4. What Rates Should PG&E Offer Each Customer Class and When?

This section answers the first two questions posed in the Supplemental Scoping Memo:

· What types of dynamic pricing tariffs should PG&E offer to its customers, and

· When should PG&E offer each type of dynamic pricing rate to each customer class?

This decision does not itself adopt any rates and does not commit the Commission to approve specific rates. Instead, this decision establishes dates when PG&E will be required to propose specified rates. We refer to these dates as the timetable. In the proceedings in which the Commission considers PG&E's specific rate proposals, the Commission could decide to adopt different rates or a different timetable based on the information presented to the Commission at that time.

Attachment B includes an illustrative timetable that summarizes PG&E's customers' rate options if the Commission adopts the rates that PG&E is required to propose pursuant to this decision.¹⁵

4.1. Dates of PG&E Filings

PG&E recommended that the timetable should adhere to the existing GRC Phase 2 and Rate Design Window process.¹⁶ In D.07-03-044, the Commission adopted a settlement that shifted PG&E's next GRC by one year, so PG&E will file its GRC Phase 2 in March 2010, and the rates will have an effective date of January 1, 2011. According to the Rate Design Window process adopted for PG&E in D.89-01-040, PG&E files rate design revisions on November 25^th of a particular year and the new rates are supposed to become effective on May 1^st of the following year. In summary, PG&E's GRC Phase 2 and Rate Design Windows are subject to the following schedule from 2008 to 2012:

Filing Date	Effective Date of Rates
November 25, 2008	May 1, 2009
November 25, 2009	May 1, 2010
March 1, 2010	January 1, 2011
November 25, 2011	May 1, 2012

The filing schedule adopted in the following sections adheres in part to this schedule. However, based on comments, some filing dates have been delayed to allow more time for PG&E to prepare filings. For instance, the filing date of the 2008 Rate Design Window will be delayed from November 25, 2008 to February 28, 2009. Furthermore, the effective dates of some rates have been delayed to allow more time for PG&E to conduct customer education and make necessary system upgrades following adoption of the rates by the Commission.

4.2. Large C&I

Large C&I¹⁷ customers with maximum load greater than 500 kW have been on mandatory TOU rates since the late 1970's or early 1980's, depending on the size of the customer.¹⁸ In 2001, the California legislature appropriated $35 million to be used by the CEC "to provide time-of-use or real time meters for customers whose usage is greater than 200 kilowatt."¹⁹ The interval meters installed under the CEC's program can support CPP and RTP in addition to TOU rates. In a related decision, the Commission required mandatory TOU rates for all customers with maximum demand greater than 200 kW who received new meters via the CEC's funding.²⁰

Large C&I customers also have the option to sign up for a voluntary CPP rate. Non-time-variant rates and RTP are not currently available to large C&I customers. A number of demand response programs are available to these customers as well.

As a result of these past policies, the vast majority of large C&I customers have been on TOU for over five years, and some have been on TOU for as long as 30 years.

PG&E's customers in this category are generally on Schedule E-20 (for customers with maximum demand 1,000 kW and greater), Schedule E-19 (for customers with maximum demand between 500 kW and 1,000 kW), and Schedule A-10 TOU (for customers with maximum demand between 200 kW and 500 kW). ²¹

4.2.1. What Dynamic Pricing Rates Should PG&E Offer Large C&I Customers?

Parties' Comments

BOMA does not support CPP as a default rate. BOMA argues that CPP is not a truly dynamic rate since the critical peak rate is triggered administratively by the utility based on pre-determined conditions, and the periods when events are called by the utility will only reflect real-time marginal system costs by chance. BOMA believes RTP is the best rate to promote economic efficiency and rate equity. Thus, BOMA supports the prospect of RTP becoming the default rate.²²

CLECA believes that CPP is a viable rate option for some customers and should be available to large C&I customers on a voluntary basis. CLECA notes that some large customers are already on CPP and have achieved significant usage reductions by also using Auto DR enabling technologies.²³ CLECA believes RTP should be available on an optional basis.²⁴

EPUC argues that large customers have relatively flat load profiles, suggesting these customers have little ability to reduce or shift load. Therefore, EPUC concludes that a mandatory CPP rate would be punitive and would not result in meaningful load reductions. EPUC is also concerned that the month-to-month bill volatility associated with CPP is not appropriate for a default rate.²⁵

SDG&E supports exploring RTP as a rate option, but believes it is premature to implement until MRTU is implemented and well understood. In the interim, SDG&E supports continued implementation of CPP as a default rate for large and medium C&I customers. SDG&E further recommends the Commission adopt default dynamic pricing for each of the utility's customer classes. SDG&E explains that "[d]ynamic rates should be designed in such a fashion where a particular price signal can be provided to the customer with little or no transactions cost and that the information content embedded in such a price signal achieves corresponding behavioral actions that allow customers to manage their energy usage and resulting energy bills."²⁶

Discussion

We believe RTP should be developed and made available for large C&I customers as soon as feasible. Large C&I customers already have considerable experience with TOU rates. Thus, we expect that, offered an opportunity to enroll in RTP, many large C&I customers will find new ways to deploy enabling technologies and manage their energy costs, which will benefit the customers and the efficiency of the overall market. Therefore, once MRTU becomes operational we expect the utilities to promptly develop RTP as required by D.05-11-009. We agree with BOMA that RTP is the best rate to promote economic efficiency and equity between customers.

In the interim, we agree with SDG&E that default CPP is appropriate for large C&I customers. We support default CPP because it more closely aligns the retail rate with the wholesale market, and it can give customers an opportunity to manage their usage and lower their bills.

We disagree with EPUC that default CPP is punitive. As CLECA has pointed out, many customers that have enrolled in CPP on a voluntary basis have been able to significantly reduce their usage during critical peak events, especially with the help of enabling technologies. We expect many more customers will be able to reduce their bills by doing the same.

