ࡱ> CDBܥhW eFk7hvvyyyyyzzzzz z zz41zzzzzzzz46668nBeXX4yz67zzzz4ryyzzrrrzyzyz4@8<1yJ&z|yyyyz4rrBEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA Order Instituting Rulemaking on the Commission's ) Proposed Policies Governing Restructuring ) California's Electric Services Industry and ) R.94-04-03 I (Filed April 20, 1994) Reforming Regulation. ) __________________________________________) ) Order Instituting Investigation on the Commission's ) Proposed Policies Governing Restructuring ) I.94-04-032 (Filed April 20, 1994) California's Electric Services Industry and ) Reforming Regulation. ) __________________________________________) JOINT COMMENTS OF CALPINE CORPORATION, CINERGY SERVICES, MOCK ENERGY SERVICES, NORAM ENERGY MANAGEMENT, INC. AND STONE & WEBSTER MANAGEMENT CONSULTANTS ON THE RETAIL SETTLEMENT AND INFORMATION FLOW AND METER AND DATA COMMUNICATION STANDARDS WORKSHOP REPORTS Introduction and Summary In accordance with the schedule established in the above-captioned proceeding, Calpine Corporation, Cinergy Services, Mock Energy Services, NorAm Energy Services and Stone & Webster Management Consultants (jointly referred to herein as the "Joint Parties") hereby submit their Joint Comments in response to the Rate Settlement and Information Flow (RSIF) and Metering and Data Communication Standards (MDCS) workshop reports filed with the California Public Utilities Commission (CPUC) by Pacific Gas & Electric Company (PG&E), San Diego Gas & Electric Company (SDG&E) and Southern California Edison Company (Edison) (jointly referred to herein as the UDCs). RSIF Report It is abundantly clear that the RSIF Report is a work in progress. The parties which have participated in the pre-workshop, the workshop and the various sub-workshops have agreed that there is a need to file supplementary RSIF reports on August 15 and September 30 to address the outstanding high priority issues that must be resolved as soon as possible. Section 1.D. 1. identifies the "high-priority" areas as including: (1) protocols for transfer of billing and account data; (2) auditing and performance monitoring; (3) methods for calculating distribution losses; and (4) load profiling communication methods. The Joint Parties would suggest that two additional items be added to the high-priority list: (1) data integrity and quality; and (2) Direct Access Service Request (DASR) and account maintenance data monitoring. The former is a basic prerequisite for the efficient functioning of the entire RSIF process while the latter is critical due to the importance of the DASR process to the implementation of customer choice. In Section I.D.2., the report highlights medium-priority areas such as rights and procedures to access information in the UDC meter listings. The report suggests that it is not clear who may have access to such information or the means which would be utilized for such access. The Joint Parties suggest that the appropriate means will be a customer information request which has been verified by written authority of the customer whose meter is in question or has been independently verified by a third party (IVA) under a DASR request. Such a request could be filed by an ESP, a meter vendor or the customer itself. With regard to the issue of universal identifiers, the Joint Parties support the proposal made by Southern California Gas Company at the RSIF workshop, as described below. In the meantime, it should be sufficient to use the existing UDC meter number or account number with a prefix added to identify the appropriate UDC. Finally, Section I.D.3. identifies as an other priority issue, the need for common contract and rule formats for the UDCs. The report suggests that so long as the basic content is consistent, consistency of form can wait until after 1/1/98. The Joint Parties strongly object to this position and suggest that if the UDCs are unwilling to produce common contract and rule formats, customers, consumer groups and ESPs will undertake the effort. As announced at the pro forma tariff workshop held on August 7-8, the newly-formed Direct Access Alliance has undertaken the task of drafting a proposed tariff and UDC-ESP service agreement which would have statewide applicability. The Joint Parties are members of the Direct Access Alliance and strongly endorse and support its efforts to produce such a tariff and service agreement. It is clear that many other issues will need further attention after the supplementary reports are filed. Since so many issues remain unresolved, it is difficult to treat the workshop report as being final in any practical sense. Instead, it is a good status report of the work in progress as of the time that the procedural calendar required that a report be issued. Although it is hoped that these issues will be resolved through further cooperative efforts, it is clear that significant differences remain, as summarized in Section I.E. In particular, the allocation of settlements and imbalances by the Independent System Operator (ISO) is a critical issue which will be resolved in another forum. In the ISO Tariff filing, dated March 31, 1997, there is a description of the proposed system by which schedules will be submitted and received, congestion will be identified and adjusted for and energy imbalances