PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA

ENERGY DIVISION*					RESOLUTION E-3662
                                					       MAY 4, 2000	 

RESOLUTION

Resolution E-3662.  Pacific Gas and Electric (PG&E) and Southern California Edison Company (Edison) seek revisions to tariffs to comply with the requirements of Assembly Bill (AB)811.  Approved as modified.   

By Edison Advice Letter  1430-E filed on January 14, 2000
and PG&E Advice Letter 1953-E filed on January 14, 2000. 
 
______________________________________________________________________________

Summary

This Resolution approves tariff revisions proposed by Southern California Edison (Edison) and Pacific Gas and Electric (PG&E) to comply with the requirements of Assembly Bill (AB)811 regarding the calculation of the Power Exchange (PX) credit.  The Resolution requires Edison and PG&E to notify all eligible customers likely to be affected by this legislation and clarifies that the provisions of AB811 are only applicable during the “rate freeze” imposed by AB1890.  Edison’s request to establish a memorandum account to record implementation costs is approved.  PG&E may record its implementation costs into its Electric Restructuring Costs Account (ERCA).  

Background

AB1890, California’s electric restructuring legislation, froze rates for residential and small commercial customers at a level 10% lower than rates in effect on June 10, 1996; froze rates for all other customers at their June 10, 1996 level; unbundled rates into their component parts; and required that direct access customers receive an hourly credit of the Power Exchange price.

Public Utilities (PU) Code Section 368(b) of AB1890 required that each investor-owned utility file a cost recovery plan that “shall provide for identification and separation of individual rate components such as charges for energy, transmission, distribution, public benefit programs, and recovery of uneconomic costs.”  In Decision (D.)97-08-056 (also known as the “Unbundling Decision”), the Commission adopted the tariffs necessary to implement this requirement.

One of the major issues of controversy in the proceedings leading up to the adoption of D.97-08-056 was the methodology that would be used to allocate the energy and competition transition charge (CTC) portion of each customer’s bill.  The Commission considered two different approaches, the residual CTC method and the average CTC method before adopting the use of the average CTC method to allocate energy and transition costs.

Under the residual CTC method, the CTC component of a direct access customer’s bill with an hourly meter would be calculated as the mirror image of the hourly Power Exchange (PX) credit that a direct access customer receives after subtracting out the applicable transmission, distribution, and public purpose components (T&D/PP).  For a customer with an average rate of 8 cents/kWh for example, 3 cents/kWh of which represents the T&D/PP component of the bill, the customer’s PX credit would vary with the hourly variation in the PX price.  During on-peak hours, when the PX price is 4 cents/kwh, the CTC component of the bill would be 1 cent.  During off-peak hours, when the PX price is 1 cent/kwh, the CTC component is 4 cents.

Under the average CTC method, a weighted-average of the energy and PX credits based on the load-profile for the entire customer class is developed.  Since rates are frozen, this essentially creates an average CTC rate as well.   For a customer with an average load profile, the average rate over the period would be equal to the frozen rate (in this example 8 cents/kwh).  The higher on-peak prices would be offset by the lower off-peak prices.  Customers with better than average load-profiles and an appropriate interval meter can save money under this methodology and there is an incentive for customers to switch their energy usage to lower-priced off-peak hours.  

Both the average and residual CTC methodologies have advantages and disadvantages.

The advantages of the average CTC method are that it;
•	More equitably allocates CTC to customers who use large amounts of energy on-peak;
•	Provides an incentive for customers to shift energy usage from higher-priced on-peak hours to lower priced off-peak hours. 
•	Prepares direct access customers for the post-transition period competitive marketplace by providing some hourly price signals 

The major disadvantage of the average CTC method is that it;
•	Prevents some customers (primarily those who use above average amounts of energy on-peak) from taking advantage of direct access.

Several parties have stated that, since the average CTC method is calculated based on each customer classes’ average load profile, by definition ½ of all customers will have a load profile worse than average and are thereby precluded from taking advantage of direct access.  Although for a number of reasons this estimate of ½ is overly high, it is an accurate characterization that the use of the average CTC method provides no incentive for a portion of each customer class from participating in direct access.

The residual CTC method offers none of the efficiency, or load-shifting benefits that the average CTC method does.  However, the residual CTC method does allow all customers with appropriate interval meters to take advantage of direct access. 

In D.97-08-056 the Commission adopted the use of the average CTC method to calculate customer bills and reaffirmed its use in D.97-09-125, and D.97-11-026. 