BOMA raises another criticism of CPP by arguing that CPP is not actually a form of dynamic pricing since so many of the parameters of the rate are administratively determined. We disagree with BOMA. Although the CPP price and the calling of events are not entirely market based, the CPP price and events can be good market proxies if the rate is designed well and called appropriately by the utility. In fact, one of the reasons the Commission has been pursuing CPP is that true market-based dynamic pricing that is tied to day-ahead energy prices cannot be developed until the day-ahead wholesale market is operational. In some respects, CPP is a second-best rate option until RTP can be developed and implemented. The Commission supports BOMA's desire to move to RTP as reflected in the timetable we adopt below, but we continue to believe, consistent with the Commission's determination in D.06-05-038, that CPP should be the default rate for large C&I customers.

4.2.2. When Should PG&E Introduce Dynamic Pricing to Large C&I Customers?

According to the draft timetable in the January 23, 2008 Ruling, PG&E would propose that in 2010, its large C&I customers would have to choose either TOU/CPP or RTP.²⁷ Starting in 2011, RTP would become the default rate. TOU and TOU/CPP would continue to be available as optional rates. The draft timetable also proposed that PG&E would file revisions to its existing CPP rate in 2008 with an effective date in 2009.

Parties' Comments

PG&E claims that metering and billing system constraints prevent moving all large C&I customers to CPP or RTP until 2011. Of PG&E's approximately 9,000 large C&I customers, about 5,500 are billed through PG&E's primary billing system, the Customer Care & Billing (CC&B) system. The CC&B system cannot directly accept interval metering data and does not support CPP and RTP. The remaining large customers, including customers who are generally on CPP and other more complex rates, are on a different billing system - the Advanced Billing System (ABS).

PG&E is upgrading the CC&B system to bill new rates including CPP as part of the AMI project. PG&E is also planning to replace large customers' interval meters with new AMI meters. The CC&B upgrade and meter upgrade will enable PG&E to bill large customers on CPP. However, PG&E does not plan to upgrade the system for large C&I customers until the end of the AMI roll-out in 2011. PG&E explains that to implement default CPP or RTP before 2011, the 5,500 large customers currently being billed on its primary CC&B system would have to be temporarily moved to the ABS billing system until they can be moved to the upgraded CC&B system in 2011 or 2012. This will be complicated and cost approximately $30 million according to PG&E's initial rough estimates.^{28 29}

PG&E offers several reasons related to MRTU why RTP in particular cannot be implemented in 2010. First, PG&E cites the delay of MRTU start-up. The CAISO has indicated that the MRTU launch will be in the fall of 2008. PG&E wants to allow the MRTU market to stabilize over two full summers before filing an RTP rate, followed by one year for customer education. According to PG&E's preferred schedule, RTP would be available to customers in 2012.

Second, PG&E is concerned that MRTU will continue to change after its start-up. PG&E notes that MRTU Release 1A,³⁰ including Scarcity Pricing, will be implemented one year after MRTU start-up. Also, the wholesale price cap will be raised to $1,000/MWh in 2010 or later. Third, PG&E notes that the communications network to deliver day-ahead prices to investor owned utilities (IOUs) and retail customers needs to be developed and installed. PG&E says this issue should be addressed by the CAISO DR Infrastructure working group.

PG&E raises other more general concerns related to the timeline. PG&E argues that the relationship between dynamic pricing and demand response programs is complicated, so new dynamic pricing should wait until the 2009 to 2011 demand response program cycle is complete. PG&E also points to the Commission's resource adequacy proceeding, R.05-12-013, where the Commission will decide whether or not to implement a centralized capacity market, which could in part determine if energy prices are volatile. PG&E argues that the dynamic pricing decision should follow the resource adequacy decision.

Given these concerns, PG&E recommends implementing default CPP for large C&I customers in 2011, delaying RTP until 2012, and keeping RTP as an optional rate.

CLECA believes 12 to 18 months of data from the new MRTU day-ahead market will be needed so that parties can be confident that the market is fully functional. Therefore, CLECA expects that 2011 is the soonest RTP could be implemented.³¹ CMTA and EPUC echo CLECA's timing concerns. CMTA additionally emphasizes that customers need real-time access to their usage information, which will also require some time.³² EPUC suggests that CPP should be the default rate in 2010 given the delay in MRTU development.³³

Discussion

We disagree with PG&E's conclusion that billing system and metering limitations require delaying default CPP and RTP until 2011 or 2012. Instead, we conclude PG&E should revise its AMI plans to support default CPP for large C&I customers in 2010 and optional RTP in 2011.

The decision approving PG&E's AMI project, D.06-07-027, does not mention PG&E's plans or timeline to upgrade its large customers' meters and billing system. The constraints identified by PG&E appear to be related to the utility's internal planning rather than any explicit Commission direction.

The Commission directed the utilities to propose AMI projects primarily because AMI enables greater demand response through dynamic pricing and demand response programs.³⁴ PG&E, however, argues that its AMI project is an impediment to dynamic pricing. This is inconsistent with the Commission's policy objectives. Therefore, we will require PG&E to realign its internal AMI plans with the Commission's policy objectives.

We will require PG&E to make adjustments to its AMI deployment plan so that large C&I customers have the metering and billing systems in place to support default CPP in 2010 and optional RTP in 2011. Meeting these requirements would likely require PG&E to upgrade large C&I customers' meters more quickly and require an earlier upgrade of the CC&B system. PG&E should develop a plan that avoids moving customers back and forth between the CC&B and ABS systems unnecessarily.

To the extent PG&E believes it needs additional authorizations from the Commission to modify its AMI deployment plan, PG&E should request such authorizations in its AMI upgrade application, A.07-12-009. Also, if PG&E believes it needs authorization to spend more money to modify the schedule, PG&E should make a request in A.07-12-009 and provide the necessary justification. If the utility needs to incur incremental costs prior to a Commission decision in A.07-12-009, PG&E may record its incremental costs in a memorandum account and seek recovery in A.07-12-009.

