12. Assignment of Proceeding

Rachelle B. Chong is the assigned Commissioner and David K. Fukutome is the assigned Administrative Law Judge in this proceeding.

Findings of Fact

1. In "California Demand Response: A Vision for the Future (2002-2007)," attached to D.03-06-032 as Attachment A, the Commission stated that electric customers should have "the ability to increase the value derived from their electricity expenditures by choosing to adjust usage in response to price signals."

2. The EAP II identifies demand response, along with energy efficiency, as the State's "preferred means of meeting growing energy needs."

3. A key action in the EAP II is "to make dynamic pricing tariffs available for all customers."

4. Rate design proceedings are the appropriate forum to address dynamic pricing.

5. In D.06-05-038, the Commission directed each utility "to incorporate default CPP tariffs for large customers into their next comprehensive rate design proceeding or other appropriate proceeding if directed by the Commission."

6. In D.05-11-009, the Commission directed each utility to submit RTP tariffs in its first comprehensive rate design proceeding, following the CAISO's implementation of its MRTU.

7. According to PG&E's current advanced metering plans, by 2012, all of PG&E's customers will have advanced meters, so all customers can take advantage of dynamic pricing.

8. Large C&I 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.

9. 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 customers with maximum demand greater than 200 kW who received new meters through a program funded by the CEC.

10. Large C&I customers have been on TOU rates for between five and thirty years.

11. RTP is the best rate to promote economic efficiency and equity between customers; however, RTP cannot be developed and implemented until MRTU becomes operational.

12. CPP 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.

13. The Commission directed the utilities to propose AMI projects primarily because AMI enables greater demand response through dynamic pricing and demand response programs.

14. PG&E's current AMI deployment plans are not consistent with the Commission's policy objectives.

15. The delay in the on-line date of MRTU requires a delay in the development and implementation of RTP.

16. Two full summers of experience with MRTU are not needed before beginning to develop RTP.

17. A means to deliver day-ahead prices to IOUs and retail customers needs to be developed to effectively implement RTP.

18. Requiring PG&E to propose a default CPP rate for large C&I customers in early 2009 with an effective date on or before May 1, 2010 provides sufficient time for customer education.

19. TOU is not dynamic pricing because the rate does not change based on day-ahead or real-time market or system conditions.

20. Non-time-differentiated rates do not reflect the time varying costs of providing electricity.

21. Medium C&I and small commercial customers are capable of managing their energy use in response to dynamic pricing.

22. Small commercial customers require more time for customer education and outreach than do large and medium C&I customers.

23. The Commission did not wait until all large C&I customers had interval meters before making TOU a mandatory rate for large C&I customers with interval meters.

24. PG&E's current medium C&I and small commercial CPP rate can be combined with either a non-time-differentiated rate or a TOU rate.

25. Large agricultural customers with maximum load greater than or equal to 200 kW currently have interval meters and are required to take service on a TOU rate.

26. Since most customers with maximum load less than 200 kW 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.

27. In D.07-09-004, the Commission approved a settlement between PG&E and the BOMA that removed the ban on submetering in commercial buildings so that commercial building tenants could receive appropriate price signals and have the opportunity to effectively use dynamic pricing options and participate in energy conservation programs.

28. The default CPP rate adopted for SDG&E in D.08-02-034 provided for an initial 45-day opt-out period, and if a customer does not opt out to a TOU rate during the first 45 days the customer will be required to remain on the CPP rate for a full year.

29. Bill protection can help customers become familiar and comfortable with a new rate.

30. CPP is intended to reflect real-time system conditions, and system conditions vary from one year to the next.

31. While tight supply and demand conditions are most likely to occur on summer weekday afternoons, tight conditions or high wholesale energy prices can also occur on weekends and holidays, and potentially at other times of the year.

32. It is premature to address the details of RTP.

33. D.08-04-050 requires the three major investor owned utilities to conduct annual studies of their demand response activities.

Conclusions of Law

1. It is reasonable to require PG&E to file dynamic pricing rates as part of the Rate Design Window, but delay the effective date to allow more time to develop rates and allow time for customer education following adoption of the rates by the Commission.

2. The 2008 Rate Design Window should be delayed from November 25, 2008 until February 28, 2009 to give PG&E more time to prepare its filings.

3. PG&E should develop RTP rates and make them available to all customers as soon as feasible.

4. PG&E should adopt CPP as the default rate for C&I customers with maximum load greater than 200 kW.

5. PG&E should revise its AMI implementation plans to support default CPP for large C&I customers in 2010 and optional RTP in 2011.

