel all sectors, AMR and TOU capability ABB commercial and industrial, AMR and TOU capability The Centron meter is the one currently being installed in all residential applications. If a TOU rate is requested, then a Sentinel meter would be installed. Issues and Considerations related to Smart Meters What is a Smart Meter? Traditional electrical meters only measure total consumption and do not provide information regarding when the energy was consumed. Smart meters provide an economical way of measuring this information, enabling the utility to price electricity based on the cost of generating the electricity at the time it was purchased. The basic definition of a smart meter, in the context of the EPAct is a meter that is capable of measuring consumption during the time it took place, and thus can facilitate time-based rates. Many common definitions of smart meters include the communication aspect. By this definition, a smart meter identifies consumption in more detail than a conventional meter, and communicates that information via some network back to the local utility for monitoring and billing purposes. Smart meters usually involve a different technology mix such as real-time or near real-time reads, power outage notification, and power quality monitoring. These added features provide more capability than simple AMR (automated meter reading). In order to implement a two-period TOU rate, a CPP or an RTP program, special electronic meters are required to collect, store, and communicate the data to a utility s CIS system. These meters are designed in a modular fashion to (1) allow for recording consumption assuming differing levels of complexity in the TOU rates structure and (2) accommodate a variety of communications technologies for data collection. Major manufacturers of metering equipment provide both single phase and three phase meters capable of supporting TOU rates. In order to collect the data from the meters, these meters are designed to work with either a specific communications technology such as Power Line Carrier or to allow the purchaser to select the type of preferred communications technology (cell phone, radio frequency, fiber optics) and select a communications module that can be added to the meter. In addition to the meter itself, an advanced metering installation requires communication networks and data management systems. These additional components are referred to as the advanced metering infrastructure (AMI). PASADENA WATER AND POWER ENERGY POLICY ACT OF 2005 15

Smart Meter Implementation Cost The cost for smart metering infrastructure is becoming more consistent and better understood due to the significant number of large-scale installations. The cost components of smart meters include: Advanced metering infrastructure system hardware and software New meters and related equipment and labor Installation IT integration Other utility internal costs Meter Costs PWP is currently in the process of installing new Centron meters throughout the city (AMR, but no TOU). The cost for each meter is approximately $70. For customers that request a TOU meter, the Sentinel type would be provided at a cost of just under $500. For comparison, based on discussions with other utilities and meter manufacturing companies, costs for single-phase meters range from approximately $190 to $500 per meter depending on the communications module and the module required to accommodate the Two-Period TOU rate program. Generally, costs for three phase meters range from approximately $300 to $800 per meter depending on the communications module and the module required to accommodate the TOU rate program. Costs for multi-phase meters designed for large loads range from approximately $400 to $1,500 per meter depending on the communications module and the module required to accommodate the TOU rate program. Advanced Metering Infrastructure Costs The costs for smart meter communications components are illustrated in Table 2. Communication System Type Table 2 Smart Meter Infrastructure Component Cost Installed Cost ($/meter) Walk/Drive-By Radio $50 - $90 Radio Fixed Network $100 - $160 Power Line Fixed Network $110 - $175 Source: EEI, Deciding on Smart Meters: The Technology Implications of Section 1252 of the Energy Policy Act of 2005, September 2006 Another report by FERC 1 indicates that the per-meter hardware costs for AMI range between $68 and $100, and the total installed capital cost ranges between $135 and $214 per meter. 1 US Federal Energy Regulatory Commission, Assessment of Demand Response & Advanced Metering, Staff Report, August 2006. PASADENA WATER AND POWER ENERGY POLICY ACT OF 2005 16

