A. In General
PG&E recommends that the Commission adopt all of the recommendations of the PSWG, including those which did not have unanimous support. PG&E states that for those recommendations which did not have unanimous support, the overwhelming majority of the PSWG participants still supported the recommendation.
PG&E points out that the recommendations were developed in a fair and open process, and represent a careful balancing of all interests. PG&E asserts that the Commission should not be tempted to adjust the majority recommendations in the report to cater to a few discontented voices.
The CEC believes that truly permanent standards should apply consistently to all providers of any given competitive service, whether that provider is a UDC or another firm. The CEC asserts that the PSWG's recommendations essentially exempt the UDCs' bundled services from the permanent standards. The CEC contends that this is fundamentally unfair because it imposes various costs on competitive providers of services by specifying standards for equipment and data processing. In contrast, the UDCs are not obligated to meet the same standards.
The CEC states that D.97-05-039 "clearly permits the three UDCs to enter the competitive metering service, even for bundled service customers." The CEC believes that now is an appropriate time for the Commission to be:
"absolutely clear that all new metering and communication equipment installations for both direct access, PX [Power Exchange] Hourly Price, and ordinary bundled service customers should conform with any standards imposed as a result of the PSWG report. Otherwise, UDCs will be installing equipment that may not be compatible with future requirements and that will create new `distribution system' stranded costs." (CEC Comments, pp. 10-11.)
The CEC also contends that the Commission should clarify that the UDCs' operations should conform to all MSP and MDMA requirements by a date certain for all customer activities, whether direct access, PX hourly price, or bundled service customers. The CEC suggests January 1, 2000 as an appropriate target.
The CEC contends that the presumption of technical competence of the UDCs as an interim measure was an appropriate presumption, but is not one that should carry over as a permanent standard. The CEC recommends that the Commission create and adopt a common set of equipment standards, data management protocols, and employee qualifications for each functional service across the entire industry so as to level the playing field for all market entrants.
The CEC contends that the standards should be designed to achieve well defined functional or performance objectives, or business or regulatory requirements. Some of the recommended standards lack clarity as to what objectives the standards are trying to achieve. If further efforts by stakeholders are necessary, the CEC recommends that the Commission specify the objectives, or the business or regulatory requirements, that it wants to achieve. If that is not possible, the CEC believes the Commission should direct the participants to begin their efforts by reaching a common understanding of the objectives. By defining the objectives, the CEC believes that the working groups will be able to complete their work more efficiently.
SCE recommends that the Commission adopt the unanimously supported recommendations as a new General Order, and that the resolution of any disputed issues be added to the General Order.
The joint parties caution that the Workshop Report must be read with the understanding that it was prepared by a body of stakeholders, many of whom were indifferent, or in some cases opposed to the Commission's goals for customer choice, interoperability, and national standards.
The joint parties take issue with the statement in the Executive Summary of the Workshop Report which states:
"However, having universal interoperability and interchangeability between the meter and data retrieval technologies is not feasible without constraining technological alternatives."
The joint parties assert that the above statement is incorrect. The joint parties point out that relatively short and simple meter data messages can be carried by almost any standard communication network such as telephone, fiber, or radio. These communication networks can accept input from many different devices such as telephone receivers, modems, facsimile machines, etc.
The joint parties state that IEEE Standard 1397 specifies that an interface between a meter and a generic communications network can and should be developed. The IEEE SCC31 has a working group that is addressing a standard that will interface any meter to a radio frequency network, and be compatible with existing and planned Utility Communication Architecture (UCA) -compliant communications networks.6
The joint parties also take issue with the statement in the Executive Summary which states:
"The PSWG agreed that the only area where universal interoperability and interchangeability could be realistically achieved at this time was at the interface between the meter and hand-held devices using an optical port."
The joint parties contend that this statement is technically incorrect. The joint parties assert that, in several instances, interoperability using different technologies and existing standards can be achieved. They believe that the standards being developed by the IEEE in support of the UCA activities will make it possible to develop meters that have a high degree of interchangeability within the next few years. The joint parties state that a better and more correct statement is:
"At the present time interoperability and interchangeability between the same meter and data retrieval technologies generally requires matching of technologies, but this condition is expected to change in the next few years." (Joint Parties' Comments, p. 4.)
The joint parties contend that the PSWG did not discuss or vote on any item that suggested universal interoperability, or that a single meter could be used with any or all communication technologies that are currently on the market. They contend that meters with appropriate interfaces can be designed today to send their messages over nearly all well-designed communication media.
The joint parties contend that the issues of interoperability and open architecture are of concern to customers because they affect the compatibility of the customer's meter with the metering devices used by other ESPs. The joint parties feel that a direct access customer should be informed at the outset as to whether the customer's direct access meter will be compatible with the metering systems of other ESPs, should the customer decide to switch.
