Before the Public Utilities Commission of the State of California

Application of PACIFIC GAS AND ELECTRIC COMPANY To Identify Separate Components of Electric Services Industry and Rates, Effective January 1, 1998.
                (Electric)            (U 39 E)	

A.96-12-009

Application of SAN DIEGO GAS AND ELECTRIC COMPANY (U 902-M) For authority to Unbundle Rates and Products.

A.96-12-011

In the Matter Of The Application Of SOUTHERN CALIFORNIA EDISON COMPANY (U 338-E) Proposing The Functional Separation Of Cost Components For Energy, Transmission and Ancillary Services, Distribution, Public Benefit Programs and Nuclear Decommissioning, To Be Effective January 1, 1998 In Conformance with D.95-12-036 As Modified by D.96-01-009, the June 21, 1996 Ruling of Assigned Commission Duque, Decision 96-10-074, and Assembly Bill 1890.

A.96-12-019	

CONCURENT REPLY BRIEF OF THE
OFFICE OF RATEPAYER ADVOCATES

CATHERINE A. JOHNSON
Staff Counsel

Attorney for the Office of Ratepayer Advocates

California Public Utilities Commission
505 Van Ness Ave.
San Francisco, CA 94102
Phone: (415) 703-1385
May 9, 1997	Fax: (415) 703-4432

Before the Public Utilities Commission of the State of California

Application of PACIFIC GAS AND ELECTRIC COMPANY To Identify Separate Components of Electric Services Industry and Rates, Effective January 1, 1998.
                (Electric)            (U 39 E)	

A.96-12-009

Application of SAN DIEGO GAS AND ELECTRIC COMPANY (U 902-M) For authority to Unbundle Rates and Products.

A.96-12-011

In the Matter Of The Application Of SOUTHERN CALIFORNIA EDISON COMPANY (U 338-E) Proposing The Functional Separation Of Cost Components For Energy, Transmission and Ancillary Services, Distribution, Public Benefit Programs and Nuclear Decommissioning, To Be Effective January 1, 1998 In Conformance with D.95-12-036 As Modified by D.96-01-009, the June 21, 1996 Ruling of Assigned Commission Duque, Decision 96-10-074, and Assembly Bill 1890.

A.96-12-019	

CONCURENT REPLY BRIEF OF THE
OFFICE OF RATEPAYER ADVOCATES

The Office of Ratepayer Advocates (ORA) of the California Public Utilities Commission (Commission) pursuant to the Commission’s Rules of Practice and Procedure and the briefing schedule adopted by the Administrative Law Judge, respectfully submits its Concurrent Reply Brief on the unbundling of major rate components for electric industry restructuring.
I.	Introduction 
In this reply brief, the Commission’s Office of Ratepayer Advocates (ORA) responds to selected issues addressed in opening briefs (OB) of parties to the December 6, 1996, ratesetting applications of Pacific Gas and Electric Company (PG&E), San Diego Gas and Electric Company (SDG&E), and Southern California Edison Company (SCE) (Collectively, “Applicants”).
II.	Scope and Objectives of Proceeding
A.	The Adopted Level of Unbundling Should Allow Industry Structure to Evolve
ORA’s Exhibit 41 (p. 4) noted that the utilities’ cost allocations would produce a category in this proceeding that would be better called “UDC” functions than “distribution”, and recommended undertaking a more comprehensive separation of non-competitive, semi-competitive, and fully competitive functions within the electric industry, as the Commission has done in telecommunications.  Noting that the intervenor testimony on separation of customer service functions (a) generally brings up broader needs for a ratesetting structure that can avoid cross-subsidization between utility functions, while (b) it does not necessarily require the unbundled functions to be subject to competition. ORA’s Exhibit 42 clarified that ORA has no objection to adopting a more refined approach in the near term, and recommended concepts for a near-term basis for the longer-term examination of unbundling that ORA has recommended.  The Utility Reform Network’s (TURN) and Utility Consumers Action Network’s (UCAN) OB (e.g., p. 2) eloquently presents the reasons why, once the Commission has established an initial rate unbundling, the utilities must be directed to present a “bottoms-up” review of their accounts and activities in order to achieve a more precise identification and assignment of their costs, and why the rates that are implemented as of January 1, 1998, should be set subject to subsequent adjustment.
Cross-examination revealed that the identification of competitive functions would be incomplete unless recommendations like TURN/UCAN’s are adopted.  For example, ORA’s cross-examination of SCE’s witness Ziegler revealed a presumption that SCE’s Customer Service and Information costs (which TURN/UCAN characterizes as marketing) would not be performed by other energy service providers:
Q.	Are there any activities among the ones you've listed for which energy service providers other than the UDC will incur costs in order to serve their own customers?
A.	Not that are not recovered by them.  In other words -- let me explain -- they may offer services for profit.
Q.	Which of these services will they have to engage in?
A.	I would not speculate on that.  That would be their choice as they enter the marketplace.
Q.	Certainly there are some that they're going to have to do just as Edison has to do?
A.	I don't believe so because they will be providing generation power.  These services are related to the distribution utility services, not generation provision.
…
MR. BERDGE:  Q.  If these energy service providers do engage in some of these activities that you've identified for Edison, will that permit Edison to reduce any of its costs of operation because these energy service providers take over some of these responsibilities?
A.	No, sir, it will not.
Q.	And why is that?
A.	Because all of the customers will continue to be connected to the electric wires, and these services have to do with consulting with them on power quality, with helping them to select the best regulated tariff that the UDC will continue to offer, assisting them with energy safety and energy efficiency.  So these services will continue to all customers even those with direct access.  (6 RT 754, 756-758)