6. PG&E should propose RTP rates for all customer classes after one summer of experience with MRTU as part of its 2011 GRC Phase 2 filed in March 2010.

7. It is reasonable to wait for two full summers of experience with MRTU before implementing RTP.

8. Since RTP needs to be delayed until 2011, PG&E should propose to make CPP the default rate in 2010 for large C&I customers.

9. Requiring PG&E to propose that CPP be made the default rate for large C&I customers in 2010, and requiring PG&E to propose RTP in 2011 is consistent with past Commission decisions.

10. PG&E should file a proposal for a default CPP rate for large C&I customers by February 28, 2009 with an effective date on or before May 1, 2010.

11. It is reasonable to subdivide commercial and industrial customer with maximum load less than 200 kW into two subgroups: those with maximum demand between 20 kW and 200 kW, referred to as medium C&I, and those with maximum demand below 20 kW, referred to as small commercial.

12. TOU should not be the default rate for medium C&I and small commercial customers.

13. TOU with CPP should be the default rate for medium C&I and small commercial customers.

14. It is reasonable for PG&E to provide a customer with maximum load less than 200 kW 12 months with a new advanced meter to observe its usage before moving to a default time-differentiated rate.

15. PG&E should offer optional RTP to all customer classes at the same time it is introduced for large C&I customers.

16. PG&E's proposal should not offer non-time-differentiated rates to any C&I or agricultural customer with maximum load less than 200 kW after the customer has had a new AMI meter for 12 months, starting in 2011.

17. PG&E should propose to make TOU with CPP the default rate for medium C&I and small commercial customers starting in 2011.

18. It is reasonable for the Commission to adopt default rates for customers based on their metering capability.

19. A CPP rate should be a TOU rate with an additional critical peak price that is charged during critical peak periods.

20. PG&E should revise its CPP rates for medium C&I, small commercial, and residential customers so that the CPP rates include TOU rates during non-critical periods.

21. Large agricultural customers should generally have the same rate options as large C&I customers.

22. PG&E should propose implementing default CPP for large agricultural customers one year after large C&I customers to allow more time for customer outreach and education.

23. A.07-12-009 is an appropriate forum to consider PG&E's PTR proposal.

24. The Commission should establish a point in time when residential rate design will be thoroughly examined.

25. PG&E should not exclude commercial master-metered customers from the dynamic pricing rates that the utility proposes.

26. It is reasonable to require PG&E to follow the rate design guidance adopted in this decision.

27. Rate design should promote economically efficient decision-making.

28. To promote economically efficient decision-making, rates should be based on marginal cost.

29. Other objectives, such as energy efficiency, and legal requirements, such as baseline allowances, should be addressed when designing specific rates, and any deviation from marginal cost should be minimized.

30. Rates should also seek to provide stability, simplicity and customer choice.

31. If customers on a particular rate schedule reduce their usage in a manner that reduces a utility's costs then the customers on that rate should see a commensurate reduction in their bills.

32. Dynamic pricing rates should include a capacity reservation charge, or a similar feature, that allows a customer to pay a fixed charge for a predetermined amount of its load and pay the dynamic price for consumption in excess of the reserved capacity.

33. Customers should have the opportunity to opt out of a default dynamic pricing rate to another time-variant rate.

34. Utilities should offer optional bill protection to customers on default dynamic pricing rates.

35. The utilities should bid demand reductions due to dynamic pricing into the CAISO's day-ahead market.

36. The critical peak price should represent the marginal cost of capacity used to meet peak energy needs plus the marginal cost of energy during the critical peak period.

37. The utility should explain what it used as the basis for the marginal cost of capacity in its CPP rate and why.

38. The annualized cost of a new combustion turbine is a reasonable proxy for determining the marginal capacity prices; however, alternative bases include actual utility costs, CAISO scarcity prices (if adopted by FERC and implemented by the CAISO), and centralized capacity market or bulletin board prices (if implemented).

39. Critical peak pricing rates should include a critical peak price during critical peak periods and time-of-use rates during non-critical periods.

40. Since the critical peak price is intended to reflect the marginal cost of generation that is needed to meet peak period usage, CPP rates should not have summer generation demand charges.

41. The utilities should be able to call a variable number of events each year, and the rate should be designed based on the number of events that would be called during a typical year.

