8. Rate Design - Agricultural Customers

8.1. Agricultural Customer Access to Information

CFBF and AECA identify the need for the availability of adequate interval data to agricultural customers before such customers default or make decisions about PDP. Both want agricultural customers to default to the new rates only after they have had comprehensive access to meaningful interval data for at least 12 months. In addition, AECA urges that such information be made available in one downloadable aggregated format for multiple meters, before requiring a migration to default dynamic rates or mandatory TOU rates. CFBF requests that after the 12 months of information is available, there should be four months before the customer must make a decision. In addition, CFBF states that farmers should not be required to decide these important issues during planting, growing or harvesting seasons (approximately April through October).

CFBF also has proposed that agricultural customers receive 12 months of bill analysis or "shadow bills," which would show, for the same usage as the current bill, the bill expected under the relevant dynamic pricing option. CFBF proposes that this information also be available at least an additional four months on top of the proposed 12 months before the customer must make a decision.

PG&E agrees with the general principle that customers need access to interval usage information, but takes issue with the agricultural intervenors' specific proposal for access to 12 months of interval data. According to PG&E, the only agricultural customer class subject to default PDP is the large customer class; and approximately 700 of these customers currently have or can have access to interval data via the InterAct tool on PG&E's website. Also, on average, customers receiving SmartMeters are getting access to interval usage data within 30 days of meter installation. Thus, customers will have sufficient data to make informed decision and there is no need to depart from PG&E's proposal to use the one-year anniversary of SmartMeter installation to determine when the customer becomes subject to default PDP. In addition, PG&E argues that starting the 12-month clock based on AMI interval data availability would have a major negative impact on cost and schedule for PDP.

With respect to AECA's multiple meter request, PG&E states that its proposed customer service on-line (CSOL) changes in this proceeding will make data for multiple accounts accessible and downloadable with a single login, and the request is unnecessary and will adversely affect cost and schedule.

With respect to "shadow bills," PG&E objects to this request because it will be providing tools on CSOL that customers can use to run their own bill analyses. Unlike the CSOL tools, hard copy shadow bills would not enable the customer to do "what if" analyses, to test what happens with various changes in its energy demands under different rates and scenarios. PG&E asserts that the CSOL tools will be superior to "shadow bills" for that reason. PG&E also notes that CFBF's "shadow bill" proposal would add significant costs and delay to PDP implementation.

8.1.1. Discussion

Under PG&E's proposal that the choice should be made 12 months after the meter is installed, it appears that most affected customers would have to make a choice with respect to opting out of the PDP program while having only 10 or 11 full months of interval data. Depending on which months are missing, full bill analyses with respect to when PDP rates would apply may be difficult or not possible. The consequence of such limitations may well be that customers would choose to opt out of the program rather than assume an unknown risk. As a general matter, we feel it is appropriate and reasonable that a customer have access to 12 months of interval data before having to make a choice. However, we see this as a problem more for the smaller customers than for the larger customers.

The first default date for PDP is May 1, 2010 and affects large C&I customers. Such customers already have access to 12 months of billing quality interval data on which to make a decision regarding PDP rates. Additionally, these customers will have the benefit of direct contact and interaction with a customer service representative to aid in this process. There may well be some newer customers who will have to either make a choice with respect to, or be defaulted onto, PDP rates with only 10 or 11 months of interval data. Depending on which months are missing, bill analyses with respect to the time period when PDP rates would apply may be difficult. In such situations, we expect that PG&E's customer representatives would be able to provide the necessary assistance in order to overcome this obstacle to customers' full understanding of their situations and options.

