D R A F T
PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA

ENERGY DIVISION					RESOLUTION E-3650
                                					            APRIL 6, 2000	 

RESOLUTION

Resolution E-3650.  Pacific Gas and Electric (PG&E) and Southern California Edison Company (Edison) seek authority to offer new demand responsiveness programs to pay large customers to curtail energy use during periods of high energy prices.  Approved as modified.   

By   Edison Advice Letter  1418-E filed on November 8, 1999
and PG&E Advice Letter 1934-E filed on November 10, 1999
 
______________________________________________________________________________

Summary

This Resolution approves, with modifications, the demand responsiveness programs for the year 2000 proposed by Southern California Edison (Edison) in Advice Letter 1418-E and Pacific Gas and Electric (PG&E) in Advice Letter 1934-E.  These Advice Letters would create two new rate schedules-- Schedule VPRC—Voluntary Power Reduction Credit for Edison and Schedule E-BID—Price Responsive Load Program for PG&E.   

The purpose of these new rate schedules is to identify a group of customers who are willing to voluntarily curtail their energy usage in exchange for monetary compensation during time periods when the day-ahead Power Exchange (PX) price is expected to be equal to or greater than $250/mWh.   By having these customers reduce their energy usage, the total demand for energy is reduced, putting downward price pressure on the market clearing prices of the Power Exchange.  The savings from the reduced energy prices are intended to outweigh the costs incurred in getting these customers to voluntarily curtail.  This is intended to result in net savings to ratepayers. 

The utilities’ proposals in their current advice letters are similar in many respects to the demand responsiveness programs approved by the Commission for the summer of 1999 but which the utilities chose not to implement.   

Approval of the utilities’ programs, as modified, offer several potential benefits to ratepayers.  They include;

•	Allowing the utilities and the public to gather additional information on how customers respond to hourly changes in energy prices;
•	Putting downward price pressure on the market clearing prices of the Power Exchange.  This has the potential to increase the recovery of the utilities’ transition costs thus shortening the length of the transition period;
•	Improving operation of the wholesale energy market; and
•	Improving the reliability of the electric system to the limited extent that the program attracts new customers who are not already on a utility’s existing interruptible rate schedule.   

The utilities’ programs are only available to the bundled customers of the utility and are not available to direct access customers.

Approval of the utilities’ demand responsiveness programs may potentially effect the ability of Energy Service Providers (ESPs) to offer their own demand responsiveness programs to their direct access customers.  It is unclear how many ESPs are currently offering their own demand responsiveness programs and to what extent. Even with the utilities’ programs, however, ESPs should still be able to offer their own demand responsiveness programs; possess significantly more flexibility than the utilities in tailoring their programs to specific customer needs; and may be able to participate (to varying degrees) in any load management or reduction programs offered by the Independent System Operator (ISO).  

The utilities’ design of their programs do much to ensure that the program cannot be used to selectively target individual customers as part of a customer retention program.   Design features include; clearly transparent price signals to determine when curtailment levels occur; clearly determined calculation of incentive payments; and the utilities’ commitment that customers will participate in the program on a “first come, first served basis.”   However, the level of incentives proposed by the utilities for customers willing to curtail may encourage some customers to switch from direct access back to bundled utility service in order to take advantage of the utilities’ demand responsiveness programs.  The magnitude of this switching is difficult to forecast. 

The Resolution approves the utilities’ program for the year 2000 only.  It does not pre-judge either the desirability or need for the utility to offer these programs in subsequent years.  The future role of the utility as a provider of energy services should be addressed in the appropriate Commission proceedings.  Approval of this program is not meant to “grandfather” these programs for future years. 

The Alliance for Retail Markets (ARM) opposes adoption of PG&E’s and Edison’s programs believing that they are anti-competitive; hinder the development of a competitive energy marketplace; and pre-judge the role of the utility as default provider once the transition period ends. The California Farm Bureau Federation (Farm Bureau) also opposes adoption of PG&E’s program and states that PG&E’s proposal should have been filed as an application rather than as an Advice Letter. 