We agree with PG&E that the delay in the on-line date of MRTU requires a delay in the development and implementation of RTP. We also agree with PG&E and other parties that we need some experience with MRTU before implementing RTP. However, we disagree that two full summers of experience are needed with MRTU before even beginning to develop RTP. Instead it is reasonable for PG&E to propose an RTP rate after one summer of experience, as part of the 2011 GRC Phase 2 filed in March 2010. The effective date of the RTP rate, if approved by the Commission, should be prior to the summer of 2011. That would allow two full summers of experience (2009 and 2010) before implementation of RTP. PG&E could conduct a customer education campaign during the latter part of 2010 and the first part of 2011.

PG&E also argues that dynamic pricing needs to be delayed due to the eventual implementation of the CAISO's MAP, the future lifting of the wholesale energy price cap, the 2009 to 2011 Demand Response programs, and the Commission's pending decision on capacity markets. We disagree with PG&E's conclusion. The wholesale and retail energy markets will continue to evolve, and PG&E's dynamic pricing rates may need to evolve as well. We believe it is more prudent to direct PG&E to proceed with dynamic pricing on a date certain with the expectation that dynamic pricing may need to be modified over time.

PG&E also raised the concern that the communications network to deliver day-ahead prices to IOUs and retail customers needs to be developed and installed. We agree that this important issue needs to be addressed. We are confident that PG&E can work with other stakeholders to provide a solution by 2011. We direct PG&E to continue working with the CAISO's DR Infrastructure working group and with stakeholders in other forums so that the necessary communications infrastructure is in place by 2011. We will also require PG&E to develop a timeline that shows what steps PG&E will take to make sure that all the necessary systems are in place to support RTP in 2011. PG&E should include the timeline in its 2011 GRC Phase 2 application.

The draft timetable in the January 23, 2008 Ruling proposed that large C&I customers would have a choice between CPP and RTP in 2010. However, since RTP needs to be delayed until 2011, we conclude that PG&E should propose to make CPP the default rate in 2010. RTP could subsequently become the default rate; however, we do not believe customers should be moved between rates too frequently, so we believe that RTP should remain an optional rate.

Past Commission decisions affirm the reasonableness of the timeline we adopt here. In D.06-05-038, the Commission declined to adopt proposed settlements that would have adopted voluntary critical peak pricing tariffs for PG&E, SCE, and SDG&E that would have been available to bundled customers with peak demands greater than or equal to 200 kW. The Commission directed the utilities to incorporate default critical peak pricing tariffs for large customers into their next comprehensive rate design proceeding or other proceeding as directed by the Commission.

PG&E had already filed its 2007 GRC Phase 2 at the time of D.06-05-038, and according to the standard three-year GRC cycle, PG&E's next GRC would have been its 2010 GRC. Although the Commission approved a settlement in D.07-03-044 that delayed PG&E's next GRC until 2011, requiring PG&E to propose a default CPP rate that would be effective in 2010 is consistent with the timetable the Commission approved in D.06-05-038 since PG&E's next GRC had been expected in 2010.

Also, in D.05-11-009 the Commission directed each utility to submit RTP tariffs in its comprehensive rate design proceeding following the CAISO's implementation of its MRTU.³⁵ Requiring PG&E to file an optional RTP rate as part of its 2011 GRC Phase 2 is clearly consistent with prior Commission direction.

We will not require PG&E to file an application to revise its optional large customer CPP rate 30 days after the adoption of this decision as proposed in the January 23, 2008 Ruling. Instead, when PG&E files its proposal for default CPP rates, PG&E should revise its rates to be consistent with the rate design guidance adopted in this decision. We believe having PG&E propose revisions to the large customer CPP rate and propose default CPP for large C&I customers in the same application is a more efficient use of the Commission's and parties' resources.

In summary, we will require PG&E to file a proposal for a default TOU/CPP rate for large C&I customers as part of its 2008 Rate Design Window with an effective date on or before May 1, 2010. The rate must be consistent with the rate design guidance adopted in this decision. As indicated previously, the filing date of the 2008 Rate Design Window will be delayed from November 25, 2008 to February 28, 2009 to provide PG&E additional time to prepare its filing. We believe this timeline will allow sufficient time for a Commission decision and customer education. PG&E should submit a proposal for an optional RTP rate as part of its 2011 GRC Phase 2 in March 2010. The effective date of the proposed RTP rate should be on or before May 1, 2011.

4.3. Medium C&I

The January 23, 2008 Ruling grouped together all small and medium C&I customers with maximum demand less than 200 kW for the purposes of the draft timetable. PG&E recommended subdividing this group into two groups: those with maximum demand between 20 kW and 200 kW, referred to here as medium C&I³⁶, and those with maximum demand below 20 kW, referred to here as small commercial. We have adopted PG&E's proposed divisions in this decision.

Medium C&I customers are not required to be on TOU rates, and most are not. Medium C&I customers will be receiving AMI meters as part of PG&E's AMI initiative.

The January 23, 2008 Ruling proposed that PG&E would make rate proposals that could result in CPP becoming the default rate starting in 2010 for medium C&I customers that have AMI meters. Customers would have the option to switch to TOU, but a flat rate would no longer be an option. RTP would become available on an optional basis beginning in 2011.

Parties' Comments

PG&E recommends making TOU the default rate for this customer class rather than TOU/CPP. CPP would remain as an optional rate. RTP would be introduced as an optional rate in 2012. PG&E's proposal does not specify whether a non-time-differentiated rate would remain an option.³⁷

PG&E also argues that a customer should be allowed 18 months of experience with an AMI meter before moving to a new time-differentiated default rate. They also argue for 12 months after tariff approval for customer outreach-four months to prepare materials and eight months for customer outreach.³⁸ According to PG&E's proposal, the utility would file default TOU in November 2008, a Commission decision would come in December 2009, customer outreach would occur in 2010, and the rate would be effective on January 1, 2011.³⁹

Discussion

We disagree with PG&E that TOU should be the default rate. The Commission's policy is to implement dynamic pricing for all customers, and TOU is not dynamic pricing because the rate does not change based on day-ahead or real-time market or system conditions. Therefore, the timetable we adopt here requires PG&E to propose TOU/CPP as the default rate.