Ms. Ziegler’s opinion that other energy service providers (ESPs) would not need to engage in these activities was not supported by the testimony of witnesses representing ESPs.  Instead, these witnesses demonstrated that they are necessary activities for ESPs, and either will be part of the utility’s competitive activity or will be unnecessary for the utility to perform.  As Enron’s witness Tabors stated, they are competitive activities:
Q.	Turning to page 17 of your testimony, in the last question and answer on that page, starting on line 19 -- … you discuss the assignment of administrative and general costs.  Does the proper pricing of a regulated firm's products when it participates in competitive markets involve allocation of both direct and common costs?
A.	Yes.
…
Q	Do you have any understanding as to whether retailers other than the utility distribution company are likely to incur costs for the analysis for customers of regulated tariff options?
…
A.	An unregulated entity who is competing with a regulated entity, which is the way I interpret your question, will carry out analyses of all other options that would be available to a customer while attempting to convince that customer that the service and the price that they are providing is more advantageous.
Q.	Would marketers also incur costs associated with market research on customer satisfaction with service?
A.	Yes.
Q.	And would marketers incur costs associated with education to customers on technologies that would improve their business processes?
A.	Yes.  Absolutely.
…
Q.	Based upon your experience with customers -- and we're talking about customers receiving services from marketers -- … would you expect that customers would also expect to receive the same services, such as analysis of tariff options or research on customer satisfaction or education, also from the utility distribution company?
A.	I would expect that if, by utility distribution company, you mean someone who is an entity that is also capable of delivering electricity to that customer, then the answer would be yes; I would expect that they would in fact be looking to provide those same value-added services in this quasi-competitive market that I believe you've just described where I have some people who are -- some entities who are regulated still, and I have others who are simply competing at market prices.  (9 RT 1181-1184)
while as Southern Energy’s witness Muller stated, they will be unnecessary for the utility to perform in the future:
Q.	I would like to ask you a few questions to determine some of the ways that Southern Energy's customers would be affected by the decision coming out of this proceeding.  First, will Southern Energy need to engage in analysis of regulated tariff options in order to serve its retail customers?
A.	Yes.
Q.	Will Southern Energy need to engage in market research on customer satisfaction with service as part of providing service?
A.	Yes.
Q.	Will Southern Energy need to engage in customer education activities concerning ways to improve its customers' energy usage?
A.	Absolutely.
Q.	In your view are services like these essential or optional to a retailer such as Southern Energy?
A.	Essential.
Q.	Do you believe Southern Energy's customers will call upon the UDCs to duplicate the customer service activities that Southern Energy provides?
A.	No.  That is why they hire us.  (10 RT 1261-1262)
The Commission has also disagreed with SCE that activities such as assistance to customers concerning the use of technology are essential for funding by the utility.  SCE’s witness Ziegler asserted that this activity is essential:
MR. BERDGE:  Q  Ms. Ziegler, why would Edison need to provide technologies to improve their business process, that you referred to in your testimony, to customers of Edison when Edison is a wires company only?
A.	One of the services that we provide which is a benefit to all participants in the marketplace, other providers as well as generators, is to help customers to use electricity in the most efficient way that they can.  Technologies, in some cases, will increase the use of electricity; in some cases it will be energy-efficient electricity.  But those are services to help customers to operate in a more efficient way.  And those would continue to need to be offered to customers in addition to what other providers are offering.  (6 RT 759-760)
However, Ms. Ziegler admitted that although SCE requested funds in its 1995 rate case for customer technologies and technology commercialization, SCE did not receive authorized funds for those activities.  (6 RT 768 and 770)