One option that the Commission considered in the debates that led up to the adoption of D.97-08-056 would be to allow direct access customers the opportunity to make a selection as to which method they would prefer to utilize.  This approach would have maximized the number of customers able to utilize direct access while at the same time providing a large number of direct access customers with some hourly price signals.  At the time that D.97-08-056 was being considered, however, this option appeared to be precluded by PU Code Sec. 368(b) of AB1890.  This section required that default customers remaining with the utility pay the same unbundled rates as direct access customers.  You cannot maintain complete parity between all default and all direct access customers when default customers are paying rates based on one methodology, while some direct access customers are using one methodology and other direct access customers are using a different methodology

On September 16, 1999, Governor Davis signed AB811. This legislation added Section 367.7 to the PU Code.  This legislation requires that up until June 30, 2000 direct access customers can make a one-time selection as to which methodology they wish to utilize, either the residual CTC or average CTC methodology, to calculate their rates. All new direct access customers who have an hourly meter installed on or after June 30, 2000will have their rates calculated based on the residual CTC method.  Existing customers who already have an hourly meter and do not make their one-time selection will continue to have their rates calculated based on the average CTC method.  AB811 requires that the Commission implement a methodology to allow direct access customers to use the residual CTC method.  

Additionally, AB811 provides that the utilities may recover through rates “the incremental billing costs incurred” in implementing the provisions of AB811; and that there “shall not be any shifts in costs between customer classes…consistent with the firewall provision set forth in subdivision (e) of Section 367.”   

A Coordinating Commissioner’s Ruling (CCR) dated November 5, 1999 directed the “Energy Division to conduct an informational workshop, followed by filing of an application or advice letter as appropriate, by the responded utilities to implement AB811.”  A workshop was held on December 1, 1999 followed by Rule 22 meetings on December 14, 1999 and January 11, 2000.  

At the workshop, San Diego Gas & Electric (SDG&E) stated that the provisions of AB811 only applied during the rate freeze period, and that since SDG&E had ended its rate freeze there was no need for SDG&E to file an Advice Letter.  All parties, including the Energy Division, endorsed this conclusion. 
 
On January 14, 2000 Edison and PG&E filed their respective Advice Letters to implement the provisions of AB811 as required by the CCR.

Notice 

Notice of PG&E Advice Letter 1953-E and Edison Advice Letter 1430-E was made by publication in the Commission’s Daily Calendar.  PG&E and Edison state that a copy of their Advice Letters were distributed in accordance with Section III-G of General Order 96-A.  
Protests

PG&E’s Advice Letter 1953-E and Edison’s Advice Letter 1430-E were timely  protested by Energy Management Services (EMS) and the University of California/California State University (UC/CSU).

EMS seeks clarification of an issue raised in the AB811 implementation workshop relating to customer notification.  EMS requests that the utilities notify “all eligible” customers about their need to make a one-time election by June 30, 2000.  This would include not only direct access customers who already have a meter installed but also bundled service customers who may already have, or choose to have installed, the necessary metering equipment.

UC/CSU request that customers be allowed to make an annual selection as to which methodology they choose to use rather than a “one-time selection” as proposed by the utilities.

PG&E and Edison responded to the protests.  

Discussion

AB811 will only be effective during the rate freeze period for California’s investor-owned utilities. The provisions of AB811 refer to the calculation of the PX credit and not PX charges. Once the rate freeze ends there will no longer be a PX credit.  The methodology proposed by AB811 for calculating the PX credit after June 30, 2000 can only be implemented by those utilities which are still under the rate freeze provisions of AB1890.  It is for this reason that the Energy Division concluded during the implementation workshop, and all parties agreed, that SDG&E did not need to file an Advice Letter to comply with the provisions of AB811.  

Energy Division has reviewed the tariff revisions proposed by Edison and PG&E and finds them reasonable.  

The request of UC/CSU that customers be allowed to make an annual selection as to which methodology they prefer should be denied because it is precluded by the provisions of AB811.  As both Edison and PG&E state in their response to UC/CSU’s protest, AB811 only allows customers to make their elections “on a one-time basis before June 30, 2000.”  AB811 does not provide for an annual selection process. 

Since the provisions of AB811 are only applicable during the rate freeze, any election made by customers by June 30, 2000 should only remain in effect for a maximum time period of 21 months depending upon the end of the rate freeze.  Therefore, it is unclear if the benefits of allowing for an annual selection period, even if allowed by AB811, would be worth the administrative effort.