We agree with PG&E that customers receiving new AMI meters should have time to observe when and how they use energy before moving to a new time-differentiated rate. We believe 12 months is appropriate so that a customer may observe how its usage patterns in different weather seasons change throughout a year. Eighteen months, as proposed by PG&E, is excessive and unnecessary.

Customers should have the opportunity to go onto TOU/CPP before the initial 12 months is over. Customers should also have the option to move onto RTP, rather than TOU/CPP, before or after the initial 12 months if RTP is available.

PG&E should propose that after 12 months of experience with the new AMI meter customers should be defaulted to a TOU/CPP rate, with the first customers moving to TOU/CPP in 2011. Delaying implementation of default TOU/CPP until 2011 will give PG&E additional time for customer education and billing and other system upgrades. TOU should be available as an optional rate, and RTP should be introduced as an optional rate in 2011, the same time it is introduced for large C&I customers. We see no reason why RTP cannot be offered to medium C&I customers at the same time those rates are introduced for large C&I customers.

PG&E's current CPP rate applicable to medium C&I customers is offered as a supplement to the standard rate offerings. A customer could combine the CPP rate with either a non-time-differentiated rate or a TOU rate. We believe a CPP rate should be a TOU rate with an additional critical peak price that is charged during critical peak periods. Therefore, we believe PG&E's medium C&I CPP rate should be coupled with PG&E's medium C&I TOU rate. We will require PG&E to file a revised medium C&I CPP rate as part of the 2008 Rate Design Window that includes TOU rates during non-CPP periods and that would be effective no later than May 1, 2010.

In summary, we will require PG&E to file a proposal for a default TOU/CPP rate for medium C&I customers as part of its 2008 Rate Design Window. The effective date of the proposed rate should be on or before February 1, 2011, allowing time for a Commission decision and subsequent customer education. PG&E should submit a proposal for an optional RTP rate as part of its 2011 GRC Phase 2 in March 2010. The effective date of the proposed RTP rate should be on or before May 1, 2011, allowing time to develop the rate and allowing time for customer education following adoption of the rate by the Commission.

4.4. Small Commercial

PG&E's small commercial customers are not required to be on a TOU rate, and most are not.⁴⁰ Small commercial customers will be receiving AMI meters as part of PG&E's AMI initiative.

According to the draft timetable in the January 23, 2008 Ruling, PG&E would propose CPP as the default rate starting in 2010 for small commercial customers that have AMI meters. Customers would have the option to switch to TOU, but a flat rate would no longer be an option. RTP would become available on an optional basis beginning in 2011.

Parties' Comments

PG&E's proposed timetable for small commercial rates would essentially maintain the status quo with a non-time-differentiated rate as the default and TOU and CPP as optional rates. PG&E proposes to introduce RTP as an optional rate in 2013.

PG&E argues that small commercial customers will require two years of customer education and outreach before moving to a time-differentiated default rate. PG&E believes default CPP should not be considered until the 2011 GRC Phase 2. PG&E also proposes to delay RTP for small commercial customers for an additional year to learn from larger customer RTP rates.

DRA notes that only half the AMI meters will be installed by 2010, and DRA asserts that placing only half of PG&E's small commercial customers onto a TOU rate is discriminatory.⁴¹

SDG&E believes TOU rates for small commercial customers should be encouraged as a step toward introducing dynamic pricing.⁴²

EPUC believes that the system peak is driven by residential and small commercial load; therefore, in the future there should be no flat rate options for residential and small commercial customers.⁴³

Discussion

We disagree with PG&E's alternative timetable, as it is inconsistent with the Commission's desire to make dynamic pricing ubiquitous for all customers. We also believe that with AMI and customer education, small commercial customers are capable of managing their energy use in response to dynamic pricing. However, we do agree with PG&E that small commercial customers require more time for customer education and outreach. Therefore, the timetable we adopt for PG&E's default TOU/CPP rate for small commercial customers is delayed for a year relative to the large C&I customers, which puts small commercial customers on the same schedule as medium C&I customers. We will require PG&E to implement default TOU/CPP for small commercial customers starting in 2011 for those customers who have had AMI meters for 12 months or more.

We disagree with DRA that PG&E should not default customers with AMI meters to a time-differentiated rate when some customers do not have AMI meters. In D.01-05-064 as modified by D.01 08-021 and D.01-09-062, the Commission required mandatory TOU rates for all large C&I customers who received new meters via the CEC's funding. The Commission did not wait until all large C&I customers had interval meters before making TOU a mandatory rate for customers with interval meters. Instead the Commission concluded a customer's default rate depended on the customer's metering capability. We are requiring PG&E to propose a comparable requirement here for small commercial customers.

Furthermore, we believe small commercial customers should have an opportunity to benefit from their new AMI meters as soon as possible, and we believe TOU rates and dynamic pricing will benefit small commercial customers by giving them an opportunity to reduce usage during high cost periods and shift usage to low cost periods.

PG&E's current optional small commercial CPP rate is the same as the medium C&I CPP rate. Consistent with the discussion regarding the medium C&I CPP rate we will require PG&E to file revised small commercial CPP rates as part of the 2008 Rate Design Window that include TOU rates during non-CPP periods and that would be effective no later than May 1, 2010.

We disagree with PG&E that RTP needs to be delayed until 2013 for small commercial customers, especially since it is an optional rate. We expect some small commercial customers will want to take full advantage of their new AMI meters and sign up for RTP. With the development of new enabling technologies, RTP could present significant opportunities for small commercial customers to reduce their bills. The Commission desires to empower consumers, big or small, to have the tools to better manage their energy usage and their bills. Therefore, we will require that RTP be made available for small commercial customers on an optional basis in 2011.