Examples like these marketing activities initially addressed by TURN/UCAN illustrate the importance of not stopping with the initial rate unbundling that can be accomplished in this proceeding, but instead undertaking a more detailed review of the utilities’ accounts and activities during the transition period of electric industry restructuring.
III.	Separation of Revenue Requirement
A.	Comments Common to All Applicants
1.	Principles for Unbundling Should Promote Effective Competition
As explained in ORA’s OB (pp. 4-7, 15-16), PG&E’s reliance on incremental cost analysis principles misrepresents the underlying economic theory (as do the other utilities’ proposals).  PG&E’s OB asserts that its proposal to allocate none of its “residual” costs to generation is supported by its consulting economist Parsons. (pp. 17-19)  This misrepresents Dr. Parsons’ testimony.  First, Dr. Parsons clarified during cross-examination that in referring to a “lower bound for pricing”, prices could be higher than that level.  (8 RT 1013-1014)  He further stated that to remain viable, any firm must be able to recover all of its costs through the sum of the prices for all of its services.  (8 RT 1008)
Furthermore, cross-examination revealed that Dr. Parsons had not analyzed several pertinent factors that are necessary before reliance can be placed on his testimony. His prepared testimony (Ex. 3, p. SGP-2) stated that PG&E’s generation cost estimates are probably overstated due to technological improvement over time. However, he admitted that he did not know whether California’s electricity market is currently considered to be over capacity; nor had he thought about whether, in this circumstance firms that enter the market would use existing plants rather than build new plants. Further, Dr. Parsons was unsure of “the details” of the utilities’ plans to divest existing generation plants.  (8 RT 1010-1011)  In his prepared testimony Dr. Parsons acknowledged that the “net incremental cost test” (which accounts for cross-elastic effects) is theoretically superior to the “gross” test that he had considered. (Ex. 3, p. SGP-4) However, cross-examination showed that he had not “made any determination or attempted to make analysis in any detailed form at all as to whether any cross-elasticity effects exist” (8 RT 1011-1012), and that there could be cross-elasticity effects if a utility’s activities included customer energy information or assistance with choosing or installing energy efficient technologies. (Ibid.)
Notably, Dr. Parsons also testified that some marketing costs are volume-sensitive.  (8 RT 1008)  This supports TURN/UCAN’s recommendation to include the generation function in the allocation of marketing costs.
PG&E’s arguments concerning allocation of common costs seek support from sources like CPUC D.94-09-065, using citations such as:  “the Commission has decided that incumbent telephone utilities are not required to allocate common overhead costs (i.e., residual costs) to Category II or Category III services.”  (PG&E OB, p. 18, referring to D.94-09-065, pp. 32-34)  However, the cited pages (32 to 34) do not discuss the question of allocation of overhead or residual costs.  This omission is not equivalent to a decision that an allocation is not required.  The silence in the cited pages on any number of other issues can hardly be interpreted as a decision to forego any number of other requirements.  Instead, the Commission thus indicates that category II (semi-competitive) services should have a price floor, implying that the utility’s pricing strategy can include prices higher than the floor to recover contributions to the common costs of overhead. 
Regarding monopoly (Category I) services, D.94-09-065 states at page 34:  “for monopoly services, prices should be cost-based, and our guideline is that rates for Category I services should equal the DEC [direct embedded cost] of the service.”  Thus, the decision suggests that the price of monopoly service, which in the present electric cost-separation proceeding is transmission and distribution, should contain no component of common costs beyond direct embedded cost.  Although recovery of generation costs, including generation’s share of common costs, will involve issues to be addressed by the PX, the ISO, and the CPUC’s divestiture and CTC proceedings, costs must be determined in this proceeding for the regulated functions of transmission and distribution, for the purpose of cost separation effective January 1, 1998.  ORA has recommended that the best way to find the share of current common costs that belongs to transmission and to distribution is through the use of a reasonable allocator to allocate all current common costs among all functions, including generation.
