BEFORE THE
PUBLIC UTILITIES COMMISSION
OF THE STATE OF CALIFORNIA

	Application of Pacific Gas and Electric	)
	Company to Identify and Separate		)	      Application 96-12-009
	Components of Electric Rates,		)	   (Filed December 6, 1996)
	Effective January 1, 1998. (U-39 E)		)
	                                                                   	)
	Application of San Diego Gas and Electric	)
	Company (U 902-M) For Authority to		)	      Application 96-12-011
	Unbundle Rates and Products		)	   (Filed December 6, 1996)
	                                                                    	)
	In the Matter of the Application of Southern	)
	California Edison Company (U 388-E)	)
	Proposing the Functional Separation of	)
	Cost Components for Energy, Transmission	)
	and Ancillary Services, Distribution, 		)
	Public Benefit Programs and Nuclear 	)	      Application 96-12-019
	Decommissioning, To be Effective		)	   (Filed December 6, 1996)
	January 1, 1998 In Conformance With	)
	D.95-12-036 as Modified by D.96-01-009,	)
	the June 21, 1996 Ruling of Assigned	)
	Commissioner Duque, D.96-10-074, and	)
	Assembly Bill 1890.				)
	                                                                    	)

Testimony of

Alan Chalfant

On Behalf of

California Industrial Users

Project 6130
February 1997

Brubaker & Associates, Inc.
St. Louis, Missouri  63141-2000

Before the

PUBLIC UTILITIES COMMISSION
OF THE STATE OF CALIFORNIA

Application Nos. 96-12-009, 96-12-011 and 96-12-019

Direct Testimony of Alan Chalfant

Q	PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
A	Alan Chalfant; 1215 Fern Ridge Parkway, Suite 208; St. Louis, Missouri 63141-2000.

Q	WHAT IS YOUR OCCUPATION.  
A	I am a consultant in the field of public utility regulation with Brubaker & Associates, Inc., regulatory and economic consultants.  

Q	PLEASE SUMMARIZE YOUR EDUCATIONAL BACKGROUND AND EXPERIENCE.
A	This is included in Appendix A of my testimony.  

Q	ON WHOSE BEHALF ARE YOU APPEARING IN THIS PROCEEDING?
A	I am appearing on behalf of the California Industrial Users (CIU).  The members of CIU include large industrial customers of Pacific Gas & Electric Company (PG&E) and Southern California Edison Company (SCE or Edison).

Q	WHAT IS THE SUBJECT OF YOUR TESTIMONY?
A	I will address several issues of concern in the December 6, 1996 unbundling filings of PG&E, SCE, and San Diego Gas & Electric Company (SDG&E).  Since CIU members are not large users on the SDG&E system, I will be addressing its proposals only with respect to their similarity or dissimilarity to those of the other utilities.  I will address the following specific issues:
	(1)	The appropriate unbundled distribution and transmission revenue requirements;

	(2)	The proposed methods for functionalizing Administrative and General (A&G) expenses;

	(3)	SCE’s proposed allocations of certain cost components such as nuclear decommissioning costs;

	(4)	PG&E’s proposed proxy for unbundled rates; and

	(5)	SCE’s proposed method of reconciling Power Exchange (PX) bill settlement costs.

Q	HAVE YOU REVIEWED THE FILINGS OF THE UTILITIES ON THESE ISSUES?
A	Yes.  In addition, I have reviewed the workpapers and computer spreadsheets supporting the utilities' filings and have attended nearly all of the sessions of the Ratesetting Working Group (RWG) concerning these filings.

Q	PLEASE SUMMARIZE YOUR RECOMMENDATIONS ON EACH OF THESE ISSUES.
A	(1)	Each utility's 1998 distribution revenue requirement should be established by subtracting the transmission revenue requirement that the utility proposes to the Federal Energy Regulatory Commission (FERC) from the total non-generation revenue requirement.  During 1998, proceedings should be held for all three utilities that would establish their 1999 distribution revenue requirements.