will be identified and allocated so that settlements can be made. Section I.E. notes that there are three levels of allocation of settlement imbalances to market participants, (1) by the ISO to scheduling coordinators (SC); by the SCs to their energy service providers (ESP); and (3) by the ESPs to their end-users. The Joint Parties endorse the position enunciated by Enron in its comments on the preliminary workshop report which contend that the market will ensure a fair allocation since any unfairly treated customers will complain or switch to other service providers. The CEC suggests that the CPUC should oversee settlement and imbalance allocations to ensure that end use customers are treated as fairly as possible. The Joint Parties believe that such an effort is beyond the regulatory authority of this Commission since the transactions will tend to fall under FERC, rather than CPUC jurisdiction. There is a common interest among all players to ensure that imbalances are settled as quickly and fairly as possible. The market will produce solutions to this problem which will ultimately be more efficient and accurate than any system which could be imposed by regulatory fiat or control. Section II.A.2.b. of the report describes the activities of the metering data management agent (MDMA) to include (1) collection of data; (2) validation, editing and estimation; (3) database management; (4) dissemination; (5) storage; and (6) security. The Joint Parties believe that the report should more heavily stress the need for adoption of a uniform push communications technology to be used for the performance of these functions. Throughout the report, when reference is made to the communication of data from the MDMA to the ESP, the use of push communications technology should be assumed. This issue will be dealt with in greater detail in the supplemental reports to be filed with the Commission. The Commission should aggressively endorse the development of an industry-wide push communications technology which, under appropriate service agreements, should provide for secure and accurate data collection, timely and efficient processing and dissemination and readily accessible storage and retrieval. Section II.B.1.b.i. provides certain assumptions which control the illustration of required information flows in Map II.8. One assumption is that, the ESP has decided to conduct consolidated billing and to take the risk of customer non-payment of both its own charges as well as those of the UDC... (emphasis added). The language which is italicized is gratuitous and unnecessary for an explanation of Map II.8 and should be stricken. Section III.A.2.c. suggests that market participants should have the right to request raw meter data for a particular end-user by paying an additional charge. The Joint Parties believe that this information should be considered proprietary and confidential to the customer, as described in Section I.D.2 above, and should not be subject to such release unless authorized in writing by the customer. Section III.A.2.e. provides that UDCs will make the most recent year of consumption data available to customers choosing direct access for the first time. Thereafter, the report mandates that ESPs will be required to provide this information when a customer switches to another ESP. The Joint Parties support the position of Green Mountain and other parties who believe that UDCs should always be required to provide this information. Section III.B. provides for a universal meter identifier system proposed by Southern California Gas Company and endorsed by CCES and First Point Utility Solutions. The Joint Parties believe that a universal identifier (such as a 10-character alpha-numeric string) would permit clear and consistent data communication as well as deter energy theft by ensuring that each active universal identifier was allocated to one energy supplier and one distribution services supplier. The receipt of energy by an unauthorized meter would be instantly identifiable and all other parties would benefit by this swift detection. The report suggests that a subgroup of RSIF participants will continue to examine this issue and that such a system is not expected to be implemented before January 1, 1998. However, since the eventual implementation is in the best interests of the state, the participants in the RSIF process should be certain to adopt interim transaction data sets which will accommodate the future use of universal identifiers. Section III.D.1. provides that ESPs will be responsible for providing information to UDCs with regard to customer usage, load history, billing options, etc. The report should clarify that such information is only required to be provided by an ESP which elects to provide meter reading services for its customers and which also opts for either consolidated UDC billing or dual billing. In such case, the UDC clearly needs the appropriate usage information for its own billing purposes. In the case of consolidated ESP billing, consumption information will be provided in connection with the ESPs remittance of sums due to the UDC and need not be provided separately. Section III.D.2.c. provides that customer payment information should not be shared by a UDC and an ESP due to the LOCs concern