For the February 1, 2011 and November 1, 2011 effective default dates, large agricultural and medium and small C&I customers will face default to PDP and small agricultural customers will face default to mandatory TOU. Having 12 months of interval data available before requiring choices related to these defaults is much more important than for large C&I customers. While large agricultural customers already have interval meters, most medium and small C&I and small agricultural customers will be subject to time varying rates for the first time. For these customers, access to the full 12 months of interval data prior to making default choices is the most critical. The lack of such information can be problematical with respect to fully understanding their situations and options with respect to PDP. As indicated previously, if certain historic usage during PDP periods is not available, the effect of PDP rates and the need to change usage patterns may not be fully understood, and customers may simply choose to opt out of PDP to reduce high bill risks. While there will be customer outreach and education as well as the opportunity to contact customer representatives, the type of assistance afforded to all large customers through direct customer representative contact will not be the norm for the smaller customers. The least we can do is ensure that customers subject to the February 1, 2011 default date have 12 months of interval data before being subject to that process. Therefore, with respect to the February 1, 2011 and November 1, 2011 effective default dates, PG&E shall not default any affected customers to PDP/TOU rates until it is able to provide access to 12 months of recorded interval data at least 45 days prior to the default date.

We do not agree that agricultural customers require an additional four months to make their decision regarding PDP/TOU defaults and options. There is no convincing evidence to support the proposition that in this respect they require more time than those in the other affected customer classes who will have 45 days to make their decisions. Likewise, we will not require that farmers be allowed to defer their decisions during planting, growing, and harvesting seasons.

With respect to AECA's request regarding the availability of information in one downloadable aggregated format for multiple meters, PG&E does not object to the request because of the need for such information, but asserts that its proposed CSOL functionality will address AECA's concern. We agree with PG&E, and, as discussed later in this decision, note that the PG&E proposal to implement such CSOL functionality is approved. We therefore expect that the CSOL feature to aggregate information will be available to the large agricultural customers before they are subject to being defaulted to PDP. PG&E should not default such customers with multiple accounts to PDP until this feature is available.

Likewise, with respect to CFBF's "shadow bill" proposal, PG&E objects to the proposal but does not object to the need for such bill analysis. PG&E argues that its proposal for enhanced CSOL functionality will provide such analysis as well as analyses using varying scenarios. Again, we agree with PG&E, and, as discussed later in this decision, note that the PG&E proposal to implement such CSOL functionality is approved. Again, we expect that this feature will be available to agricultural customers before they are subject to being defaulted to PDP. We also note that this CSOL feature to calculate bills under varying scenarios is very important and necessary not only for agricultural customers, but for all customers, to evaluate the effects of PDP and make appropriate choices. PG&E should not default any customers subject to the February 1, 2011 and November 1, 2011 effective dates for defaulting to PDP until this feature is available at least 45 days prior to their default dates.

8.2. Other Agricultural Customer Issues

In this proceeding, AECA recommended an alternative dynamic pricing scheme similar to an SCE rate that provides a table of TOU prices on a year-ahead basis, which is adjusted for weather. AECA states it would offer significantly more flexibility and would encourage voluntary participation within the agricultural class.

PG&E opposes this recommendation indicating that it is impractical. PG&E alleges that AECA mischaracterized the SCE proposal, the SCE proposal is being discontinued, AECA's proposal would have large cost and schedule impacts, and it would needlessly complicate customers' choices.

AECA also states that SmartMeter installation and the emergence of dynamic pricing create the opportunity to virtually master meter farm operations' multiple accounts in ways that could fundamentally transform agricultural energy management practices, providing significant system benefits. AECA recommends that the Commission develop programs that enable growers to virtually aggregate multiple meters.

PG&E states that the proposal is moot, because, in effect, agricultural customers will receive the benefit of virtual master metering through the PDP rate design. PG&E adds that to the extent that AECA wants virtual master metering for purposes other than PDP, the issue belongs in the rate design phase of a GRC.

In its opening brief, AECA states that both of its proposals require significant study and analysis and, given the limited scope of the rate design window, concedes that consideration of such topics is likely better determined in PG&E's next GRC. AECA now requests that the Commission order PG&E to raise both issues in their next GRC for consideration.

In its reply brief, PG&E renewed its objections to the proposals and indicated that while parties are free to raise such issues in the rate design phase of GRCs, PG&E should not be required to do so.

8.2.1. Discussion

Since AECA is withdrawing consideration of both proposals in this proceeding, we will not rule on the merits of the proposals at this time. Also, we note PG&E's responsive testimony and objections and we will not require PG&E to raise either issue in its next or future Phase 2 GRC proceedings. However, at such times, parties are free to raise and support such issues on their own.

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