42. The utilities should be able to call critical peak events any day of the week, year round.

43. The energy charge for RTP rates should be indexed to the CAISO's day-ahead hourly market prices.

44. At least initially, RTP should be based on day-ahead hourly market prices that have been aggregated across PG&E's service territory. As the market develops, locational prices should be considered.

45. The Commission should determine the degree to which the marginal cost of capacity is not incorporated into the CAISO's day-ahead hourly market prices.

46. PG&E should conduct annual studies of TOU with CPP, RTP, and PTR during years each of those rates is in effect by applying the load impact protocols adopted in D.08-04-050.

47. PG&E's rate proposals filed pursuant to this decision should be consistent with the rate design guidance adopted in this decision.

48. PG&E should seek recovery of expenditures necessary to implement dynamic pricing incurred in 2011 and later in general rate cases.

49. PG&E should seek recovery of incremental expenditures required to implement dynamic pricing incurred before 2011 in the application(s) in which PG&E proposes the specific dynamic pricing rates.

50. PG&E should be authorized to record incremental expenditures required to implement specific dynamic pricing rates in a memorandum account and should seek recovery of any such expenditures in the related rate design proceeding.

ORDER

IT IS ORDERED that:

1. Pacific Gas and Electric Company (PG&E) shall modify its advanced metering infrastructure (AMI) deployment plan so that customers with maximum demand greater than or equal to 200 kilowatts (kW) have the metering and billing systems in place to support default critical peak pricing (CPP) in 2010 and optional real time pricing (RTP) in 2011.

2. If PG&E requires additional authorizations from the Commission to modify its AMI deployment plan, PG&E shall request such authorizations in its AMI upgrade Application (A.) 07-12-009.

3. Any request by PG&E for approval of expenditures to modify the AMI deployment plan shall be made in A.07-12-009 and shall include the necessary justification.

4. Prior to a Commission decision in A.07-12-009, PG&E may record incremental costs required to modify the AMI deployment plan in a memorandum account and seek recovery in A.07-12-009.

5. PG&E shall propose the following rates as part of its 2008 Rate Design Window, which shall be filed no later than February 28, 2009. The effective date of these proposed rates shall be on or before May 1, 2010:

· One or more default CPP rates for commercial and industrial (C&I) customers with maximum load greater than or equal to 200 kW; and

· Revised optional medium C&I, small commercial and residential CPP rates that include time-of-use (TOU) rates during non-CPP periods.

6. PG&E shall propose the following rates as part of its 2008 Rate Design Window, which shall be filed no later than February 28, 2009. The effective date of these proposed rates shall be on or before February 1, 2011:

· One or more default CPP rates for C&I customers with maximum load less than 200 kW that have had an AMI meter for 12 months or more. PG&E's proposal shall not offer non-time-differentiated rates to customers with maximum load less than 200 kW that have had an AMI meter for 12 months or more;

· One or more default CPP rates for agricultural customers with maximum load greater than or equal to 200 kW that have had an AMI meter for 12 months or more;

· One or more default TOU rates for agricultural customers with maximum load less than 200 kW that have had an AMI meter for 12 months or more; PG&E's proposal shall not offer non-time-differentiated rates to customers with maximum load less than 200 kW that have had an AMI meter for 12 months or more;

· One or more optional CPP rates for agricultural customers with maximum load less than 200 kW.

7. PG&E shall propose optional RTP rates for all customer classes as part of its 2011 General Rate Case Phase 2 to be filed on March 1, 2010. The effective date of the proposed rates shall be on or before May 1, 2011.

8. PG&E shall file an application proposing a default CPP rate for residential customers 30 days after any change in the law that changes the Assembly Bill 1X 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 Assembly Bill 1X rate protections in a manner that could allow default or mandatory time-variant rates for residential customers, then PG&E shall file an application proposing a default CPP rate for residential customers not later than 90 days after the Commission decision goes into effect and is no longer subject to rehearing or judicial review. PG&E shall propose an effective date that is no later than one year after the filing date unless PG&E can justify a later effective date as being necessary to allow time for customer education and system upgrades.

9. The rate design guidance in Attachment A is adopted. Attachment A is to be read in the context of the overall decision.

10. The rates proposed by PG&E pursuant to this decision shall be consistent with the rate design guidance in Attachment A.

11. PG&E shall conduct annual studies CPP, RTP, and peak time rebate (PTR) during years each of those rates is in effect by applying the load impact protocols adopted in Decision (D.) 08-04-050, and PG&E shall use its load impact studies to estimate the likely responses of customers to dynamic pricing rates. PG&E shall submit the studies in accordance with D.08-04-050.