B. Interconnection, Open Architecture, and Interoperability
The PSWG relied on Diagrams A and B in the Workshop Report to describe the points where standards can be used to define interoperability. Instead of using Diagrams A and B, ORA favors the use of the IEEE 1397 Architectural Reference model as the tool for defining interoperability and open architecture. ORA, as well as the other joint parties, believes that the IEEE model is broader, and provides a greater technical description to current and future component and systems developers.
ORA and the other joint parties also point out that the IEEE model uses the OSI model. According to the joint parties, the OSI model is an industry standard that defines data communication services in the form of seven distinct layers. This layering process allows a change to be made to one given layer, without impacting the remainder of the model. As a result, interoperability can be greatly enhanced without having to define a technology based on the OSI reference model. Diagrams A and B do not contain any references to the OSI model. Due to the incomplete communication specifications in Diagrams A and B, the joint parties contend that other providers who want to facilitate customer choice may face barriers to entry.
C. Meter Communications
1. ANSI C12.19
The Workshop Report included the comments by ABB, which favors the adoption of ANSI C12.19. ABB states that it was a participant in the development of ANSI C12.19. ABB states that the standard was expressly designed to encourage and enhance competition by reducing the time and effort needed to add new and different metering products. To encourage this, a single data structure standard was used. This data structure can be used with multiple transport schemes.
ABB also states that the data structures were not modified to limit their application to any one media. Instead, the standard was designed so that the data structures could meet the needs of the simplest device and yet be expandable beyond any meter in production today. ABB also points out that the data structure allows manufacturers to keep their tables confidential, while other manufacturers who want to, can allow for interoperability.
NERTEC supports the adoption of ANSI C12.19, but disagrees with the unlimited exemption for existing meter types. NERTEC believes C12.19 provides an adequate structure for data definitions, format definitions, and common syntax, which will assure a level of interoperability, and provides a foundation for further standard development.
NERTEC believes that PSWG's recommendation to grandfather those meter types produced before March 20, 2000 from the C12.19 standard should be limited to a maximum of two or three years. NERTEC believes that an unlimited exemption may impair interoperability.
ITRON contends that the recommendation to adopt C12.19 will stifle and reduce competition. In addition, such a standard will be expensive to support and has several drawbacks. For example, ITRON points out that ANSI 12.19 was not intended to provide, and does not ensure or guarantee interoperability. Only a portion of the applications layer of the seven layer OSI model uses data models. No other layers of the OSI model have been standardized for meter reading except for some aspects of the optical and telephony physical layers.
ITRON also points out that the C12.19 standard was prepared for a traditional utility monopoly market, i.e., single utility access to multiple meter types, and was not intended to address issues relating to multiple supplier access. ITRON also contends that C12.19 contains mechanisms which increase the data transmission required to communicate information. This has the potential to increase message lengths, resulting in more expensive communication costs, and shorter battery life for battery powered products.
The California Competition Network, Enron, Schlumberger, and CellNet oppose making the ANSI C12.19 standard a mandatory requirement for direct access meters. They cite four reasons in support of their opposition. First, they contend that the standard is not necessary to make the market work. Second, such a standard will result in added costs because new functions will have to be added to existing and new products. Third, the Workshop Report states that C12.19 does not achieve interoperability. The standard would merely add one aspect of standardization to the meter interface, but would not result in an interoperable standard. They also contend that there is no consensus that the level of standardization in C12.19 is the right standard, nor even that it is an improvement. Fourth, the parties who support applying C12.19 to ESP provided meters, voted against applying the standard to UDC provided meters. They contend that for whatever reasons the UDCs had for voting that the standard should not apply to UDC meters, the same reasoning should apply to ESP provided meters.
The California Competition Network, Enron, Schlumberger, and CellNet also disagree with the statement in the Workshop Report that "moving the point of interoperability closer to the customer makes it easier to switch ESPs." They contend that ease of switching depends on maximizing customer convenience and minimizing cost, and that the proximity of interoperability to the customer is not necessarily related to these two factors.
The CEC's comments take issue with the C12.19 recommendation. The CEC points out that the recommendation will allow unlimited grandfathering of non-conforming meter types because meter types approved before March 20, 2000 may continue to be installed past that date. The C12.19 standard is also a problem for radio frequency systems. In addition, the standard has technical features that permit the meter to be configured to communicate in proprietary protocols, which does not promote the standardization of metering data communications.