We find some merit with EMS’ suggestion that all affected customers should be notified of their need to make a one-time selection by June 30, 2000, a position opposed by Edison and PG&E.  As EMS notes:

There are bundled customers that have interval meters in place or can have an interval meter in service by June 30, 2000.  For instance, there are many commercial and industrial customers that would have returned to bundled service and would have the requisite meter in place.”  

The most likely customers to be affected by AB811 are the larger customers with suitable interval meters already installed.  These customers – whether bundled or on direct access – should be notified of their options under AB811. 
EMS suggests, and we agree, that the level of notification need not be complex.  EMS suggests, for example, that :

[T]he notice could be as simple as a statement that (1) AB811 provides an opportunity that expires on June 30, 2000, (2) points the customer to a CPUC World Wide Web URL, and (3) informs customers that they must act quickly if they want to pursue the option. 

The utilities should provide this level of notice to their larger customers affected by AB811, except that they should direct inquires to their own web sites (not the Commission’s) as well as the applicable customer service telephone number of each utility for further information.

AB811 states that the utilities may recover through rates “the incremental billing costs incurred” in implementing the provisions of AB811.  Neither PG&E nor Edison has provided estimates of the costs of implementing AB811.  In a letter to the Assembly Daily Journal Assemblymember Fred Keeley, author of AB811, stated:

During the debate on AB811 in Senate Energy, Utilities, and Telecommunications Committee on July 13, 1999, testimony by the affected utilities revealed a wide disparity as to the cost of implementing these provisions.  Cost ranges from $250,000 to $1 million were indicated by PG&E, yet Edison testified that the cost would be de minimis.  As a result, discussion centered around a cost cap and what if any, costs would be recoverable.  Ultimately, the committee was reluctant to place a cap in the bill, anticipating that the affected utilities would seek to recover costs at the upper limit of any cap, regardless of the actual costs.  Therefore, the committee resolved that any determination regarding the reasonableness of such costs and their possible recovery should fall to the Commission and be examined under existing procedures used in reasonableness reviews by that body.

Edison requests establishment of a new memorandum account to track implementation costs, and Edison’s request is approved. 

PG&E did not provide any tariff revisions to record its implementation costs.  Consistent with long-standing Commission policy, PG&E must have an appropriate account in which it may book recorded expenses prior to seeking their recovery in rates. In its comments on the draft Resolution, PG&E suggests, and we agree, that its implementation costs should be recorded in its Electric Restructuring Cost Account. Actual recovery in rates of any costs booked to any memorandum account associated with implementation of AB811 will require a subsequent order of the Commission.  We would expect that the total amount of costs sought for recovery should be consistent with the estimates that the utilities provided to the California State Senate.  

Neither PG&E nor Edison addressed the provisions of AB811 that as a result of its implementation there “shall not be any shifts in costs between customer classes…consistent with the firewall provision set forth in subdivision (e) of Section 367.”    

In their applications for rehearing of D.97-08-056, both Edison and PG&E asserted that adoption of the average CTC method instead of the residual CTC method would result in the utilities collecting less in CTC revenues, thereby affecting the utilities’ “ability to fully recover transition costs before the end of the transition period.” Although the Commission rejected the utilities’ assertions as unpersuasive, AB811 now precludes any new customers from using the average CTC method after June 30, 2000.   The adoption of AB811, according to the utilities’ stated position, should have a positive effect in increasing the amount of CTC recovery.  Since no party (including the utilities) raised the issue of cost-shifting as a result of AB811, we conclude that its effect is either minimal or non-existent and that no further ratemaking actions are necessary to implement this provision of AB811.

Comments

The draft Resolution of the Energy Division in this matter was mailed to parties in accordance with Public Utilities Code Section 311(g) on April 4, 2000.  Comments were filed by Edison and PG&E on April 18, 2000.  The major concern expressed by Edison and PG&E was the draft Resolution’s requirement that all eligible customers be notified about the provisions of AB811.  Edison and PG&E both state that only those customers likely to be affected by AB811, which are the larger customers who already have hourly meters installed, need to be notified.  The draft Resolution has been changed to reflect this concern.  Additionally, PG&E clarified that it intends to seek recovery of its AB811 implementation costs through its ERCA account. 

Findings

1.	Southern California Edison (Edison) in Advice Letter 1430-E and Pacific Gas and Electric (PG&E) in Advice Letter 1953-E propose tariff revisions to comply with the requirements of Assembly Bill (AB)811 regarding the calculation of the Power Exchange (PX) credit.

2.	There are equity and efficiency advantages to using the average CTC method but it has the disadvantage of preventing some customers from taking advantage of direct access.