The California Energy Commission (Energy Commission) shares ARM’s concerns about potential anti-competitive effects but that “overriding concerns about system adequacy and reliability justify temporary implementation of the program(s)” provided certain program modifications are made.  

The Office of Ratepayer Advocates (ORA) and the Farm Bureau state that there is no evidence PG&E’s program will reduce overall energy costs and under certain circumstances, according to the Farm Bureau, could actually increase energy costs.  ORA and the Farm Bureau state that PG&E’s program should be subject to reasonableness review if adopted by the Commission.   

The Energy Commission and other parties propose a number of modifications to the utilities’ programs.  

This Resolution adopts several modifications to Edison’s and PG&E’s proposal.  These modifications include requiring that:

•	PG&E and Edison expand their programs to allow up to at least 50 smaller customers (defined as customers with a maximum demand under 500 kW) to participate if they meet the necessary metering and communication requirements, and to increase this number if it is cost-effective to do so; 
•	PG&E provide the same level of detail in its reporting requirements that Edison has already agreed to provide;
•	PG&E and Edison provide a detailed economic study on the total costs of the program and its economic benefits.  This should include detailed information on the effect of the program, if any, in lowering the day-ahead PX price; an economic study of the reasons for the high PX prices during the hours the program is in operation; the effect of the program on all other energy markets operated by the ISO (particularly the effect of customers who voluntarily commit, and then fail to curtail, upon the imbalance energy market); an economic study (including elasticity estimates) of the price-responsiveness of load to energy prices; the available operating reserves (calculated both before and after subtracting out customers on interruptible rate schedules) during times of program operation; and any other information useful in evaluating the program.  
•	PG&E should seek to limit the maximum total load reduction for any one curtailment event to a target goal of 500 mWh per hour;  
•	The administrative costs of the program for both utilities be subject to reasonableness review; 
•	The baseline for calculating energy reductions be changed from 5 days to 10 days;
•	PG&E and Edison should, as part of their compliance filings, identify and/or propose necessary safeguards to prevent customers from receiving more than one payment for the same curtailed load; 
•	Edison modify its accounting and tariffs to separately track both 1) the administrative costs of the program and 2) incentive payments made under its program; 
•	Edison and PG&E assign all costs of their program (both administrative and incentive payments made under the program) to the PX component of their customers’ bills.
•	Edison and PG&E should subtract the “otherwise applicable energy charge” in determining the level of incentive payment; 
•	Customers on existing interruptible rate schedules should be allowed to participate in the program but should be paid only 50% of the incentive payment; and,
•	Edison and PG&E are strongly encouraged to seek out the participation in this program of new customers (those who are not an existing interruptible rate schedule).  To provide a further incentive to attract new customers, these customers will receive 100% of the incentive payment for their participation.
 
With these modifications we believe the Resolution approves programs that will benefit ratepayers, enhance the operation of the wholesale electric market, and minimize the programs’ effects on the development of a competitive marketplace. 

Background

Assembly Bill (AB)1890, California’s electric restructuring legislation, requires that electric rates for each customer class are frozen at either the rates in effect on June 10, 1996 for industrial and large customers or a 10% discount off of rates in effect on June 10, 1996 for residential and small commercial customers.  These “frozen” rates shall remain in effect until the end of the transition period.  During the transition period California’s three largest electric utilities (PG&E, Edison, and San Diego Gas & Electric) are required to purchase from the Power Exchange all of the energy needed for those customers not choosing direct access.

The combination of these two factors creates problems when energy prices are high.  In its Advice Letter filing PG&E provided an hypothetical example of having to purchase energy from the Power Exchange at upwards of 75 cents/kWh in order to sell it to its customers at 8 cents/kWh.  During periods of high energy demand (such as during hot summer afternoons), end-use customers, insulated from the high energy prices of the wholesale PX market due to the rate freeze, have no incentive to reduce their energy usage. 

In a competitive marketplace, it is the interaction of supply and demand that sets the price.  Higher prices for a good have the dual effect of encouraging suppliers to offer greater volumes while at the same time encouraging consumers to either consume less or switch to alternative products.  During the rate freeze period for California’s electric industry, only the supply portion of the above equation operates when energy prices are high. Due to the rate freeze, the demand side of the equation is largely unaffected by higher prices.

