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Home My WebLink About12 ELEC RESTRUTURE 02-02-98 NO. 12 2-2-98 Inter-Com DATE: TO: FROM: SUBJECT: FEBRUARY 2, 1998 · ~VILLIAM A. HUSTON, CITY MANAGER CHRISTINE A. SHINGLETON, ASSISTANT CITY MANAGER STRATEGIC ASSESSMENT FOR THE CITY OF TUSTIN RESTRUCTURING UNDER ELECTRIC RECOMI~fEN~ATION It is recommended that the City Council receive and file the subject report and direct staff to schedule, a future City Council workshop to discuss the subject report in more detail. FISCAL 13{PACT No direct fiscal impacts at this time. Opportunities for some immediate electric cost savings may be. possible in the short term with no action by the City of Tustin. BACKGRO~/DISCTISSION In March, 1997, the City Council authorized the firm of Resource Management International, Inc. (RMI) to undertake an analysis of options available to the City for the achievement of cost savings in the purchase of electricity based on the restructuring of the electric industry to be implemented pursuant to .M3 1890, additional state law and adopted California Public Utility Commission (CPUC) rules and regulations. Attached is the report entitled "Strategic Assessment for the City of Tustin Under Electric Restructuring" which is a culmination of RMI's work efforts. The report provides the City with the following: · An overview of City electric loads; · Opportunities for achieving cost savings in meeting these loads from either Southern California Edison (SCE) or an alternate power supplier or energy service provider and; Any potential advantage to aggregating the City's electric loads with MCAS-Tustin loads, loads of other industrial, commercial, and or residential electric consumers in the City, or loads of other agencies. The report is intended to provide a basis for any decisions regarding the City's choice of an electric service provider in the future. However, there are benefits and costs that need to be taken into consideration in review of available options. William A. Huston Electric Restructuring February 2, 1998 Page 2 Since the timetable for the City pursing any available options is entirely at the City's discretion, staff would suggest that the City Council have an opportunity to review the attached report. Once the City Council has an Opportunity to complete its review of the document, we would recommend scheduling a special workshop to discuss the report and any direction to staff that the ou ha ,sitar, STRATEGIC ASSESSMENT FOR THE CITY OF TUSTIN UNDER ELECTRIC RESTRUCTURING PREPARED FoR: City of Tustin RESOURCE MANAGEMENT INTERNATIONAL, INC. Unpublished Work © January 1998 TABLE OF CONTENTS STRATEGIC ASSESSMENT FOR THE CITY OF TUSTIN UNDER ELECTRICAL RESTRUCTURING SECTION PAGE SUMMARY ............................................................................................................... 1-1 1.1 OVERVIEW OF ELECTRIC RESTRUCTURING ............................................ 1-1 1.2 SUMMARY OF POTENTIAL SOURCES OF ELECTRICITY COST SAVINGS .......................................................................................... 1-1 1.3 SUMMARY OF OPTIONS AND RECOMMENDATIONS ........................... 1-3 2 PURPOSE OF REPORT ........................................................................................... 2-1 BACKGROUND OF ELECTRIC INDUSTRY RESTRUCTURING ...................... 3.1 AB 1890 .............................................................................................................. 3-1 3-1 3.1.1 Direct Access to IOU Customers ...................................................... 3-2 3.1.2 Special Protections for Smaller Customers ...................................... 3-2 3.1.3 Requirements for Load Aggregators ............................................... 3-2 3.1.4 Limitations on Avoidance of IOU CTC ........................................... 3-3 3.1.5 Municipal Utility Public Goods Charge ............ .............................. 3-3 3.2 SB 477 AMENDMENTS TO AB 1890 .............................................................. 3-3 3.3 CPUC AND FERC IMPLEMENTATION OF RESTRUCTURING ............... 3-4 3.3.1 FERC Implementation of Reslxucturing .......................................... 3-4 3.3.2 CPUC Implementation of Restructuring ......................................... 3-4' 3.3.2.1 The CPUC Direct Access Decision ......................... , .......... 3-5 3.3.2.2 The CPUC Metering and Billing Decision ....................... 3-6 4 ANALYSIS OF CITY ELECTRIC LOADS ............................................................. 4-1 OPTIONS FOR ELECTRIC SERVICE .................................................................... 5-1 5.1 DIRECT ACCESS FOR CITY LOADS ............................................................. 5-1 5.1.1 City Service Needs ............................................................................. 5-1 5.1.2 Assessment of Potential Alternate Power Suppliers and Energy Service Providers ........................................................ 5-2 5.1~3 Other Cities' and Entities' Direct Access Arrangements ................ 5-5 5.1.4 Process for Soliciting and Evaluating Bids to Provide Direct Access Service ........................................................ 5-7 '5.1.5 Potential'Costs/Savings for City Direct Access .............................. 5-7 5.2 CITY AGGREGATION OF DIRECT ACCESS LOADS ............................... 5-10 5.2.1 Aggregation with MCAS ................................................................ 5-11 5.2.2 Aggregation with Other Agencies ............................................ '. .... 5-12 TABLE OF CONTENTS 5.2.3 Industrial and Manufacturing Aggregation .................................. 5-13 5.2.4 Residential and Small Commercial Aggregation .......................... 5-14 5.2.5 Combined Aggregation ................................................................... 5-17 5.3 STATUS QUO: SERVICE FROM SCE .......................................................... 5-17 5.3.1 SCE Bundled Service with 10 Percent Rate Reduction ............ .. .... 5-17 5.3.2 Access to PX Hourly Prices ............................................................. 5-19 5.3.3 Potential for Spedal SCE Rate or Services ..................................... 5-19 5.4 COST/BENEFIT SUMMARY ......................................................................... 5-21 5.5 SCE DISTRIBUTION VOLTAGE UPGRADE ............................................... 5-22 5.6 POTENTIAL INSTALLATION OF NEW GENERATION FACILITIES .... 5-23 5.7 POSSIBILITY OF FORMATION OF MUNICIPAL UTILITY ...................... 5-23 ISSUES AND RECOMMENDATIONS .................................................................. 6-1 6.1 Issues and Concerns ......................................................................................... 6-1 6.2 Recommendations ............................................................................................. 6-2 A B C D LIST OF APPENDICES DATA COLLECTED AND DATA ANLAYSIS METHODOLOGIES ................ A-1 CURRENT PROCEDURES FOR DIRECT ACCESS IMPLEMENTATION (AS OF NOVEMBER 14, 1997) ................................................................................ B-1 SCE RESIDENTIAL LOAD PROFILE .................................................................... C-1 SCE ENERGY SERVICES ......................................... .' ........................................... ~. D-1 BID SOLICITATION AND EVALUATION PROCESS ........................................ E-1 SECTION 1 SUMMARY 1.1 OVERVIENV OF ELECTRIC RESTRUCTURING With the coming restructuring of the California electricity industry, there will be opportunities for informed electric consumers to achieve savings on their cost of electricity. The electric rates of California's investor-owned utilities (IOUs), including Southern California Edison Company (SCE), are some of the highest in the nation, and the introduction of competition into the California electric industry will allow customers to choose among suppliers in seeking the best available deal. The City of Tustin (City) is currently served by SCE and will be in position to take advantage of cost saving opportunities. However, the extent of those potential savings is limited in the near term for electric customers of California's IOUs by the mandate of California law and the California Public Utilities Commission (CPUC) that the IOUs are entitled to recover a "comPetition transition 'charge" (CTC) to be imposed for the next four years through the year 2001 to recover their "stranded investment" in generation and other facilities that will be rendered uneconomic in the new competitive era. CTC charges are anticipated to mount to as much as one-third of an IOU's current billing rate. These charges will be added to the costs of serving a current IOU customer regardless whether the IOU continues to provide service or the customer procures its power from an alternate power supplier or energy service provider (ESP). Therefore, while some savings should be achievable in the next four years, the City is likely to have to wait until the CTC recovery period has ended to achieve more substantial savings. 1.2 SUMMARY OF POTENTIAL SOURCES OF ELECTRICITY COST SAVINGS Despite the burden of the CTC for the near term, immediate electricity cost savings may be achieved from among the following sources of savings: Savings.on the cost of electricity generation (commodity cost) from the purchase of power from an alternate power supplier or ESP, including the following potential options: · Indexed commodity price based on a percentage of the price paid by SCE for the purchase of power from the California Power Exchange (PX). · Shared savings price based on a percentage of the differential between the PX price and the commodity production cost incurred by the alternate supplier. 1-1 SU1VEvIARY Savings resulting from improvement in efficiency of energy use or shifting of time of energy use - potentially based on programs instituted by an alternate ESP. Savings that may be available from economies of scale in electricity purchasing, metering, billet, g, etc. Savings that may be based on diversity of load profile resulting from load aggregation. The City may be able to realize the foregoing savings through the individual components listed above or in the form of overall fixed electricity pricing or a discount off the total electric bill that the City would otherwise pay to SCE, without regard to the commodity cost or other specific elements of the City's electric service. One cost saving that the City will be able to realize immediately on January 1, 1998 even if it does not change service providers is the ten percent reduction in electric rates mandated by state law to go into effect on that date for the accounts of residential and "small commercial customers," having a maximum peak demand of less than 20 kilowatts (kW). While that reduction will not apply to the City's largest electric loads, such as its water treatment plants, large pumps, and city hall, the reduction will apply to many smaller City accounts (accounts served under SCE's GS-1 rate schedule). However, a surcharge will be imposed on those accounts after the year 2001 to repay the bonds that will finance that immediate rate reduction. Tustin may be able to achieve potential electric cost savings in addition to the ten percent reduction for small customers mandated by law by means of a number of electric service alternatives, including the following: Direct purchase of electricity for City-owned loads from an altemate power supplier or ESP. Comprehensive energy services arrangement with an ESP, including other energy efficiency, load management, and engineering improvements in addition to electricity purchases. City aggregation of its loads with other electric loads for purchase from an alternate power supplier or ESP. · Aggreg-ation with the Marine Corps Air Station (MCAS), Tustin. · Aggregation with other neighboring cities or agencies. Aggregation with industrial and/or commercial loads in city limits. Aggregation with city residential customers. Aggregation with combinations of the above. 1-2 SUMMARY Continued service from SCE with an attempt to obtain a discount rate or other SCE service benefits. · Upgrade in the transformer voltage or distribution system by which the City receives power from SCE at major City loads. · Any potential benefits that might result from formation of a municipal utility. Many factors will enter into the determination of the best opportunity among the options available to the City for electricity cost savings. The analysis set forth in this report indicates that a comprehensive arrangement with an alternate, energy provider, including load aggregation with the MCAS and/or with large manufacturing and commercial loads in the City, may achieve the most optimum electricity cost savings, unless significant service and cost reductions are negotiated with SCE. Recent trade press analyses suggest that major ESPs and potential customers are concerned that little in the way of significant savings in electricity costs is achievable for all but the largest electricity consumers with the most flexibility in their consumption patterns. Most notably, with the exception of only generally-described arrangements by the cities of Palm.Springs and South San Francisco, there have been no announced deals that would propose to provide significant savings to residential customers. For example, Enron's recent media blitz promoting its offer of a ten percent rate reduction plus two weeks free electricity after one year would provide no savings for residential customers over the reduction mandated by law during that first year. Moreover, assuming Enron's offer of two weeks of free electricity is based on an average bill, the savings would be less than four percent of the resident's annual bill, applied only after Enron had obtained a year of revenues from serving that customer. (If the free electricity is implemented during the winter months, it would be of even less value.) In addition, direct access service may not be initiated until each current customer of an IOU requesting such service submits a formal written request for service. Thus, it appears that there are significant obstacles to be overcome if the City should desire to become an aggregator for residential electric customers in its city limits. 1.3 SUMMARY OF OPTIONS AND RECOMMENDATIONS The timetable for the City's development of alternate energy service options is entirely at the City's discretion. There are no deadlines that must be met in order to obtain such alternate service after electric industry restructuring has been implemented. Alternate service is currently required to be made available on (or shortly after) January 1, 1998, and the IOUs have been directed to begin accepting requests for direct access service by November 7, 1997. Tustin may select an alternate power supplier or ESP at any time after that date and will be able to take Service from that alternate provider in due course after 1-3 SUMMARY making that selection. The City will simply retain SCE as its default service provider after January 1,1998 until it may choose to utilize an alternate provider. This report concludes that it is currently premature for the' City to proceed immecliately with the effort and expense of preparing and reviewing responses to a request for proposals (RFP) for alternate electric service strictly for the City's own electric accounts. Based on information provided, the City has an on-peak electric load of approximately 2.7 MW and annual usage of approximately 16,000,000 kWh, with an annual electric bill in the neighborhood of $1,400,000. Even 'with the maximum reported figure of five percent guaranteed savings from an alternate service provider, the City's ann~al savings would- only be in the range of $70,000. Savings in that range - even if achievable - would seem to make the cost of the RFP process a marginally beneficial one at best for the City's own loads.' However, the many potential opportunities available to the City for aggregation of its electric loads with those of others provide the City a range of options for proceeding with efforts to achieve significant energy cost savings. As a rule of thumb, it appears that aggregated electric loads begin to appear particularly attractive to alternate service providers in the range of 20 MW peak load and/or 100,000,000 kWh per year. Figure 1 set forth below shows projected loads available for aggregation with City loads that could build the total amount of aggregated load to the general range of attractiveness to bidders. Based on the foregoing estimates, there should be enough potential load within Tustin's city limits available for aggregation to reach the threshold of attractiveness to alternate energy service providers (ESPs). Furthermore, as set forth in the summary of potential benefits in the Load Aggregation Summary that follows on pages 1-10 and 1-11, the total potential savings to electric customers within Tustin city limits could amount to as much as $793,384 if a reasonable assumed percentage of those certain customers 'were to participate in the aggregation effort. The analysis set forth in this report indicates that a comprehensive arrangement with an alternate energy service provider, including load aggregation with the MCAS and/or with large manufacturing and commercial loads in the City, holds the most promise for achieving optimum electricity cost savings for electricity customers in the City. Moreover, if the City were to undertake to form a joint action agency for electricity purchasing with other agencies such as the Tustin Unified School District or neighboring cities, the load of any other agency could increase that available total load or could replace one or more types of loads listed in the table (such as the residential component). While an aggregation effort which takes the MCAS Tustin Project into account may take several years and may not be reasonable until after the year 2000, the City could explore other aggregation possibilities that could expedite implementation. 1-4 OgOg /.tOT, 9 ~,0~ 01.0~ /..00~ £00~ 666 !, ~'66 !, SUMMARY While the City is considering its load aggregation and other alternate electric service options, in the interim it will remain an electric customer of SCE. In order to proceed with its decision making process with regard to its electric service options, the City needs to make the following decisions and take the following associated actions: : The City must determine whether it is willing to devote time and resources to developing a load aggregation effort to enhance its electric service options by increasing its purchasing power. · If not, theft the City should: 1) Evaluate measures that it may be able to take on its own to reduce its costs of electric service from SCE, including more efficient operation of its water system to minimize electricity usage during periods of peak system, demand and potential re-negotiation of its current franchise agreement with SCE. Utilize services offered by SCE to reduce its costs, including SCE's energy efficiency services, optimal rate schedule identification, possible consolidated billing, and other SCE services. 3) Particularly evaluate the option of utilizing the "Hourly PX Rate Option" for its larger electric loads that are able to minimize electric usage during peak periods. Evaluate unsolicited proposals that the City may receive from alternate electric service providers. If interested, the City must determine whether it is willing to attempt to organize a residential load aggregation effort. If so, then the City must commence the preparation of marketing materials, prepare a customer agreement and information notice, enter into a service provider agreement with SCE, and engage in other actiVities necessary to provide service to residential customers. Whether or not the City undertakes residential load aggregation, the City should identify and contact primary potential load aggregation candidates, including large manufacturing and commercial businesses, the TuStin Unified School District, and neighboring cities. 