	(2)	The generation function should not be excluded from the allocation of what the utilities have determined to be “common” or “shared” A&G costs.

	(3)	Costs such as Public Benefit program costs and nuclear decommissioning costs currently allocated on an equal percent of marginal cost (EPMC) basis should be allocated in the unbundled rate setting on that same basis rather than on a uniform cents per kWh basis.
	(4)	The Commission should order PG&E to implement actual unbundled rates in lieu of PG&E's unbundled rate surrogate at the earliest possible date.

	(5)	Edison's proposed true-up of PX credits should be revised to avoid the likelihood of over or under-recovery.

Determining the Unbundled Transmission
and Distribution Revenue Requirements   

Q	PLEASE DESCRIBE WHAT YOU PERCEIVE TO BE THE RELEVANT ISSUES CONCERNING THE ESTABLISHMENT OF UNBUNDLED REVENUE REQUIREMENTS FOR TRANSMISSION AND DISTRIBUTION.
A	At the present time, all three utilities have a bundled non-generation revenue requirement approved by the California Public Utilities Commission (CPUC).  Those revenue requirements provide for recovery of all non-generation costs including transmission, distribution and all other costs incurred by each of the utilities.  In establishing those revenue requirements, this Commission did not make a specific determination as to a transmission revenue requirement or a revenue requirement for the non-transmission costs.  Moreover, the information for making such a determination is not available in the records of the cases which established the non-generation revenue requirements.  This is, in part, because the facilities considered to be transmission at the time those cases were decided are different than the facilities defined as transmission in the pertinent FERC orders and, in part, because there was no need to separate transmission and distribution for the purposes of those cases.
	This presents a problem as California continues its implementation of a restructured electric services industry, in light of the transfer from the CPUC to the FERC of the responsibility for determining the transmission portion of the utility revenue requirements.  While the utilities will apply for a determination of their transmission revenue requirements in their forthcoming March 31, 1997 filings at the FERC, there are currently no plans for proceedings in which the CPUC would establish the utilities' distribution revenue requirements prior to the implementation of restructuring on January 1, 1998.

Q	HOW HAVE THE UTILITIES PROPOSED TO DETERMINE THEIR DISTRIBUTION REVENUE REQUIREMENTS ONCE THE FERC HAS ESTABLISHED A TRANSMISSION REVENUE REQUIREMENT?
A	The utilities have all proposed that their distribution revenue requirement be set residually by subtracting the FERC approved transmission revenue requirement from the total non-generation revenue requirement.  SCE proposes a rate credit approach which, while different in form, produces the same results as the revenue credit approach.  This difference relates to the particulars of SCE's non-generation performance-based ratemaking (PBR) mechanism which will have to be taken into account in fashioning a solution to this revenue requirement issue.  Otherwise, my analysis and proposed alternative approach are as applicable to SCE's rate credit mechanism as they are to the revenue-based proposals of PG&E and SDG&E. 

Q	DID ALJ WEISSMAN'S JANUARY 31 RULING IN THIS MATTER ADDRESS THIS ISSUE?
A	Yes.  In that Ruling, the ALJ stated:  “It is not sufficient to suggest that a category such as Distribution can be determined on a residual basis.  Each dollar must be related to and reasonable in light of a category of activity or expense that is clearly a part of the broader functional area.  Each applicant should re-examine its application in light of this requirement and offer supplemental information, as needed, no later than February 14, 1997.”

Q	DID THE UTILITIES MAKE SUPPLEMENTAL FILINGS IN WHICH THIS ISSUE WAS ADDRESSED?
A	Both SCE and PG&E addressed this issue in Supplemental Testimony filed on February 14, 1997.  SCE clarified why it feels its “rate credit” method is necessary and proper.  PG&E also restated its arguments in favor of a residual determination of the distribution revenue requirement but concluded:  “Nevertheless, if the Commission rules that the distribution revenue requirement for 1998 may not be determined on this residual basis, PG&E’s filing provides ample support for assigning costs to distribution on a functional basis.”  (PG&E Supplemental Testimony, Page 2-1)