The CEC asserts that the C12.19 debate reflects a fundamental disagreement among the parties about whether standardization at the meter communications level will enhance customer choice and facilitate a competitive, innovative marketplace for electricity, metering and related services. The CEC believes that the Commission did not direct the PSWG to standardize meter communications. Instead, the CEC contends that the Commission's objective in unbundling metering services was to facilitate the direct access market by permitting a customer to choose among the ESPs. What is unclear is whether the meter communication standards furthers this objective. The CEC believes that there needs to be some real experience with the competitive provisioning of metering services before the issue of meter communication standards can be resolved.
PG&E states that it understands the concerns expressed in the minority opinions that the C12.19 standard should be mandated for all meter technologies since for many communication technologies, a C12.19 data format will not allow for interchangeability between meters. However, if a solid state meter using a Type 2 optical port had to comply with C12.19, that would permit interoperability. PG&E states that such a requirement would allow customers to change ESPs, or to default to the UDC, without requiring that their meters be changed.
SCE is unclear about the intent of NERTEC's comments with respect to the C12.19 standard. If NERTEC's intent is to require the replacement of all meters that are not C12.19 compliant within three years, then SCE opposes the recommendation. SCE contends that such a requirement would result in increased costs to replace essentially new meters.
SCE points out that other parties oppose C12.19 on the basis that if the standard is required of new meters, it must have value, and therefore should apply to the UDCs' existing meters. SCE contends that those parties ignore that if the UDCs were required to replace their installed base of meters, this would greatly increase costs for those customers who choose to remain bundled customers. SCE supports the PSWG recommendation that meters installed before March 20, 2000 be grandfathered until the end of their service life.
ORA abstained from voting on the C12.19 standard. ORA points out that the standard addresses the format and communication of data tables of metered data. Although ORA favors a standard which promotes comparable measurement, the vote also included the proposal to grandfather existing non-complying equipment. ORA favors a two- or three-year exemption from compliance, rather than an unlimited exemption. ORA believes that the exemption discourages real customer choice because the meter manufacturers can continue to maintain and sell older equipment which does not have to meet the C12.19 standard.
The joint parties contend that the C12.19 standard should be adopted. The adoption of that standard will allow for the creation of a common data format whereby metering data can be consistently communicated and shared with other systems. The joint parties contend that the C12.19 standard is necessary in order to have "plug and play" capability for the various meter-related components. However, the adoption of just the C12.19 standard is not enough. Instead, a complete set of interfaces must be defined in order to have plug and play components. No single standard can assure interoperability in a complex system. A set of standards is especially important when there are multiple suppliers offering the same kinds of products and services.
Some vendors have suggested that the Commission should let the market decide which standard, technology, or communication protocol is best. The joint parties state that allowing multiple proprietary protocols, and letting the market sort out the winners will work, but that consumers will lose out and end up confused. The joint parties favor the adoption of a common set of interfaces, rather than letting the market decide which protocols to use.
The joint parties disagree with some of the statements made by the parties that oppose the C12.19 standard. One of the statements is that "Interoperability of meters would require selection of a single communications technology...." The joint parties state that the technologies are not the constraining factor in achieving interoperability. Appropriate interface standards can be selected which would enable different vendor products to interoperate. The joint parties assert that if the vendor did not bundle the meter reading, transport, and metering functions into a single product or service using proprietary protocols, that product or service would be able to operate with another vendor's products. For example, the joint parties point out that several vendors have bundled the transport mechanism into their product and service offerings. As a result, there are many different proprietary transport mechanisms and interfaces. The joint parties contend that the C12.19 standard should be used by the different vendors for base level interoperability.
The joint parties also disagree with the concept that added costs should be the basis of rejecting a standard. That is because all market participants will be required to meet the standard, and competition will determine who is more efficient in meeting the requirements. In addition, standardization normally reduces the cost of products. The joint parties assert that the manufacturers who seek to preserve proprietary protocols do so because they are able to charge consumers a premium price for a unique product.
The joint parties take issue with the comment at page 20 of the Workshop Report that the ANSI C12.19 standard is not compatible with all radio frequency based technologies. That comment is true, but the joint parties point out that this standard is compatible with some radio frequency based technologies and products. They also state that the C12.19 standard does not always result in a longer message length or that the standard results in the use of more bandwidth. The joint parties contend that even if some meter manufacturer's message length increases slightly, that is a small price to pay for industry-wide interoperability.
The joint parties disagree with Itron's comment that the current C12.19 standard is flawed. The joint parties contend that the standard is complete, as witnessed by the fact that several manufacturers already have products for sale that incorporate the C12.19 standard. The joint parties state that the so-called "flaws" are in large part due to the changes that certain manufacturers have requested so that the standard can accommodate the needs of their existing protocols.