In summary, we will require PG&E to file a proposal for a default TOU/CPP rate as part of its 2008 Rate Design Window with an effective date on or before February 1, 2011. We will require PG&E to file an optional RTP rate as part of its 2011 GRC Phase 2 in March 2010 with an effective date on or before May 1, 2011. We believe this schedule will provide time for customer education and necessary PG&E system upgrades subsequent to a decision.

4.5. Agricultural

Large agricultural customers⁴⁴ currently have interval meters and are required to take service on a TOU rate. Small and medium agricultural customers⁴⁵ generally do not have TOU or interval meters and are not required to take service on a time-variant rate. However, some small and medium agricultural customers have chosen to take service on TOU rates. Large agricultural customers can enroll in CPP on an optional basis, but PG&E does not currently offer an optional CPP rate for small and medium agricultural customers.

Based on the draft timetable in the January 23, 2008 Ruling, PG&E would be required to propose moving large agricultural customers to a CPP or RTP rate starting in 2011. Customers would have the option to opt out to a TOU rate. The date of 2011 was intended to provide time for customer education and the development and deployment of enabling technologies.

The January 23, 2008 Ruling provided that PG&E would be required to propose moving small and medium agricultural customers with new AMI meters to a default TOU rate starting in 2010. TOU/CPP would be available as an optional rate, and RTP would be offered as an optional rate starting in 2011.

Parties' Comments

According to PG&E's alternate proposal, TOU would remain the default rate for large agricultural customers. PG&E proposes considering whether to adopt TOU/CPP as a default rate in the 2011 GRC Phase 2. PG&E would propose that an optional RTP be made available to large agricultural customers in 2012, the same time PG&E proposes RTP for large C&I customers.⁴⁶

PG&E proposes that a non-time-variant rate would remain the default rate for small and medium agricultural customers. PG&E would consider whether to adopt TOU/CPP as a default rate in the 2011 GRC Phase 2 and would consider default TOU and TOU/CPP again in the next GRC after 2011. PG&E would propose that an optional RTP be made available starting in 2013, the same time PG&E proposes RTP for small commercial and residential customers.⁴⁷

CFBF argues that mandatory dynamic pricing would harm agricultural customers and would result in little if any load reductions. CFBF explains that agricultural loads are primarily related to pumping water, and the pumps tend to be spread out over many acres which would make them difficult to access in response to a dynamic pricing event. Also, the pumps are generally not variable, so an agricultural customer's only possible response is to entirely shut off a pump. CFBF states that TOU rates, on the other hand, have benefited agricultural customers and the grid. CFBF recommends keeping dynamic pricing voluntary, with possible incentives for enabling technologies.⁴⁸

SCE notes that over 70% of the agricultural load in its territory is already on optional TOU rates.⁴⁹ SDG&E recommends default CPP for agricultural customers with TOU rates as additional options.⁵⁰

Discussion

We believe large agricultural customers should generally have the same rate options as large C&I customers. We disagree with PG&E that TOU should remain the default rate for large C&I customers. The Commission's policy is to implement dynamic pricing for all customers, and TOU is not dynamic pricing because the rate does not change based on day-ahead or real-time market or system conditions.

In D.05-04-053, the Commission discussed issues related to agricultural pumping usage and noted that many farmers receive water based on schedules determined by the State Water Project and the Central Valley Water Project. As a result, the water projects' schedules determine when farmers use water and, thus, electricity. Nonetheless, in D.05-04-053 the Commission concluded "[W]e believe that all customers should receive price signals that indicate when power is more expensive to procure. Thus, in the longer term, especially with coordination with the State Water Project and the Central Valley Water Project, we would expect that any changes to default rates would apply to agricultural customers over 200 kW."⁵¹ We reaffirm the Commission's prior determination and conclude that CPP should be made the default rate for the large agricultural customers.

We expect many large agricultural customers will find ways to manage their energy usage during critical peak events. The large percentage of load on TOU rates indicate that agricultural customers can adapt to time-variant rates. CPP will give large agricultural customers an additional incentive to explore energy management solutions to lower their usage during critical peak events and, thus, lower their bills.

Therefore, the timetable we adopt here requires PG&E to propose CPP as the default rate.

We believe it is appropriate for PG&E to propose implementing default CPP for large agricultural customers in 2011, one year after large C&I customers, to allow more time for customer outreach and education. We believe optional RTP should be offered in the same timeframe. TOU should also remain as an option for large agricultural customers.

PG&E should submit a proposal for default CPP and optional RTP for large agricultural customers as part of its 2008 Rate Design Window in early 2009. The effective date of the proposed default CPP should be on or before February 1, 2011. The effective date of the optional RTP rates should be on or before May 1, 2011.

For small and medium agricultural customers, we believe it is reasonable to delay implementation by one year relative to the timetable put forth in the January 23, 2008 Ruling. PG&E should be required to propose making TOU the default rate starting in 2011 for small and medium agricultural customers with advanced meters as part of its 2008 Rate Design Window. We do not have a sufficient record in this proceeding to conclude that TOU/CPP is the appropriate default rate for these customers. However, PG&E may elect to propose default TOU/CPP for small and medium agricultural customers in its 2008 Rate Design Window and include a justification for why TOU/CPP is an appropriate default rate.

Since many small and medium agricultural customers do not have TOU meters or interval meters, the energy usage information provided by their new AMI meter may be their first source of accurate information about when and how they use electricity. This Commission would like to ensure that these customers have the opportunity to better manage their energy usage and costs. Therefore, we will require that PG&E propose that a customer not be defaulted to a TOU rate until they have had any AMI meter for 12 months. This is the same provision we are requiring for medium and small C&I. If a small agricultural customer wants to move to a TOU, TOU/CPP, or RTP rate before they have had any AMI meter for a full 12 months, they should be permitted to do so.