Q	WHAT ARGUMENTS HAVE THE UTILITIES OFFERED IN SUPPORT OF THE RESIDUAL APPROACH TO DETERMINING THE DISTRIBUTION REVENUE REQUIREMENT?
A	There appear to be two basic arguments.  The first argument is that the residual approach is necessary to insure that the rates adopted in this proceeding plus the rates adopted by the FERC for transmission will not over or under-collect the revenue requirement last adopted by the CPUC.  As stated by PG&E in its Supplemental Testimony, “PG&E should not enjoy a windfall or suffer a shortfall because of unbundling.”  (PG&E Supplemental Testimony, Page 2-1)  The second argument is that the residual approach eliminates the need for litigation of a new distribution revenue requirement.

Q	WHAT IS YOUR POSITION CONCERNING THE RESIDUAL APPROACH TO DETERMINING THE DISTRIBUTION REVENUE REQUIREMENT?
A	I oppose it as now proposed.  I agree that it would stress the resources of all the parties as well as the Commission and its Staff to develop distribution revenue requirements for all three utilities from the ground up during 1997.  I cannot, however, agree with the argument that they should be fully protected from any revenue impact resulting from the change in jurisdictional responsibility for a portion of their costs.  Contrary to PG&E’s concerns that it should not suffer a shortfall because of unbundling, it is not unbundling that causes that concern.  Rather, it is the fact that a different regulatory authority will have jurisdiction over a portion of its costs that were formerly regulated by the CPUC.   Thus, the utilities have known, or should have known, for some time now that the amount of their non-generation revenue requirement was not something to be taken for granted.  

Q	WHAT FACTORS COULD BRING ABOUT DIFFERENCES BETWEEN FERC AND CPUC AUTHORIZED REVENUE REQUIREMENTS FOR TRANSMISSION SERVICE?
A	There are many.  The following are just a few examples.  First, the allowed rate of return could differ between jurisdictions.  In fact, it probably should be different because the risk associated with the costs regulated by the FERC is likely to be different than the risk associated with the costs last determined by the CPUC.  Second, there could also be differences in policies concerning depreciation and all other elements of cost.  Third, the test years used to establish rates could well be different.  Fourth, the method of separating wholesale and retail cost responsibilities could differ.  In all of these cases, the utilities should be subject to the FERC with respect to the determination of transmission revenue requirements rather than to be left indifferent as would be the case if this Commission promised to allow the utilities to recover in their distribution rates any costs denied by the FERC.

Q	UNDER THE RESIDUAL DETERMINATION OF THE DISTRIBUTION REVENUE REQUIREMENT PROPOSED BY THE UTILITIES, WHO WOULD BEAR THE RISK THAT THE UTILITIES JUSTIFY TO THE FERC THE LEVEL OF COSTS THEY DEEM TO BE THE TRANSMISSION PORTION OF THEIR NON-GENERATION REVENUE REQUIREMENTS?
A	Under the utilities' proposal, the distribution customers of the utilities bear that risk.  Thus, to the extent that the utilities do not make an adequate showing to the FERC in support of their claimed transmission revenue requirements, any of the requested revenue denied by FERC would simply flow through to raise the level of distribution rates.

Q	ARE YOU AWARE OF ANY PARTICULARLY TROUBLESOME POSSIBILITIES PRESENTED BY THE RESIDUAL METHOD?
A	Yes.  Many FERC proceedings are resolved by settlements among the parties.  It appears that under the residual method of determining the transmission revenue requirement, it may be possible for the utilities to make up for concessions granted to wholesale customers with higher distribution rates.  This is totally improper.