The joint parties also disagree with Itron's statement that the adoption of the C12.19 standard will stifle, not encourage competition, and that the standard will assist those firms who already have some aspects of C12.19 in their product. The joint parties contend that several firms have foreseen and actively participated in the development of standards, and may indeed benefit from marketing standard products. However, the joint parties assert that it is not a wise policy to penalize firms who had the foresight to invest their resources in the development of a standard that will benefit all consumers through competition and consequent price reductions.
The joint parties oppose the unlimited "grandfathering" of non-complying metering equipment because it will limit the options of customers if meter manufacturers decide to maintain and sell older equipment. Also, allowing non-complying meters to have an unlimited life seriously compromises the purpose of achieving a minimum level of interoperability. Furthermore, the grandfathering may result in consumers having to pay for the inefficiencies of inflexible and fundamentally obsolete equipment which will have to be later replaced at a consumer and societal cost. The joint parties recommend that the grandfather clause be limited to a maximum of two years.
2. Visual Display
The Workshop Report states that ABB and NERTEC do not believe that all meters should be required to have a local visual kWh display. They contend that the two reasons for having a local display, the customer's need to verify the bill, and the UDC's need for access, can be met by different technologies. For example, a customer with a solid state meter may prefer the convenience of having a display inside one's home or business, or being able to access the data on a computer rather than walking outside to read the meter. ABB and NERTEC contend that requiring the use of a local visual display will limit product innovation and impose additional costs on the consumer.
PG&E supports the majority recommendation that the meter must have a kWh display on the meter that is accessible to an on-site meter reader. PG&E contends that having a display on the meter provides the most basic level of interoperability because it gives all of the parties an opportunity to retrieve meter usage when other communication systems fail, and allows the customer to visually monitor usage. Without a visual meter display, PG&E asserts that it is more difficult to determine whether a meter is working or not. PG&E also contends that the visual meter display is consistent with bundled service, because UDCs currently require a digital kWh display for bundled customers.
PG&E is opposed to the proposal of ABB and NERTEC that customers be allowed to have a display in their home or business as a substitute for a display on the meter. PG&E contends that their proposal is unacceptable, and will destroy the basic level of interoperability provided by a visual display. In addition, PG&E asserts that the kind of technology favored by ABB and NERTEC has not been proven to be reliable or economic.
The CEC also agrees with the PSWG recommendation to require a visual display on the meter. The CEC, however, opposes the requirement that the display be limited to kWh. If the billing is based on determinant units other than kWh, the customer should be able to visually verify these determinants, and the standard should provide for this capability.
In Section V.4 of the Workshop Report at page 27, the need for "visual meter read requirements" was discussed. SCE contends that this should have read "back-up meter read requirements." SCE also contends that the wording was altered from the original text that was presented and approved at the PSWG plenary meeting on April 30, 1998. SCE asserts that the following is how the recommendation should have appeared:
"There are two reasons for requiring a meter display. (1) For consumer protection. The consumer can verify that the meter read matches the bill and (2) for on-site interrogation when another communications system fails. The PSWG agreed that the dials on an electromechanical meter are sufficient for these needs. An electronic meter shall display the total kwh energy consumption as minimum. Additionally, a meter must have a physical interface to enable on-site interrogation of all stored meter data." (SCE Comments, p. 3.)
SCE asserts that through this omission, the meaning of the recommendation was changed. A visual display allows back-up meter reading capability for only cumulative meters or peak demand. For meters that store data on an hourly basis or at 15-minute intervals, a physical interface must exist to allow on-site retrieval of the data. SCE recommends that the Commission adopt the original text, which SCE asserts accurately states the intent of the participants. SCE also recommends that "stored meter data" should be defined as more that 15 days of data.
3. Type 2 Optical Port
The Workshop Report states:
"The PSWG recommends that optical ports not be required. If a meter has an optical port that is physically identical to an ANSI Type 2 optical port, then the optical port shall meet all the requirements of ANSI C12.18. Other optical port types are exempt from this requirement." (Workshop Report, p. 12.)
SCE states that the above recommendation simply says that a C12.18 optical port shall meet the standards for a C12.18 optical port. As written, the PSWG recommendation would allow any type of optical port to be used. SCE contends that if some interoperability is to be achieved, then there should be a standard for the method of communication. SCE recommends rewording the PSWG recommendation to state: "If an optical port is used, it must be a Type 2 port and meet ANSI C12.18."
SCE also recommends that to meet the requirement of back-up meter read capability, and the objective of interoperability, a Type 2 optical port should be required for any meter that stores more than 15 days of data. SCE states that other communication ports would not be prohibited, provided the Type 2 port is also provided. Customers would benefit from this recommendation because any new ESP selected by the customer would be able to communicate with this kind of meter.