Demand responsiveness programs attempt to instill some pressure on the demand side of the equation to reduce the overall price of energy.  Since most customers are insulated from increasing energy prices due to the rate freeze, during the rate freeze period demand responsiveness programs generally must pay customers to voluntarily curtail their energy usage.  The underlying assumption about these programs is that by paying some customers to reduce their energy usage, the reduced demand for energy will result in all other customers paying a lower energy price than they otherwise would have.  To date, there have been no empirical studies to observe and prove this phenomenon in the California electric market.

To use an illustrative example, if a utility such as PG&E or Edison is required to purchase 20,000 mWh from the Power Exchange at a price of $250/mWh, than the utility would pay $5 million/hour to meet its energy needs.  By paying some of its customers (in this example 500 mWh of demand) an incentive payment of $250/mWh to curtail their energy usage, the utility need only purchase 19,500 mWh from the Power Exchange to meet its needs.  Because the utility is demanding less energy from the Power Exchange, the market-clearing price should be lower (in this case we will assume it drops to $240/mWh).   The total cost to the utility under this scenario is $4,805,000. Although the utility has had to pay $125,000 to some of its customers to curtail their load, the effect of this reduced demand was to lower by $320,000 the price that the utility had to pay for it’s remaining 19,500 mWh of load.  The net savings in this example are $195,000 (approximately 4% lower).

Description of the Utilities Proposals

Edison and PG&E both seek authority to establish demand responsiveness programs.  Under these programs the utilities would establish a pool of customers willing to voluntarily curtail their energy use in exchange for an incentive payment when energy prices in the PX are expected to be equal to or greater than 25 cents/kWh.  The incentive payment would be equal to the market-clearing price of energy in each utility’s service territory. Both also seek approval of contract forms that would be needed for customers to sign-up for the program.

The proposed programs would be limited to 500 customers in the case of PG&E, and a limit of 500 mWh of load reductions in the case of Edison. 

The programs are limited solely to customers taking bundled service from the utility and are not available to those customers utilizing direct access. 

The programs are limited to each utility’s largest customers (over 500 kW of maximum demand) because there is a need to monitor the energy usage of customers participating in the program on an hourly basis to ensure compliance.  These large customers already have the necessary hourly metering equipment.  

The program would not be available to customers who are on rate schedules that already send hourly price signals to the customer such as Edison’s Real Time Pricing tariff.  Customers who are on the utilities’ interruptible rate schedules would be eligible for the program, but would not be paid if the ISO subsequently called its own curtailment event at the same time that the utilities’ demand responsiveness programs were in effect.   
  
These curtailment programs would be triggered whenever the day-ahead price in the Power Exchange is equal to or greater than $250 mWh (25 cents/kwh).  When this event happens, the utilities would notify customers who had expressed an interest in curtailing their load.  These customers could “bid in” load reductions for the following day’s on-peak hours.  The utilities would select which customers would be curtailed on a first-come, first-served basis; thereby ensuring that no customer receives preferential treatment.  Customers would be paid the market-clearing price for the amount of load they curtailed.  The amount of curtailment would be determined by comparing each customer’s energy usage during the curtailment event against their baseline or historical energy usage.     

Customers participating in the program may voluntarily commit but are not required to reduce load.  Should a participating customer commit to reduce load and then fail to do so  Edison will remove them from the program the second time this event happens.  PG&E will remove a customer from the program the third time they fail to curtail. 

PG&E and Edison state that their demand responsiveness programs offer several advantages to ratepayers.  First, these programs allow the utilities to gain information on how customers will respond to changes in energy prices.  Second, the programs benefit ratepayers by reducing the total price that the utilities must pay for their energy purchases from the PX. This would increase the amount of “headroom” available to pay off transition costs, thus allowing the rate freeze to potentially end sooner than it otherwise would have.  Third, the programs may improve the efficiency of California’s wholesale electric market by providing some demand elasticity during periods of high demand.  Fourth, the programs may help in maintaining the reliability of the electric system by reducing total demand during hours of peak energy usage.

