5. Remaining Scoping Issues
Certain parties request that this proceeding be expanded to include gas metering infrastructure issues. PG&E favors this expansion on the basis that advanced metering is more likely to be cost effective when deployment is structured to capture customer, societal, and utility savings benefits. PG&E believes that reductions in overall electricity and natural gas metering reading costs cannot occur unless both electric and natural cost meters are read remotely. CCE agrees with PG&E. SDG&E initially expressed concern about including this issue in a proceeding whose schedule is already ambitious, but does agree that there are savings from avoiding reading gas meters if some sort of advanced meter reading capability is already in place (WS-1RT 89:1-9).9 Thus the initial divergence of opinion on whether to include gas metering infrastructure issues no longer exists and no other party has expressed opposition to expanding the proceeding in this limited way. CUE notes that displacing manual meter reading may require alternative methods for routine inspection of the distribution system to spot trouble.
In the interests of preserving options, not foreclosing them, we believe that Working Groups 2 and 3 should analyze the issue of installation of metering systems with dual-fuel reading capabilities, and should also quantify the potential costs/benefits of including metering systems capable of reading and communicating both electricity and natural gas usage to the distribution utility compared to electric-only metering systems. This effort is confined to the dual-fuel respondent utilities, and is limited as stated above. We do not intend to develop dynamic gas tariffs, nor delve into any broad-ranging review of the natural gas market in this proceeding. (See, WS-1 RT 92:18-18.) We invite comment from any party who disagrees with this outcome.
A second scoping issue relates to the inclusion of direct access customer issues in this proceeding. Direct access customers, who are equipped with interval meters, currently constitute 14% of total IOU load, and 36% of the IOU industrial class (greater than 500 kW). As such they are a significant potential source of demand response resources.10
However direct access customer inclusion presents many complexities for policymakers. For example, these customers' energy charge is set by an Energy Service Provider (ESP), not by the CPUC, raising the specter of melding disparate billing and pricing mechanisms. Some suggest that ESPs could develop their own demand response programs, or participate in IOUs' demand response programs if billing and pricing issues are resolved. Major contract negotiation may be one possible outcome (WS-1 RT 97:15-98:12). The questions are many and multi-faceted, and the answers remain elusive at this point, but the opportunities appear to be great. Balancing these factors, the staff supporting the policy group favors including direct access customers in the demand response rulemaking.11 This will require that we consider whether direct access customers have the same metering and communication infrastructure as bundled customers, as well as their ability to participate in demand reduction programs where permissible under ESP contracts. WG2 and WG3 should consider how direct access customers would be affected by the development of bundled service dynamic tariffs, and whether we should consider the interaction of dynamic tariff or emergency requirements on ESP product offerings.
9 The staff supporting the policy working group prepared and presented a list of "Pros and Cons" relative to the issue of installing meters with dual fuel reading capabilities. This document is attached to this ruling as Item 9.
10 See Item 10, "Direct Access and Demand Response OIR. Working Group Meeting - August 26, 2002."
11 See CPUC Energy Division staff recommendation, Item 10. CPA staff also believes that inclusion of these customers is the best way to ensure a statewide solution (WS-1 RT 100:2- 5).