1-6 ~ ~ SUM/vlARY Based on the results of-its contacts with potential load aggregation candidates, the City must determine whether a critical mass of potential load has been identified to be particularly attractive to alternate service providers. · · If not, then the City should undertake the actions listed above for continuing service from SCE, If so, then the City should enter into an arrangement with those other potential candidates to share the costs of preparation and to issue a joint RFP for electric services. The City and its load aggregation group should prepare, issue, and evaluate responses to the RFP. If the responses are not attractive, then the City should undertake the actions listed above for continuing service from SCE. If an attractive service proposal is received, then the City and its load aggregation group should award .the bid to the proponent, negotiate a service agreement, and commence taking service. 1-7 SUMMARY Based on the foregoing information and the more detailed analysis set forth in the body of this report, the City has available to it at this time the following primary options and associated costs and benefits: Options No Action (Remain SCE Customer) Alternate Service for City Loads Only Load Aggregation (General) Light Industrial and Commercial Customers Residential and Commercial Customers Other Public Agencies · MCAS Tustin Benefits Costs No City costs to implement. Potential service improvements and cost reductions offered by SCE. City electric cost savings: $50,000/year (est.). City electric cost savings: $70,000/ year (est.), assuming sufficient load to increase City purchasing power. Assumed electric cost savings to customers: $491,244/year (est.). Unquantified benefits of promoting business retention and attraction of new businesses. Assumed electric cost savings to customers: $232,140/year (est.) Unquantified benefits of service to City residents. Potential indirect benefits to City residents from aggregation with TUSD and reduction of school costs. Unquantified electric cost savings to MCA$ Tustin businesses and residents. Unquantified benefits of promoting business retention and attraction of new businesses. City electric cost savings may not be maximized. Electric cost savings for City businesses and residents may not be maximized. Costs of RFP or other ESP selection process (one-time cost of $50,000). Electric cost savings for City businesses and residents may not be maximized. Costs of RFP or other ESP selection process (one-time cost of $50,000). Costs of customer solicitation and administration of any load aggregation effort (varying by scope of aggregation effort). Costs of City program to solicit customer participation ($50,000 for one year effort); costs of part-time administration ($20,000/year) Costs of City program to solicit customer partidpation ($100,000 for one year effort); costs of administration ($50,O00/year) Costs of participation in joint action agency or other joint effort ($50,000 for costs of RFP or other ESP selection process effort); costs of part-time administration ($10,000- $20,000/year). Unquantified costs of City program to solicit customer participation at this time; unquantified costs of administration at this time. More detailed study necessary. In evaluating the foregoing options and associated benefits and costs, the City must keep a number of significant factors in mind. First, the quantified estimates of the benefits of alternate electric service are reasonable approximations only through early in 2001, when SCE's ability to impose 'its competition transition charge ends. Starting approximately April 1, 2002, there may be much greater benefits available in terms of reductions in the 1-8 SUMlvlARY cost of electricity. In the year 2000, the electric service industry will see an adjustment in the transmission access charge cost component reflecting performance of the ISO. Second, the estimates of the costs to the City of implementing various forms df load aggregation programs assume that the City will be able to develop such programs and administer them on a part-time basis, with the exception of a residential load aggregation program. Another consideration in that regard is that if the City is able to obtain the services of an alternate electric service provider to undertake a substantial portion of the efforts associated with load aggregation development and administration, the City may be able to reduce those estimated costs. Finally, the City should keep in mind that the "no-action" option may be modified at any time the City should find it advantageous in the future to seek an alternate service provider or participate in a load aggregation program. The associated benefits and costs would remain essentially the same as listed (except for the time value of money), at least through the end of 2001. The following pages provide a condensed summary of the City's load aggregation options and decision making process. 1-9 SUMMARY Load Aggregation Summary Who can aggregate loads? Any groups of IOU customers Public Agencies Private business enterprises Residential customers Why load aggregate? Cost saving to' City electrical loads Reduce electric costs to: Promote retention of existing business enterprises Create a competitively attractive businesses environment Provide savings to City residents What service options exist? SCE rates and services Unsolicited offers from ESPs City directed RFP for energy service contract Candidates for load aggregation? City electric accounts Light industrial customers Other light industrial Residential SCE customers Commercial load Other public agencies MCAS Tustin Phase I 2001 8.0 MW Phase II 2005 25.0 MW Phase III 2010 44.0 MW Phase IV 2017 52.0 MW 2.7MW 27.0 MW 14.2 MW 20.0 MW 8.0 MW (Load potential not 7.0 MW 1.0 MW 21.0 MW 4.0 MW 36.0 MW 8.0 MW 43.0 MW 9.0 MW (City identified) (Not identified) (Residential type) identified) (Co mmercial/Indus trial) (Residential/Public) (Commercial/Industrial) (Residential/Public) (Commercial/Industrial) (Residential/Public) (Commercial/Industrial) (Residential/Public) 1-10 SUMMARY Who benefits and by how much? KWh/yr annual energy $ Saving Assuming Assumed %. 100% Participation City electric accounts 16,000,000 Light industrial customers 98,950,178 Other light industrial customers 48,072,377 Residential SCE customers 87,600,000 Commercial load supporting residential 49,056,000 Total potential savings to customer $1,400,000 70,000 $70,000 9,895,018 371,063 494,751 4,807,238 120,181 240,362 8,760,000 109,500 n/a 4,905,600' 122,640 n/a 793,384 What factors influence City role? · Marke. ting/ survey process (staff time) · Cost to promote aggregation · Overall complexity · Return on investment. · Benefit to citizenry What' City alternatives exist? · Allow public to respond to industry marketing · Encourage full service ESP entries into community · City generally Coordinates aggregation interest · City partnership with full service ESP When to load aggregate? · Public survey/marketing complete · Adequate interest established · Adequate potential load identified (See following procedural diagram for City RFP process) 1-11 0 SECTION 2 PURPOSE OF REPORT The City desires an analysis of the options available to it for the achievement ~f cost savings in the purchase of electricity in light of the forthcoming restructuring of the electric industry in California. This report provides the City .with an overview of City electric loads, opportunities for achieving cost savings in meeting those loads from either SCE or an' alternate power supplier or energy service provider, and any potential advantages to aggregating_ the. City's electric loads with MCAS loads, loads of other industrial, commercial, and/or residential electric consumers i~ the City, or loads of other agencies. This report is intended to provide a basis for the City's decision regarding its choice of electric service provider for the near future. 2-1 SECTION 3 BACKGROUND OF ELECTRIC INDUSTRY RESTRUCTURING Califomia's electric industry has been dominated by its three major IOUs, with rates that are some of the highest in the nation. However, in recent years, federal .law has allowed independent power producers to develop new electric generating facilities to sell power to the IOUs and has provided greater opportunities for competing power suppliers to obtain access to.utility transmission systems. In addition, California is surrounded by existing utility companies with significantly lower costs of supplying power. As a result, there has been increasing pressure in recent years on California to take action to introduce greater competition - and anticipated lower power costs - into its electric industry. The CPUC adopted a policy decision in 1995 to commence the restructuring of the electric industry for IOUs in California. However, it was California Assembly Bill No. 1890, enacted in September 1996 (AB 1890), that provided the impetus targeting January 1, 1998 for the 'implementation of that restructuring. And it is that restructuring process that may provide the City of Tustin the opportunity to achieve .savings in its cost of futUre electricity purchases. 3.1 AB 1890 AB 1890 established fundamental elements of electric industry restructuring in California, including: Author/z/ng the IOUs to recover all of their "stranded investment" in now uneconomic generation facilities and other facilities through the competition transition charge (CTC) by means of a rate freeze for all current IOU customers until January 1, 2002 (instead of rate reductions that would otherwise be called for), except for the residential and small commercial customer rate reduction described below; Imposition of that crc obligation on current IOU customers on a non-bypassable basis, with limited exceptions not extending to customers choosing to take direct access service from alternate energy service providers; and Imposition of a ten percent (10%) reduction in retail rates for residential and small commercial customers of the IOUs effective January 1, 1998, with another ten percent (10%) reduction on January 1, 2002, financed by several billion dollars of "rate reduction bonds" to be repaid by those customers over a period extending well beyond the rate freeze period. 3-1 BACKGROUND OF EL lC INDUSTRY RESTRUCTURING The City should be aware that the ten percent rate reduction will be applied to IOU customer accounts with a peak demand of less than 20 kW, which SCE advises will include many of the City's smaller accounts (as further discussed in Section 5.3.1 below). In addition, AB 1890 included numerous provisions that affect the City's options regarding choice of electricity suppliers and potential achievement of electricity cost savings, including the following3 3.1.1 DIRECT ACCESS TO IOU CUSTOMERS Section 365(b)(1) requires the CPUC to authorize direct transactions between electricity suppliers and end use customers of the IOUs, subject to implementation of the non- bypassable CTC. Direct access is to commence simultaneously with the start of the Independent System Operator (ISO) and PX in California, no later than January 1, 1998. 3.1.2 SPECIAL PROTECTIONS FOR SMALL CUSTOMERS While AB 1890 in large part treats industrial and large commercial customers of the IOUs as capable of fending for themselves in taking advantage of opportunities provided by the availability of direct access to electricity suppliers, Section 3310a) includes extensive protections against misleading direct'access marketing efforts for residential and small commercial customers, defined as those with a maximum peak demand of less than 20 kW.2 Those protections are described in detail in Appendix B. 3.1.3 REQUIRE~ FOR LOAD AGGREGATORS In providing for direct transactions with IOU customers, AB 1890 sets forth express requirements that must be met to aggregate electric loads and the role of public entities in that process. Section 366(a-b) requires the CPUC to allow for aggregation of load on a voluntary basis by private market aggregators, cities, counties, special districts, and others, based on a positive written declaration by each customer, without which the IOU remains the default provider. Also, if a public agency, such as Tustin, wishes to serve as a community aggregator on behalf of residential customers, Section 366(c) requires that agency to offer service to all residential customers within its jurisdiction. ~ The relevant provisions of AB 1890 are now set forth as Sections 330-397 of the California Public Utilities Code. Sections referenced are sections of the Public Utilities Code, unless otherwise indicated. 2 That is the same group of customers that will receive the ten percent rate reduction on January 1,1998 financed by the IOUs' "rate reduction bonds." 3-2 BACKGROUND OF ELECTRi,_ iNDUSTRY RESTRUCTURING 3.1.4' LIMITATIONS ON AVOIDANCE OF IOU CTC AB 1890 also includes extensive provisions limiting the ability of IOU direct access customers to avoid the obligation to pay the CTC of the IOU in Sections 367-379. In~'luded among those provisions, Section 369 provides that the obhgation to pay the crc cannot be avoided by the formation of a local publicly owned electric utility or the annexation of any portion of an IOU's service area by an existing local pubhcly owned electric utility. Among the means estabhshed by AB 1890 for avoiding the IOU crc are the use of power from previously-authorized self-generation, cogeneration, or emergency generation facilities (Section 372) and the use of specifically-authorized amounts of power provided by irrigation or other specified districts to pumping load and specified uses of federal power marketing agency preference power (Section 374). The City should be aware of those limited crC avoidance options in its consideration of potential options. However, we are unaware of any practical way in which the City could take advantage of those CTC exemptions. 3.1.5 MUNICIPAL UTILITY PUBLIC GOODS CHARGE Another provision of AB 1890 requires local publicly owned electric utilities to establish a "public goods" charge to be imposed on its local distribution service (Section 385). "Public goods" are considered to be energy efficiency and conservation programs, renewable energy resources, energy research and development programs, and low-income assistance programs. The CPUC has long required the customers of the IOUs to fund "public goods" programs through their retail rates, and AB 1890 directs both the IOUs and municipal utilities to continue to fund those programs. Only if Tustin were to form a new municipal utility would that provision be applicable. 3.2 SB 477 AMENDMENTS TO AB 1890 The California legislature has recently acted to impose additional requirements on the direct access market beyond those specified in AB 1890. Califomia Senate Bill No. 477, chaptered August 15, 1997 (SB 477), adds additional registration, registration fee, disclosure, and standards of conduct requirements to those set forth in Section 394(a) applicable to alternate Energy Service Providers (ESPs) regarding direct access service to current IOU customers. Examples of Alternate ESPs are described in Section 5.1.2. These increased requirements are discussed further in Appendix B with regard to the possibility that Tustin might desire to serve as a load aggregator and ESP for electric consumers in its city limits. The bill also exempts a public agency aggregating electrical services for residential customers within its jurisdiction from the requirements of AB 1890 that a change in service provider to existing IOU residential or small commercial customers must be verified 3-3 _., BACKGROUND OF EL dC INDUSTRY RESTRUCTURING (Sections 366(d), 366(e)) and that such a service provider must register with the CPUC (Section 394). If Tustin were to provide electric service within its jurisdiction, these exemption provisions would make it easier for the City to serve as the aggregator for its customers.3 .' 3.3 CPUC AND FERC IMPLEMENTATION OF RESTRUCTURING Within the legislative framework established by AB 1890, the CPUC and the Federal Energy Regulatory Commission (FERC) have been working to develop the new industry structure for the electric industry in California. 3.3.1 FERC IMPLEMENTATION OF RESTRUCTURING FERC has authorized the creation of an independent system operator (ISO) to assume · operating control over transmission facilities in California to allow open access for transmission of power into and within the state. FERC has also authorized the creation of a California Power Exchange (PX) into which the CPUC has directed the IOUs to sell all of their power supplies and from which the CPUC has directed the IOUs to purchase all of their power needs for the next four years. FERC has continued to indicate that it proposes to issue its approval of the actual ISO and PX structures in time for the commencement of operations by January 1, 1998. However, numerous issues and concerns have been raised regarding the proposed ISO and PX structures, which could cause FERC to delay its final approval of implementation. 3.3.2 CPUC IMPLEMENTATION OF RESTRUCTURING The CPUC has conducted extensive proceedings to implement the regulatory structure to allow direct access by the IOUs' retail electric customers to alternate sources of electric supplies. The cPUC in mid-1997 adopted Decision 97-05-040 (Direct Access Decision), a policy decision directing the IOUs to allow direct access for all customers on January 1, 1998, rather than the phased implementation previously planned and provided in AB 1890. The CPUC has adopted a number of other decisions on restructuring matters in 1997, but it must still issue decisions on several critical matters before direct access can begin, including: · Determination of the amount of the IOUs' CTC; 3 SB 477 also makes dear that its consumer protection provisions do not apply to service to customers of local publicly owned electric utilities, in the event the City were to form a municipal utility. 3-4 BACKGROUND OF ELECTR~ ,NDUSTRY RESTRUCTURING Methods by which the IOUs will "unbundle" their tariff rates to separate costs avoided by direct access customers from those that all customers must still pay; ., The terms of the divestiture by the IOUs of designated generating units; and Many of the terms and conditions on which direct access service by ESPs will be provided. Some of the key asp~ts of restructuring that the CPUC has already specified are set forth below. Appendix B contains more detail regarding those CPUC requirements, particularly with regard to Tustin's potential role as a load aggregator.. 3.3.2.1 The CPUC Direct Access Decision The CPUC's Direct Access Decision mandates that a service provider must obtain formal written authorization from every current IOU residential and small commercial customer (less than 20 kW maximum peak demand) that it seeks to serve. The Direct Access Decision does not directly impose that requirement with regard to industrial and large commercial customers, but it indicates that such customers will be entering into "direct access contracts." In the Direct Access Decision, the CPUC sets forth the following additional "standards and procedures" that the IOUs must follow in processing direct access requests. ' · Each IOU will begin accepting direct access requests on November 1, 1997. · The IOUs will process direct access requests .on a first-come, first-served basis. Direct access requests received on or before the fifteenth of the month will be switched over during the next month's billing cycle. · Direct access requests must be in a format acceptable to the IOU. · Direct access requests must be verified, if required. · IOUs must accept direct access requests in electronic format. · Specified procedures will be triggered in the event of a backlog of direct access requests. 3-5 .. ~..... BACKGROUND OF ELE~ £ INDUSTRY RE. STRU~NG IOUs must submit a monthly report to the CPUC for the period from November 15, 1997 through June 30, 1999 regarding their direct access implementation activities, including all direct access activities dur~g the prior month. In addition, the Direct Access Decision sets forth an extensive set of requirements and rules regarding (1) service fees, (2) the 20 kW threshold for load profiling and metering matters, (3) metering and meter reading options, (4) billing options, (5) procedures for settlements, and (6) IOU transactions with affiliates. A key factor in the rules adopted by the CPUC in the Direct Access Decision regarding the availability of direct access service to all IOU customers is the requirement that customers with a maximum demand of 20 kW or more will have to utilize a meter with the capability of hourly metering.4 The CPUC indicates, however, that it will consider exemptions for customers with a maximum demand between 20 kW and 50 kW. As the customer is responsible for the cost of the meter and its installation, the City should be aware of that requirement and its potential expense and effect on the timing of direct access service. Customers with a maximum peak demand below 20 kW will be eligible for direct access service based on statistical load profiling, rather than metered consumption. The CPUC is currently conducting a process to develop and specify the load profile methodologies that will be accepted for use in providing direct access service. The Direct Access Decision .provides that the CPUC will reevaluate the use Of load profiling in the year 2000. 