PG&E is proposing to track the payments made to customers to curtail their energy use to its Transition Revenue Account and has proposed the necessary tariff changes.  Edison states that it also will credit payments as an offset to its Transition Revenue Account but has not proposed any changes to its tariffs to implement this provision.

PG&E estimates the start-up and on-going administrative costs of its program at approximately $1.5 million, about 20% of which may be recovered from program participants through a $600 per customer enrollment fee.  PG&E seeks the establishment of a new account (the E-Bid Memorandum Account or EBIDMA) to track its incurred costs for potential future recovery in rates.  Actual recovery in rates of any expenses booked to the E-BIDMA would have to be approved by the Commission in a subsequent decision.

Edison did not provide any estimates for the start-up or administrative costs of its program, although its costs are probably about the same as PG&E’s given the programs’ similarities.  Edison does not propose an enrollment fee.  Edison is not seeking recovery in rates of the administrative costs of the program, stating that it will absorb these costs within its existing revenue requirement. 

Notice 

Notice of PG&E Advice Letter 1934-E and Edison Advice Letter 1418-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.  On November 22, 1999 Edison filed substitute Tariff Sheets to its Advice Letter.  PG&E filed substitute tariff sheets to its Advice Letter on February 3, 2000.
Protests

PG&E’s Advice Letter 1934-E was timely protested by ARM, the Energy Commission, the Farm Bureau, and ORA.  The California Large Energy Consumers Association (CLECA) also filed comments that were generally supportive of PG&E’s filing.

Edison’s Advice Letter 1418-E was timely protested by ARM and the Energy Commission.

PG&E and Edison responded to the protests.  

The following is a more detailed summary of the major issues raised in the protests and the utilities’ responses.

The Utilities’ Proposed Programs are Anti-Competitive

The major issue raised by all of the protestants is that the utilities’ proposed programs are anti-competitive.  As the Energy Commission states:

The ability of [the utilities] to offer this program rests solely on [their] unique position as the incumbent utility with a large number of customers and a large aggregate load. The [utilities can identify a subset of its customers that are willing to participate in such a program and derive benefits for all of its remaining bundled service customers…No ESP can accomplish the same result. 

ARM states that the utilities’ proposals inappropriately leverage their incumbent advantage to the detriment of competition.  ARM cites as an example the utilities’ ability to allocate program costs over their entire captive customer base of several million customers.   An ESP attempting to offer a similar service must attempt to recover its program costs solely from those customers participating in the program.  Additionally, because the utilities in their role of default providers start out with a significant share of the market for energy, the utilities gain most of the savings from any reduction in energy costs achieved through demand responsiveness programs.  ARM notes that if an ESP “were to develop a similar demand responsiveness program for its customers, and effected the same kind of reduction in PX clearing prices (benefiting Edison’s bundled customers), the ESP would not be able to allocate program costs to those same bundled customers.” 

Allowing the utilities to offer demand responsiveness programs, according to ARM, also changes the role of the utility as a “disinterested” provider of energy services.  Currently the utility has no financial incentive to encourage a customer to choose either direct access or remain a bundled utility customer.  Allowing the utility to offer demand responsiveness programs now gives the utility a financial incentive to encourage customers to remain with the distribution utility.  ARM fears that the utility will use the demand responsiveness programs as a “customer retention” tool to deter customers from switching to direct access.  

Additionally, ARM states that it is new “value-added” energy services, such as demand responsiveness programs, which are precisely the type of programs ESPs need to offer in order to differentiate themselves in the marketplace from default energy service.  The utilities’ proposals, according to ARM, not only have the utility competing against the ESPs in the provision of value-added services, but also allow the utility to recover the cost of these programs from all of the utilities’ captive customers.   

PG&E and Edison respond to the protestants’ concerns by stating that ESPs, as well as the utilities, can offer their own demand responsiveness programs.  Edison states that even an ESP with only one customer could offer a demand responsiveness program if it chose to do so.  Both utilities emphasize the apparent inconsistency in ARM’s protest in which ARM states that ESPs are already offering demand responsiveness programs but elsewhere states that these programs are not available to direct access customers.
  