For small and medium agricultural customers, PG&E should file a proposal to make TOU the default rate for customers who have had AMI meters for 12 months or more as part of its 2008 Rate Design Window. PG&E should also include an optional TOU/CPP rate for small and medium agricultural customers in its 2008 Rate Design Window filing. The proposed rates should be effective on or before February 1, 2011, allowing time for a Commission decision and customer education. PG&E should submit a proposal for an optional RTP rate as part of its 2011 GRC Phase 2 in March 2010. The effective date of the proposed RTP rate should be on or before May 1, 2011.

PG&E's proposal should not include a non-time-differentiated rate as an option after a customer has had a new AMI meter for 12 months. Non-time-differentiated rates should not be offered since such a rate would not even reflect the time varying costs of providing electricity in an average sense, like a TOU rate.

4.6. Residential

Most of PG&E's residential customers are on a non-time-differentiated rate with five tiers, each tier having a progressively higher rate. A customer's usage during a billing cycle up to a certain specified number of kWh is charged at the lowest rate. The usage above that amount, but below another specified amount is charged the second lowest rate, etc. PG&E currently offers TOU and CPP rates to residential customers on a voluntary basis. A proposal for a new peak time rebate (PTR) is before the Commission in A.07-12-009, PG&E's application to upgrade its AMI project.⁵²

The draft timetable for residential customers in the January 23, 2008 Ruling included two different scenarios-one assuming that the AB1X rate protections remain in place throughout the time period and one assuming that AB1X rate protections are no longer in place.⁵³ The timetable did not make any assumptions about when AB1X rate protections will end.

The scenario that assumes AB1X rate protections remain in effect further assumes that residential customers can only be offered TOU, CPP, and RTP on a voluntary basis. Customers could be placed on a PTR on a default basis since PTR is designed to be compliant with AB1X.

The only new rate required by the draft timetable while AB1X rate protections remain in place is optional RTP, which would be available to residential customers in 2010.

The draft timetable recommended that 30 days after the Commission or the legislature determines AB1X rate protections end, PG&E would be required to propose default TOU with CPP for residential customers with an effective date one year after AB1X rate protections end. The proposal should give customers the ability to opt out to a flat rate or TOU.

Parties' Comments

PG&E recommends that the Commission wait and see if PTR and optional CPP are successful. According to PG&E, the Commission should consider default TOU/CPP in the first GRC after the AB1X rate protections have ended. PG&E also argues RTP for residential customers should be delayed until 2013 because more time is needed to monitor the MRTU market and learn from larger customer RTP.⁵⁴

SCE notes that any bill impacts associated with lifting the AB1X rate protections may necessitate a multi-year transition plan.⁵⁵

DRA supports "limited experimentation" with PTR for residential customers. To reduce the potential for "free riders,"⁵⁶ DRA supports providing larger rebates for customers with enabling technologies and lower rebates for customers without enabling technologies.⁵⁷

DRA supports offering both PTR and CPP to customers, provided that they are limited to one of the two options. DRA expects some customers with higher than average load factors (i.e., flatter load profiles) will benefit more from CPP than PTR since CPP will allow those customers to avoid cross-subsidizing customers whose consumption profiles are characterized by "peakier" use.⁵⁸

DRA believes that analysis performed by TURN using data for SCE suggests that the greatest potential for residential class demand response is among customers whose electric use is in the upper tiers. DRA hypothesizes that the Commission's demand response objectives could be met while AB1X rate protections remain in place by making minor changes to upper tier rates. DRA believes a time-differentiated rate for residential customers deserves special consideration in PG&E's 2011 general rate case.⁵⁹

DRA thinks it is premature to adopt post-AB1X rate design since the timing and conditions that will exist when AB1X is lifted are so uncertain. DRA also believes bill analysis must be performed before setting the policy direction, and it is too early to perform a meaningful bill analysis.⁶⁰

TURN urges the Commission not to consider any major change in the mandatory or default rate design for residential customers at this time. TURN believes there is no urgency since the utilities are just beginning to deploy advanced meters. TURN believes that any consideration of mandatory or default TOU or CPP rates for residential customers would require careful analysis of relevant data and would necessitate an evidentiary hearing. TURN filed a "conditional" motion for evidentiary hearings on December 11, 2007 in which TURN moved for evidentiary hearings if the Commission intends "to consider policies that would establish a time-differentiated rate structure for the residential class on a mandatory or default basis." ⁶¹

TURN emphasizes that whether or not AB1X rate protections remain in place, residential rates also need to comply with Public Utilities Code Sections 739(c)(1) and 739.7, which require baseline rates and an increasing block rate structure. TURN cautions that these additional legal requirements will complicate the design of a future TOU/CPP rate. TURN recommends against taking on these legal and rate design issues prior to the filing of an actual rate design proposal.⁶²

SDG&E supports PTR as an interim step while AB1X rate protections remain in place. After AB1X rate protections have been removed, SDG&E supports exploring TOU and CPP as default options.⁶³

EPUC believes that the system peak is driven by residential and small commercial load; therefore, in the future there should be no flat rate options for residential and small commercial customers.⁶⁴

Discussion

There is no intention to address legal interpretations as to AB1X in this proceeding. For the purposes of the timetable we adopt here, we will assume that residential customers can only be offered TOU, CPP, and RTP on a voluntary basis.⁶⁵ PTR is designed to be compatible with the AB1X rate protections, so we assume that customers could be placed on a PTR on a default basis.

However, if the Commission determines in any other forum that time-variant or dynamic pricing rates could be offered to residential customers on a default or mandatory basis before AB1X protections are totally removed, the assumptions we are making here would need to be reconsidered. Another forum where the Commission is currently examining the implications of AB1X on residential rate design is A.07-01-047, where the Commission is considering a proposal put forth by SDG&E, who has argued that AB1X allows the rate freeze to be gradually phased out. Also, we encourage DRA to make recommendations in a future rate design proceeding as to how changes to the upper tiers could allow for time-variant pricing, as suggested by DRA in this proceeding.