The joint parties state that the data communication standards for a Type 2 optical port, i.e., the data format, the application layer, data link layer and physical layer protocols, are necessary to ensure interoperability. That is why the joint parties believe that these four data communication standards should be selected for as many technologies as possible. These four layers would promote the interoperability of different hand-held devices that read information from meters made by different manufacturers.
4. Interface Standards
The Workshop Report at page 15 states: "The Meter Communications Subgroup agreed not to identify or recommend standards for every interface level (numbers 1 through 5 in Diagram B)." The joint parties contend that the decision not to identify standards for every interface level is the equivalent of agreeing not to develop a complete set of standards for meter reading. The joint parties contend that if true interoperability is to be achieved, all of the pieces of the system need to be linked through a defined set of standard interfaces, which is something the PSWG did not do.
The joint parties disagree with the following statement which appears at p. 15 of the Workshop Report:
"Interface (2) represents the data communications interface between the MDM/Meter Reading function and the Wide Area Network (WAN) System employed. The PSWG decided that it was not necessary to identify data communications standards for this interface. Since this interface is currently within a bundled function, PSWG did not explore any standards."
The joint parties contend that interface (2) is not a bundled function. They assert that a meter reader can interface the meter reading system to employ the Internet, the public switched telephone system, or many public packet data networks. The joint parties state that the interface is only bundled for the proprietary systems which have incorporated a wide area communications function into their product and service offerings. The joint parties contend that this bundled group of interfaces is actually several distinct interfaces. By not identifying a standard for the different interfaces, the joint parties contend that there will be no common link for these various interfaces.
The joint parties state that interface standards must be specified for every point at which it is desired to have interoperability. The AMRA standards committees are currently developing interface standards to address many of those interface standards. Significant effort is required by the manufacturers and standards groups to achieve a level of interoperability. The joint parties recommend that these efforts be monitored.
The joint parties also take issue with the PSWG's statements regarding the degree to which interchangeability is feasible. The joint parties argue that interchangeability of discrete components across technologies is feasible in many cases, such as using the Internet or public packet switching systems. The joint parties also assert that technology-specific interchangeability requires specifying a standard at every interface and is practical for many technologies at this time.
The joint parties also disagree with the PSWG's recommendation to define a level of interoperability at interface 3 of Diagram B, where the meter meets the communication connector. The joint parties contend that such a standard restricts customer choice by giving existing meter manufacturers a strong permanent position that excludes new meter manufacturers from entering the market. This occurs because the MDMA must have a complete set of all meter protocols in order to read all meters. New market entrants must convince all MDMAs to add another meter protocol to their library before the new meters can be marketed. In addition, it complicates adding new capabilities to meters because the meter protocols must be modified to support the new capability.
The joint parties state that the PSWG interpreted its mission to define a system that would facilitate the operating of an automatic meter reading (AMR) system. However, the PSWG ignored issues about linking the AMR system to other utility or customer systems. The joint parties contend that such an approach will lead to an AMR system that will be unable to communicate with any other automated utility system. The UCA framework is addressing these kinds of issues, and the joint parties recommend that these issues be considered in a future standards proceeding.
D. EDI Implementation
PG&E supports PSWG's recommendation that there be a migration to EDI. PG&E points out, however, that this change will require systems programming work. PG&E also points out that the cost of maintaining both the MEP and EDI will be a significant drain on programming resources. To minimize the costs of supporting two duplicative systems, PG&E requests that the Commission specify that all market players, i.e., UDCs, ESPs, and MDMAs, be required to move to an EDI protocol, and that the MEP system sunset within six months of EDI implementation.
The CEC supports the use of EDI for MDMA data exchanges, but opposes the requirement that the Internet be the sole communication mechanism. The CEC asserts that the specification of a single communication mechanism will restrict innovation, and the development of an improved communication system for the electric service marketplace. The CEC believes that the use of the Internet, or any other communication means, should be a business decision between the parties involved in the data transaction. The CEC also opposes the requirement for the use of hyper text transfer protocol (HTTP) as the only allowable protocol. The CEC contends that the use of HTTP, or any other communication protocol such as file transfer protocol (FTP), should also be a business decision between the parties involved in the data transaction.
SCE supports a migration from MEP to EDI, but voted against the PSWG recommendation because of concerns about implementing the recommendation without adequate planning and testing. SCE's specific concerns are:
· Stabilization of the business transactions. It is more efficient to migrate to a replacement which includes all the required fields and transactions, than to continually modify the EDI protocol to incorporate new information or transactions. When the unbundling of meters occurs for all customers in 1999, the MDMA transactions are likely to be impacted, and the EDI format should incorporate these additional requirements.