Edison also states that to the extent that demand responsiveness programs lower the PX price, all buyers from the PX, including ESPs, will benefit.  CLECA, in its comments to PG&E’s Advice Letter makes a similar point, namely that reduced PX energy prices are likely to result in lower overall energy prices, thus benefiting all energy users including direct access customers. 

The Program Costs Should be Borne by Program Participants

ARM 	urges that if the Commission adopts the utilities’ proposals it require the utilities to recover their program’s start-up and administrative costs through a service fee paid solely by program participants.  This would mitigate the anti-competitive impacts of the program and prevent cost shifting of a value-added service onto non-participants and direct access customers. 

PG&E and Edison oppose such a proposal, arguing that it is the non-participants who are receiving the benefits of the program through reduced energy costs and therefore should pay for program costs. 

Relationship to “Default Provider” and Post-Transition Ratemaking

A number of parties raise issues regarding the role of the utility as a default provider of energy services once the rate-freeze ends.  

ARM argues that adoption of the utilities’ proposal would “prejudge the issue of the role of the default supplier” by allowing the utilities to offer a value-added service directly to end-users.  This is a contentious issue, according to ARM, which the Commission is currently considering in a number of procedural forums.  

ARM, the Energy Commission, and ORA all suggest that a better alternative to the utilities’ proposed demand responsiveness programs would be for the Commission to adopt rate design policies that directly impose the cost of hourly PX prices upon the end-use consumer.  The Energy Commission and ORA recognize, however, that this policy cannot be implemented until after the rate freeze ends.  The Energy Commission and ORA do suggest, however, that customers be informed that the Commission is currently considering hourly pricing options.  

The Farm Bureau goes a step further and opposes PG&E’s program on the assumption that the transition period for PG&E will end prior to the start of summer 2000, thereby negating any need for the program.

PG&E and Edison respond by stating that all of the issues raised by the protestants are currently being considered in the Commission’s Post-Transition Ratemaking Proceeding or in other forums.  They view it as premature to notify customers about rate changes that might occur once the transition period ends until after the Commission issues its decisions on this issue. 

Any Demand Responsiveness Program Should be Transitional Only

ARM, CLECA, the Energy Commission, and ORA all state that any utility demand responsiveness program approved by the Commission should be transitional in nature and not pre-judge the utility’s ability to continue to offer this program. ARM is worried that approval of the utilities’ program would not only deter development of demand responsiveness programs by ESPs but also “grandfather” the utilities’ programs, making it more likely that they will be extended into future years.  ORA and the Energy Commission both support limiting any program solely to the summer of 2000 and that there should not be any automatic extension of the program to the year 2001.

Both PG&E and Edison agree that these programs will only be in effect for the year 2000.  Any extension of these programs for the following summer would require further Commission action.

Need for Reasonableness Review 

ORA and the Farm Bureau note that PG&E’s filing contained insufficient data to evaluate the program benefits.  As a result, ORA could not conclude that the program would actually benefit ratepayers. The Farm Bureau raises the concern that if PG&E relies on program participants to curtail their load, and then these customers fail to do so, PG&E could find itself paying high imbalance energy charges to meet the unexpected shortfall.  This could actually result in increased energy costs for PG&E. 

To address these concerns, ORA and the Farm Bureau request that PG&E’s program be subject to reasonableness review. 

PG&E opposes any reasonableness review, stating that it will not offer a demand responsiveness program if its shareholders are exposed to the unknown risk of a reasonableness review without having any corresponding benefits.  Additionally, PG&E states that by establishing clearly defined parameters for program participation it has very little discretion in how the program operates, thereby negating the need for reasonableness review. 

Extension of PG&E’s Program into the Fall Months

 The Energy Commission proposes that PG&E’s program should expire at the end of the summer season (October 31, 2000) rather than December 31, 2000.  PG&E  opposes an early termination, arguing that while high energy prices are most likely to occur in the summer months, they could occur in the later months of the year as well due to outages and other factors. 