3.3.2.2 The CPU¢ Metering and Billing Decision Other than the requirement of hourly meters for direct access customers with 20 kW or more of maximum demand, the Direct Access Decision's requirements regarding metering are limited to requiring an 'informal process to develop open architecture standards for the interface of direct access customer metering with the meter reading equipment of the IOUs . or of another meter reading provider. However, on the same day that it issued the Direct Access Decision, the CPUC issued Decision 97-05-039 providing for the unbundling of metering and billing functions currently performed by the IOUs (Metering and Billing Decision). In the Metering and Billing Decision, the CPUC establishes three options for direct access customer metering: (1) separate (dual) metering and meter reading, (2) IOU consolidated metering and meter reading, or (3)service provider consolidated metering and meter reading. Metering services may be provided by alternate service providers as of January 1, 1998 for customers with maximum demands of 20 kW or more, and may be provided for all customers effective January 1, 1999. The Metering and Billing Decision 4 In addition to serving as the limit for the hourly metering requirement and for AB 1890's consumer protection provisions, 20 kW is specified in AB 1890 as the maximum peak demand of a "small commercial customer" for purposes of the cut-off for eligibility for the. ten percent rate reduction required by AB 1890 (Section 368) for residential and small commercial customers beginning on January 1,1998. 3-6 BACKGROUND OF ELECTi~ .NDUSTRY RESTRUCTURING also establishes the same three options for direct access customer billing as it does for metering: (1) separate (dual) billing, (2) IOU consolidated billing, or (3) service provider consolidated, billing. However, these billing options will be available for all customers as of -. January 1,1998. 3-7 SECTION 4 ANALYSIS OF CITY ELECTRIC LOADS The primary factor that will determine Tustin's prospects for achieving potential savihgs in its costs of electricity is the type and amount of electric loads of the City. In particular, the attraction of potential alternate power suppliers and ESPs to submit competing offers to provide electric cost savings is likely to depend .in large part on the size of the City's load (and consequently the magnitude of potential profits to a service provider) and the degree to which the City may be able to operate those loads at times of the day and year other than summer weekday kffemoons when the peak demands occur on the electric system and consequently power prices are at their highest. SCE's "on-peak" period for purposes of its time-of-use rates is from noon to 6:00 p.m. on weekdays from June I through September 30 of each year. As with any electric utility customer, the City's load varies on a daily basis, exhibits differences between week days and weekend days, and experiences a shift in energy usage between winter and summer months. Due to the proximity to the ocean, .the climate for the City is mild. Therefore, the differences between winter and summer are relatively small, with the notable exception of the City's water pumping loads which may be as much as fifty percent higher during the summer months.. Loads associated with the Pumps, Water Treatment Plants, and Traffic Lights are assumed to occur evenly around the clock. Power for City Hall, Senior Center, Columbus-Tustin Gym, City Yard, and other City buildings tends to be 'consumed during the day and into the evenings. Sports Lighting occurs during evening periods and Street Lighting operates mostly all night. Based on information regarding recent usage obtained from the City and SCE, the following is the City's approximate current peak load and annual consumption per category of electric usage for City facilities only: Pumping Loads Water Treatment Plants City Hall/Senior Center/Gym/ City Yard/Other Buildings Street Lights Traffic Lights Sports Lights Parks/Irrigation Non-Coincident Load and Annual Consumption Peak Load (kW) 1,070 650 580 200 365 500 25 3,390 kW Annual Consumption (kWh) 6,900,000 3,700,000 2,100,000 1,o5o, ooo 1,900,000 500,0o0 15o, ooo 16,300,000 kwh 4-1 , _YSIS OF CITY ELECTRIC LOADS For all practical purposes, energy rates on the wholesale market are divided into on-peak and off-peak periods. Typically, on-peak periods occur during the daylight hours on week days. Though there can be rates associated with shoulder-periods, all the rest of the time is considered off-peak. From the 10ad results listed above, it appears that the m~imum daily on-peak load would be during the summertime and would be approximately 2,690 kW. Street Lights and Sports Lights are excluded due to their operation only at night. The following figure illustrates the approximate load profile for the City's accounts during a peak summer day. 4-2 E E 0 0 0 0 0 0 0 0 0 0 0 0 ~0 0 ~0 0 UO 0 o 0 SECTION 5 OPTIONS FOR ELECTRIC SERVICE Given the foregoing types and volumes of City loads, the City must evaluate its ~lectric service needs in addition to its desire to obtain lower-cost power. Included in that evaluation should be the City's need for reliability of service, its interest in and w~llingness to implement modifications in energy consumption and City facilities consuming that energy, and its willingness to shift its time of use of electricity. Beyond that, the City may consider other options for potential reductions in the cost of its electric service, including aggregation of City loads with other electric loads, availability of cost reductions from its current supplier, SCE, and other more innovative measures. 5.1 'DIRECT ACCESS FOR CITY LOADS The most obvious result of the restructuring of California's electric industry is the opportunity for electric customers to obtain direct access to the proliferation of power suppliers and ESPs that are now engaged in the advance marketing of their' services throughout the state. The following sets forth a framework for the City's evaluation of its own electric loads and the types of entities active in the marketplace and types of arrangements being offered, in Order to allow the City to determine the prospects for achieving significant cost savings from direct access strictlY for the City's own loads. 5.1.1 City SERVICE NEEDS As an initial, aspect of its evaluation of the opportunities available for electricity cost savings in the new competitive marketi the City needs to identify electric service characteristics that it considers necessary for its operations. Of course, reduction of the cost of its electricity purchases will be a primary consideration. However, several other factors may be significant to the City. Reliability of service is critical to City facilities' and should be an important factor in evaluating options for electric service. While restructuring in concept should not reduce the quality of electric service by the local distribution company (SCE) to the City, there are innumerable details of the interaction between the distribution companies and alternate ESPs still to be worked out, including fights and responsibilities in the event, of nonperformance by an ESP. On the other hand, the City may be able to obtain services from an ESP to improve its reliability of service to particular facilities, including installation of back-up generators or other electric system improvements. The City should 'particularly identify any special reliability needs for its city hall facilities, its water treatment system fadlities, or any other City fadlities. The City may wish to spedfy particular aspects of electric service quality that it seeks in the event it solicits proposals from ESPs in the future or in seeking improvements from SCE in its quality of service. .'TIONS FOR ELECTRIC SERVICE Another aspect of electric service that Tustin should consider as part of its evaluation of service options is its willingness to implement modifications in its facilities that might result in improvements in the efficiency of its electric consumption. As part of an offer of a reduced electricity bill, an ESP may propose to identify and implement improvem"ents in the City's pumps, motors, lighting, and any' of a number of the City's other electricity consuming equipment and devices. Such improvements could be undertaken by the ESP or the City, in either case in anticipation that-capital costs would be repaid out of the energy cost savings. In addition, an ESP may propose modifications to the transformers and substations serving the City's loads, including potential connection to the scE system at a higher voltage. The City should determine in advance whether it will seek or encourage ESP proposals that may base cost savings on effidency improvements of those types. A potentially very significant additional aspect of its electric service that the City should consider in advance is its willingness and ability to shift its electric consumption from periods of peak electric usage to off-peak periods. One of the most significant developments in the restructured electric market will be greater emphasis on the cost of electricity by time-of-use. The City will particularly need to determine whether it can modify its operation of the pumps and other elements of its water system to minimize electricity usage during peak summer periods. If the City has not already adopted programs for such load shifting, then it should determine whether it would be willing to do so in response to the recommendations of an ESP or on its own initiative. 5.1.2 ASSESSMENT OF POTENTIAL ALTERNATE POWER SUPPLIERS AND ENERGY SERVICE PROVIDERS There are numerous ESPs registered with the CPUC to provide direct access electric service in California. Trade press estimates place the number at over one hundred. In addition, there are well over one hundred federally-licensed power marketers in the United States, in addition to all of the electric utilities in the western United States, all able to provide supplies of power for delivery by those ESPs. While the City may wish to seek proposals for power supplies and/or direct access service from all power suppliers and ESPs that may offer it, the City may prefer to establish a more limited bidders list. To assist the City in evaluating potential power and service providers in the future, the following describes some of the more prominent suppliers currently active in the California market. Enron/FirstPoint Utility Solutions Enron, based in Houston, Texas, is one of largest companies in the natural gas industry and has publicized its intention to become the nation's leading electridty provider. It is currently marketing to direct access customers in California through its affiliates, Enron Power Marketing and Enron Energy Services. Recently, it 5-2 OP l iONS FOR ELECTRIC SERVICE completed its merger with Portland General Electric corporation (PGE), an investor- owned utility based in Portland, Oregon. PGE's affiliate, FirstPoint Utility Solutions (FirstPoint), was the first entity to enter into an arrangement with a California municipality to offer alternate energy service and load aggregation, with the City of Palm Springs. FirstPoint also entered into the second announced municipal alternate energy service arrangement in California, with the City of South San Francisco. With the completion of the merger, Enron/FirstPoint is one of the leading competitors in the California market, particularly in marketing to municipalities and their residents. New Energy_ Ventures (NEV). NEV, based in Los Angeles, was formed in April 1995 with the express intention of serving as a buyers' agent for end-use electric customers, arranging to procure energy supplies for those customers from the least-expensive sources of supply available in the new market. Several leading executives of NEV are former executives of SCE, and NEV and SCE have engaged in some public disagreements. Tucson Electric Power recently purchased fifty percent (50%) of NEV. NEV first made news by announcing the offer of energy cost savings to a group of southern California cities and has subsequently announced arrangements with a number of other organizations, including several alliances of commercial organizations. Recently, NEV announced an arrangement with the Association of California Water Agencies (ACWA) to offer to procure power supplies at a discount for ACWA's member agencies and to provide other energy services. Energy Pacific Energy Pacific is the jointly-owned affiliate of Enova, the parent company of San Diego Gas & Electric Company (SDG&E) and Pacific Enterprises, the parent company of Southern California Gas Company. The formation of Energy Pacific anticipates the pending merger of the two parent companies. Energy Pacific has not yet made a major impact on the industry, but it is quite actively marketing to potential direct access customers. Edison Source Edison Source is an affiliate of SCE created to participate in the energy services industry. Edison Source has publicly indicated that it has had difficulty defining its. role and market strategy in the new industry. In addition, its ability to market to Tustin may be limited by CPUC restrictions on affiliate transactions that may discourage its marketing within the SCE service area. 5-3 ?TIONS FOR ELECTRIC SERVICE PG&E Energy Services PG&E Energy Service is an affiliate of Pacific Gas and Electric Company (PG&E). It appears interested in becoming more active in the energy services market in California and has entered into an arrangement to supply blocks of po~ver to members of the Association of Bay Area Governments (ABAG). PacifiCorp PacifiCorp, based in Portland, Oregon, is the parent company of Pacific Power & Light and has been active in marketing energy services in California, including the arrangement to supply blocks of power to ABAG members. Bonneville Power Administration (BPA) BPA is a federal power marketing agency based in Portland, Oregon which controls a vast amount of power generated from federal hydroelectric fa~lities in the Pacific Northwest. BPA has combined with other entities - recently with National Gas & Electric - to market a combination of its power and other ESP energy services in California. Several other potential service providers, including Enron and NEV, have indicated that they also have agreements or intentions to purchase BPA power for sale in California. Avista Energy. Avista Energy is an affiliate of Washington Water Power and has been active in marketing energy services in California. Avista Energy has announced arrangements to procure and deliver to California customers hydroelectric power from the Pacific Northwest. Seattle City Light Seattle City'Light, based in Seattle, Washington, is another potential supplier of Pacific Northwest hydroelectric power to California customers. Seattle City Light has in some instances combined with CNG Energy Services to market services in California, including the arrangement to supply bloCks of power to ABAG members. Duke Energy/DukeSolutions Duke Energy and DukeSolutions are both affiliates of Duke Power, a utility holding company based in North Carolina. Duke Energy has a tentative arrangement to work with the Los Angeles Department of Water and Power (LADWP) to help LADWP transition to the new restructured industry, but SCE has attempted to displace Duke Energy, and that arrangement has been stalled. DukeSolutions will be marketing to direct access customers and is promoting a comprehensive energy services approach. 5-4 OP nONS FOR ELECTRIC SERVICE There are many other power marketers and ESPs that may be of interest to the City. A category of ESPs that has been particularly prominent in targeting the residential customer market are the so-called "green" power marketers. Several ESPs have indicated that they will attempt to secure power from renewable and alternative energy sources and mk~ket it to residential customers at a premium price. Among the ESPs that may pursue that strategy are Enron Energy Services, Edison Source, and PG&E Energy Services, in addition to ESPs focusing primarily on that market. Other ESPs are expected to market electric service in combination with natural gas service and communications services, and several have indicated that they will market 'to residential customers through affinity groups. The City should be aware of the range of ESPs and marketing strategies whether or not it opts to become directly involved in electric load aggregation itself, since those ESPs are likely to be marketing to Tustin residents in any event. 5.1.3 OTItER CITIES' AND ENTrl'IES' DIRECT ACCESS AND LOAD AGGREGATION ARRANGEMENTS There have been a few direct access and load aggregation arrangements that have already been put in place in California that have received significant publidty. Although the details of those arrangements have not been publicized or are not available, the general structure of those arrangements and the range of options currently available are generally known. In addition, a number of dries and agencies are currently in the process of establishing direct access arrangements. Some of the more prominent efforts are described below. City of Palm Springs · The City of Palm Springs was the first municipality in California to announce a direct access arrangement. Palm Springs has a long history of complaints regarding the cost of power from SCE and had originally attempted to obtain federal approval to-purchase alternate poWer supplies and transmit that power over SCE's distribution lines to its residents as a munidpal utility not owning the distribution system. FERC denied that Palm Springs application as an unauthorized request for retail wheeling (prior to AB 1890 and California's adoption of a direct access program). Upon the announcement of the coming availability of direct access in California, Palm Springs entered into an arrangement with FirstPoint to provide direct access power and to conduct load aggregation and direct access marketing to Palm Springs residents. That arrangement includes the city's participation in and endorsement of Enron/FirstPoint's marketing efforts to city residents. 5-5 .... ' . FIONS FOR ELECTRIC SERVICE City of South San Francisco The City of South San Francisco was the second city to announce a formal arrangement for direct access power purchasing. South San Francisco has entered into an arrangement with FirstPoint in which FirstPoint has proposed to prdvide a five percent (5%) discount off the electric bill of all electric customers, in South San Francisco and to provide additional energy services to electric customers in the city. Although South San Francisco includes a substantial industrial electricity load, the announced discount would also apply to the city's residential customers. However, South San Francisco had to agree to a five-year power purchase' commitment in exchange for that deal. South San' Francisco 'utilized RMI's services in preparing and evaluating the responses to its request for proposals. City of San lose The City of San Jose recently announced a request for proposals to provide the city and other potential electric loads with up to 63 MW of direct access electric service. San Jose is currently reviewing the proposals received and anticipates selecting a winning proposal in November 1997. Association of Bay Area Governments {ABAG) ABAG has undertaken a program of arranging for the availability of blocks of power for direct purchase by its member agencies. It has indicated that 81 agencies have joined its aggregation program, with about 200 MW of load. ABAG has arranged for power purchases from PacifiCorp, PG&E Energy Services, and Seattle City Light/CNG Energy Services. Association of California Water Agencies (ACWA) ACWA has recently chosen NEV to provide energy services to members that desire such services. NEV reportedly will offer ACWA's member agencies (for accounts above 20 kW) a choice between (1) a five percent reduction from the cost of electricity otherwise available from their existing service provider and (2) a large percentage share of the savings relative to the otherwise applicable cost of electricity. NEV will also offer to provide optional energy services to ACWA members to improve their efficiency and cost-effectiveness of electricity consumption. City of San Diego The City of San Diego recently established a short-list of bidders in response to a request for proposals to serve the city's approximately 56 MW electric load for city facilities. San Diego Association of Governments (SANDAG) SANDAG recently issued a request for proposals to serve as much as 220 MW of its members' electric loads. 