B.	PG&E
(Section not used.)
C.	SCE
1.	SCE Should Allocate Its Franchise Fees Between Generation and Non-Generation.
In its opening brief, SCE asserts that Section 6353 of Senate Bill (SB) 278 requires SCE to collect franchise fees from direct access customers based upon an imputed calculation of the customer’s usage and that, therefore, ORA’s franchise fee allocation recommendation is moot.  SCE explains that Section 6353 of SB 278 requires SCE to multiply the customer’s energy usage by the “weighted average cost” of the energy and then to multiply that figure by a franchise factor for direct access customers.  (SCE OB, pp. 61-62)
Actually, SCE’s explanation of Section 6353 of SB 278 supports ORA’s position that franchise fees should be allocated between generation and non-generation functions.  ORA’s witness, Ms. Tan,  testified:
“I was just trying to make sure there are certain principles being applied to the cost allocation.  And one is that if the other generator suppliers based on the outcome of the Legislature, would have to charge their customers or they would collect franchise fees in some form, then the UDC have to do the same for the generators that it owned.”  (12 RT 1560)
According to SCE’s interpretation of Section 6353, SCE would collect some franchise fees for the direct access customers who procure generation from other market suppliers.  Based on ORA’s principle stated above, SCE should also collect franchise fees from its bundled customers for SCE’s own generation.  As ORA pointed out, the current franchise fees contain embedded fees for both generation, transmission and distribution, i.e., total sales.  (12 RT 1561)  To allocate all of its own franchise fees to non-generation as SCE proposes, would result in the generation-related franchise fee costs being included in the T&D rates.  Consequently, a direct access customer might be charged the generation-related franchise fees twice: one is embedded in SCE’s T&D rates and the other is a separate franchise surcharge as required by Section 6353 of Senate Bill (SB) 278.
PG&E believes that it should allocate the franchise fees among the functions (Ex. 17, pp. 2-13 & 2-14);  SDG&E allocated at least the ECAC related franchise fees to generation (7 RT 918).  There is no reason that SCE should be allowed to shift all of its generation-related franchise fees to the non-generation sectors.  SCE should be directed to allocate its franchise fees between generation and non-generation such that its generation business is not afforded a competitive advantage over other generation suppliers.
D.	SDG&E
SDG&E’s OB misstates ORA’s recommendations and/or positions in important areas.
1.	SDG&E Has Mischaracterizes ORA’s Positions on Cost Recovery And Cost Separation.
In supporting its opinion that it is appropriate to determine the distribution revenue requirement on a residual basis, SDG&E states:
“ORA agrees with SDG&E that the correct process for unbundling is to separate revenue requirements based upon SDG&E’s last GRC and subsequent PBRs.  ORA also agrees that the residual determination of the distribution revenue requirement is appropriate (see generally, Exh. pp. 1-4 and pp. 7-8).  ORA just disagrees with SDG&E on the correct escalation methodology to apply between 1993 and 1996.”  (SDG&E OB, p.6, lines 18-21)
SDG&E misrepresents ORA’s testimony. ORA has not stated or implied the views summarized by SDG&E above. ORA’s direct testimony expressed concerns about SDG&E’s direct cost allocation approach.  For instance, ORA pointed out that SDG&E:
“Rather than assigning or allocating the individual components of the 1996 ECAC revenue requirement (which includes its PBR base rate revenue) to the various functions, it derives the functional revenue requirements from other sources (e.g., 1993 GRC, D.92-12-019, and AB1890), except for the CTC revenue requirement.”  (Ex. 41, p. 6)
ORA’s silence on certain issues should not be interpreted as agreement with any particular position.  As ORA stated in its testimony, it anticipated exploring direct cost allocation issues further in hearings and briefs.  (Ex. 41, p. 5)  Consequently, ORA set forth its recommendations in its opening brief.  ORA’s recommendation regarding SDG&E’s distribution revenue is specifically addressed in ORA’s opening brief, section III.D.2 (p. 23).  ORA’s OB states agreement with intervenors that the utilities’ residual approach to setting the distribution revenue requirement is inappropriate. (ORA OB section III.A, p. 19)