Q	DO YOU HAVE ANY SUGGESTIONS FOR A PROCEDURE THAT WOULD SEPARATE CPUC AND FERC AUTHORITY IN DETERMINING DISTRIBUTION AND TRANSMISSION REVENUE REQUIREMENTS, RESPECTIVELY, WITHOUT REQUIRING LITIGATION OF THE UTILITIES' DISTRIBUTION REVENUE REQUIREMENTS IN 1997?
A	Yes.  On March 31, 1997 the utilities will be making filings with the FERC to establish their transmission revenue requirements.  Those filings will reflect the costs of the facilities that the FERC has found to be under its jurisdiction.  It is my recommendation that each utility’s 1998 distribution revenue requirement be established by subtracting the proposed revenue transmission revenue requirement from the total non-generation revenue requirement.  In the case of SCE, the proposed transmission rates would be subtracted from the total non-generation rates.  This will insure that the costs for each function properly match the facilities now assigned to that function.  (The CPUC revenue requirements determined in this manner would remain in place until changed by the CPUC.  Any FERC decision addressing transmission revenue requirements could change a utility’s transmission rates but not its distribution rates.)

Q	WHAT ARE THE ADVANTAGES OF THIS APPROACH?
A	I believe it resolves most of the problems associated with the proposed residual approach.  First, it does not require CPUC rate cases in 1997 to determine the distribution revenue requirement.  Second, it preserves the CPUC’s established revenue requirement related to the facilities under its jurisdiction.  Third, it preserves the authority of the FERC to establish transmission revenue requirements.  Fourth, it provides the utilities with a strong incentive to file accurate estimates of their transmission costs with the FERC.  Finally, it eliminates any potential incentive for a utility to make rate concessions in favor of its wholesale customers at the expense of its retail customers.

Q	ARE YOU RECOMMENDING THAT THE 1998 DISTRIBUTION REVENUE REQUIREMENT ESTABLISHED AS YOU HAVE PROPOSED BE USED AS THE STARTING POINT FOR OPERATION OF DISTRIBUTION PBR’S?
A	No.  While I believe that my recommendation preserves the CPUC’s latest established distribution revenue requirements, I agree with the need for a bottom-up determination of the utilities' distribution revenue requirements as soon as possible.  In particular, it would be improper to allow several annual escalations of a distribution revenue requirement that was derived on the basis of a return on equity established for generation, transmission and distribution plant.  Therefore, I recommend that proceedings be held during 1998 to establish the 1999 distribution revenue requirements of all three utilities.  Such a proceeding is already contemplated in the case of PG&E.

The Allocation of A&G Expenses
Q	WHY IS THE TREATMENT OF A&G EXPENSES AN ISSUE IN THIS PROCEEDING?
A	Because the amount of the total non-generation revenue requirement is affected by the way these costs are spread among the various functions.  Specifically, an understated allocation of A&G expenses to the unregulated (and partially divested) generation function will result in an overstatement of the regulated transmission and distribution revenue requirements.  Not surprisingly, all of the utilities have proposed unreasonably low allocations of A&G expenses to the generation function.

Q	HOW WERE THESE COSTS TREATED IN PAST RATE CASES OF THE UTILITIES?
A	Because there was no need to arrive at a functionalized unbundling of costs, it was not necessary to make such determinations in past rate cases.  In order to arrive at an unbundled cost for each component, however, it is necessary to assign a portion of A&G costs to each function.

Q	HOW HAVE THE UTILITIES UNDERSTATED THE AMOUNT OF GENERATION A&G EXPENSES?
A	Both PG&E and SCE recognize that there is a “shared” (PG&E) or “common” (SCE) pool of A&G costs that cannot be attributed to a specific function based on cost-causation.  For PG&E, this shared pool represents about $108 million which is more than 27% of total A&G costs and approximately 9% of total operating expenses.  My best estimate for Edison is that its common pool is in the neighborhood of $175 million which is a little less than 50% of total A&G and about 12% of total operating expenses.  However, neither utility assigns any of these costs to generation.