5-6 C,.. ~ONS FOR ELECTRIC SERVICE 5.1.4 PROCESS FOR SOLICITING AND EVALUATING BIDS TO PROVIDE DIRECT ACCESS SERVICE If the City determines in the future that it wishes to seek potential direct access service, the process for soliciting and evaluating bids to provide that service should be quite straightforward. The City would most likely follow its preferred government procurement process for unique services. Assuming the City does not have a particular preferred supplier, and would not attempt to utilize a sole-source procurement process, there are two primary models that l~ave been used by other government agencies in soliciting direct access service proposals. Refer to Appendix E for a description of the process for soliciting and evaluating bids to provide direct access service. 5.1.5 POTENTIAL COSTS/SAVINGS FOR CITY DIRECT ACCESS The extent of the interest of prospective ESPs and power marketers in the California market and the steps that have been taken already by the cities and other agencies described above indicate that Tustin may be able to achieve, in the future, modest cost savings in its purchase of electricity and in its use of energy services in general if the City- . is able to aggregate its use of electricity with its large industrial, commercial, and future users of the MCAS-Tustin property. Based on the types of arrangements that have been promoted by prospective service providers, Tustin should be able to solicit proposals that offer choices of potential savings for the City's purchases to serve City electric loads from among the following possible offers of direct savings in' electricity purchase price: Savings on the cost of electricity generation (commodity cost) from the purchase of power from an ESP, including the following potential options: Indexed commodity price based on a percentage of the price paid by SCE for the purchaSe of power for sale to Tustin from the PX. Shared savings price based on a percentage of the differential between the PX price and the commodity production cost incurred by the alternate energy service provider. · Fixed pricing. Guaranteed or shared savings based on a percentage of the City's otherwise applicable electric bill from SCE. The primary choice that the City is likely to have to make among potential proposals to provide electric cost savings is the degree of risk it is willing to assume. The lower risk 5-7 .'TIONS FOR ELECTRIC SERVICE option would be to select an indexed price, either as a percentage of the PX cost or as a percentage of the otherwise applicable bill. A more risky option, but one that may provide the opportunity for greater cost savings, would be a share-the-savings approach - either as a percentage of the savings in generation costs over the PX cost or as a percentage' of the savings off the otherwise applicable bill. There is much speculation in the electric industry regarding projected PX prices. To the extent that the IOUs are able to keep the PX price low in order to maximize their collection of their CTC, the City could realize significant electricity cost reductions from a purchase 6ption linked to the PX price. Alternatively, some speculate that the administrative costs of the PX, its acknowledged difficulties in commencing full-scale operations immediately, and the PX's own assertion to FERC that the availability of a single market price to low- cost producers will result in an overall increase in power costs will combine to make the PX a relatively high-cost source of power. The City should monitor the latest forecasts of that PX price prior to making any choice between options linked to that price and other options. One consideration with regard to. the percentage of bill approach in either case is establishing a dear understanding how the amount of the otherwise applicable bill will be determined. Another key factor in either case is establishing a basis for comparison of the use of only generation cost as the determinant of savings as opposed to the entire bill amount. The generation cost is generally expected to be only one-third to one-quarter of the total bill amount. Therefore, the percentage savings off the generation cost would have to be three to four times the percentage savings off the total bill in order to provide the same overall savings. Finally, selection of a fixed price (which may vary by time-of-use period) is arguably the most risky option with regard to the substantial uncertainties in the coming competitive market, although it may provide the security of a guaranteed discount off the current cost of electridty. Any fixed-price offer should be evaluated very carefully against forecasts of the PX price and other projections of the cost of power in the new market. Savings resulting from improvement in effidency of energy use or shifting of time of energy use- potentially based on programs instituted by an ESP- are another source of potential cost savings for the City as a result of choosing to obtain services from an ESP. As discussed in Section 5.1.1 above, an ESP is very likely to propose to review the City's uses of electricity and to implement measures to increase the efficiency of use and to shift usage from higher-cost peak periods to other lower-cost times of day. The City will need to consider whether it is willing to make an investment in modifications to its water system operating procedures, pumps, motors, lighting, and potentially even transformers and substations serving City loads. The City should attempt to obtain favorable terms from an ESP for these services, possibly including ESP financing of costs or provision of services or improvements at no cost to the City. 5-8 .,.)NS FOR ELECTRIC SERVICE Savings may also be available from economies of scale in electricity purchasing, metering, billing, and other aspects of simply consolidating all of the City's current individual accounts with SCE. One factor that the City will need to determine is whether an ES'P will offer cost savings based on consolidation of metering and/or billing of the extensive set of individual accounts that the City now has with SCE On the other hand, .the City will bear the cost of purchasing and installing an hourly interval meter for each load of 20 kW or greater for which it seeks direct access, unless it negotiates an agreement with an ESP to assume the cost of meter installation or obtains an exemption from the CPUC for loads between 20 kW and 50 kW.. The least expensive interval meter cost projected by SCE in its proposed direct access directory is $392, plus another $100 for SCE to remove the existing SCE meter and $100 for SCE to install the new meter. Those potential expenses may not justify the City bearing the cost of interval metering.installation for smaller City loads. Moreover, ESPs may be expected to seek to perform metering and billing services for the 'City. The City should compare their proposed costs of performing those services, including their proposals with regard to meter purchase and installation, as part of its evaluation of the overall benefits of their proposals. Another important factor for the City to keep in mind in choosing to switch to an ESP is the potential need to impose on that ESP its share of the responsibility for utility franchise fees and utility users taxes that may not be collected from SCE after the switch. California law provides for an electricity transportation surcharge to be imposed on transportation customers to replace franchise fees that otherwise would have been collected from the utility holding the franchise for the lines over which the power is transmitted.~ However, inclusion of a provision to that effect in any agreement with an ESP should ensure that the City will not suffer any loss in revenues from those sources in the event of a switch of providers. Claims have been made that overall electric cost savings of up to twenty percent of the total electric bill will be available in the new energY market. However, savings of that magnitude do not appear to be realistic during the next four years of payment of the IOU CTC. It appears at present that savings being offered may result in at most five percent reductions in otherwise applicable electric rates for the immediate future, with greater savings dependent on the ability of a customer to make significant shifts in its time of energy use to off-peak hours and/or to improve its efficiency of energy use substantially. The mount of potential savings may also depend in part on whether the City is willing to share some of the risk of power purchase prices with its power provider or will only take the risk of switching suppliers based on a 'guarantee of savings. ~ California Public Utilities Code Sections 6350-6354. 5-9 ,2PTIONS FOR ELECTRIC SERVICE The general average SCE electricity rate for City accounts is currently $0.09/kWh, and City loads total approximately 2.7 MW (on-peak) and 16,000,000 kWh per year, resulting in a combined annual electric bill for City accounts in the neighborhood of $1,400,00C~. The potential savings available to the City if it simply opts for a guarantee of a lower electricity price, assuming that it would not possess sufficient purchasing power to obtain a five percent savings guarantee, could amount to as much as $50,000 per year until the CTC terminates on January 1, 2002. This savings estimate is based on advertised offers that have been received elsewhere in California that may be available to the City as an individual customer. Upon the termination of the IOU rate freeze and CTC collection in 2002, electricity prices will clearly fall substantially. At a minimum, the price should fall by the amount of the CTC -- on the order of $0.03/kWh or one-third of the current frozen IOU rates. Prices could fall even further, but it is virtually impossible to determine today how far they will fall given all the uncertainties of the operation of the new market. Moreover, the IOUs will not be obligated to sell into and purchase from the PX at that point, which has been speculated may cause the PX to go out of existence. Therefore, the City should exercise caution in making any commitments or accepting any projections regarding power prices and cost savings in the year 2002 and thereafter. Only if the City were to be able to obtain a guarantee of a discount from SCE's price at that time would it be reasonable for the City to consider a deal of more than four years. In addition to the foregoing savings based on alternate power supply and energy service options now available to the City for its own electric loads, there is a possibility that additional savings could be available from aggregation of the City's loads with other electric loads. Some of those load aggregation possibilities are evaluated below. In addition, the City should determine whether it may be able to achieve electric cost savings while continuing to take service from SCE or by identifying innovative power supply sources. Those possible options are also evaluated below. 5.2 CITY AGGREGATION OF DIRECT ACCESS LOADS In addition to the opportunities available to the City for savings in electricity purchase costs limited to the electric loads of the City's own facilities, there are potential advantages that may be available to the City from aggregating its electricity purchases with those of other electric customers in the vicinity. Such aggregation has the potential to (1) increase total electric load being served, potentially making the combined set of customers more attractive to ESPs and power marketers and creating more competition and ultimately a more attractive service offer and (2) improve the load profile of the City's loads - ff aggregation is done with loads using more power off-peak than the City - making it less expensive overall to serve the combined set of customers and allowing prospective service providers to make more attractive service offers. 5-10 Or · ~ONS FOR ELECTRIC SERVICE However, the City should take into account the possibility that a prOspective service provider may consider relatively small additions to the City's total load to be insign, ificant in making the volume of service attractive and may consider the increased complikations of serving a collection of entities to be as much of a disincentive than an incentive to offer service to the City. In addition, the City must recognize that entities that have a more cost- effective load profile to serve than the City may find it disadvantageous to aggregate with the City - particularly if they are able to solicit a favorable deal on their own. Therefore, the City may find that there are practical obstacles to load aggregation that may minimize its potential to improve the City's opportunities for electric cost savings. 5.2.1 AGGREGATION WITH MCAS In light of the proposed closure of the Marine Corps Air Station (MCAS), aggregation of the City's electric loads or other combination with the MCAS seems to be a logical way in which to establish electric service for both sets of loads. Projected growth in electric loads for the MCAS based on the MCAS reuse study are set forth in the following table. However, the current MCAS load of approximately 2 MW is comprised essentially of electric loads based on current military activities which are expected to be phased out. The addition of this load to that of the City may not significantly increase competition to provide the City with immediate .energy service savings. Moreover, the slight summer peak in load shown in the companion RMI MCAS study would do little to improve the City's load profile. Therefore, there may be no particular benefit to the City in the short term to attempt to aggregate with the MCAS. Projected Development Demand Phase Year (Me[sawatts) Phase I 2001 8MW Phase II 2005 25MW Phase III 2010 44MW Phase IV 2017 52MW Phase V 2020 52MW For the long term, however, the substantial increase in MCAS electric loads projected in plans for MCAS reuse would make the MCAS more attractive for aggregation with the City. If MCAS loads grow to the ultimate projection of 52 MW BY 2017, or even to the Phase II projection of 25 MW BY 2005, the increase in potential purchasing power for the City could allow the City to obtain better energy purchase terms based on that increased volume of sales. The only potential drawback of City aggregation with MCAS loads is that the reuse plan anticipates that the expansion of MCAS development would be composed · in large part of commercial uses, which are anticipated to have highest electricity usage during the summer afternoon peak period with little flexibility for load shifting to off-peak 5-11 . .. ?TIONS FOR ELECTRIC SERVICE periods. However, the potential advantages of increased purchasing power would seem likely to offset any drawback in that regard. Therefore, the City should begin now to consider the logistics and potential of load aggregation on the MCAS Tustin Project.2 · · 5.2.2 AGGREGATION WITH OTHER AGENCIES The possibility of aggregation with other agencies in the vicinity of Tustin is rather speculative at this time. Contacts with the Tustin Unified School District indicate that the district is interested in aggregation options and is currently involved in a preliminary review of aggregation options by all county school districts. However, district- representatives indicated that they would be open to review of the possibility of aggregation with the City. The Orange County League of Cities indicated that it is not actively considering leading an aggregation effort but that the cities of Brea and Placentia, in particular, are actively investigating direct access electricity purchase options. Contacts with the City of Placentia indicate that it has been leading a public agency load aggregation effort for the past two years for agencies in north Orange County. A consortium of some 20 agencies has been formed, including cities, school districts, water districts, and other agencies. However, those a. gencies have not entered into a joint powers agency agreement or other formal joint action arrangement. The consortium is currently considering aggregation only of the electric loads of those public agencies, although aggregation with business and/or residential loads may be considered in the future. While members of the consortium are still in the process of developing load profile information regarding their electric uses, they believe that the consortium is large enough to have significant purchasing power. Tustin should note that the consortium believes that the day-time peak loads of its members' city hall operations will be balanced out to some degree by night-time pumping operations of members operating water systems. The consortium has met with twelve of the largest prospective service providers in the California market, including IOUs, and has prepared a draft RFP for alternative electric service. However, the consortium is likely to hold off issuing the RFP until at least the end of the year, preferring to evaluate the operation of the new electric industry structure for at least a few months before soliciting alternate service proposals. The consortium would likely give Tustin favorable consideration if the City wished to join. The consortium meets at 8:30 a.m. of the first Tuesday of each month, and Tustin is welcome to attend those meetings. The organizer of the meetings and primary contact person for the City of Placentia on this matter is Chris Becker, Director of Public Works, at (714) 993-8245. ' To the extent the City may choose to consider establishing a municipal utility for the MCAS (or for its entire area), service to the combined loads of the MCAS and the City by that utility should be evaluated. 5-12 .ONS FOR ELECTRIC SERVICE The most notable joint agency aggregation efforts, as described in Section 5.1.3 above, have used existing regional or interest-group organizations such as the Association of Bay Area Governments (ABAG), the San Diego Association of Governments (SANDAG), the Association of California Water Agencies (ACWA), or other existing organizati6ns to undertake the energy Services solicitation function while all the individual agencies involved undertake their own process for evaluating the merits of the services and rates offered to the group. Without the availability of such an existing organization, the logistics of establishing a multi-agency load aggregation and power procurement cooperative arrangement could make it difficult to implement. The logistical difficulties associated with forming a new aggregation pool do not appear likely to be overcome in the immediate future. Therefore, exploration of the possibility of joining the north Orange County consortium led by the City of Placentia appears to be the only public agency opportunity immediately available to Tustin. The City would be well-advised to proceed on its own initiative for the present, while continuing to explore aggregation interest on the part of neighboring cities and other agencies. Particularly if the City chooses not to make a long-term commitment regarding service provider and electricity price at this time, there will be additional opportunities in the future to establish and benefit from a cooperative purchasing arrangement. Of course, the City would want to seek 'out other cities and agencies with load profiles at least as good as that of Tustin, in order to avoid having its electricity cost increased as a result of a higher cost to serve the combined loads. 