2.	SDG&E’s Load Dispatching Costs Should Be Assigned to the Generation Function
SDG&E argues that it is appropriate to allocate the $3.3 million expenses relating to system control and load dispatching to its combined transmission and distribution revenue requirement because the company will continue to incur load dispatching costs for the foreseeable future.  (SDG&E OB, p. 17)  SDG&E, then, goes on to suggest that it makes no sense for the Commission to remove costs associated with load dispatching from SDG&E’s revenue requirement only to reinstate them after January 1, 1998; and points out that ORA’s witness made her recommendation to disallow these costs without knowledge of the power quality needs of SDG&E’s manufacturing customers. (Id., p. 18)
It appears that SDG&E may be confused.  ORA has not recommended disallowing the expenses relating to system control and load dispatching; instead, ORA mainly recommends that these costs be properly assigned to the generation function because these are production (generation) related expenses as SDG&E has identified.  (Ex. 41, p. 8)  Further, because SDG&E continues to suggest that it has no plan to divest any generation facilities in the near future (Ex. 8, pp. IV-1, IV-2), these generation O&M expenses are properly allocated to the generation function as they incur.  SDG&E, seems to believe that allocating expenses to the generation function represents a “disallowance” of the expenses.  ORA disagrees.  The utilities are allowed the opportunity to recover their generation costs through various channels, such as through transition cost recovery, or the power exchange market, and through the ISO contracts for providing services such as ensuring power quality and reliability.
3.	Franchise Fees and Uncollectibles Should Be Allocated Between Generation and Non-Generation Functions
SDG&E argues that its witness, Mr. Swanson, clarified on the stand that SDG&E did allocate some Franchise Fees and Uncollectibles (FF&U) to generation revenue requirement.  (SDG&E OB, p. 18)  However, in its opening brief, SDG&E failed to mention that there is a distinction between the FF&U expenses associated with the ECAC (and ICIP) and those associated with base rate revenues.  Mr. Swanson explained that the ECAC-related FF&U was assigned to the generation revenues (7 RT 918), and ORA takes no issue with that.  However, SDG&E allocates 100% of base rate-related FF&U to the combined transmission and distribution revenue requirement.  (Ex. 8, p. II-2)  SDG&E’s witness Swanson, acknowledged that there are also capital costs and operating costs of the fossil-fired generation plants being included in SDG&E’s base rate revenue requirement.   (7 RT 924)
In SCE’s non-generation PBR, the Commission ordered SCE to allocate the uncollectibles associated with base rate revenue requirements to generation and non-generation based on total other expenses.  (D.96-09-092, ordering paragraph A.1.f) In its opening brief, ORA explains that the same logic should be applied to the franchise fees.  (ORA, OB, p. 14)  Therefore, the Commission should direct SDG&E to allocate its FF&U associated with base rate revenues between generation and non-generation (transmission and distribution) functions.
IV.	
 Revenue Allocation and Rate Design
A.	Comments Common to All Applicants
1.	Rate Design for Competition Transition Charge, Direct Access and Virtual Direct Access Should Promote the Commission’s Restructuring Goals and Result in Appropriate Price Signals
ORA’s OB (pp. 34-38) explains why ORA’s proposed rate design for CTC charges to direct access and virtual direct access customers is the correct approach for accomplishing the goals of the Commission’s policy decision (D.95-12-063) and is fully consistent with AB 1890.  In order to achieve the Commission’s goals such as transparent, reliable price signals even during the transition period, ORA recommends calculating the CTC charge as a rolling average for each time-of-use (TOU) period in the customer’s billing period. The CTC rate would be calculated for the customer’s otherwise-applicable tariff (which in turn would be based on a rolling average PX cost and schedule-specific load profile). This would allow creation of optional tariffs on which the hourly PX price would be added to other rate components, resulting in a total rate on the optional tariffs that reflects market prices.  (Ex. 41, pp. 25-28;  ORA OB, pp. 34-38)  That is, all customers defined as having the same “otherwise-applicable tariff” would pay the same CTC charge (a simple rate design that precludes cost-shifting). Variations in energy charges for customers who select direct access or virtual direct access options would vary from the energy charges on bundled rates based on their hourly usage and the hourly prices of their energy providers.  In contrast, the utilities’ proposals fail to accomplish the Commission’s goals and the directions of AB 1890. Further,  review of the utilities’ arguments, as summarized in their opening briefs, shows that they are internally inconsistent.
This week, the Commission confirmed its goal of establishing rate options that provide virtual direct access.  D.97-05-039 (unbundling of revenue cycle services, pp. 2-3 mimeo) states:  “In this decision, we also re-affirm the commitment in the Preferred Policy Decision (D.95-12-063 as modified by D.96-01-009) to bring the benefits of the hourly-pricing of electricity created in the Power Exchange (PX) to as many customers as possible.”  D.97-05-040 (direct access states:
“The Preferred Policy Decision ordered the utilities to offer the hourly PX rate option, i.e., virtual direct access, by January 1, 1998 ...  The hourly PX rate option called for by the Preferred Policy Decision requires the utility to offer customers a rate option that allows them to purchase electricity at the prevailing PX price.  Such a rate option allows individual customers to participate in the PX market by providing them with the opportunity to reduce their electricity bills by responding to real time prices.  ...  That is, if a customer is able to shift its electricity demand to a time period when the hourly PX price is cheaper, such a shift could produce savings for this customer.” (D.97-05-040 pp. 36-39.)
A footnote notes that a pending issue is whether the rate freeze (i.e., AB 1890) prohibits any actual bill savings from occurring, and the text defers the development of the hourly PX rate option to this proceeding.  (D.97-05-049, footnote No. 18) ORA’s OB (pp. 34-38) explained that ORA’s proposed CTC rate design is consistent with AB 1890 and promotes legislative goals as well as the Commission’s goals.  PG&E’s witness Pease acknowledged that section 378 of AB 1890 allows the Commission to authorize new optional rate schedules and tariffs that accurately reflect customers’ loads and costs of service, and that AB 1890 does not restrict the creation of rate options that would allow customers to shift demand between hours that have different energy costs and thereby allow the customers to have opportunities to reduce their bills.  (8 RT 1043)
Contrary to the citation in PG&E’s OB (p. 29) that AB 1890’s “section 368(b) requires that direct access customers pay the same non-energy amounts as full service customers”, PG&E’s OB (p. 26) acknowledges that, under its proposal, “the PX cost for direct access customers will be calculated differently than for full service customers.”  Under AB 1890’s rate freeze, simple arithmetic dictates that PX costs cannot be calculated differently while non-PX amounts are to remain the same.
SDG&E asserts that ORA’s proposal would cause some customers to receive bill increases, contrary to the requirements of AB 1890.  (SDG&E OB, p. 19)  However, this misstates ORA’s proposal for virtual direct access to be an optional rate, with a customer’s otherwise applicable schedule to remain under the protection of AB 1890’s rate freeze.  (Ex. 41, pp. 25-28;  ORA OB, pp. 34-38;  13 RT 1715-1718)  SDG&E’s OB (p. 19) states that a utility’s ability to collect CTC revenues should not vary because a customer opts for direct access, while its testimony attributes its lack of a rate option that would reflect hourly prices in energy markets with a principle that a customer’s CTC rate would not vary based on whether the customer has an hourly meter.  (Ex. 10, pp. 16-17)  Cross-examination of SDG&E’s witness Hansen demonstrated, however, that the effect of SDG&E’s rate proposal is in fact to charge customers different CTC rates depending on the presence of an hourly meter, and that under SDG&E’s proposal, a customer who had no change in rate schedule, but for whom an hourly meter is installed, could face an increase in CTC charges.  (3 RT 389-392)