However, the prices have been dropping in recent years and case studies since 2004 have revealed ranges of $68 - $86 for hardware costs, and $135 - $150 for installed capital cost. A typical breakdown of these installed capital costs is shown in Table 3 below: Cost Component Table 3 Breakdown of Installed Capital Costs Percent Endpoint Hardware 45% Network Hardware 20% Installation 15% Project Management 11% IT 9% CIS and IT Costs In addition to the meter hardware and installation cost, and the AMI hardware and installation cost, is the cost for IT and data management. A full AMR with real time pricing capability would require a significant overhaul of the PWP data management system. PWP estimates the cost to replace the current billing system between $2 and $5 million, depending on the type of system. Total Costs A more comprehensive evaluation would be needed to obtain the overall cost for implementing smart meters on a system-wide basis. However, based on the values indicated above, a ballpark high-end estimate can be made: Meter cost ($450) + Infrastructure Cost ($100) = $550 per customer Number of Customers = 62,235 Total meter Implementation Cost = 62,235 x $550 = $34,229,250 CIS Replacement = $5,000,000 Total = $39,229,250 Benefits of Smart Meters Organizations seeking to install smart meters in their territories or jurisdictions ultimately conduct a detailed cost/benefit study. These studies result in net present values or benefit cost ratios. The benefits of smart meters are more difficult to determine and are not as well know as the meter costs. However, in a variety of case studies, most have shown the benefits outweigh the costs. For example, PG&E has derived a B/C ratio of 1.01 and SDG&E found a ratio of 1.08 2. In both of these cases, since the ratios are near 1.0, the costs are nearly equal the benefits. 2 Australia Ministerial Council on Energy, Information Paper on the Development of and Implementation Plan for the Roll-out of Smart Meters, January 2007. PASADENA WATER AND POWER ENERGY POLICY ACT OF 2005 17

On the other hand, Southern California Edison initially found the cost in excess of the benefits (BC ratio 0.59). The benefits of smart meters can include: Peak reduction local distribution Peak reduction generation Billing and collection Meter reading Trading risk management Network management Metering savings Customer service In all cases the majority of the benefits come from the peak reductions and savings in meter reading. According to EEI, the single greatest benefit is the reduction or elimination of manual meter reading, accounting for between one and two thirds of the total benefit. For PWP, the current plan for installing AMR-capable meters for all customers will capture a significant portion of this benefit. It may also be possible by upgrading to a fixed communication network, that the Centron meters could provide the data necessary to support TOU rates. Summary and Considerations PWP offers time-of-use rates and can provide a TOU meter for any customer. PWP has not yet evaluated the impact of providing TOU rates and meters to all customers. Some considerations include: Determine the costs and benefits of installing smart meters for all customers. Evaluate the costs and benefits of the different smart metering types. Compare the costs and benefits of smart meters for different customer classes. Understand and evaluate the impact of TOU rates on IT and database systems. Evaluate the impacts of networking and communications systems (e.g., if a fixed network is used, the basic Centinel meter can transmit every 5 minutes and would be able to support various TOU rates). Detailed cost-benefit studies can be conducted. However, experience has shown that for utilities like PWP, the cost for full TOU and Smart Meter implementation far exceeds the benefit. PASADENA WATER AND POWER ENERGY POLICY ACT OF 2005 18

Exceptions are when significant new resource development is needed and there is a significant gap between base load and peak. For PWP, the desired effect for peak shaving and demand response can likely be achieved through offering a program to selected large commercial and industrial customers at relatively low cost. PASADENA WATER AND POWER ENERGY POLICY ACT OF 2005 19

Fuel Diversity and Generation Efficiency Standards While PWP has not recently published a separate fuel sources plan, the 2007 Draft IRP does address both fuel diversity and the efficiency of current fossil fuel generation. EPACT 2005 Requirements The EPAct 2005 requires each electric utility to develop a plan to minimize dependence on a single fuel source and to ensure it uses a diverse range of fuels and technologies to generate electricity. The Act states: Each electric utility shall develop a plan to minimize dependence on one fuel source and to ensure that the electric energy it sells to consumers is generated using a diverse range of fuels and technologies, including renewable technologies. A fuel sources plan would analyze the fuel mix in PWP s current resource portfolio, and address how PWP will plan resources in the future while attempting to minimize the dependence on a single fuel source. Diversified portfolios mitigate exposure to both operational and financial risks associated with over-reliance on a single fuel source. Fuel diversity can produce a variety of potential benefits, including: Reduction of price volatility Mitigating regulatory risk associated with individual fuels Environmental benefits Improved system reliability Improved operational flexibility In addition, EPAct 2005 requires each utility to develop and implement a 10-year plan to increase the efficiency of its fossil fuel generation. PWP Current Status Senate Bill 1305 (SB 1305) requires every retail supplier that makes an offering to sell electricity that is consumed in California shall disclose its electricity sources. The California Energy Commission developed a standard reporting format called the Power Content Label. The resulting fuel resource mix for PWP is located in Table 4. In addition, the fuel resource mix for the state is included for comparison. According to this information, PWP is primarily dependent on coal for 67 percent of the total energy supply. PASADENA WATER AND POWER ENERGY POLICY ACT OF 2005 20