Q	WHY HAVE NONE OF THESE COSTS BEEN ALLOCATED TO GENERATION IN THE UTILITY PROPOSALS?
A	The utilities have used a decremental approach and have determined on that basis that no A&G costs will go away when the utility is no longer responsible for the generation function.  Thus, PG&E states that it “. . . would avoid none of the residual shared cost if it were to divest generation assets.  The residual shared cost will remain with the transmission, distribution, and PPP functions.”  (Direct Testimony of PG&E, Page 2-18) Similarly, SCE states:  “Costs in the common pool by their nature reflect activities that are company-wide and will continue to be incurred even if divestiture results in changes in Edison’s assets, employment or revenues.”  (SCE-1, Appendix C, Page 12)

Q	DO THESE ARGUMENTS JUSTIFY THE ALLOCATION OF ALL SHARED A&G COSTS TO THE NON-GENERATION FUNCTIONS?
A	No.  First, the fact that much of the generation may be divested is not a critical factor here.  The critical factor is that generating costs will not be a part of the regulated revenue requirement whether or not it is divested, and that the current level of A&G expenses were approved on the assumption that the associated services would serve all functions including generation.  AB1890 provides that A&G costs associated with fossil generation must be recovered through sales to the PX.  Thus, a reasonable share of A&G must be allocated to the generation function.

Q	WHAT ARE THE SERVICES THAT ARE COVERED BY THE SHARED A&G EXPENSES?
A	These are primarily costs related to the corporate level activities of the utilities such as the salaries of corporate officials.  Although I refer only to A&G expenses throughout this discussion, it should be recognized that common plant costs such as the cost of corporate offices are also at issue here and the same concepts and arguments apply to common plant that apply to A&G expenses.

Q	WOULD THERE BE ANY REDUCTION OF NON-GENERATION SHARED A&G COSTS AS A RESULT OF EITHER DEREGULATING OR DIVESTING GENERATING PLANT?
A	If utilities are allowed to assign all of these costs to the non-generation functions, then the costs will not be reduced because there will be no incentive to trim back these costs to meet the reduced needs of the smaller regulated entity.  If, on the other hand, a reasonable share of these costs are assigned to the generation function, there will be reductions because the utilities will have an incentive to reduce these costs to levels more consistent with the amounts required to support the new, smaller, regulated portions of their companies.

Q	ARE THERE ANY PRACTICAL WAYS OF ACCOMPLISHING SUCH REDUCTIONS?
A	Yes.  A realistic allocation of A&G costs will force the utilities to look at measures that firms in competitive industries have been utilizing for some time.  Apart from simply downsizing the existing corporate support, many activities could be outsourced to other companies that could provide the service more efficiently.  Also, to the extent the utility maintains a generation function, it could continue to provide existing A&G services to the generating function which would reimburse the regulated utility.  To the extent that plants are divested, it could sell those services to the new owners of the plants.  In short, given the proper incentives, there is little doubt that creative utilities will find a way to make efficient use of the departments that are supported with A&G expenditures.

Q	WHAT IS YOUR SPECIFIC PROPOSAL FOR ASSIGNING SHARED OR COMMON A&G COSTS TO THE UNBUNDLED FUNCTIONS?
A	I recommend that each utility be required to allocate shared or common A&G costs across all functions, including generation.  In the case of PG&E, this means that it should not be allowed to restate the labor allocation factor by zeroing out generation.  Thus, the allocation factors used by PG&E summarized in Column (1) of Table 1, below, should be replaced with the actual labor allocation factors shown in Column (2), also drawn from PG&E's workpapers.

TABLE 1			
   Function   	PG&E Factor
(1)	Labor Factor
(2)	
Distribution	83.85%	56.04%	
Transmission	9.04%	9.04%	
Generation	0.00%	27.80%	
PPP	4.66%	4.66%	

Source:  PG&E Spreadsheet “A&GWORKP.XLS, Page 1			

	SCE uses a “multi-factor” formula developed for this restructuring procedure which allocates common A&G costs based on O&M expenses, labor costs, and capital expenditures to allocate its common A&G costs.  However, like PG&E, it has essentially zeroed out the generation allocation factor and recalculated the allocation factors to the other functions.  I recommend that SCE be required to apply its multi-factor formula to allocate its common A&G across all functions, including generation.