Other utility arguments that do not involve AB 1890 are also unsupported by the record.  PG&E asserts that rate structures like ORA has recommended would produce an inappropriate incentive to elect direct access that runs counter to the basic rationale for electric restructuring, which it purports is fair competition in the electric supply market.  (PG&E OB, p. 28)  However, PG&E’s testimony cites the Commission’s policy decision (D.95-12-063, pp. 77-78) as directing the utilities to make virtual direct access options available to customers no later than January 1, 1998, as it represents a “triple win” benefiting:  (1) customers who reduce cost by shifting load, (2) society at large which defers demand for new generation, and (3) investors in existing plant and equipment who see it put to more productive use.  (Ex. 1, pp. 4-8 to 4-9)  That is, PG&E itself has described the intent of restructuring as something other than a one-dimensional comparison of which supplier has the lowest energy costs.
PG&E asserts essentially that to allow customers’ energy costs to vary with market prices creates the “undesirable” outcome that a customer with a better than class-average load profile could benefit by simply electing direct access and installing an hourly meter, since its energy choice would be based on its actual load profile.  (PG&E OB, p. 28)
PG&E’s argument overlooks its own testimony that customers can already choose service on TOU rates (Ex. 1, p. 4-9), and that PG&E’s existing TOU rates provide an incentive for customers to shift their use to the off-peak TOU period that “may very well be greater” than the rates that would come out of the Power Exchange.  (8 RT 1029)  PG&E offers the existence of TOU rates as a substitute for virtual direct access (Ex. 1, p. 4-9), but acknowledges that (1) the Commission desires an option which reflects current market prices (8 RT 1030-1031) and (2) the rate differential on its TOU schedules has not been updated since its test year 1993 general rate case and is unlikely to be updated before 2002 (8 RT 1044-1045).
SCE asserts that ORA’s recommended CTC rate design has “technical problems” (SCE OB, pp. 72-75), but never identifies any alleged “technical problems” with ORA’s recommendation other than the need to calculate an average PX price for several rate schedules.  SCE does not detail why it would be more difficult to calculate PX costs for several rate schedules than for thousands of individual customers, but if SCE anticipates real difficulty in performing this arithmetic, it will have the opportunity to propose alternatives during the tariff phase of this proceeding.  SCE’s citation of ORA’s testimony that customers will choose their energy supplier based on long term price expectations (SCE OB, p. 76) is a distortion of the record that does not require elaboration here, since ORA’s testimony is clear from the cited transcript.
PG&E’s statement (OB, p. 29) that it is remarkable that at a time when increased accuracy through hourly meters is universally considered desirable so that customers fully understand their cost of service, parties would consider basing a bill component on an average, even though the desired hourly information is available, would be well-founded if it referred to a rate component that revealed cost of service to customers in a positive manner, as a price signal to which they can respond.  The utilities’ proposals will not provide such price signals (e.g., 8 RT 1032-1035 and 8 RT 1128-1134).  Revealing variations in cost of service to customers through their rates is precisely why ORA has recommended its CTC rate design.  In summary, it is the utilities’ refusal to implement a meaningful virtual direct access option that is incredible in light of the Commission’s clear policy directions.
B.	
PG&E
(Section not used)
C.	SCE
(Section not used)
D.	SDG&E
1.	SDG&E’s Implementation of Rate Reduction Bonds Is Contrary to Commission Policy
As discussed in ORA’s OB (pp. 43-45 and 50-52), implementation of AB 1890’s 10% rate reduction for residential and small commercial customers must not preclude the Commission’s long-standing policy of offering time-of-use (TOU) rates to all customer classes, to reflect cost-causation principles that have been adopted for all capacity costs.  ORA points out that SDG&E has, instead, eliminated such rates for residential and small commercial customers through its Advice Letter 991‑E. In that advice letter, SDG&E represented to the Commission that such closure is appropriate because the “Commission’s vision is hourly rates”. However, in this proceeding SDG&E has failed to propose options to the Commission for these customers to have either hourly or TOU rates.