3.	The residual CTC method allows all customers to take advantage of direct access but does not offer the equity and efficiency advantages of the average CTC method. 

4.	In D.97-08-056 the Commission adopted the use of the average CTC method to calculate customer bills and reaffirmed its use in D.97-09-125, and D.97-11-026. 

5.	At the time that the Commission was considering the adoption of D.97-08-056 PU Code Sec. 368(b) of AB1890 appeared to preclude allowing direct access customers the opportunity to make a selection as to which method they would prefer to utilize. 

6.	AB811 requires that up until June 30, 2000 direct access customers can make a one-time selection as to which methodology they wish to utilize, either the residual CTC or average CTC methodology, to calculate their rates.  All new direct access customers who have an hourly meter installed on or after June 30, 2000 will have their rates calculated based on the residual CTC method. Existing customers who already have an hourly meter and do not make their one-time selection will continue to have their rates calculated based on the average CTC method.

7.	AB811 requires that the Commission implement a methodology to allow direct access customers to use the residual CTC method.  

8.	AB811 provides that the utilities may recover through rates “the incremental billing costs incurred” in implementing the provisions of AB811; and that there “shall not be any shifts in costs between customer classes…consistent with the firewall provision set forth in subdivision (e) of Section 367.”

9.	AB811 only allows customers to make their elections “on a one-time basis before June 30, 2000” and does not provide for an annual selection process. 

10.	The provisions of AB811 are only applicable during the rate freeze period. 

11.	SDG&E, because its rate freeze has ended, is not subject to the provisions of AB811. 

12.	Edison and PG&E should notify all of their larger customers with suitable interval meters already installed, whether bundled or on direct access, that are affected by this legislation.  

13.	Edison’s request to establish a memorandum account to record implementation costs associated with billing changes should be approved. 

14.	PG&E may record its implementation costs to its Electric Restructuring Cost Account. .

15.	In testimony before the Senate Energy, Utilities, and Telecommunications Committee PG&E estimated the cost of implementing the provisions of AB811 at $250,000 to $1 million while Edison estimated the costs would be de minimis. 

16.	 Actual recovery in rates of any costs booked to the utilities’ memorandum account will require a subsequent order of the Commission.

17.	Since no party (including the utilities) raised the issue of cost-shifting as a result of AB811, we conclude that its effect is either minimal or non-existent and that no further ratemaking actions are necessary to implement this provision of AB811.

18.	The protest of Energy Management Services regarding notification of affected customers should be granted as discussed in this Resolution.

19.	The protest of the University of California/California State University regarding annual selection should be denied as being precluded by AB811.

Therefore it is ordered that:

1.	The request of Southern California Edison Company (Edison) in Advice Letter 1430-E and Pacific Gas & Electric (PG&E) in Advice Letter 1953-E to modify their tariffs to comply with the provisions of Assembly Bill(AB)811 are approved as modified in Ordering Paragraphs #4 and #6.

2.	The provisions of AB811 shall be effective for Edison and PG&E only until the end of the rate freeze for each utility. 

3.	Edison’s request to establish a memorandum account to record implementation costs associated with billing changes is approved.  Actual recovery in rates of any costs booked to this memorandum account shall require a subsequent order of the Commission.

4.	 PG&E may record its  implementation costs to its  Electric Restructuring Cost Account 

5.	Actual recovery in rates of any costs booked to these accounts shall require a subsequent order of the Commission.

6.	Edison and PG&E shall notify all of their larger customers with hourly meters that are affected by AB811 through a notice that explains that: (1) AB811 provides an opportunity that expires before June 30, 2000; (2) points the customer to each utilities’ web site and customer service telephone number; and (3) informs customers that they must act quickly if they want to pursue the option.   Edison and PG&E shall work with the Public Advisor’s Office on appropriate language to implement this requirement.

7.	The protest of Energy Management Services regarding notification of affected customers is granted as discussed in this Resolution.

8.	The protest of the University of California/California State University regarding annual selection is denied.

9.	This Resolution is effective today.  

I certify that the foregoing resolution was duly introduced, passed and adopted at a conference of the Public Utilities Commission of the State of California held on May 4, 2000; the following Commissioners voting favorably thereon:

					___________________
		                                                    WESLEY M. FRANKLIN							 			Executive Director

LORETTA M. LYNCH
          President
HENRY M. DUQUE 
							JOSIAH L. NEEPER
							RICHARD A. BILAS
 CARL W. WOOD
 								Commissioners