with, sharing of credit information. The existence of delinquencies or payment disputes do not go to the fundamental issue of credit analysis, i.e., does a customer have the financial wherewithal to pay? Rather, such information provides an insight into payment behavior and is essential for an ESP to make an informed decision as to whether to accept a new customer. The Joint Parties support the sharing of such information. Section III.F.2.b. provides that UDCs will assign customers to load profiles based on customer class or rate schedule. Further segmentation would be deferred to a proceeding in 1998. The Joint Parties believe that adequate information is available for the UDCs to at least provide segmentation based on climate zones prior to January 1, 1998. Such a step would eliminate the gross discrepancies which would exist between, for example, a residential customer in Santa Monica and one in Palm Springs, both of whom would be assigned the same load profile by Edison, if the UDC proposal is adopted. In addition as described in their comments on the load profiling workshop report, the Joint Parties support the use of dynamic, as opposed to static, load profiling as soon as possible by all UDCs. Section III.G.1. provides that each UDC is responsible for generating estimated distribution loss factors. The report then states that the, relevant Local Regulatory Authority must approve these factors prior to their use. It is not clear what is meant by the relevant Local Regulatory Authority. Furthermore, the sentence should be modified to provide that such review and approval should be conducted in accordance with standard industry practices and provide for a similar review by other market stakeholders, such as customers, SCs and ESPs. The Joint Parties agree that the determination of the proper distribution loss methodology should be resolved before January 1, 1998. Section III.J.1. (page 52) specifies that the preferred communications network for financial transactions should be WEnet, using any of the options available from MCI. The Joint Parties believe that it is highly inappropriate and anti-competitive for this Commission to sanction the use of particular providers when other vendors can provide the same service. The references to specific vendors should be deleted. Also, Section III.J.2. regarding data transfer protocols states that the PG&E format was accepted as a starting point with migration to national standards as they are accepted by the CPUC. The Joint Parties oppose the use of the PG&E format on the grounds that a preferable ANSI standard can be selected and made operational before such ANSI standards are required for use by the market. Section IV.C.2. raises the question of whether MDMAs should be required to provide rapid access capability to customer information or permitted to offer such services for fee in the commercial market. Another area of conflict among the parties at the workshop is the customers right to data access beyond the calculation on the bill. The Joint Parties support the position espoused by the Office of Ratepayer Advocates ("ORA") that customers should have (1) the right to ongoing data access from the MDMA, independent of the ESP; and (2) the right to all data gathered by the meter, even if not used to calculate the bill. Data and information gathered by the meter can be used by customers to calculate their own load profiles, analyze consumption patterns and plan for more efficient energy purchasing strategies. It is in the best interests of customers to have free access to this information and not to be charged a fee as a value-added service. Finally, as stated above, the RSIF report contemplates the need for ongoing implementation efforts by various stakeholders to resolve remaining issues. The Joint Parties believe that some Commission oversight will be required and that the Commission should prescribe an expedited process for resolving any technical disputes. The supplemental filings made by these stakeholder groups should be reviewed on an expedited basis by the Commission so that implementation by January 1, 1998, will not be delayed. Metering and Data Communication Standards Report The Joint Parties believe that the MDCS workshop report does not adequately convey the level of disagreements which were expressed by participants at the workshop and that the report primarily documents common terminology and issues which were not in significant dispute. The report opts for an expedited system of shortcuts to implementation which may complicate the eventual adoption of a common national standards for meter and data communications. A primary example of such a shortcut is the adoption of the so-called PG&E Protocol. The Joint Parties believe that a preferable system can be adopted and introduced prior to January 1, 1998. Finally, although the Commission has consistently indicated a preference for decisions and systems which maximize customer choice, the workshop report proposes solutions which are more designed for the convenience of the UDCs than the furtherance of customer choice. The Commission must establish initial metering and data communication standards and mechanisms which will facilitate the evolution from interim technologies to systems which comply with