12. PG&E shall conduct an ex post review of when CPP events were called, as described in this decision, and shall present the results of this analysis in its GRC Phase 2's and any other proceeding in which CPP rate design proposals are being considered.

13. PG&E shall seek recovery of expenditures necessary to implement dynamic pricing incurred in 2011 and later in general rate cases.

14. PG&E shall seek recovery of incremental expenditures required to implement dynamic pricing incurred before 2011 in the application(s) in which PG&E proposes the specific dynamic pricing rates and shall provide the necessary justification.

15. PG&E is authorized to record incremental expenditures required to implement specific dynamic pricing rates in a memorandum account and shall seek recovery of any such expenditures in the related rate design proceeding.

16. PG&E's dynamic pricing proposals filed pursuant to this decision shall at a minimum include the following: (1) an explanation of how its rate design is consistent with the rate design guidance summarized in Attachment A; (2) a bill analysis showing the full distribution of customer bill impacts under the proposed rate or rates; (3) an explanation of how PG&E intends to conduct customer education for the new dynamic pricing rate; (4) a description of the bill analysis tools that PG&E will provide to customers once a rate or rates are adopted; (5) any other information required by this decision.

17. PG&E shall continue working with the California Independent System Operator's Demand Response Infrastructure working group and with stakeholders in other forums to develop the communications infrastructure necessary to support RTP by 2011.

18. PG&E shall include a timeline in its 2011 General Rate Case Phase 2 showing what steps PG&E will take to make sure that all the necessary communications systems are in place to support RTP in 2011.

19. PG&E shall offer customers tools so that customers can determine bill impacts of any dynamic pricing rates that the Commission adopts for PG&E.

20. A.06-043-005 is closed.

This order is effective today.

Dated July 31, 2008, at San Francisco, California.

MICHAEL R. PEEVEY

President

DIAN M. GRUENEICH

JOHN A. BOHN

RACHELLE B. CHONG

TIMOTHY ALAN SIMON

Commissioners

ATTACHMENT A

Rate Design Guidance

All Dynamic Pricing Rates

· Rate design should promote economically efficient decision-making.

· To promote economically efficient decision-making, rates should be based on marginal cost.

· Other objectives, such as energy efficiency, and legal requirements, such as baseline allowances, should be addressed when designing specific rates, and any deviation from marginal cost should be minimized.

· Rates should also seek to provide stability, simplicity and customer choice.

· If customers on a particular rate reduce their usage in a manner that reduces a utility's costs then the customers on that rate should see a commensurate reduction in their bills.

· Dynamic pricing rates should include a capacity reservation charge, or a similar feature, that allows a customer to pay a fixed charge for a predetermined amount of its load and pay the dynamic price for consumption in excess of the reserved capacity.

· Customers should have the opportunity to opt out of a default dynamic pricing rate to another time-variant rate.

· Utilities should offer optional bill protection to customers on default dynamic pricing rates.

· The utilities should bid demand reductions due to dynamic pricing into the California Independent System Operator's (CAISO's) day-ahead market.

Critical Peak Pricing

· The critical peak price should represent the marginal cost of capacity used to meet peak energy needs plus the marginal cost of energy during the critical peak period.

· The utility should explain what it used as the basis for the marginal cost of capacity in its critical peak pricing (CPP) rate and why. The annualized cost of a new combustion turbine is a reasonable proxy for determining the marginal capacity prices; however, alternative bases include actual utility costs, CAISO scarcity prices (if adopted by the Federal Energy Regulatory Commission and implemented by the CAISO), and centralized capacity market or bulletin board prices (if implemented)

· Critical peak pricing rates should include a critical peak price during critical peak periods and time-of-use rates during non-critical periods.

· Since the critical peak price is intended to reflect the marginal cost of generation that is needed to meet peak period usage, CPP rates should not also have summer generation demand charges.

· The utilities should be able to call a variable number of events each year, and the rate should be designed based on the number of events that would be called during a typical year.

· The utilities should be able to call critical peak events any day of the week, year round.

Real-Time Pricing

· The energy charge should be indexed to the CAISO's day-ahead hourly market prices.

· At least initially, RTP should be based on day-ahead hourly market prices that have been aggregated across PG&E's service territory. As the market develops, locational prices should be considered.

· The Commission should determine the degree to which the marginal cost of capacity is not incorporated into the CAISO's day-ahead hourly market prices.