Given our assumptions, we will still require PG&E to make several proposals related to residential rate design. PG&E has already filed a PTR proposal in A.07-12-009, PG&E's application to upgrade its AMI project. PG&E has proposed that the PTR would be effective in 2010. A.07-12-009 is an appropriate forum to consider PG&E's PTR proposal.

PG&E's current residential CPP rate is offered as a supplement to the standard single family residential rate offerings. A customer could combine the CPP rate with either a non-time-differentiated rate or a TOU rate. We believe a CPP rate should be a TOU rate with an additional critical peak price that is charged during critical peak periods. Therefore, we believe PG&E's residential CPP rate should be coupled with PG&E's residential TOU rate. We will require PG&E to file a revised residential CPP rate as part of its 2008 Rate Design Window that includes TOU rates during non-CPP periods and that would be effective no later than May 1, 2010.

We disagree with PG&E that optional RTP for residential customers should be delayed until 2013. We expect that given the diverse population of residential customers, many will want to take advantage of RTP much sooner. Other utilities already offer RTP to residential customers and many customers have signed up and reduced their bills.⁶⁶

We will require PG&E to propose optional RTP for residential customers that would be available in 2011, the same time RTP would be available for other customer classes. PG&E should submit a proposal for an optional RTP rate as part of its 2011 GRC Phase 2 in March 2010. The effective date of the proposed RTP rate should be on or before May 1, 2011.

Even with a 2011 effective date for PG&E's residential RTP rate, PG&E would still significantly lag behind utilities in other parts of the country.

We agree with TURN that it is premature and unnecessary to tackle the legal and policy issues surrounding the design of residential rates once AB1X rate protections are no longer in place. We do, however, believe it is important to establish a point in time when residential rate design will be thoroughly examined.

Therefore, we will require PG&E to file an application proposing default TOU/CPP for residential customers 30 days after any change in the law that changes the AB1X rate protections in a manner that could allow default or mandatory time-variant rates for residential customers. If the Commission approves a decision that interprets the AB1X rate protections in a manner that could allow default or mandatory time-variant rates for residential customers, then PG&E should file an application proposing default TOU/CPP for residential customers no later than 90 days after the Commission decision goes into effect and is no longer subject to rehearing or judicial review. The effective date of the proposed rate should be no later than one year from the filing date unless PG&E can justify a later effective date as being necessary to provide time for customer education and system upgrades.

By requiring that PG&E file a default TOU/CPP proposal for residential customers, we are not in this decision concluding that a default TOU/CPP rate will or should be adopted. We are not adopting post AB1X rate design in this decision. Rather PG&E's future proposal will trigger a thorough consideration of the policy and legal issues surrounding residential rate design. At that time, the Commission will be able to perform bill analysis, as recommended by DRA, and will be able to fully consider all relevant legal and policy issues. The Commission can also consider a transition plan as recommended by SCE.

To clarify once again, the only policy path we are setting in this decision is that the Commission will fully evaluate residential rates after the AB1X rate design protections are no longer in place or have materially changed.

4.7. Direct Access (DA) and Community Choice Aggregation (CCA) Customers

Since dynamic pricing as discussed in this decision only relates to the generation component of the unbundled rate, DA and CCA customers would not be eligible for dynamic pricing rates offered by the utilities. However, the load serving entities that serve DA and CCA customers could themselves offer dynamic pricing options.

4.8. Standby, Net Metered, and Master Metered Customers

EPUC believes standby customers should be exempt from CPP rates since a standby customer generally only takes utility service during periods when the customer's generation equipment unpredictably fails. In those cases, the customer would be unable to respond to a CPP event.⁶⁷

PG&E states that net metering and master-metered accounts should be restricted from eligibility, which PG&E says is consistent with current practice.⁶⁸

We do not have sufficient input from parties to address standby customers, net metered customers, and residential master metered customers in this decision. PG&E and other parties should address the applicability of dynamic pricing to standby, net metered, and master metered customers in context of specific rate proposals.

However, we can address commercial submetering. In D.07-09-004, the Commission approved a settlement between PG&E and BOMA that removed the ban on submetering in commercial buildings. In removing the ban on submetering, the Commission stated that "as a matter of policy, it is important for commercial building tenants to receive appropriate price signals and to have the opportunity to effectively use dynamic pricing options and participate in energy conservation programs."⁶⁹ Since submetering in commercial buildings is intended to encourage and facilitate tenants' participation in dynamic pricing, PG&E should not exclude commercial master-metered customers from the dynamic pricing rates that the utility proposes.

¹⁵ The dynamic pricing rates discussed in this decision are only applicable to bundled-service customers.

¹⁶ GRC Phase 2 typically addresses revenue allocation, marginal cost and rate design.

¹⁷ We define large C&I customers as those with maximum demand greater than or equal to 200 kW.

¹⁸ See D.85559, 1976 Cal. PUC LEXIS 1308 (Cal. PUC 1976) (ordered three major utilities to implement mandatory TOU for customers with demands greater than 500 kW); D.86632, 1976 Cal. PUC LEXIS 931 (Cal. PUC 1976) (approved mandatory TOU rates for PG&E customers with maximum load greater than 4,000 kW); D.90588, 1979 Cal. PUC LEXIS 772 (Cal. PUC 1979) (approved mandatory TOU rates for PG&E customers with maximum load between 1,000 kW and 4,000 kW); D.92553, 1980 Cal. PUC LEXIS 1279 (Cal. PUC 1980) (approved mandatory TOU rates for PG&E customers with maximum load between 500 kW and 1,000 kW).

¹⁹ Assembly Bill 1X 29 from the 2001-2002 First Extraordinary Session, Section 14(d)(4)(B).

²⁰ See D.01-05-064 as modified by D.01-08-021 and D.01-09-062.

²¹ The relevant tariffs indicate the applicability with greater specificity.

²² BOMA Comments, February 28, 2008, pp. 3-4.