national standards such as those administered by the American National Standards Institute ("ANSI"). Such systems have been developed by a fair and patient process of market-wide testing and analysis, rather than merely for the convenience of a particular manufacturer or end-user. This is a critical issue, since electric customers may invest in systems which comply with interim standards but which are ultimately rendered inefficient or even inoperable by the adoption of a national standard. This is a barrier to customer choice and competitive markets, since such customers will find the cost of deploying a new system to be expensive and frustrating. Given the short time remaining until the scheduled January 1, 1998, implementation date, the Commission should direct interested parties from all stakeholder groups to form a work group which would analyze national standards consistent with the goals of direct access implementation, customer choice and open architecture. Once the work group has selected and adopted appropriate national standards, the Commission should issue a schedule for replacement, modification or adaptation of interim metering and data communication systems to comply with national standards. The national standards which are adopted must have certain characteristics which comply with the goals of this Commission to facilitate competition. Prime among these characteristics is the need for interoperability. While it is not possible to quantify a particular level of interoperability which can be achieved by a date certain, it is important to postulate a minimum level of functionality. At a minimum, the standards which are adopted should permit (1) all meter-reading systems to work with all meters; (2) all meter data management systems to work with all meter reading systems; and (3) all users of meter data to access all meter data. A positive step towards the realization of these goals would be the adoption of ANSI C12.19 as the appropriate standard for how data are transferred from the meter. The Joint Parties endorse the comments on the draft workshop report which were filed by the Automated Meter Reading Association, the Electric Power Research Institute and the Office of Ratepayer Advocates with regard to the adoption of ANSI C12.19. In addition, the Joint Parties support the recommendation of these parties, as indicated in the report, for the adoption of the Utilities Communication Architecture, as reflected in the use of IEEE SCC 36 (CASM). The adoption of these standards will not inhibit the use of various transport methodologies, such as radio, telephone or Internet. The market will, and should, decide what standards are ultimately adopted. However, the adoption of ANSI C12.19 and IEEE SCC 36 (CASM) will provide a solid foundation which will lead the industry toward standardization of all functions over time. Chapter III of the report defines the concept of open architecture as applied to MDCS. The Joint Parties generally agree with the definition provided, except with regard to Section III.A.1.a)(ii) wherein it is stated that, Market participants will retrieve data from the MDMA to carry out their responsibilities. It would clearly be preferable to utilize systems which will push data to recipients as opposed to those which require the recipient to pull the data. This is because the receiver of data in a pull technology does not know when the data is available and must constantly inquire as to the data availability. In push technology, the data is sent to the receiver as soon as it is available. It is clearly preferable to reduce the volume of data transmissions which are repetitive and inefficient and therefore push communications technology should always be utilized. Section IV.B. of the report deals with the existing meter standards which are utilized by California's UDCs and provides that meters must meet local UDC standards. The Joint Parties join ORA in protesting the imposition of local UDC standards. At the very least, there should be uniform statewide standards. The UDCs should meet to resolve any differences in their respective standards before January 1, 1998. Chapter VI of the report deals with the standards for the installation, operation and maintenance of meter reading systems. The Joint Parties express their support for the following positions: ( Implementation of a customer-read program in which customers are permitted to read their own meters, subject to routine editing and validation by the MDMA and independent verification at least every twelve months to ensure meter accuracy, as proposed by ORA in Section VI.A.1.b)(i); ( Daily reading of interval meters, as proposed by CEC, in order to reduce the interval where a meter is producing bad data and provide access to meter data which will support such applications as load scheduling to the ISO and local bidding to the PX, as described in Section VI.B.1.d)(ii); and ( Holding all market participants to the same meter reading performance standards, as proposed by Schlumberger in Section VI.C.4. In addition, the Joint Parties object to the report's assumption that UDCs are the only entity capable of certifying firms which wish to provide MDMA services. Section VI.B.3.c) provides that such firms can begin to submit applications to