5.2.3 INDUSTRIAL, M. ANUFACTURI~G, AND LARGE COMMERCIAL AGGREGATION Large industrial and manufacturing businesses are some of the most attractive electric customers for direct access service providers due to their large volume of electricity consumption and their typically more flexible consumption patterns. Such customers should be very attractive to the City for aggregation with City loads. However, such customers are very likely to be the subject of individual marketing efforts by ESPs and may have little interest in joining in an aggregation effort with potentially less-desirable City loads. Moreover, Tustin has very little in the way of heavy industrial businesses, although it does have a number of light industrial and manufacturing businesses. Therefore, opportunities for City aggregation with industrial and manufacturing loads are . limited. Large commercial businesses can sometimes also present loads of suffident size and flexibility to be attractive as electric customers. New Energy Ventures (NEV) in particular has targeted and boasts of the substantial number of large commercial customers that have joined its "buyers' alliance." However, commercial businesses typically have loads that peak with peak electric system usage, with relatively little ability to shift that load significantly to off-peak periods, limiting their attractiveness as aggregation partners for the City. In addition, Tustin contains only a relatively small number of such large 5-13 TIONS FOR ELECTRIC SERVICE commercial businesses. Therefore, opportunities for City aggregation with' large commercial loads are also limited. Based on information provided by the City, the following page includes Tustin's 'largest industrial, manufacturing, and commerdal businesses, with the estimated electricity consumption of each. The businesses identified in the table are estimated to have a total load of approximately 27.3 MW. Other large businesses within the City are estimated to have another 14 MW of load. Assuming that the City might have a 75 percent chance of interesting the identified loads in a load. aggregation effort and a 50 percent chance for other businesses, an estimated 27.5 MW of industrial and commercial loads are projected to be currently available for aggregation with the City. 5.2.4 RESIDENTIAL AND SMALL COMMERCIAL AGGREGATION One of the most debated aspects of electric industry restructuring is whether there will be any benefits available to residential customers from direct access and/or load aggregation. Residential customers typically have their highest electric usage very near times of system peak demand, and are not easily motivated to shift usage to off-peak periods, making their load profile relatively unattractive to prospective power suppliers. (See APpendix C for a residential load profile for SCE, provided as part of Attachment E to the Report on June 5, 1997 Direct Access Workshop on Load Profiling, submitted to the CPUC on June 16, 1997.) In addition, the costs of serving residential customers are relatively high in relation to the amount of energy purchased'by such customers. Also, an ESP seeking to serve residential customers is required to comply with special consumer protection standards that are not applicable to other customers. In combination, those factors provide substantial disincentive to the City in its consideration of aggregation of City loads with residential customer loads. Consumer advocates and a number of prospective ESPs have been quoted as concluding that ESPs will be unable to provide significant cost savings to residential customers in relation to their cost of electricity from their current IOU distribution company, particularly given the ten percent rate reduction those customers will already receive for the next four years as mandated by AB 1890. In fact, a number of prospective ESPs have indicated that they will propose to charge a premium price to residential customers for the purchase of "green" power produced from renewable and alternative resources. Reports from other states and market surveys appear to indicate that a significant number of California residential customers will be willing to pay above-market prices for such "green" power. 5-14 City of Tustin Aqgregatable load Business Name Street I KWD Kilowatt Demand per Hour per Day (Peak) 12am-5am 5am-9am 9am-5pm 5pm-9pm i9pm-12pr, 1 Trinity Broadcasting Michelle Dr 400.0 80 200 400 400 80 2 Trinity Broadcasting Michelle Dr 400.0 80 200 400 400 80.. 3 Toshiba Amer. Med Michelle Dr 1,755.0 176 878 1,755 702 176 4 Home Depot El Camino 1,250.0 125 625 1,250 1~.250 250 5 Costco Wholesale El Camino 1,250.0 125 625 1,250 1,250 250 6 Ikea U.S. West El Camino 625.0 63 313 625 625 .. 125 7 MicroElectronics/MEI Edinger Ave 1,134.0 113 567 1,134 454 113 8 Ralph's Grocery Co. Jamboree Rd 144.0 14 72 144 1~ 29 9! Ralph's Grocery Co. Red Hill Ave 144.0 14 .72 144 144 29 10 Ralph's Grocery Co. Irvine Blvd 144.0 14 72 144 144 29 11 Steclcase Inc - Fab Warner Ave 1,536.0 154 768 1,536 614 154 12 Steelcase Inc - Office Warner Ave 216..0 22 108 216 86 22 13 Steelcase Inc - Warehouse Warner Ave 180.0 18 90 180 72 18 14 Silicon Systems - A - OfficeMyford Dr 320.0 32 160 320 128 32 15 ~Silicon Systems - D - whse Myford Dr 40.0 4 20 40 16 4 16 Silicon Systems - B - R&D Myford Dr 1,161.6 116 581 1,1 62 465 116 17 Silicon Systems- C- R&D Myford Dr 1,152.0 115 576 1,152 461 115 18! Pair Gain Technologies Franklin Ave 1,920.0 192 960 1,920 768 192 19 Ricoh Electronics Bell Ave 1,395.0 140 698 1,395 - 558 140 20 ~Ricoh Electronics Valencia Ave 1,440.0 144 720 1,440 576 14~ 21 Ricoh Electronics - Fab Warner Ave 1,368.0 137 684 1,368 547 137 ?? Ricoh Electronics - Whse Warner Ave lP_5.0 13 63 125 50 13 23 Ricoh Electronics - Office Warner Ave 256.0 26 128 256 102 26 24 Revere Transducers - Fab Franklin Ave 810.0 81 405 810 324 81 __5 Revere Transducers-whse Franklin Ave 200.0 20 100 200 80 20 26 Morton Electronic- Process Michelle Dr 750.0 75 375 750 300 75 27 Morton Electronic - Whse Michelle Dr 100.0 10 50 100 40 10 28! Pacific Bell Edinger Ave 400.0 40 200 400 160 40 29 Pacific Bell Edinger Ave 400.0 40 200 400 160 40 30 Pacific Bell Uyford 800.0' 80 400 800 320 80 31 Larwin Square E. 1st St 1,600.0 160 800 1,600 1,600 320 32 Jamboree PIa;,~ Edinger Ave 300.0 30 150 300 300 60 33 Donahue Schriber Jamboree S.Twr 600.0 60 300 600 600 120 34 L'Garde Inc Woodlawn Ave 1,250.'0 125 625 1,250 1,250 250 35 Laguna Cooke Co Mosher Dr 334.4 33 1.67 334 134 33 36 J. Ray Construction Co White #150 (Irvinl - - -- ' ' ' 371 Consolidated Reprographics W. 1st St 320.0 32 160 320 320 192 38 Cherokcc International LLC Dow Ave 1,080.0 108 540 1,080 432 108 Total City identified customers 27,300 2,810 13,650 27,300 15,976 3,701 Hours of operation 24 5 4 8 4 3 KWHs Subtotal 362,057 14,050 54,600 218,400 63,905 11,102 City identified customers @ 75% 271,543 10,538 40,950 163,800 47,929 8,327 Other commercial & industrial ' 14,185 1,419 7,093 14,185 5,674 1,419 Hours of operation I 24 5 4 8 4 3 KWHs Subtotal / Dayl 175,896 7,093 28,370 113,482 22,696 ' 4,256 Other unidentified customers @ 50% 87,948 3,546 14,185 56,741 11,348 2,128 KWD Total Total 41,485 4,PP9 t 20,743 41,485 21,650 5,119 KWD Total Discounted 27,568 2,817I 13,784 27,568 14,819 3,485 · KWHs Total/Dayl Total 537,953 21,143 I 82,970 331,882 86,601 15,358 KWHs Total / Day Discounted 359,491 14,084I 55,135 220,541 59,277 10,454 Tustin .'TIONS FOR ELECTRIC SERVICE Enron's recent media blitz promoting its offer of a ten percent rate reduction plus two weeks free electricity after one year would provide no savings for residential customers over the reduction mandated by law during that first year. Moreover, assuming Enron's offer of two weeks of free electricity is based on an average bill, the savings would 'be less than four percent of the resident's annual bill, applied only after Enron had obtained a year of revenues from serving that customer. (If the free electricity is implemented during the winter months, it would be of even less value.) A decision by Tustin to undertake load aggregation for residential customers within its city limits would entail a major effort by the City. While AB 1890 and SB 477 would exempt -the City from registratic~n with the CPUC and from customer switching confirmation requirements, those laws would still impose substantial information disclosure requirements and standards of conduct on the City, require the City to obtain written consent from each customer, and require the City to offer direct access service to each residential customer within its boundaries. To the extent the City may wish to give more thorough consideration to the details of implementation of a residential load aggregation and direct access program, a description of many of the more significant applicable requirements and market rules is set forth in Appendix B. Based on available information regarding the City's population and t6tal electricity consumption within its city limits, the City's total residential load is estimated to be roughly 20 MW. Of course, that is the maximum load that would be available for aggregation by the City. Even if the City should choose to undertake residential load aggregation, it will not have an exclusive right to solicit its residents unless it undertakes to form a munidpal utility encompassing its city limits. Otherwise, the City will have to compete with all other prospective ESPs that may choose to market to Tustin residents. And the City will have to'market to all its residents, while ESP may be selective. Assuming that as many as one-half of residential customers will be reluctant to change from SCE as their current service provider, and that other marketers would likely capture at least one- half of customers within the City that would consider changing service provider, the realistic potential residential load that might be available for aggregation by the City is more on the order of 5 MW. It is not dear that the increase in purchasing power that such additional load might add to the City's own loads would be significant, and it is unlikely to outweigh the disincentives to the City in undertaking residential load aggregation. Associated with the City's residential load is a set of small commercial businesses that provide local services to City residents. That electric load is not captured in the estimates of large commercial loads set forth in Section 5.2.3 above and is estimated to be approximately 8 MW. Assuming that the City would have a fifty percent chance of interesting such businesses in load aggregation, those small commercial businesses provide a potential additional 4 MW of load available for aggregation. 5-16 - - Or ~'IONS FOR ELECTRIC SERVICE 5.2.5 COMBINED AGGREGATION To maximize the potential increase in purchasing power that may be available to the City from load aggregation, the City should consider aggregation of a combination of th~ types of loads discussed above. Because of the potential obstacles to aggregation with all of those types of loads, as described above, there may not be enough additional load in any .single category to make a significant difference. However, in combination those loads amenable to aggregation may provide the City with additional bargaining leverage. So long as the City's costs of solicitation' and negotiation are not extraordinary, there should be no disincentive to engaging in a multi-faceted effort at aggregation. The potential combined loads potentially available to the City for aggregation are set forth in the figure on the following page. As can be seen from the figure, the City already has a critical mass of load potentially available for aggregation if it can interest just the identified industrial, manufacturing, and large commercial businesses in its city limits to participate. Moreover, if the City is able to interest other agencies in aggregation efforts, then even that industrial/commercial load may not be an essential element. However, the aggregation effort will require the devotion of time and energy by the City. Therefore, although an aggregation effort holds poten~al promise for bringing significant benefits to the City, it cannot be implemented immediately and should follow the steps set forth in Sections 1.3 and 6.2 of this report. 5.3 STATUS QUO: SERVICE FROM SCE Although there appear to be potential savings available from the purchase of electricity from alternate power suppliers or ESPs, the City should investigate the potential availability of similar savings from SCE. At a minimum, SCE has a "virtual direct access" service option that should be available to the City. In addition, SCE may be willing to undertake energy service improvements that would reduce the City's power purchase costs, even under SCE's rate freeze. The City should also investigate the possibility that SCE may be willing and able to provide some form of rate discount or more beneficial rate schedule for all or part of the City's loads. 5.3.1 SCE BUNDLED SERVICE WITH 10 PERCENT RATE REDUCTION If the City does not take any action to select an alternative service option,' it will by default remain a ';bundled'' service customer of SCE. Under SCE's rate freeze, the City would continue to pay the rates set forth in its applicable rate schedules for its larger accounts based on an historic average power supply cost, while SCE purchases its power supplies 5-17 Tustin Load Growth (Available for Aggregation !MCAS Commercial MCAS Residential City Commercial/ Industrial Large City Commercial/Industrial & i Manufacturing Identified City Commerci= City Residential Govemment Uses Yearn OP, ,oNS FOR ELECTRIC SERVICE from the PX and retains the difference for application to its CTC. SCE advises, however, that the ten percent rate reduction required by AB 1890 for residential and small commercial customers will be applied to the City's accounts on SCE's GS-1 rate schedule. While that includes about 100 City accounts, those accounts are limited to very"small electricity consumption, amounting to less than ten percent of the City's annual usage and less than five percent of its annual cost of electricity. That small amount of savings has little significance to the City in its evaluation of its long-term energy service options. 5.3.2 ACCESS TO PX HOURLY PRICES An alternative that the CPUC has mandated to be made available to the City directly from SCE is the Hourly PX Rate option, otherwise known as "virtual direct access," whereby the City will be able to choose to base the commodity (generation) cost component of its rate on the hourly PX price. That option is intended to allow IOU customers with load profiles more favorable than average (less on-peak usage) to take advantage of variations in energy prices based on market forces, just as a customer choosing actual direct aCcess can obtain a purchase offer based on a market price for power. The primary difference is that the Hourly PX Rate option is limited to purchases from the PX, while actual direct access purchases can be made from any power source, and can be made from a supplier offering a deal that is not directly tied to power supply cost. In any event, eligibility for SCE's Hourly PX Rate option is conditional upon the customer's use of "interval metering," consisting of a meter capable of reading and storing electric consumption data at hourly intervals in conformance with CPUC performance 'specifications. In response to a request for interval meter billing data for City loads, SCE indicated that the City does not currently utilize interval metering for its loads. As discussed above, the matter of metering may be a significant factor for the City. Each interval meter purchased from SCE is projected by SCE to cost a minimum of $392 plus an installation charge of about. $100 and a charge for removal of the existing meter of $100. The City's evaluation of the benefits of the Hourly PX Rate option must take into account that meter installation cost plus the additional costs of meter service, which may amount to from $7.00 to $20.00 per meter per month above standard SCE changes. 5.3.3 POTENTIAL FOR SPECIAL SCE RATE OR SERVICES In addition to making the foregoing comparison of direct access offers against the standard service choices available from SCE, the City might find it worthwhile to solicit some type of special rate or other special services from SCE to make service from SCE more attractive than the offer of a direct access service provider. Within the constraints of SCE's rate freeze, it is unlikely that SCE would offer or be able to obtain CPUC approval for a direct rate discount or special.anti-bypass rate in order to retain Tustin as a customer. However, depending on SCE's particular interest in Tustin as a customer, SCE may have the 5-19 ,:ti'IONS FOR ELECTRIC SERVICE flexibility to work with the City to attempt to identify other sources of savings to the City in continuing to take service from SCE. SCE representatives contacted indicated that those potential options might include '~nergy service improvements that would reduce the City's power purchase costs or a more beneficial rate schedule for all or part of' the City's loads. SCE indicated that it has previously reviewed potential energy efficiency improvements in the City's water system, but that the City did not find those improvements feasible at the time. SCE has many other types of energy efficiency programs. It has the ability to reconfigure .its distribution, metering, and/or billing systems to the City's benefit if it so chooses. SCE also can review all the rate schedules under which the City currently takes service at its many different accounts to determine whether the City might benefit from taking service under an equally applicable but more cost-effective existing rate schedule. A summary provided by SCE of the services it has to offer the City is included in Appendix D. Finally, SCE might be able to agree to renegotiate its franchise fee agreement with the City. According to the franchise fee statement from SCE, the City's franchise agreement with SCE provides that SCE will pay the City an annual franchise fee of one percent of the gross annual receipts from SCE's electricity sales in the city limits (or two percent of the gross annual receipts attributable to SCE's facilities used to serve loads within the City, if that were a higher amount). That amounted to approximately $500,000 for 1996. It may be possible for SCE to increase the amount of that payment in lieu of redudng its rates. Alternatively, the City of Sacramento recently received publicity as having adopted the first utility trench cut fee in the state. Tustin might propose to establish a similar fee with SCE's support as a way of developing additional revenues to offset its electric costs. It seems possible that SCE might be able to provide the City with sufficient electric cost savings from among all the foregoing sources that the City might not find it worth the effort to switch service providers at this time. 5 -20 Ol · ,ONS FOR ELECTRIC SERVICE 5.4 COST/BENEFIT SUMMARY Based on the foregoing analysis, the City has available to it at this time the following primary options and associated costs and benefits: Options No Action (Remain SCE Customer) Benefits No City costs to implement. Potential service improvements and cost reductions offered by SCE. Costs City electric cost savings may not be maximized. Electric cost savings for City businesses and residents may not be maximized. Alternate Service for City Loads Only City electric cost saVings: $50,000/year (est.). Costs of RFP or other ESP selection process (one-time cost of $50,000). Electric cost savings for City businesses and residents may not be maximized. Load Aggregation (General) Light Industrial and Commercial Customers Residential and Commercial Customers · Other Public Agendes City electric cost savings: $70,000/year (est.), assuming. sufficient load to increase City purchasing power. Assumed electric cost savings to customers: $491,244/year (est.). Unquantified benefits of promoting business retention and attraction of new businesses. Assumed electric cost savings to customers: $232,140/year (est.) Unquantified benefits of service to City residents. Potential indirect benefits to City residents from aggregation with TUSD and reduction of school costs. Costs of RFP or other ESP selection process (one-time cost o f $50,000). Costs of customer solicitation and administration of any load aggregation effort (varying by scope of aggregation effort). Costs of City program to solicit customer participation ($50,000 for one year effort); costs of part-time administration ($20,000/year) Costs of City program to solicit customer partidpation ($100,000 for one year effort); costs of administration ($50,000/year) Costs of participation in joint action agency or other joint effort ($50,000 for costs of RFP or other ESP selection process effort); costs administration ($10,000 - $20,000/year). 