Table 4 PWP Power Content Label Second Quarter 2007 Energy Resources 2007 PWP Power Mix 3 2006 CA Power Mix 4 Eligible Renewable 9% 5% Biomass and Waste 7% <1% Geothermal 1% 4% Small Hydroelectric ( 30 MW) <1% <1% Solar <1% <1% Wind <1% <1% Coal 67% 29% Large Hydroelectric (> 30 MW) 5% 31% Natural Gas 11% 35% Nuclear 7% <1% Other <1% - TOTAL 100% 100% Pasadena Water and Power published a draft Integrated Resource Plan (IRP) January 31, 2007. Within the document, PWP included the following passage regarding the utility s reliance on coal: Throughout the public process of presenting this draft plan, it was clear that the citizens of Pasadena have a strong desire to reduce the consumption of coal as power generation fuel. PWP shares this strong desire. State legislation has reinforced this concept, and federal legislation over the next several years will likely impose a national standard. PWP recognizes that too much coal is burned to meet the needs of the city. The current 65 percent reliance does not reflect fuel diversity, increases greenhouse gases over a more balanced portfolio, and is at risk of increasing costs through further carbon restrictions or carbon taxes. For all of these reasons, the goal of this plan is to reduce this reliance on coal in a prudent manner through the years. 3 http://www.ci.pasadena.ca.us/waterandpower/power_contentlabel%201stqtr2007.asp 4 Letter from California Energy Commission, April 16, 2007. PASADENA WATER AND POWER ENERGY POLICY ACT OF 2005 21

PWP is working with the other IPP 5 participants to investigate solutions to the CO 2 emissions. There should be no expectation that technology can solve this problem and other options will be investigated such as partial divestiture or renewable energy blending. All of these options will have a consequent cost that PWP will present as an addendum to this report. The costs may include the loss of the associated transmission line (the Southern Transmission System). If a reduction in output from IPP is pursued, additional studies will be required to determine replacement power. One possibility is an increase in local generation. This option will require a further investigation of transmission and distribution impacts associated with increased generation in Pasadena as well as the feasibility of increasing the licensed capacity of local generation 6. In addition, EPAct 2005 requires each utility to develop and implement a 10-year plan to increase the efficiency of its fossil fuel generation. PWP s IRP addresses this issue as well. It is recommended that PWP re-power approximately 110 MW of local generation to replace aging, inefficient units with natural gas combined cycle technology. Summary and Considerations While PWP has not published a separate fuel sources plan, the IRP does consider this issue and the concluding recommendations account for shifting energy supply away from coal to other resources, including a high renewable resource target. PWP could easily create a separate Fuel Diversity Plan report with very little, if any, new analysis. Alternately, PWP could issue a declaration that the fuel diversity and generation efficiency issues were covered in the 2007 Integrated Resources Plan. 5 Intermountain Power Project (IPP) 6 Pasadena Water and Power, Integrated Resource Plan, Draft, January 31, 2007. PASADENA WATER AND POWER ENERGY POLICY ACT OF 2005 22

Procedural Considerations The general process for a municipal or public utility board to consider and determine whether or not to implement a particular standard is specified by PURPA. The primary requirements are to hold a public hearing, and then make a consideration and determination of appropriateness of each federal standard. For reference, this section includes first some process information based on PURPA specification, next examples of what other utilities are doing or have done related to this standard is provided, and finally recommendations based on PURPA specifications and the utility interpretations of the specification are provided. EPAct 2005 Requirement Based on the PURPA specifications, the basic procedural requirements for consideration of the standards are: 1. Public notice of hearing invite comments 2. Hold public hearing present data and hear public comment 3. Consideration of standard 4. Make determination in writing based upon findings and evidence presented in the hearing in relation to the three purposes of PURPA 7 and state laws 5. Determination made available to the public While the process appears fairly simple, it has been interpreted many different ways by utilities. Processes Established by Other Utilities EESC conducted research regarding the processes established by other utilities around the country for comparison. This section includes brief summaries of selected utilities and their process and timelines for conducting the public process. City Public Service (San Antonio, Texas) CPS has outlined their process as follows: Publication of CPS Energy staff's preliminary recommendations on the company's Web site, cpsenergy.com - April 6, 2007 7 Three Purposes of PURPA: Encourage conservation of energy supplied by electric utilities Encourage optimal efficiency of electric utility facilities and resources Encourage equitable rates for electric consumers. PASADENA WATER AND POWER ENERGY POLICY ACT OF 2005 23