· Impact on resources. The resources needed for this effort require a trade-off of other system changes that are currently planned for 1998 and 1999, and affects both UDC and ESP resources.
· Internet Reliability. Currently, EDI is most often transmitted through a value added network for reliability reasons. MDMA transactions are time critical and must be reliable, and the potential impact of a delay or loss of information over the Internet needs to be evaluated. The reliability of transmitting large volumes of data over the Internet on a timely basis must be tested.
· Maintenance Costs. The costs of developing EDI transactions and the associated maintenance costs of security, disaster recovery, and outage activity must be factored into the evaluation of this change.
SCE recommends that the MEP-to-EDI transition team develop a project plan for the migration, and that the plan be published by June 1, 1999. The plan should review and comment on the areas of concern, detail a timeline for a transition to EDI, establish an EDI protocol, establish change control procedures, identify support resources, and address security and data integrity.
The joint parties encourage the Commission to ensure that a migration to EDI as the data exchange format takes place. The joint parties believe that the migration to EDI will establish specific standards which will allow for the effective electronic exchange of customer data. The joint parties also believe that the Commission should encourage parties who are involved in developing further standards for EDI and other communications to integrate their efforts, and to make future recommendations to the Commission as electronic commerce standards evolve.
E. Meter Data Management and Meter Reading
The Workshop Report recommends that the MDMAs be allowed to subcontract any of the activities for which they are approved. Although the CEC supports this proposal in principle, it opposes the recommendation at this time. The CEC is concerned that the proposal could result in a substantial change to the current metering and MDM regulatory framework, and could affect the accountability for data quality and integrity. Although the proposal states that the MDMA would retain full responsibility for the activities of its subcontractors, the proposal would allow a certified MDMA to divest itself of its staff and become a manager of subcontractors rather than a fully qualified provider. The CEC contends that such a result is not consistent with the way in which these functions were originally structured.
The CEC also states that the Workshop Report seems to assume that the meters will only measure kWh. The CEC believes that the billing determinants for competitive services should be negotiated business decisions between the suppliers and consumers. The CEC asserts that any standardization efforts for metering and data communications should accommodate billing determinants besides, or in addition to, kWh.
SCE supports the PSWG recommendation to allow an MDMA to subcontract functions that relate to meter reading. However, the PSWG recommendation needs to be clarified to state that the MDMA is still responsible for the performance of any work that is subcontracted, and that the subcontractors must demonstrate that they are capable of performing those functions.
SCE points out that it is a supporting member of the Joint Petition to Modify D.97-12-048, which was filed with the Commission on May 29, 1998. That petition recommends that an MDMA may subcontract functions to an MSP. SCE recommends that the Commission incorporate the recommendations from the Joint Petition with those from the PSWG report.
SCE states that it is agreeable to the MDMA performance exemptions in Section VI of Appendix C of the Workshop Report, but voted against the item because of a lack of specificity. SCE supports the recommendation that in the event of a large catastrophe, performance be reported separately and not counted against the MDMA.
SCE also supports the principle that data estimated due to meter failure be exempt, so long as the ESP and the MDMA have taken appropriate steps to remedy the situation. SCE recommends that the estimated data exemption only apply if two conditions exist: (1) the exemption should only occur after verification by manual reading that the meter has failed and there is no problem with the remote reading technology; and (2) the exemption cannot occur for an account more than once in a 12-month period. SCE asserts that these two conditions will prevent abuse of the exemption and create an incentive to replace or repair faulty meters.
F. VEE
Enron points out that the Workshop Report has identified two separate procedures to perform high/low range checks on monthly meter data. The first procedure that is recommended by the PSWG is to use a simple procedure for determining the appropriate high and low limits for validating data. This procedure sets the high limit to 200% of historical average daily usage (ADU) and sets the low limit to 40% of historical ADU. The current period ADU has to be within this range; otherwise, the meter reading must be estimated.
A second procedure, which Enron contends is more complicated and is used only by PG&E, utilizes valid data ranges based on the computation of the mean and standard deviation of the ADU using the previous day's ADU. This procedure attempts to take into account any abnormal usage patterns such as weather, geography, etc. Enron contends that this procedure requires a large set of data to define a reasonable statistical sample for the region and day in question. Enron argues that only the UDCs have sufficient information in a database to calculate the parameters needed for high/low validation. Also, the UDCs' statistical sample greatly exceeds the totality of data for all direct access customers, i.e., the UDCs have the advantage of using both direct access and bundled customers to form the validation database. Enron asserts that this procedure would place the ESPs who are MDMAs at a disadvantage.
Enron supports the adoption of a single, consistent standard for a high/low range check, and believes that the PG&E procedure is inconsistent with this objective.