5-21 -. ..... 'TIONS FOR ELECTRIC SERVICE Options MCAS Tustin Benefits Unquantified electric cost savings to MCAS Tustin businesses and residents. · Unquantified benefits of promoting business retention and attraction of new businesses. Costs Unquantified costs of City program to solidt customer. participation at this time; unquantified costs of administration at this time. More detailed study necessary. In evaluating the foregoing options and associated benefits and costs, the City must keep a number of significant factors in mind. First, the quantified estimates of the benefits of alternate electric service are reasonable approximations only through the year 2001, when SCE's ability to impose its competition transition charge ends. Starting in the year 2002, there may be much greater benefits available in terms of reductions in the cost of electricity. Second, the estimates of the costs to the City of implementing various forms of 'load aggregation programs assume that the City will be able to develop such programs and administer them on a part-time basis, with the exception of a residential load aggregation program. Another consideration in that regard is that if the City is able to obtain the services of an alternate electric service provider to undertake a substantial portion of the efforts associated with load aggregation development and administration, the City may be able to reduce those estimated costs. Finally, the City should keep in mind that the "no-action" option may be modified at any time the City should find it advantageous in the future to seek an alternate service provider or participate in a load aggregation program. The associated benefits and costs would remain essentially the same as listed (except for the time value of money), at least through the end of 2001. 5.5 SCE DISTRIBUTION VOLTAGE UPGRADE Another potential benefit that SCE might be able to offer the City if it wishes to retain the City as a customer is the cost savings associated with taking electric service at a higher voltage, thereby avoiding a portion of SCE distribution charges. It is beyond the scope of this study to undertake an engineering evaluation of each portion of the SCE distribution system serving a City load to determine whether the cost of installation of additional transformers or other equipment would be justified by the savings in distribution charges that would result. However, the City could certainly request that SCE conduct such an evaluation in order to assist the City in identifying sufficient cost savings to justify continuing to take service from SCE. iONS FOR ELECTRIC SERVICE In the event SCE shows a lack of interest in evaluating the potential benefits to Tustin of taking service at a higher voltage, then the City would almost certainly want to solicit an analysis from prospective ESPs of that matter, either in their proposals or in subs.equent efforts by a chosen ESP to provide the City with a package of energy services. 5.6 POTENTIAL INSTALLATION OF NEW GENERATION FACILITIES An additional option available to the City that might serve to reduce the City's cost of electricity over the long term might be the installation of new electric generation facilities to allow the City to serve its own electric loads'. Such generation could take the form of new gas turbine generators or a cogeneration system associated with a large load. However, several factors are likely to make this option impractical at the present time. First, air quality and other environmental regulations would pose substantial barriers to such facilities. Moreover, AB 1890 provides that the IOU CTC cannot be avoided by installation of such facilities to serve existing IOU loads. Finally, the introduction of competition into the energy production market is likely to keep commodity prices relatively low for some time. All of the foregoing factors make an investment in new generation facilities quite risky at this time. 5.7 POSSIBILITY OF FORMATION OF MUNICIPAL UTILITY A final potential cost-saving option available to the City is the formation of a'municipal utility encompassing its city boundaries. In years past, conflicting studies have endorsed munidpalization options as cost-effective and have shown the same options to be prohibitively expensive - primarily based on conflicting assessments of the value of the existing utility electric system that would be purchased by the munidpality. The difficulty of resolving that conflict has been a substantial deterrent to the implementation of municipalization efforts in recent years and led in the recent past to efforts by the City of Palm Springs and others to implement partial municipalization through condemnation of existing utility meters or installation of duplicate meters accompanied by requests for wheeling of power over the utility's distribution system to those meters. The FERC ruling that Palm Springs' proposal constituted a "sham" wholesale transaction prohibited by the Federal Power Act effectively put an end to such proposals. However, with the advent of direct access service, some of the primary potential benefits of municipalization may be realized without the need to litigate the matter of the price of the utility's electric system. Cities may now provide direct access service over the distribution system of the IOU with only the payment of a cost-based rate for use of that distribution system, rather than having to fight the battle over the condemnation value of the system and having to procure financing for the purchase. Moreover, AB 1890 included an express provision that the CTC of the IOUs cannot be avoided through munidpalization, eliminating that potential incentive. Thus, as discussed above and in Appendix B, Tustin may through direct access service and load aggregation among the electric customers ,~IONS FOR ELECTRIC SERVICE within its city limits achieve the result of serving all customers that wish to be served by the City. 5-24 SECTION 6 ISSUES AND RECOMMENDATIONS 6.1 ISSUES AND CONCERNS The foregoing evaluation of Tustin's options for achieving savings in its electricity costs, and potentially the costs of electricity for other electric customers in its city limits, has highlighted a number of issues and concerns that the City must address in its deliberations regarding its preferred option. Some of the more significant of those issues and concerns ' may be summarized as follows: What is the extent of cost savings available for the City from direct access suppliers? Can the City achieve savings of as much as five percent off its otherwise applicable electric bill without making any changes in its electricitY consumption? Is the City willing to take on the greater risk of a share-the-savings agreement in expectation of achieving greater savings than by the guaranteed percentage reduction approach? How long a term of agreement is the City willing to enter into in order to achieve maximum cost savings? What additional savings are available to the City if it agrees to implement energy efficiency measures, load shifting programs, and other cost-saving measures? Does it need to contract with an ESP in order to achieve those savings or could it implement those savings on its own initiative? What, if any, types of load aggregation would be cost-effective for the City? Is the City prepared to take on the logistical and practical obstacles to load aggregation, particularly the extensive procedures and requirements applicable to residential load aggregation? What will the City do with regard to the MCAS and will that have any effect on the City's choice of electric service options? Can and will SCE offer reduced rates, beneficial services, or other incentives for the City to remain an SCE electric customer? Are there potential transformer voltage upgrades or other distribution system service modifications that could provide electric cost savings for the City? Are those savings equally available whether service is provided by an ESP or SCE? Are there cost-effective opportunities available for the installation of new electric generation facilities in the City? If so, are the environmental regulatory barriers to such generation surmountable? 6-1 JES AND RECOMMENDATIONS Is there any benefit to be derived from forming a municipal utility encompassing the City's entire boundaries (as opposed to just the MCAS)? What form of solicitation of direct access service does the City propose to "issue? What special factors are important to the City in seeking innovative proposals from bidders? 6.2 RECOMMENDATIONS While the City should keep the foregoing issues and concerns in mind throughout the decision making process, the analysis set forth in this report leads to the following conclusions and recommendations. The timetable for the City's development of alternate energy service options is entirely at the City's discretion. There are no deadlines that must be met in order to obtain such alternate service after electric industry restructuring has been implemented. Alternate service is currently required to be made available on (or shOrtly after) January 1, 1998, and. the IOUs have been directed to begin accepting requests for direct access service by November 7, 1997. Tustin may select an alternate power supplier or ESP at any time after that date and will be able to take service from that alternate provider in due course after making that selection. The City will simply retain SCE as its default service provider after January 1,1998 until it may choose to utilize an alternate provider. It is currently premature for the City to proceed immediately with the effort and expense of preparing and reviewing responses to a request for proposals (RFP) for alternate electric service strictly for the City's own electric accounts. As discussed in Section 4, the City has an on-peak electric load of approximatelY 2.7 MW' and annual usage of approximately 16,000,000 kWh, with an annual electric bill in the neighborhood of $1,400,000. Even if the maximum reported figure of five percent savings from an alternate service provider could be realized, the City's annual savings would only be in the range of $70,000. Sa~a_ngS in that range - even if achievable - would seem to make the cost of the RFP process a marginally beneficial one at best for the City's own loads. However, the many potential opportunities available to the City for aggregation of its electric loads with those of others provide the City a range of options for proceeding with efforts to achieve significant energy cost savings. As a rule of thumb, it appears that aggregated electric loads begin to appear particularly attractive to alternate service providers in the range of 20 MW peak load and/or 100,000,000 kWh per year. The figure set forth in Sections 1.3 and 5.2.5 shows projected loads available for aggregation with City loads that could build the total amount of aggregated load to the general range of attractiveness to bidders. 6-2 ISSe.__.-AND RECOMMENDATIONS Based on those estimates~ there should be enough potential load within Tustin's city limits available for aggregation to reach the threshold of attractiveness to alternate service providers. The analysis set forth in this report indicates that a comprehensive arrangement with an alternate energy service provider, including load aggregation with the MCAS and/or with large manufacturing and commercial loads in the City, may achieve the most optimum electricity cost savings, unless significant service improvement and cost reductions are negotiated with $CE. Moreover, if the City were to undertake to form a joint action agency for electricity purchasing with other agendes such as the Tustin Unified School District or neighboring cities, the load of any other agency could increase that available total load or could replace one or more types of loads listed in the table (such as the residential component). In order to proceed with its decision making process with regard to its electric service options, the City needs to make the following decisions and take the following associated actions: The City must determine whether it is willing to devote time and resources to developing a load aggregation effort to enhance its electric service options by increasing its purchasing power. · If not, then the City should: 1) Evaluate measures that it may be able to take on its Own to reduce its costs of electric service from SCE, including more efficient operation of its water system to minimize electricity usage during periods of peak system demand, and potential re-negotiation of its current franchise agreement. 2) Utilize serVices offered by SCE to reduce its costs, including SCE's energy efficiency services, optimal rate schedule identification, possible consolidated billing, and other SCE services. 3) Particularly evaluate the option of utilizing the "Hourly PX Rate Option" for its larger electric loads that are able to minimize electric usage during peak periods. 4) Evaluate unsolicited proposals that the City may receive from alternate electric service providers. If interested, the City must determine whether it is willing to attempt to organize a residential load aggregation effort. 6-3 JES AND RECOMMENDATIONS If so, then the City must commence the preparation of marketing materials, prepare a customer agreement and information notice, enter into a service provider agreement with SCE, and engage in other activities necessary to provide service to residential customers. Whether or not the City undertakes residential load aggregation, the City should identify and contact primary potential load aggregation candidates, including large manufacturing and commercial businesses, the Tustin Unified School District, and neighboring cities. Based on the results of its contacts with potential load aggregation candidates, the City must determine whether a critical mass of potential load has been identified to be particularly attractive to alternate service providers. If not, then the City should undertake the actions listed above for continuing service from SCE. If so, then .the City should enter into an arrangement with those other potential candidates to share the costs of preparation and to issue a joint RFP for electric services. The City and its load aggregation group should prepare, issue, and evaluate responses to the RFP. If the responses are not attractive, then the City should undertake the actions listed above for continuing service from SCE. If an attractive service proposal is received, then the City and its load aggregation group should award the bid to the proponent, negotiate a service agreement, and commence taking service. · 6-4 DATA COLLECTED AND A ANALYSIS METHODOLOGIES $7.40 per kW during the three summer months of June/July/August. In addition, there is a two-tier energy structure for which the first block has a rate of 8.124 cents/kWh and a second block with a rate of 5.091 cents. The pumps were assumed to operate during all hours of the day. .. Water Treatment Plants - Rate Schedule GS-2 The Water Treatment Plants are used to treat domestic water supplied such that the 'effluent meets the applicable regulatory standards. Like the PA-2 rate schedule, Rate Schedule GS-2 applies to loads of 20 kW or greater and includes a demand charge which is increased during the summer period and a two-tier energy structure. The base demand charge is $5.40 per kW. During the three summer months, an "adder" of $7.75 applies. The energy blocks are at 7.692 cents and 4.391 cents, respectively. The water treatment plants were assumed to operate during all hours. City Hall/Senior Center/Other City Buildings - Rate Schedule GS-2 Utility'service to the City Hall, Senior Center, Columbus-Tustin Gym, City Yard, and other City buildings with a peak usage of 20 kW or greater is provided by SCE under Rate Schedule GS-2. (The rate is described in the previous paragraph.) Those buildings not meeting the 20 kW criteria are subject to Rate Schedule GS-1. Althohgh there are minor adjustments in this rate which may be applicable to the City, there is no demand charge and the energy rate is 11.76 cents per kWh. City buildings were assumed to have daily electric usage comparable to SCE's typical residential/commercial load profile. Street Lights - Rate Schedule LS-1 Rate Schedule LS-lapplies to the Street Lights owned by SCE. The demand charges under this rate is complex and based on the number and size of lights, whether they are Mercury or High Pressure Sodium Vapor Lamps, and whether the designated for All Night or Midnight Service use. The energy charge is 5.041 cents per kWh for All Night Service and 5.371 cents per kWh for Midnight Service. Almost 2,900 lights are receiving service under this rate schedule. Street lights were assumed to operate only during night-time hours. Traffic Lights/Traffic Safety Lights- Rate Schedules TC-1 and LS-2 Rate Schedule TC-1 applies directly to the traffic signals. The rate schedule for the service provided to the traffic signals is relatively simple. Other than the base customer charge of $0.35 per day, the energy costs is 6.487 cents per kWh. The signal lights associated with almost 360 intersections are covered under this rate schedule. Rate Schedule LS-2 applies to similar lights to those covered under Rate Schedule LS-1 except that they are owned by the customer, in this. case, the City. These lights illuminate A-2 · - DATA COLLECTED AND DA'Ih ANALYSIS METHODOLOGIES the intersection above the traffic signal and do not include the traffic signal itself. Again, the demand charge under this rate is complex and based on the number and size of lights, whether they are Mercury or High Pressure Sodium Vapor Lamps, and whether they are designated .for All Night or Midnight Service use. The energy, charge matches that 6f Rate Schedule' LS-1, 5.041 cents per kWh for All Night Service and 5.371 cents per kWh for Midnight Service. Almost 360 intersections are being illuminated through service being provided under this rate schedule. Traffic lights were assumed to operate during all hours. Park Sports Lights - Rate Schedules GS-2 and GS-1 Park spo.rts lights are used to light the City's Sports Park and other parks for sporting events. Due to the size of the load, lighting is predominantly provided under Rate Schedule GS-2 as described above. (Some is provided under Rate Schedule GS-1.) As the lights are used for only short periods in the evenings, the associated load factor is relatively low. Therefore, the energy is only purchased under the Block 1 Energy Charge billing rate. Parks - Rate Schedule GS-1 General lighting assodated with the City Parks is a relatively minor expense. Except for Centennial Park, Service is provided under Rate Schedule GS-1 due to the small size of the loads. IrrigatiOn - Rate Schedule GS-1 The loads associated with the irrigation of City premiseS'is also a relatively minor expense. Service is provided under Rate Schedule GS-1 due to the small size of the loads. INDUSTRIAL AND COMMERCIAL LOADS Using the data collected regarding estimated size and type of electric usage of identified businesses in the City, typical multipliers were Used to estimate the amount of electric consumption and pattern of consumption for those businesses. An additional amount of electric load for businesses observed but not specifically identified was estimated as a percentage of the identified load. Costs of electric consumption for those loads were estimated by applying a typical multiplier to those loads based on SCE's current electric rates. Projections of growth in those loads were estimated by applying a typical growth rate multiplier to current loads. A-3 DATA COLLECTED AND 1' ANALYSIS METHODOLOGIES RESIDENTIAL AND ASSOCIATED COMMERCIAL LOADS Residential loads were estimated by applying a typical multiplier to the estimated number of households in the City, as provided by the Tustin Chamber of Commerce, and by correlating that estimate with an estimate of total load within the city limits based on the City's franchise fee data. Commercial loads associated with those' residential loads were estimated by applying a typical multiplier. Costs of electric consumption for those loads were estimated by applying a typical multiplier to those loads based on SCE's current electric rates. Projections of growth in those loads were estimated by applying a typical growth rate multiplier to current loads. POWER