local UDCs beginning November 1, 1997. It would be preferable to remove the UDCs from this process and have the certification performed by an independent entity selected by the Commission, with the advice of all interested stakeholders. A fundamental effort of the Commission's entire direct access implementation process has been to mitigate the market power of the state's utilities. If metering is to be unbundled in the interests of furthering competition, then the UDCs cannot be placed in the position of determining who will be their competitors. In other areas related to meter data management systems, the Joint Parties support the following positions: ( SDG&E's position with regard to the availability of 80% of all usage data on the scheduled read date and 90% within one day of the scheduled read date as described in Section VII.B. 15.; ( Section VII.B.18 provides for a data storage period of three days on the server. Older data is to be available for at least three years. The Joint Parties believe that more recent data (from 3 to 90 days old) should be available within one business day; and Section VII.B.19 suggests that WEnet should be investigated as a potential transfer potential. For the same reasons expressed in their comments on the RSIF workshop report, the Joint Parties believe it is fundamentally wrong for the workshop reports to designate any particular vendor. In Appendix A, the report describes metering product certification testing requirements. Sections 1 indicates a number of areas where the CPUC is to perform certain tasks, such as meter qualification tests and qualification of the facility and personnel who perform the testing. Sections 2 through 4 deal with such issues as meter failure, meter design rejection and test setup. Finally, Section 5 indicates that all such meter certifications will be performed in accordance with applicable ANSI standards. The Joint Parties believe that much of the material contained in Sections 1 through 4 of Appendix A are either duplicative or inconsistent with ANSI standards. It is not necessary for the CPUC to perform a function which is already adequately and carefully described in ANSI. Therefore, these sections should be revised to delete functions which are duplicative of ANSI standards. Finally, Appendix D deals with, among other things, the data format which will be used when data is transferred. The Appendix states that the consensus of the group was that the PG&E protocol should be adopted as an interim format for use in the MDMA information exchange process. As noted by the CEC in its comments, the PG&E Protocol has little in its favor other than its relative ease of implementation. The CEC also suggests that much better data exchange formats have been proposed, but none could feasibly be implemented by January 1, 1998. The Joint Parties believe that this is not a sufficient rationale for the adoption of the PG&E Protocol. Furthermore, the Joint Parties believe that an alternative format can be adopted before January 1, 1998, and that such an alternative would be a preferable means of migrating to the adoption of national standards, as described above. A member of the Joint Parties, NorAm Energy Management, is pursuing the development of such an ANSI format for the DASR and related transactions on a joint basis with other industry stakeholders and intends to offer an alternative to the Commission in the near future. Conclusion The Joint Parties believe that both the RSIF and the MDCS workshop reports require a great deal of additional work. Both should be viewed as works in progress which will require additional efforts by this Commission and other industry stakeholders in order to meet the January 1, 1998, implementation of direct access. The Joint Parties urge the Commission to move rapidly toward the identification and adoption of national standards which will ensure that California ratepayers are not confronted with constantly changing standards which necessitate expensive system changes. This means that the state must adopt uniform standards which facilitate customer choice rather than merely being convenient for UDCs. The reports propose certain practices and procedure which will frustrate customer choice and therefor discourage customers from participating in the new competitive electricity market which this Commission has done so much to establish. Respectfully submitted, Date: August 11, 1997 __________________________________ Daniel W. Douglass Attorney for the Joint Parties 15456 Ventura Blvd., Fifth Floor Sherman Oaks, CA 91403 Telephone: (818) 907-9898 Facsimile: (818) 907-8465 CERTIFICATE OF SERVICE I hereby certify that copies of the JOINT COMMENTS OF CALPINE CORPORATION, CINERGY SERVICES, MOCK ENERGY SERVICES, NORAM ENERGY MANAGEMENT, INC. AND STONE & WEBSTER MANAGEMENT CONSULTANTS ON THE RETAIL SETTLEMENT AND INFORMATION FLOW AND METER AND DATA COMMUNICATION STANDARDS WORKSHOP REPORTS have been served by e-mail or by mailing a copy properly stamped and addressed, by first class mail with postage prepaid, on August 11, 1997, addressed to each person shown on the attached service list. Dated August 11, 1997, at Sherman Oaks, California. __________________________________ Daniel W. 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