²³ Auto DR is a research program managed by the Demand Response Research Center (DRRC) designed to link facility energy management control systems with external utility-generated price or emergency signals. The use of this technology is integrated with various existing utility demand response programs, such as the critical peak pricing program. In D.06-11-049, the Commission directed the utilities to develop Auto DR implementation plans.

²⁴ CLECA Comments, February 28, 2008, p. 3.

²⁵ EPUC CPP Comments, March 21, 2008, pp. 5-6.

²⁶ SDG&E Post-Workshop Comments, December 11, 2007, p. 4.

²⁷ TOU/CPP is used in this decision to refer to a CPP rate with TOU pricing during non-critical peak periods.

²⁸ PG&E Comments, February 28, 2008, pp. 7, 25, 26-27.

²⁹ In Opening Comments on the Proposed Decision PG&E estimates that modifying the AMI deployment schedule to support default CPP in 2010 and voluntary RTP in 2011 for large C&I customers will cost $16 million (p. 7.) It is unclear if the $16 million cost estimate is for the same scope of work as the $30 million cost estimate.

³⁰ MRTU Release 1A is now known as Market and Performance, or MAP.

³¹ CLECA Comments, February 28, 2008, p. 2.

³² CMTA Comments, February 28, 2008, p. 2.

³³ EPUC Comments, February 28, 2008, p. 3.

³⁴ See Energy Action Plan II, p. 6.

³⁵ D.05-11-009 states "As the CAISO moves to implement its market redesign, we anticipate that transparent pricing information will become available that will facilitate development and adoption of a true RTP tariff. However, design of such a tariff cannot be performed in isolation from comprehensive rate design examination. Therefore, we direct each utility, as part of its next comprehensive rate design proceeding application following development and final implementation of an hourly day-ahead market price by the CAISO, to submit a real time pricing tariff for consideration as part of its tariff offerings." (P. 7.)

³⁶ According to PG&E, medium C&I customers are generally on the non-TOU version of Schedule A-10 or voluntarily on Schedule E-19, a TOU rate.

³⁷ PG&E Comments, February 28, 2008, Attachment A.

³⁸ PG&E Comments, February 28, 2008, p. 16.

³⁹ PG&E Comments, February 28, 2008, p. 38.

⁴⁰ According to PG&E, small commercial customers are generally on Schedule A-1, a non-time-differentiated schedule, or Schedule A-6, a voluntary TOU rate.

⁴¹ DRA Comments, February 28, 2008, p. 2.

⁴² SDG&E Post-Workshop Comments, December 11, 2007, p. 5.

⁴³ EPUC CPP Comments, March 21, 2008, p. 4.

⁴⁴ We define large agricultural customers as those with maximum demand at 200 kW and greater.

⁴⁵ We define small and medium agricultural customers as those with maximum demand less than 200 kW.

⁴⁶ PG&E Comments, February 28, 2008, pp. 38-40, Attachment A.

⁴⁷ PG&E Comments, February 28, 2008, pp. 38-40, Attachment A.

⁴⁸ CFBF Post-Workshop Comments, December 11, 2007, pp. 3-4. CFBF notes that its testimony in A.05-01-016 et al. expands on these concerns.

⁴⁹ SCE Post-Workshop Comments, December 11, 2007, p. 6.

⁵⁰ SDG&E Post-Workshop Comments, December 11, 2007, p. 4.

⁵¹ D.05-04-053, pp. 35-36.

⁵² Peak Time Rebate (PTR): A program that provides customers a rebate for demand reductions below a customer-specific baseline when the program is called due to market or system conditions.

⁵³ AB1X refers to Assembly Bill No. 1 from the 2001-2002 First Extraordinary Session as codified by Water Code section 80000 et seq. Water Code section 80110 protects the rates of residential customers for usage up to 130% of baseline quantities "until such time as the [Department of Water Resources] has recovered the costs of power it has procured for the electrical corporation's retail end use customers...."

⁵⁴ PG&E Comments, February 28, 2008, pp. 27-28, 38, 40.

⁵⁵ SCE Comments, February 28, 2008, p. 5.

⁵⁶ Under a PTR, a "free rider" would be a customer who receives a rebate because its usage was below the baseline, but in fact, the customer did not reduce its usage.

⁵⁷ DRA Post-Workshop Comments, December 11, 2007, pp. 8-9.

⁵⁸ Id., p. 10.

⁵⁹ Id., p. 9.

⁶⁰ DRA Comments, February 28, 2008, pp. 1-2.

⁶¹ TURN Post-Workshop Comments, December 11, 2007, pp. 2-3.

⁶² TURN Comments, February 28, 2008, pp. 1-2.

⁶³ SDG&E Post-Workshop Comments, December 11, 2007, p. 5.

⁶⁴ EPUC CPP Comments, March 21, 2008, p. 4.

⁶⁵ In D.06-10-051, the Commission found that PG&E's voluntary residential CPP rate adopted in D.06-07-027 is not prohibited by AB1X because the CPP rate is optional. Furthermore, D.06-10-057 states that "The Decision [D.06-07-027] is also consistent with other decisions where we have authorized similar tariff options enabling customers to better manage their overall electricity consumption patterns, thereby helping to ensure adequate state-wide electricity supply as more broadly intended by AB1X." (Page 5.)

⁶⁶ In 2006, the Illinois legislature amended Section 16-107 of Illinois' Public Utilities Act to require Ameren Utilities and Commonwealth Edison Company to offer RTP to residential customers starting in January 2007. Based on annual reports filed with the Illinois Commerce Commission, Commonwealth Edison's residential RTP program had enrolled 3,994 customers by the end of 2007 and active participants saved 13% in 2007. Ameren had 500 customers on the program by the end of 2007, and customers saved an average of 16% on their bills. The annual reports are available at http://www.icc.illinois.gov/industry/publicutility/energy/RTP.aspx.

⁶⁷ EPUC CPP Comments, March 21, 2008, p. 3.

⁶⁸ PG&E Comments, February 28, 2008, pp. 22-23.

⁶⁹ D.07-09-004, p. 34.