PG&E's comments favor the adoption of the recommendation regarding the choice of using one of the two high/low meter data range checks for monthly meter VEE. PG&E points out that under the first procedure, any read that falls outside of this range would be re-read and estimated. MDMAs that use this method would be allowed to refine it based on optional trend factors that take into account peer group usage based on demographics, climatic areas, and customer class. The second of the two alternate methods uses PG&E's existing high/low range check method, which is a more refined and complicated procedure.
PG&E points outs that the VEE technical subcommittee that analyzed this issue, which included both Enron- and CellNet, unanimously recommended to the PSWG that the permanent VEE standards include PG&E's monthly procedures as an option for all market participants. When the recommendation was put to a vote, Enron voted against including the PG&E procedure in the VEE procedure. CellNet voted in favor of the recommendation during the vote, but then changed its position two days before the Workshop Report was filed.
PG&E contends that neither Enron nor CellNet have alleged that PG&E's method lacks validity or soundness. PG&E also points out that the PG&E method is an option, and the MDMAs are free to use the first method. If the MDMA chooses to use the first method, there will be no additional record-keeping burden on the MDMA or the ESP.
As for the claim that the two alternate methods may lead to different validation results, PG&E contends that such an argument applies to all of the validation processes for monthly data. Thus, the first high/low range check procedure can also lead to inconsistencies among the different MDMAs.
PG&E asserts that if the PG&E procedure is eliminated, such a result will not promote efficiency in the marketplace. PG&E contends that the adoption of a single, consistent standard will not give the MDMAs the flexibility to implement the best VEE routines for their customers. PG&E contends that its method does not disadvantage any market participant, and produces reasonable results. PG&E states that it makes no sense to have PG&E incur the cost of substantial changes to its meter reading and billing systems to implement the first procedure, when PG&E already has in place a perfectly acceptable alternative that is supported by virtually the entire PSWG.
Contrary to Enron's contention that the validation is performed in the hand held devices used by PG&E's meter readers, PG&E asserts that it is PG&E's billing system which passes the range checks to the hand held system. PG&E contends that its hand held system does not keep historical usage history, and therefore the validations cannot be performed by simply using the hand held devices.
G. Meter Worker Qualifications
The CCUE supports the recommendation to adopt the meter worker qualifications that are detailed in Section I of Appendix D of the Workshop Report. CCUE points out that although the standards are substantially different from current utility requirements, they are sensitive to the needs of the marketplace for flexibility, and the standards reasonably protect safety.
SCE supports the meter worker classes and supports a certification process for meter workers. SCE believes, however, that the PSWG recommendation fails to include input from the UDCs and MSPs. SCE proposes that an advisory board consisting of UDC and MSP representation be responsible for the review of training materials for meter worker certification, and that the board design and perform the practical tests for meter worker classes 4 and 5. SCE contends that its proposal offers the advantage that experts in the metering industry will be involved in the review process, and that the process will promote consistency. SCE proposes that the following be added to the PSWG recommendation:
"The Meter Certification Advisory Board
The Meter Certification Advisory Board (MCAB) is granted authorization by the CPUC to administer the authorization process of MSPs' training programs and the certification of Meter Class 4-5 workers. The board has independent decision making ability over the safety of meter installations, however, certain issues will require CPUC approval.
I. Responsibilities of the Meter Certification Advisory Board
1. Reviewing the qualifications and training materials of MSP to perform training of meter worker classes 1-3. Once a MSP receives authorization from the MCAB it can issue individual Meter Worker Classes 1-3 certifications.
2. Develop and administer the exam process for Meter Worker Classes 4-5 and determine the process for maintaining certification.
II. Administration of Responsibilities7
The responsibilities of the MCAB could be performed by hiring a consultant. The MCAB will provide guidance to the consultant to implement the board's responsibilities. If a contract is needed, the board will present it to the CPUC for approval. The cost recovery of the contract would be from fees from MSPs and exam fees.
III. Appeal and Dispute Process
The CPUC is responsible to resolve any dispute or claim that the MCAB decision were [sic] inappropriate or unfair.
IV Membership of the Meter Certification Advisory Board
The board consists of highly qualified persons experienced in the electrical metering field. It is necessary that these persons are considered experts to administer the standards of safe and accurate meter installation. Because metering is connected to the electric distribution facilities, representation from the UDCs is required on the MCAB. The MCAB has an equal number of MSP representatives, which are selected by a voting process from MSPs. A chair will be appointed by the CPUC." (Workshop Report, pp. 37-38.)
The CEC points out that the PSWG proposes that the MWCO be created, while SCE prefers that the MCAB be created. The CEC states that both of these proposals recognize the need for a collaborative oversight of selected aspects of the MSP functions. However, the CEC asserts that the proposals are not comprehensive enough to address how MSP and MDMA functions will be overseen.