Proposed Changes in the Methods of Allocating Certain Cost Components
Q	WHAT IS THE GENERAL GUIDELINE THAT SHOULD BE USED IN THIS PROCEEDING TO ALLOCATE COSTS TO CUSTOMER CLASSES?
A	The same allocation method consistently approved by this Commission (i.e., the EPMC method) should be used to allocate costs in this proceeding in order to prevent cost shifting between customer classes as required by AB1890.

Q	PLEASE DESCRIBE THE ESSENCE OF THE EPMC METHOD.
A	In order to apply the EPMC method, marginal costs are calculated for each of the major functions (i.e., generation, transmission, and distribution).  These costs are used to develop a marginal cost revenue requirement for each customer class by applying the unit marginal costs to the appropriate class billing units.  Based on these calculations, a percentage share of the total marginal cost is calculated for each class.  These percentages are then applied to the total revenue requirement to determine the revenue responsibility for each class.
	It is important to recognize that the revenue requirement to which the EPMC percentage is applied includes many costs not included in the calculation of class marginal costs.  The result is an allocation of these non-marginal costs to the classes on the basis of the EPMC factor for the class.  Because the revenue responsibility of some classes historically departed significantly from the calculated EPMC target, the Commission has found it necessary to “cap” the amount of revenue allocated to some classes in rate proceedings.  However, the Commission has pursued a goal of revenue allocations based on EPMC for several years and the allocations in the most recent rate cases are quite close to EPMC.  The relevance of this for these proceedings is that when each class is responsible for revenues close to their EPMC share, an allocation of non-marginal costs based on an equal percent of class revenues is a good proxy for an EPMC allocation.

Q	HOW HAVE PG&E AND EDISON ALLOCATED NON-MARGINAL COSTS TO CUSTOMER CLASSES?
A	PG&E has generally allocated these costs on the basis of an equal percent of revenues which, as just explained, is essentially a continuation of the EPMC method.  SCE, on the other hand, has identified certain non-marginal costs that it has allocated on the basis of equal cents per kWh.  Relative to the EPMC method, an equal cents per kWh allocation will allocate more costs to high load factor classes such as SCE's TOU-8 rate schedule.

Q	WHICH NON-MARGINAL COSTS DID SCE ALLOCATE ON A CENTS PER KWH BASIS?
A	Edison allocated its Public Benefit programs costs, its Nuclear Decommissioning costs and its entire Miscellaneous Adjustment Mechanism (MAM) account on an equal cents per kWh basis.  Some of these costs are presently allocated on an equal cents per kWh basis, such as the costs associated with providing the CARE discounts for low income customers and it is appropriate to continue that practice.  The great bulk of these costs, however, are presently allocated based on EPMC percentages and Edison has offered no valid reason for changing that practice.

Q	HOW DOES EDISON ATTEMPT TO JUSTIFY THIS CHANGE?
A	Edison offers essentially two arguments supporting this proposal:  (1) dividing total costs by total kWh is easy, and (2) it doesn’t matter anyway because of the rate freeze. (SCE Direct Testimony, Page 48)

Q	DO YOU AGREE THAT EDISON’S PROPOSAL IS SIMPLE?
A	Yes.  However, the “simple” approach is quite beside the point, indeed totally improper, when the end result of using that approach is to violate the provision in AB1890 prohibiting cost shifting between customer classes. 