(END OF ATTACHMENT A)

ATTACHMENT B

Illustrative Timetable

If the Commission adopts the rates that PG&E is required to propose pursuant to this decision, PG&E's customer would have the following rate options between 2008 and 2012:

* A customer will not be defaulted to TOU/CPP or TOU until the customer has had an advanced meter for 12 months.

Flat = a seasonal, non-time-variant rate; TOU = Time-of-use; CPP = Critical Peak Pricing; TOU/CPP = Critical Peak Pricing with time-of-use pricing during non-critical peak periods; RTP = Real Time Pricing; PTR = Peak Time Rebate; With AMI = Customers with an advanced meter; Without AMI = Customers with a meter that cannot record interval usage data

(END OF ATTACHMENT B)

ATTACHMENT C

Glossary, Acronyms and Abbreviations

AB1X 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 percent 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...."

ABS Advanced Billing System: PG&E's billing system for its large customers on more complex rates and programs.

AMI Advanced Metering Infrastructure

AReM/DACC Alliance for Retail Energy Markets and the Direct Access Customer Coalition

Auto DR A research program managed by the DRRC designed to link facility energy management control systems with external utility-generated price or emergency signals, integrated with various existing utility demand response programs, such as the critical peak pricing program.

BOMA Building Owners and Managers Association

C&I Commercial and industrial customers

CAISO California Independent Systems Operator

CC&B Customer Care and Billing: PG&E's primary billing system

CCA Community Choice Aggregation

CEC California Energy Commission

CFBF California Farm Bureau Federation

CLECA California Large Energy Consumers Association

CMTA California Manufacturers and Technology Association

CPP Critical Peak Pricing: A dynamic rate that allows a short-term price increase to a predetermined level (or levels) to reflect real-time system conditions. Typically, the time and duration of the price increase are predetermined, but the days are not predetermined.

CPUC California Public Utilities Commission

CRM California Rice Millers

DA Direct Access

DRA Division of Ratepayer Advocates

DRRC Demand Response Research Center: A research center led by Lawrence Berkeley National Laboratory. The DRRC's rates project is funded by the California Energy Commission's Public Interest Energy Research program.

E-CPP PG&E's existing voluntary CPP rate for large C&I and agricultural customers.

E-CSMART PG&E's voluntary CPP rate for small commercial customers.

E-RSMART PG&E's voluntary CPP rate for residential customers.

EAP II Energy Action Plan II

EPUC Energy Producers and Users Coalition

ERRA Energy Resource Recovery Account

FERC Federal Energy Regulatory Commission

GRC General Rate Case

HAN Home Area Network: A communications system that connects an advanced meter with other devices in a customer's home or business.

IOU Investor-Owned Utility

KMEP Kinder Morgan Energy Partners

kW Kilowatt

kWh Kilowatt-hour

Large Agricultural Agricultural customers with maximum demand
Customers greater than 200 kW

Large C&I Commercial and industrial customers with

Customers maximum demand greater than or equal to 200 kW

Medium C&I Commercial and industrial customers with

Customers maximum demand greater than or equal to 20 kW and less than 200 kW

MRTU Market Redesign and Technology Upgrade

PG&E Pacific Gas and Electric Company

PTR Peak Time Rebate: 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.

RTP Real Time Pricing: A dynamic rate that allows prices to be adjusted frequently, typically on an hourly basis, to reflect real-time system conditions.

SCE Southern California Edison Company

Schedule A-1 PG&E's non-time-differentiated rate for small commercial customers.

Schedule A-6 PG&E's voluntary time-of-use rate for small commercial customers.

Schedule A-10 PG&E's rate generally applied to medium and some small C&I customers. PG&E offers a non-time differentiated and time-of-use version of the rate.

Schedule E-19 PG&E's time-of-use rate for customers with maximum load greater than or equal to 500 kW. Customers with maximum load less than 500 kW may enroll on an optional basis.

Schedule E-20 PG&E's time-of-use rate for customers with maximum load greater than or equal to 1,000 kW.

SDG&E San Diego Gas & Electric Company

Small and Medium Agricultural customers with maximum demand
Agricultural less than 200 kW

Small Commercial Commercial customers with maximum demand
Customers: below 20 kW

TOU Time-of-Use: A rate in which predetermined electricity prices vary as a function of usage period, typically by time of day, by day of the week, and/or by season.

TOU/CPP Used to refer to a CPP rate with TOU pricing during non-critical peak periods.

TURN The Utility Reform Network

WPTF Western Power Trading Forum

(END OF ATTACHMENT C)