The CEC believes that the marketplace needs a workable approach to qualification and oversight of the MSP and MDMA functions for the long term. The CEC contends that the recommendations are not appropriate beyond the near term. If the functions are truly going to be competitive, the oversight approach should treat UDCs and UDC affiliates the same as it treats non-UDC providers. Also, the DQIWG suggests the need for the ongoing recertification of these entities, scheduled performance audits, and regular performance monitoring reports. The CEC also states that a majority of the PSWG participants favor a proposal to further unbundle the MDM function, and allow firms to be certified to perform any subset of MDM activities.
The CEC believes that the Commission should start a process to develop permanent arrangements to qualify and oversee providers of metering and MDM services as soon as possible. In the area of oversight, the CEC believes the Commission should explore the feasibility of establishing direct authority over the MSPs and the MDMAs, either by the Commission or by another government agency. The CEC believes that these functions should be overseen by an appropriate authority.
H. Meter Installation
The IAEI commented that the definition of "meter" has not been determined. IAEI point out that if the utilities continue to own, operate, and maintain metering transformers as part of their distribution facilities under their exclusive control, the metering transformers will not be covered by the National Electrical Code (NEC). If customers own, operate, and maintain metering transformers as part of the meter installation, the installation will be covered by the NEC. If the NEC applies to customer-owned metering transformers, the following would have to occur:
1. All wiring and equipment that is installed shall be listed and labeled. This process could take six to twelve months or longer and may result in equipment cost increases.
2. The NEC would require that the transformer be sized based on the connected load that is served, which would result in an increase in the cost of the customer's metering installation. Currently, the utilities size current transformers based on the demand load.
3. If customers are responsible for the installation of metering transformers and auxiliary equipment, the NEC would require such installations to be inspected by the authorities having jurisdiction. This would require additional staffing and training of inspectors, which may increase permit fees that would be passed on to the customer. At the present time, the authorities having jurisdiction are not required to inspect metering transformers and auxiliary equipment installed by a utility because the installation is not covered by the NEC.
The IAEI supports the installation and maintenance of all secondary wiring, including metering transformers, meter loop wiring, test switches and phasing transformers, by the utility.
I. Future Of The PSWG
EPRI's comments about the future work of the PSWG are contained in the Workshop Report. EPRI states that the process proposed by the PSWG is inconsistent with the direction in D.97-12-048 at p. 48 which stated that: "The PSWG should also indicate whether other standards are expected in the future, and recommend a process for reviewing possible future changes to the permanent standards."
EPRI points out that there was insufficient time during the PSWG deliberations to thoroughly identify the technical requirements, and to review meter and data communication standards. EPRI notes that several meter and data communication standards will be approved by national organizations over the next several months. Once these new standards are adopted, the standards will ensure interoperability of diverse meeting and communications systems in California.
EPRI contends that as a result of the failure of the PSWG to specify key data communication standards, proprietary standards will be used at key interfaces. The use of proprietary standards will create barriers to the development of innovative products and services that other vendors could provide. That is because these vendors will need to build their products to conform to multiple proprietary data communication standards, which will increase costs and foster a fragmented, and less vibrant marketplace. In addition, if the ESPs procure products and services that utilize proprietary standards, the customers of those ESPs will tend to be "locked in" to those products or services because of incompatible metering and data communication standards.
In order to resolve this problem, EPRI recommends that a voluntary group of participants be formed to continue to address these kinds of interoperability standards. Ideally, this group would be made up of the entities which participated in the PSWG process. EPRI recommends that this group be charged with the following:
1. Identify new or changed technical requirements which impact the meter and data communication standards, and assess the impact of these changes on the installed systems or systems to be installed.
2. Identify and assess for possible implementation, new meter and data communication standards that are published or that are up for final approval from the principal national or international standard committees.
3. Prepare recommendations to appropriate standard bodies to enhance existing standards or develop new standards.
4. Prepare recommendations to the Commission for the adoption of new standards when a consensus has been reached that the new standard would foster a vibrant marketplace, or be of benefit to market participants and customers.
5. Work with entities in other states that are actively engaged in the direct access of electricity to support the adoption of national and international metering, data format, and data communication standards. Particular attention should be paid to addressing security and the adoption of security architecture.
The joint parties' comments reflect the same views as EPRI's comments. The joint parties recommend that EPRI's suggestion to form a voluntary group of participants be adopted.
6 According to the comments of the joint parties, the UCA was developed by EPRI, and is supported by the Gas Research Institute.
7 This subject heading was deleted from the Workshop Report.