Q	IS IT CORRECT THAT THE ALLOCATION OF THESE COSTS WILL NOT AFFECT ANY CUSTOMER’S BILL DURING THE RATE FREEZE?
A	Yes.  That is true during the rate freeze.  However, I do not believe that the rate freeze was intended to be an excuse for improper revenue allocation or rate design.  If it were, then the need for this proceeding is questionable.  Rather, I believe that this proceeding and the unbundled rates it produces are key elements of the restructuring process.  
	During the rate freeze, the rate revenues allocated to a class and charged to individual customers provide customers with an answer to a most important question.  How much of what I pay goes toward the CTC and, hence, should disappear in 2002?  To the extent that a simple, but inappropriate, cost allocation is used during the rate freeze with the intention of correcting the method in 2002, customers will base their post-freeze plans on erroneous price signals concerning the size of the CTC component of their bills.
	A separate problem relates to the fact that improper allocation methods, employed because of their perceived simplicity, become the status quo when post-freeze rates are determined, whatever the disclaimers concerning precedent value when they are adopted.  Moreover, as I believe all parties who have participated in rate proceedings in this and other jurisdictions will readily understand that a party seeking to change the status quo faces a daunting, uphill battle. 
	Thus, although I agree that Edison’s concern for simplicity at the expense of accuracy will not change the total amount paid by any customer during the rate freeze, one may not conclude that this approach will have no important consequences.  To the contrary, it will seriously distort the unbundled price signals received by customers during the freeze and could lead to the perpetuation of bad ratemaking after the freeze.

PG&E’s Proposed Proxy for Unbundled Rates
Q	HAVE ALL THREE UTILITIES PROPOSED UNBUNDLED RATES IN THIS PROCEEDING?
A	No.  SCE and SG&E have proposed fully unbundled rates but PG&E has proposed an alternative approach that provides information to customers concerning functional costs on the basis of class average percentages.  PG&E has also presented its method of functionalizing rates in Appendix 4A to its filing and the corresponding functionalized rates in Appendix 4B to its filing.  The purpose of these Appendices is to let parties know “. . . how PG&E would choose to functionalize each rate component” if it were to do so.

Q	WHY HAS PG&E CHOSEN NOT TO PROPOSE UNBUNDLED RATES?
A	That is not entirely clear from PG&E’s filing, however, it appears to relate to the limitations of PG&E’s billing system.  
Q	PLEASE DESCRIBE PG&E’S RATE DESIGN PROPOSAL.
A	PG&E’s rate design proposal is to determine each customer’s bill based on present rates according to the rate freeze, then calculate the amounts of that bill associated with each functional component by multiplying the total bill by the proportion of total class costs each function represents. 

Q	DOES PG&E’S PROPOSAL SATISFY THE REQUIREMENTS OF AB1890?
A	I do not believe so.  In fact, PG&E claims only that its proposal meets the “objectives” of that bill.  Its proposal does not meet the specific requirement to “. . . provide for identification and separation of individual rate components such as charges for energy, transmission, distribution, public benefits programs, and recovery of uneconomic costs.” (AB1890, Section 368, Subdivision (b))

Q	WILL THE PRICE SIGNALS PROVIDED UNDER THIS PROPOSAL BE THE SAME AS THOSE TRANSMITTED TO PG&E'S CUSTOMERS HAD IT APPLIED THE UNBUNDLED RATES THAT IT DEVELOPED IN APPENDIX 4B?
A	No.  This is demonstrated on Exhibit AC-1 (      ), Schedule 1.  This compares the billing information that would be provided to a randomly selected E-20 primary voltage customer under PG&E’s proposal with the information that would be provided to that same customer with fully unbundled rates.  This information was produced by PG&E in response to Question 14 of the DOD’s Second Data Request.  A full copy of that response is provided as Exhibit AC-1 (      ), Schedule 2.
	As this Schedule shows, the information provided to customers does not accurately convey signals of the costs incurred for each of the unbundled rate components.  In fact, only the PX charges are accurately stated.  (The level of PX costs in this example is assumed to be $0.026 per kWh.)  Both the transmission and distribution cost components of this customer’s bill would be overstated by more than 20%, giving the customer an extremely distorted signal as to the cost of these services.  Since the rate freeze requires the total bill to be the same under either approach, the CTC component would be seriously understated under the PG&E method.

Q	HOW LONG DOES PG&E PROPOSE TO USE ITS ALTERNATIVE TO UNBUNDLED RATES?
A	As I understand the proposal, PG&E intends to use its alternative method throughout the rate freeze period.

Q	WHAT IS YOUR RECOMMENDATION CONCERNING PG&E’S ALTERNATIVE APPROACH?
A	I recommend that the Commission reject PG&E’s proposal and order it to implement unbundled rates developed consistent with the methods in Appendix 4A and Appendix 4B.