PRICES Estimates of current and future power prices were based on SCE's current published rate schedules, the CPUC's specification of the elements of unbundled rates under the forthcoming restructuring of the electric industry, and information available regarding the projected costs of various elements of the power production and delivery system in the future. As noted in Section 5.1.5 of the report, there is currently much speculation regarding potential future power prices, and no long-term commitments should be made based on assumptions regarding those prices without substantial additional evaluation. In analyzing the electric power loads and power costs to the City of Tustin, it should be noted that the City has a variety of loads that are being served by SCE under a number of rate schedules. Each rate schedule contains a different customer charge, demand charge (if any), and energy charge. In general, the customer charge is a minor fee for the right to do business. The demand charge reflects the capital spent by SCE to provide service to the customer including a regulated rate of-return. The energy charge is related to the cost of fuel, operation, and maintenance expense, and/or power purchases from third parties to provide energy to the customer. Each of these components may be treated differently under the options available to the City to minimize their power cost. A-4 APPENDIX B CURRENT PROCEDURES FOR DIRECT ACCESS IMPLEMENTATION (AS OF NOVEMBER 14, 1997) The following sets forth the procedures and requirements applicable to direct access retail electric sergice implementation in 'California as they currently exist as of the date of this analysis. As can been seen from the descriptions set forth below, there are many details that have not been finalized as of the date of this analysis. Moreover, the CPUC has only recently granted interim approval of the proposed direct access tariffs and pro forma energy service provider agreements submitted by the IOUs in CPUC Decision 97-10-087 issued on October 30, 1997. In that decision, the CPUC required the IOUs to file final forms of their tariffs and agreements by November 28, 1997. Thus, the following requirements should be reviewed with the understanding that significant changes may be made in them. A. REQUIREMENTS FOR SIGN-UP OF FORMER IOU CUSTOMERS The CPUC has adopted requirements that must be met by any prospective electric service provider in signing up current electric customers of IOUs for direct access. Section 366(a- b) requires the CPUC to allow for ag~egation of load on a voluntary basis by private market aggregators, cities, counties, special districts, and others, based on a positive written declaration by each customer, without which the IOU remains the default provider. The CPUC's Direct Access Decision further mandates that a service provider must obtain formal written authorization from every, current IOU residential and small commerdal customer (less than 20 kW maximum peak demand) that it seeks to serve. The Direct Access Decision does not directly impose that requirement with regard to industrial and large commercial, customers, but it indicates that such customers would be entering into "direct access contracts." 1. CUSTOMER INFORMATION NOTICE A fundamental element of the sign-up process is the requirement of AB 1890 (Section 394(b)) that the service provider provide each prospective customer .a notice (1) describing the price, terms, and conditions of the proposed service, (2) explaining the applicability and amount of the CTC, and (3) describing the customer's right to rescind its agreement with the service provider. The CPUC also requires the notice to include a telephone contact number in the event of any customer questions. The Direct Access Decision does not speci/y the form of the notice. However, the Direct Access Decision requires that the notice incorporate the following language of AB 1890 (Section 395): a) In addition to any other right to revoke an offer, residential and small commercial customers of electrical service have the right to cancel a contract for electric service until midnight of the third B-1 CURRENT PRO 'RES FOR DIRECT ACCESS IMPLEME1~ iON (AS OF NOVEMBER 14, 199/-') b) business day after the day on which the buyer signs an agreement or offer to purchase. Cancellation occurs when the buyer gives written notice of cancellation to the seller at the address specified in the agreement or offer. c) Notice of cancellation, if given by mail, is effective when deposited in the mail properly addressed with postage prepaid. d) Notice of cancellation given by the buyer need not take the particular form as provided with the contract or offer to purchase and, hoWever expressed, is effective if it indicates the intention of the buyer not to be bound by the contract. SB 477 adds specific additional disclosure requirements applicable to prospective service providers. SB 477 includes the following statement of the required elements of the notice: a) A clear description of the price, terms, and conditions of service, including: The price of electricity expressed in a format which makes it possible for residential and small commercial customers to compare and select among similar products and services on a standard basis. The commission shall adopt rules to implement this subdivision. The commission shall require disclosure of the total price of electricity on a cents-per- kilowatthour basis, including the costs of all electric services and charges regulated by the commission. The commission shall also require estimates of the total monthly bill for the electric service at varying consumption levels, including the costs of all electric services and charges regulated by the commission. In determining these rules, the commission may consider alternatives to the cent-per-kilowatthour disclosure if other information would provide the customer with sufficient information to compare among alternatives on a standard basis. fie Separate disclosure of all recurring and nonrecurring charges associated with the sale of electricity. If services other than electricity are offered, an itemization of the services and the charge or charges associated with each. B-2 CURRENT PROCED~. ~,£S FOR DIRECT ACCESS IZ4PLEMENTATIuN (AS OF NOVEMBER 14, 1997) b) 'c) d) e) An explanation of the applicability and amount of the competition transition charge, as determined pursuant to Sections 367 .t.o 376, inclusive. A description of the potential customer's right to rescind the contract without fee or penalty as described in Section 395. An explanation of the customer's financial obligations, as well as the procedures regarding past due payments, discontinuance of Service, billing disputes, and service complaints. The entity's registration number, if applicable. The right to change service providers upon written notice, including disclosure of any fees or penalties assessed by the supplier for early termination of a contract. g) A description of the availability of low-income assistance programs for qualified customers and how customers can apply for these programs. 2. SB 1305 DISCLOSURE OF GENERATION SOURCE SB 1305 would require entities offering or providing electric service to residential and small commercial customers to identify the generation source of the energy purchased, as a percentage of specified categories. If Tustin should choose to market electricity to existing SCE residential and/or small commercial customers, the bill would require it to be able to determine those generation percentages, pursuant to standards to be set by the California Energy Commission. 3. SMALL CUSTOMER PROTECTIONS While AB 1890 in large part treats industrial and large commercial customers of the IOUs as capable of fending for themselves in taking advantage of opportunities provided by the availability of direct access to electricity suppliers, it includes extensive protections for residential and small commercial customers, defined as those with a maximum peak demand of less than 20 kW (Section 331(h)), as follows: (1) Section 394(a) requires entities offering electrical service to residential and small commercial customers within the service territory of an IOU to register with the CPUC. B-3 CURRENT PROC RES FOR DIRECT ACCESS IMPLEMEN'. )N (AS OF NOVEMBER 14, 1997) (2) (3) (4) (5) Section 394(b) requires that a prospective direct access service provider provide each prospective residential and small commercial customer an advance written notice regarding the service and the customer's rights. Section 395 allows a direct access customer to cancel a contract with a service provider within three days of signing that contract. Section 396 also allows such a customer to obtain specified recovery, from a service provider for violation of registration or contract cancellation requirements. Changing electric service of a small commercial customer (Section 366(d)) requires confirmation of the change through one of four specified processes. (6) Changing electric service of a residential customer (Section 366(e)) requires confirmation of the change through an independent third-party verification company. 4. IOU DIRECT ACCESS IMPLEMENTATION PLAN REQUIREMENTS AS required by the CPUC's Direct Access Decision, on July 1, 1997 the IOUs filed a joint Direct Access Implementation Plan (DAI Plan) containing detailed proposed requirements for sign-up of their customers by alternate service providers. Proposed direct access tariff rules were filed with the CPUC on July 15, 1997, with SCE submitting a revised proposal on September 16, 1997. In Section 3.4.2 of the DAI Plan, SCE has taken the position that all changes in service provider require the new service provider to obtain a written customer agreement, in a form specified by the affected IOU, to pay the CTC of that IOU. In addition, the new service provider would be required to submit to the IOU a "direct access service request" (DASR) for each customer. SCE, in its proposed tariff rules filed with the CPUC on September 16, 1997, goes so far as to provide in proposed Rule 22.E(2) that a DASR must be submitted for every customer account that will be served by an alternate service provider. The possible availability of multiple-account processing has not been resolved as yet. a) IOU Proposed Agreement with Service Providers The DAI Plan would establish a two-step process for the change of a direct access customer to an alternate service provider. First, the service provider would have to enter into "an agreement or agreements" with the affected IOU. Only then would the service provider be eligible to submit DASRs to the IOU. The DAI Plan identifies the following elements as the minimum information that a service provider must include in its agreement with the IOU: B-4 CURRENT PROCEL .ES FOR DIRECT ACCESS IMPLEMENT.4, .... 4 (AS OF NOVEMBER 14, 1997) i. Identification and contact information. iv. Ve vi. CPUC registration (for ESPs), if applicable. Warranty that it has obtained an ISO-certified "Scheduling Coordinator" (for scheduling service through the ISO) and that it will schedule all its loads through the Scheduling Coordinator. Warranty that it has obtained certification as a provider of renewable resources, if applicable. Warranty that it will employ an authorized independent verification agent, if required. Agreement to defend, indemnify, and hold the IOU harmless from and against any claims, demands, or liability arising out of actions taken by the service provider. Warranty that it will obtain from each customer a written of the customer's obligation to pay the IOU acknowledgment CTC. Specific agreement provisions regarding the metering, meter reading, and billing services or. procedures desired to be utilized. The draft pro forma agreement that SCE has proposed to enter into with service providers, as attached to its proposed tariff role, is very lengthy. If the City intends to provide service to SCE customers, it should review that draft agreement as soon as possible. In addition, extensive negotiations have taken place among the IOUs and a coalition of prospective direct access service providers regarding the IOU tariffs and service agreements. Additional changes to SCE's proposed tariffs and service agreement may result from those negotiations. In any event, the CPUC is scheduled to issue a decision soon specifying the content of the IOU tariffs and service agreements. The City should immediately obtain and review that decision when issued. b) IOU Direct Access Service Request Requirements In the DAI Plan, the IOUs propose that the individual direct access service requests submitted by service providers include the following information: B-5 CURRENT PRO~, ,RES FOR DIRECT ACCESS IMPLEMEIN. ON (AS OF NOVEMBER 14, 1997) i. Customer name Service account address IOU service account number iv. Service provider name v. Service provider (ESP) registration number, if applicable vi. Metering service option and equipment needs, if applicable for eligible customers vii. Meter identification information, if not an IOU meter viii. Billing service option Indication whether service provider is a certified renewable energy provider Xo Warranty by the service provider that the customer has signed a CTC payment agreement, if required by the IOU. The DAI Plan provides that SCE will accept a DASR only as an electronic communication. SCE's proposed service Provider agreement would require that a service provider have the capability to exchange data with SCE via the Internet, at a minimuml SCE also retains the dL~zretion to require "Electronic Data Interchange" if the service provider proposes to utilize consolidated metering or billing with SCE. B. MARKET RULES GOVERNING DIRECT ACCESS TO CURRENT IOU CUSTOMERS In its Direct Access Decision, the CPUC set forth the following additional "standards and procedures" that the IOUs must follow in processing direct access requests. Many of these rules will affect any service provided by Tustin to current SCE customers, including the following: Each IOU will begin accepting direct access requests on November 1, 1997. . The IOUs will process direct access requests on a first-come, first- served basis. B-6 CURRENT PROCED~ ..4 FOR DIRECT ACCESS IMPLEMENTAT,. .. (AS OF NOVEMBER 14, 1997) . Direct access requests received on or before the fifteenth of' the month will be switched over during the next month's billing cycle. 4. Direct access requests must be in a format acceptable to the IOU. 5. Direct access requests must be verified, if required. 6. IOUs must accept direct access requests in electronic format. . Specified procedures will be triggered in th-e event of a backlog of direct access requests. . IOUs must submit a monthly report to the CPUC for the period from November 15, 1997 through June 30, 1999 regarding their direct access implementation activities, including all direct access activities during the prior month. In addition, the Direct Access Decision sets forth an extensive set of requirements and rules regarding (1) service fees, (2) the 20 kW threshold for load profiling and metering matters, (3) metering and meter reading options, (4) billing options, (5) procedures for settlements, and (6) IOU transactions with affiliates. The key requirements and rules include the following: 1. IOU SERVICE FEES FOR ACCOMMODATION OF DIRECT ACCESS The Direct Access Decision expressly makes direct access service subject to customer payment of the IOUs' CTC. In addition, the CPUC issued Decision 97-08-056 on August 1, 1997 in its IOU rate "unbundling" proceeding that establishes the IOUs' revenue requirements for distribution access service and adopts the revenue allocation and rate design for different customer classes. However, neither the Direct Access Decision nor the unbundling decision sets forth a dear CPUC policy on the recovery by the IOUs of their asserted costs directly associated with the accommodation of direct access service to their customers. The Direct Access Decision simply requires the IOUs to submit advice letters proposing methods of determining and allocating those costs. In SCE's proposed tariff rule filing, SCE proposes new rate schedules setting forth charges that will apply in 1998 to service providers and customers for various direct access services rendered by SCE. Tustin shouid monitor SCE's tariff proceeding to be aware of, and potentially object to, the rates that SCE proposes for its asserted direct access services. 2. THE 20-KW THRESHOLD AND LOAD PROFILING A key factor in the rules adopted by the CPUC in the Direct Access Decision regarding the availability of direct access service to all IOU customers is the requirement that customers with a maximum demand of 20 kW or more have to utilize a meter with the capability of B-7 CURRENT PROt, RES FOR DIRECT ACCESS IMPLEMEN, ON (AS OF NOVEMBER 14, 1997) hourly metering) The CPUC indicates, however, that it would consider exemptions for customers with a maximum demand between 20 kW .and 50 kW. As the customer is responsible for the cost of the meter and its installation, the City should be aware of that requirement and its potential expense and effect on the timing of the provision of direct access service to customers that the City may seek to serve. Customers with a maximum peak demand below 20 kW will be eligible for direct access service based on statistical load profiling, rather than metered consumption. The CPUC is currently conducting a process to develop and specify the load profile methodologies that will be accepted for use in providing direct acce§s service. In addition, the acquisition of information for purposes of load profiling and the development of load profiles for use in forecasting load and settling imbalances has been addressed in the IOUs' Retail Settlements and Information Flow Workshop Report, issued on July 25, 1997. That report indicates that the IOUs anticipate retaining initial responsibility for calculating and maintaining load profiles. If the City intends to provide direct access service based on customer load profiles, it should participate in that CPUC process. The Direct Access Decision provides that the CPUC will reevaluate the use of load profiling in the year 2000. 