SDG&E’s OB is particularly troubling in that it not only omits discussion of creating replacements for the options that it sought to close through its Advice Letter 991‑E, but also because it opposes the remaining opportunity for TOU service to small customers, i.e., allowing customers under 20 kilowatts (kW) in size to select Schedule AL-TOU and be eligible for the rate reduction.  SDG&E bases its opposition on “problems of administering the rate reduction and the AB 1890 firewall requirement”.  (SDG&E OB, p. 20)  SDG&E has neither substantiated its assertions of administrative problems, nor identified any obstacles related to AB 1890’s firewall requirement that could not be managed by proper administration of the rate reduction.  Indeed, during SDG&E’s cross-examination, Department of Defense’s witness Brubaker declined to agree that administration of the rate reduction under ORA’s recommendations would be difficult.  (11 RT 1432-1433)  If any such problems did exist, SDG&E’s witness Hansen agreed that the presence of TOU schedules specifically for customers under 20 kW would simplify administration of the rate reduction.  (3 RT 387-388)  Administrative simplicity is simply not an excuse for ducking the Commission’s long-standing endorsement of cost-based rates or AB 1890’s adoption of the rate reduction program.
Therefore, ORA’s recommendation to maintain TOU rate options for residential and small commercial customers should be adopted.
V.	Master Meter Issues
See ORA OB (p. 52).
VI.	Bill Format
A.	Comments Common to All Applicants
1.	Power Exchange Energy Prices Must Be Shown On Bills
Perhaps because it is presented with a touch of humor that is rare in formal filings, ORA finds the California City-County Streetlight Association’s (CAL-SLA) recommendation of the 'Reed Schmidt Footnote' compelling.  (CAL-SLA OB, p. 4)  ORA has consistently recommended that the Power Exchange (PX) price must be stated on all customers' bills.  (Ex. 41, p. 38, and ORA OB, p. 54)  CAL-SLA's recommendation would add the following explanation to the statement of the PX price:  “Charge based on the weighted average costs for purchases through the Power Exchange.  This service is subject to competition.  You may purchase electricity from another supplier.”  This statement would clarify significantly why the PX price is being stated on bills, and puts into action the explanation offered elsewhere in CAL-SLA's OB that making clear information available to consumers will be essential for successful industry restructuring, e.g.:  “all recognize that under classic economic theory, competition will only benefit the informed consumer.”  (CAL-SLA OB, p. 2)  Furthermore, this requirement would be consistent with other recommendations for disclosure that are stated in ORA's OB (pp. 54-55).
2.	Other Information Should Also Be Provided
ORA agrees with position taken by TURN/UCAN (OB, pp.39-43) that the Commission should not be swayed by the utilities' arguments that they can't change their bill formats (other than for those changes they themselves have proposed) by 1/1/98.  Because information provided to consumers will play a critical part in ensuring the success of the new competitive marketplace, the utilities should be directed to implement by 1/1/98 whatever billing changes the Commission might adopt as a result of this process.  ORA also agrees with TURN/UCAN (OB, pp.43-44) that the Commission should rely on bill inserts as necessary to achieve its desired billing format by 1/1/98.  As TURN/UCAN acknowledge, bill inserts could be used to disclose the generation resource mix and emission profile information proposed by TURN/UCAN.  In addition, ORA is pleased to see that, in order to facilitate development of green markets, the California Energy Commission (OB, p. 30) has offered its services to work with the Commission and the PX to make generation source information available to customers.
VII.	Conclusion
As demonstrated in ORA’s OB and this reply brief, ORA’s recommendations in its Exhibits 41 and 42, and in these briefs, are supported by 
the record in this proceeding and reflect sound ratemaking policies.  ORA’s recommendations should be adopted by the Commission.
Respectfully submitted,
					/s/     CATHERINE A. JOHNSON
—————————————
Catherine A. Johnson
Staff Counsel

Attorney for the Office of Ratepayer Advocates

California Public Utilities Commission
505 Van Ness Ave.
San Francisco, CA 94102
Phone: (415) 703-1385
May 9, 1997	Fax: (415) 703-4432