Q	WOULD IT CHANGE YOUR RECOMMENDATION IF PG&E TRULY CANNOT IMPLEMENT ITS UNBUNDLED RATES BY JANUARY 1, 1998?
A	Yes.  If PG&E can convince the RWG that it cannot accomplish the billing changes in time for January 1, 1998 implementation, it should work with the RWG to develop a schedule for completing the necessary billing system changes.  Based on that schedule, it should implement its unbundled rates as soon as the billing system can handle the project rather than waiting until the end of the rate freeze.

SCE’s Proposed Method of Reconciling PX Bill Settlement Costs
Q	PLEASE DESCRIBE SCE’S PROPOSED METHOD OF RECONCILING PX BILL SETTLEMENT COSTS.
A	Edison anticipates that it may not actually know its PX costs for a given day for as much as 50 days after the day in question.  It proposes to use a weighted average of the day-ahead and hour-ahead PX prices to calculate customers' initial bills, with a true-up at a later date to reflect final PX settlement costs for each hour covered by the bill.
	After receiving final hourly settlements from the PX, SCE will calculate an average cents per kWh adjustment for the original billing cycle which it expects will be quite small.  It will calculate the adjustment by dividing the settlement costs by the consumption during the billing month which is covered by the settlement.  It will then apply this adjustment against consumption during the current billing month.

Q	WHAT IS YOUR CONCERN WITH THIS PROPOSAL?
A	Because usage during the month that the shortfall surcharge or over-collection credit is applied will not be the same as during the month when it occurred, the amount of the reconciliation will never match the amount of the PX settlement charges and frequently could be very different.  Indeed, under SCE’s proposals such differences will never be corrected.

Q	IS THIS A DIFFICULT PROBLEM TO REMEDY?
A	No.  I recommend either calculating the surcharge (credit) based on consumption during the month it is applied or carrying over any deficiency or excess to be included in the next month's calculations.  Another alternative, if these corrections are as small as Edison suggests, is to recover them on an annual basis through, perhaps, the MAM account.

Q	DOES THIS COMPLETE YOUR DIRECT TESTIMONY?
A	Yes, it does.

Exhibit AC-1 (       )
Schedule 1

PUBLIC UTILITIES COMMISSION
OF THE STATE OF CALIFORNIA

Comparison of PG&E's Proposed Billings
       With Billings at Unbundled Rates       

		
                 PG&E Proposal                		
     Appendix 4B 	Unbundled Rates   		
Line	        Description         	         Method         
(1)	    Amount    
(2)	        Method         
(3)	    Amount    
(4)

1	Total Bill  (Present
    Frozen Rates)	Apply Present
Charges	
$763,059.75	Apply Present
Charges	
$763,059.75

2	
Transmission Costs	
3.329% x Line 1	
$  25,402.26	Various Charges
per kW*	
$  20,562.39

3	
Distribution Costs	
14.212% x Line 1	
$108,446.05	Various Charges
per kW** and
Customer Charge =
$3.10/Month	
$  88,426.94

4	
PPP Costs	
3.798% x Line 1	
$  28,981.01	
$.00258 per kWh	
$  30,573.00	

5	
PX Costs	
$0.026 x kWh	
$308,100.00	
$0.026 x kWh	
$308,100.00	

6	

CTC Charge	
Line 1 - Lines 2
through 5	

$292,130.43	
Line 1 - Lines 2
through 5	

$315,397.42

  	   _____________________

	        *	$1.11/kW Summer Peak Demand
		$0.25/kW Summer Partial Peak Demand
		$0.24/kW Summer Max Demand
		$0.25/kW Winter Partial Peak Demand
		$0.24/kW Winter Max Demand

	      **	$4.57/kW Summer Peak Demand
		$1.03/kW Summer Partial Peak Demand
		$0.99/kW Summer Max Demand
		$1.03/kW Winter Partial Peak Demand
		$0.99/kW Winter Max Demand