3. METERING AND METER READING RULES Other than the requirement of hourly meters for direct access customers with 20 kW or more of maximum demand, the Direct Access Decision's requirements regarding metering are limited to requiring an informal process to develop open architecture standards for the interface of direct access customer metering with the meter reading equipment of the IOUs or of another meter reading provider. However, on the same day that it issued the Direct Access Decision, the CPUC issued Decision 97-05-039 providing for the unbundling of metering and billing ftmctions currently performed by the IOUs (Metering and Billing Decision). In the Metering and Billing Decision, the CPUC establishes three options for direct access customer metering: (1) separate (dual) metering and meter reading, (2) IOU consolidated metering and meter reading, or (3) service provider consolidated metering and meter reading. Metering services may be provided by alternate service providers as of January 1, 1998 for customers with maximum demands of 20 kW or more, and may be provided for all customers effective January 1, 1999. The DAI Plan and the IOUs' proposed direct access tariff rules include .extensive provisions addressing the rights and responsibilities of an alternate service provider with regard to meter installation, ownership, reading, maintenance, data access, removal, and ' In addition to serving as the limit for the hourly metering requirement and for AB 1890's consumer protection provisions, 20 kW is specified in AB 1890 as the maximum peak demand of a "small commercial customer" for purposes of the cut-off for eligibility for the ten percent rate reduction required bY AB 1890 (Section 368) for residential and small commercial customers beginning on January 1,1998. B-8 CURRENT PROCEL. ZS FOR DIRECT ACCESS IMPLEMENTA'x.. .a" (AS OF NOVEMBER 14, 1997) other aspects of metering .services. The IOUs' Retail Settlements and Information Flow Workshop Report includes an extensive discussion regarding the. need for rules for meter data access by various parties. · The IOUs' Meter Data Communication Standards Workshop Report, filed with the CPUC on July 31, 1997 adds an extensive discussion of direct access metering services and meter information management. The report reflects the current absence of agreed standards for many aspects of metering, and includes proposed standards for the following: a) Open archltec~e for metering interface and communications systems.' b) Metering equipment accuracy, reliability, communications, data storage, programming, and other parameters. c) Meter installation, maintenance, and testing. d) Meter reading and data access. The report indicates that interim standards may be needed for certifiCation, auditing, and enforcement of meter installation, maintenance, and testing standards due to the lengthy period that may be required to reach consensus on those matters. Tustin will need to become familiar with those standards and the requirements for the implementation of such standards if it is to become a direct access service provider to current IOU customers. The City should follow, and potentially participate in, the ongoing CPUC proceedings on this matter in order to become knowledgeable regarding the requirements that will govern direct access metering and to ensure that the standards that are adopted are acceptable to the City. 4. BILLING OPTIONS AND RULES The Metering and Billing Decision also establishes the same three options for direct access customer billing as it does for metering: (1) separate (dual) billing, (2) IOU consolidated billing, or (3) service provider consolidated billing. However, these billing options will be available for all customers as of January 1, 1998. The DAI Plan and the IOUs' proposed direct access tariff rules include extensive provisions addressing the rights and responsibilities of an alternate service provider with regard to coordination of information transfer and other billing matters with the IOU and with regard to the format, calculation, adjustment, delivery, and collection of c~stomer bills and other aspects of billing services. In conjunction with the mechanics of the billing options anal rules that will be applicable to direct access service, the City should also be aware of the provisions to be established by the CPUC and the IOUs for the billing of the CTC to departing IOU customers. The CPUC B-9 CURRENT PRO~ RES FOR DIRECT ACCESS IMPLEMEN, DN (AS OF NOVEMBER 14, 1997) ,- is currently reviewing CTC issues in its restructuring proceedings, and has recently issued decisions related to CTC issues. In addition, the IOUs have recently filed with the CPUC their proposed tariff rules governing CTC responsibility and billing procedures. The City should become familiar with the amount and calculation of the IOUs' CTCs, the procedure by which the CTC will be imposed on departing customers, including alternate service provider billing responsibilities, and the exemptions from CTC responsibility available to IOU customers that the City may wish to serve. 5. SETTLEMENT PROCEDURES Clbsely related to market rules and requirements regarding direct access customer billing is the matter of the rules applicable to settlement of payment obligations in the context of direct access service. Where separate (dual) billing is used, the IOU and the direct access service provider would each utilize their own payment processing and collection systems. In the case of consolidated billing by the IOU, the DAI Plan provides that direct access customer payment obligations and options would be the same as for IOU customers taking bundled service. SCE would collect payments from direct access Service providers and allocate them first to their own charges, leaving only the residual of any partial payments to be passed on to an alternate service provider. In the case of consolidated billing by the alternate service provider, the Metering and Billing Decision provides that the service Provider will be responsible for all payments owed to the IOU regardless of whether the service provider has received payment from or has the ability to collect from the customer. The DAI Plan indicates that a service provider may protect itself from the risk of non-payment by one or more of the following: a) Screening potential customers for credit risk. b) Requiring customer security deposits. c) Charging late fees to customers that miss payment deadlines. d). Refusing service to customers that miss payment deadlines. The IOUs' Retail Settlements and Information Flow Workshop Report refers to the DAI Plan with regard to settlement of retail transactions, but it indicates that a significant disagreement exists among stakeholders whether the CPUC needs to regulate the allocation of imbalances in actual versus scheduled load between the service provider and its customers. The City should monitor the CPUC's direct access proceeding to determine if the CPUC imposes additional regulation of that matter. B-10 CURRENT PROCEDt. .,3 FOR DIRECT ACCESS 12vlPLEMENTA5 .... '(AS OF NOVEMBER 14, 1997) 6. IOU AFFILIATE TRANSACTION RULES Although AB 1890 did not contain provisions addressing the matter of IOU transactions with their affiliates as alternate service providers, the CPUC in the Direct Access Decision imposes substantial limitations and requirements applicable to such transactions'.' The Direct Access Decision prohibits the IOUs from providing direct access in their own service areas through CPUC-regulated affiliates,, and adopted guidelines for unregulated affiliate transactions based on the transaction rules established for the telecommunications industry applicable to the Bell Operating Companies. The CPUC is giving further consideration to those latter rules, and may replace them in a later order. In addition, the Direct Access Decision specifies that the IOUs must offer service to their own retail customers only by purchases of power through the Power Exchange, and may not circumvent that requirement by providing or arranging separate direct access contracts for their customers at a special electricity rate. 7. ADDITIONAL MARKET RULES In its Direct Access Decision, the CPUC deferred consideration of the potential need for additional market rules (1) imposing an industry code of conduct on electric service providers and (2) imposing a bonding requirement on ESPs. The CPUC indicated that it would address those potential additional requirements, in its forthcoming decision on consumer protection matters. SB 477 requires the CPUC to impose standards of conduct on ESPs. The standards of conduct required by SB 477 also apply to a public agency providing-service within its jurisdiCtion and addresses: a) Confidentiality of customer information. b) Authority for disconnection and reconnection of customers. c) Disclosure of fees for change in service provider. d) Notices required for various matters related to service. e) Standardized bill formats. f) Rights and cost allocation regarding meter testing. g) Limitations on customer deposits that may be required. h) Additional public interest protections. B-11 CURRENT PROC., RES FOR DIRECT ACCESS IIVIPLEMEN., ON (AS OF NOVEMBER 14, 1997) ,- C. CREDITWORTHINESS REQUIREMENTS The CPUC's Direct Access Decision did not adopt particular requirements with regard to the creditworthiness of a prospective electric service provider. However, the IOUs have filed proposed tariff provisions with the CPUC setting forth their proposals to impose such requirements. SCE's proposal would impose a credit requirement only on service providers that implement their own consolidated billing procedure. SCE's proposed requirement would require one of the following: . A credit deposit of twice the maximum monthly amount owed to SCE, as estimated by SCE, in the form of (a) cash, (b) a letter of credit, (ci surety bonds, or (d) any other security or collateral that SCE accepts. '2. A guarantor of payment having a long-term credit rating of at least Baa3 from Moody's or BBB- from Standard & Poor's, Fitch, or Duff & Phelps, or a short-term credit rating of "corresponding investment grade;". . An investment-grade credit rating for the service provider plus the service provider's payment of all bills for all amounts owed to SCE under SCE's tariffs and its service provider agreement. SCE also proposes to incorporate several conditions under which it can require a service provider to "reestablish" credit by means only of the 'security deposit described above. Tustin should be aware of those potential requirements and should protest to the CPUC if SCE's proposal is unreasonable. D. REQUIREMENTS FOR RENEWABLE ENERGY PROVIDERS As discussed briefly above, the IOUs' proposed DAI Plan includes a reference to the potential need by a prospective electric service provider to obtain certification as a provider of energy from renewable resources. Section 383(b)(2) requires the California Energy Commission (CEC) to implement a process for certifying eligible renewable resource providers for purposes of obtaining allocations of funding of renewable resources provided by Sections 381 and 383. In addition, Section 365(b)(2) includes a provision allowing a customer to obtain immediate direct access service if at least one-half of its electrical load is supplied by a CEC-Certified renewable resource provider. However, the latter provision was rendered moot by the Direct Access Decision's determination that all IOU customers should be eligible for immediate direct access service. Whether or not the City might have an interest in the foregoing aspects of renewable certification, that matter is of particular interest in light of the general view, as indicated in B-12 CURRENT PRocE,. .'4S FOR DIRECT ACCESS [MPLEMENTA ~_ .4 (AS OF NOVEMBER 14, 1997) energy industry trade press and in other settings, that "green power" may command a significant market share, particularly among residential customers in various parts of California. While substantial discussion has taken place regarding the establishment of "branding" of renewable power and authoritative certification of the legitimacy of '"'green power" marketing claims, there is not yet a recognized set-of requirements applicable to prospective service providers that .might wish to market to customers based on their reliance on renewable energy sources for their power supplies. To the extent the City may wish to engage in marketing of a "green power" product as part of its direct access service program, the City should track, and potentially participate in, the development of standards for the certification of a renewable resource provider, whether through the CEC program or through standards to be developed by other organizations.2 E. DATA EXCHANGE REQUIREMENTS One of the more contentious issues in the current direct access implementation process is the set of requirements that will govern access to IOU customer data. The Direct Access Decision adopted the proposals of PG&E and SCE regarding data access. As set forth in the DAI Plan, those proposals would require the IOUs to provide "historic customer specific usage information, location and SIC information" to alternate service providers, with the identity of the customer removed. The DAI Plan 'provides that the IOUs will release customer-specific information only in accordance with the following rules: . Information will only be provided in electronic form, unless otherwise available from the IOU. . Information will only be provided twice each year for each customer account without charge, with service fees applicable to additional requests. 3. Only twelve months of historic usage data will be released. . Information will only be released upon written authorization from the customer. The Direct Access Decision also addressed the matter of access to a general IOU data base of customer information, requiring the IOUs to provide service provider access to a data base containing all of the foregoing information regarding all individual IOU customers. The Direct Access Decision ordered a workshop on issues regarding this data base, such as making the data base useful without disclosing the identity of the customers and the cost' 2 Also, the City should note that SB 1305 requires electric service providers to residential and small commercial customers to identify the generation source of the energy purchased, including "renewable" energy sources. B-13 CURRENT PROC, ,ES FOR DIRECT ACCESS [MPLEMEN1 ,N (AS OF NOVEMBER 14, 1997) and timing of providing the information. The workshop has been held, and the workshop report was submitted to the CPUC in mid-August 1997. The City should obtain a copy of that report and should continue to follow or participate in the CPUC proceeding on this matter. In addition, the IOUs' recent Retail Settlements and Information Flow Workshop Report · includes discussions of service provider access to IOU customer historic information, both for load profile purposes and for purposes of changing service providers. However, the focus of that report is on the availability and flow of information once an alternate service provider has commenced service. F. SUMMARY OF STEPS FOR TUSTIN DIRECT ACCESS SERVICE IMPLEMENTATION As a result of the number of procedural requirements that must be met before direct access service requests will be accepted and direct access service provided, the City should anticipate some delay between the time it might select an alternate power suPplier or ESP and the actual implementation of alternate service. Therefore, to the extent Tustin may be able to achieve energy costs savings fi.om the use of alternate energy service, the City will find an advantage to proceeding with its efforts as soon as practicable. Based on all of the foregoing requirements that Tustin would have to satisfy in order to develop a load aggregation program and provide service to current customers of SCE, the City should anticipate the following steps leading up to the commencement of that service: B-14 CURRENT PROCE~. .,ES FOR DIRECT ACCESS IMPLEMENTA ~.-.N (AS OF NOVEMBER 14, 1997) PHASE 1: Develop marketing plan and establish desired metering, meter INITIAL reading, and billing options. ACTIVITIES Prepare form of customer agreement. Prepare form of customer information notice. Negotiate and enter into service provider agreement with SCE, including electronic data interchange process, ff necessary. Identify and obtain Scheduling Coordinator. Obtain certification as provider of renewable resources, if applicable. Follow or participate in CPUC direct access proceedings. Contact and sign up customers. _. PHASE 2 Submit Direct Access Service Requests to SCE. PHASE 3 Commence direct access service at end of SCE billing cycle. B-15 APPENDIX C SCE RESIDENTIAL LOAD PROFILE Southern California Edison Co. Residential Load Profile 1.8- · 1.6- ' 1.4 ~ 1.2 i ~.0 0.8 ~ 0.6 ,.. . .. ~ . . 0.4 ~'-~---~ · i . 0.2 '- 0.0~, .......... .,,IIII,,,III .... I II,,IIIIIIIIIiiIIIIIII~II .... 1 3 5 7 9 11'131517192123252729313335373941434547 Half-hour -Summer peak day ' ~nter peak day ...... Average Summer Weekday .... Average ~nt~ Weekday APPENDIX D SCE ENERGY SERVICES J SOUTHERN CAUFORNIA' EDISON An .F_.DJSON INTERNA TIOHAL~ Comp~y SOUTHERN CALIFORNIA EDISON COMPANY PRODUCTS AND SERVICES POwer Products Pricing Options Energy Efficiency Environmental App. Billing Options Enedink Added Facilities ' · Agricultural Bypass Deferral Environmental PricJ.ng Credit .- ILAO/lnferrupfible Load Aggregation Pay-As-You-Grow RTP-3 RTP-3-GS RTP-TPP- 1 SSGDR TRDA/Time Related Demand Aggre. Chilled Wafer Systems Commercial Ughfing Systems Commercial, Ind. & Agri. Servcs. Prog. Compressed Air Systems Efficient Plant Improvement Energy Management Systems Hydraulic Pumping Systems Industrial Relighting (HID] Mail-In-Rebate Program Supermarket Energy Optimization Clean Heating & Cooling Clean Power Program Clean Water Technologies Food Processing TechnologieS-:: Health Care Technologies Metal Works DiskeHe Billing EDI Summary Billing Enerlink I i25 S. Grand Aw. San~a An~, CA 9270.5 714-97:~-5548 F~x 714--973-5752 baroaek~c,~..com oO .. APPENDIX E BID SOLICITATION AND EVALUATION PROCESS Relying on RMI for consulting support, the City of South San Francisco prepared and issued a Request for Qualifications seeking a "partner" in providing energy cost savings to its facilities and the electric customers within its city limits. Rather than formal proposals or bids, South San Francisco established a short-list of qualified firms, conducted extensive interviews, and presented a most qualified firm to its city council for approval. More commonly, however, cities and other agencies prepare an RFP describing the specific amount of power, energy service characteristics, and form of cost savings that they seek and solicit proposals from service providers to meet those requirements. An advantage to the latter approach is the opportrrnity to specify particular innovative services or considerations that the issuer may seek to be addressed. An RFP that encourages creativity in its responses can be'a valuable source of information for the City,'even if the City should choose not to award a contract to the bidder. An aspect of the solicitation process that may be imPortant to preserve the City's flexibility is the inclusion of an option for the City to reject all bids. While that has the potential to discourage some bidders, and possibly to limit the creativity and effort that others may invest in bid preparation, it may be very important to allow the City to take advantage of the best opportunity in a rapidly changing market. The energy trade press regularly reports instances of withdrawn and reissued RFPs and occasional cases where all bids are rejected. That option may be necessary in the event the City decides that it has not sufficiently described its needs in the original RFP or if circumstances change after the RFP is released (such as a change in load aggregation plans or a change in the position of SCE regarding its service options). The City should give strong consideration to including a provision to that effect in its RFP. The City may also wish to consider the extent' of the bidders list that it desires to establish. Because of the proliferation of ESPs and power suppliers in recent times, many organizations have found it useful to limit the set of entities eligible to submit a proposal, through a formal pre-qualification process or by means of some Other aspect of the eligible bidder qualification process that might serve to preclude frivolous bidders. After the RFP has been issued, the City may utilize as formal or informal bid evaluation process as it considers appropriate given the unique nature of the services sought. The City should be able to select a bidder based on the particularly unique aspects of its E-1 BID SOLICITATION ~ ND EVALUATION PROCESS proposal if it desires. Alternatively, the City can design an elaborate bid evaluatiOn model with quantitative scoring features that attempt to determine the winning bidder · through the application of the scoring formula. It is RMI's experience that the unique nature of the services and proposals that the City would be well-advised to solicit strongly favor a more proposal-specific evaluation rather than a numerical bid evaluation model. Once a winning proposal (or proposals, if the City is so inclined) is selected, then the City will have to negotiate a service agreement with that bidder. The large ESPs have standard form agreements that they will offer for execution, but it would likely be to the City's advantage to negotiate terms more favorable to the City and more particularly tailored to the City's specific concerns. The City may have to make a decision whether it is willing to enter into a long-term agreement in order to obtain maximum energy cost savings. Given the uncertainty of the market, particularly after the expiration of the CTC recovery in'2002, entering into a power purchase commitment extending beyond that time would entail a significant risk, which would have to be justified by a particularly beneficial set of terms. The City should assume that bidders will desire to provide metering and billing services to the City and any. aggregated loads with which the City may combine and that those bidders will also desire to serve as the City's Scheduling Coordinator for arranging transmission service to deliver alternate power supplies to the City. Whether the City will have to pay for those services may be negotiable, and the City should attempt to obtain them for the lowest cost po§sible, if it does not otherwise adversely affect the more significant terms of the deal. Bidders may also be willing to support the City's economic development programs at no cost if the City makes such a request. E-2