Appropriate Trigger Price

The Energy Commission believes that the trigger price used to initiate the voluntary curtailment program needs to be more rigorously developed to ensure an appropriate benefit threshold is reached.  It suggests, for example, basing the triggering event on the 99th percentile of energy prices or that the Commission hold workshops to determine the appropriate price.

Edison responded by noting that the 99th percentile corresponds to 8.5 cents/kWh, a price that may be too low to elicit significant demand reduction.  Both PG&E and Edison state that they adopted the 25 cent/kWh limit because; it was high enough to provide customers with an incentive to participate; ensured that there would be ratepayer benefits; and had previously been approved by the Commission as an appropriate trigger level.  Both utilities assert that energy prices and ratepayer benefits are closely correlated and that the higher the energy prices the greater the ratepayer benefit.   PG&E and Edison oppose holding workshops to fine-tune the trigger price arguing that this could delay program implementation until after the summer.   

Appropriate Incentive Payment

ARM argues that once the utilities initiate a curtailment event, the utilities are overpaying customers to curtail.  As ARM states, the utilities have proposed an incentive payment equal to the full day-ahead PX price multiplied by the amount of curtailed load.  The actual savings directly attributable to the load curtailment is this gross amount, less the revenue the customer would have paid the utilities on Schedule PX had it not curtailed load.  Because it reflects gross savings rather than net savings, the utilities proposed incentive payment exceeds the savings attributable to the load curtailment..  ARM suggests, that if adopted, the utilities’ programs should subtract the otherwise applicable energy charge from the day-ahead PX price when computing the curtailment incentive.  

Edison responded that the higher incentive payment was needed to provide an adequate incentive for load to participate in the program and curtail when needed. 

Appropriate Baseline

The Energy Commission opposes the baseline that the utilities will use to calculate the amount of load each customer curtails.  It believes that the utilities proposal utilize too short of a time period with the result that some customers will be able to game the system and earn curtailment payments for reductions in load that would have occurred anyway.  The utilities’ baseline calculations, according to the Energy Commission do not adequately reflect either normal fluctuations in energy load or circumstances where a customer’s load is trending downward due to declining business conditions.  The Energy Commission recommends that the utilities use a 15-day average rather than the 5-day average proposed by the utilities. 

The utilities believe that the 5-day average provides a current reference point for measuring customer’s response to prices.  PG&E recognizes that it is very difficult to eliminate the possibility of gaming on the part of customers.  However, since  customers do not know when PX prices will exceed the program’s trigger price, PG&E argues it may be futile, and in some cases expensive, for customers to change internal processes to game an uncertain participation in the program. 

Limitations on Program Size

The Energy Commission is concerned that the 500 mWh cap on load reduction  per curtailment event proposed by Edison may be too low given that there is no limit on the number of customers and corresponding load that may be enrolled in the program.   The Energy Commission is concerned that this could lead to Edison engaging in the “preferential selection of customers to participate in an actual curtailment event if the total pool of participants is too large.”

Edison states that it is unlikely that program participation will reach the 500 Mwh level until late in the summer of 2000.  Edison argues that the Commission could debate raising the limit if and when a demand responsiveness program is proposed for the summer of 2001.  As to the Energy Commission’s claim of preferential treatment, Edison reiterates that it will run its program on a first-come, first-served basis up to the program limit.  This eliminates any chance for Edison to prefer one customer to another. 

The Farm Bureau notes that PG&E’s currently proposed program of up to 500 participating customers is 50 times larger (500 customers) than the 10 customer pilot program that the Commission authorized last year for PG&E.

 PG&E responds that it chose its program size to be large enough to provide necessary reliability benefits. 

Including Smaller Customers

The Energy Commission suggests that both Edison’s and PG&E’s program should be broadened to allow smaller customers who possess the needed metering equipment to participate in the program, and that some smaller customers should have meters installed at ratepayer expense to participate in the program.  This would allow the utilities to gain some experience on how smaller customers would respond to changes in energy prices.

In its response, PG&E agreed to expand its program to include up to 50 smaller customers with loads less than 500 kW who are taking service on Schedule E-19 (Voluntary).  These smaller customers must already have or installed at their own expense the appropriate metering and communication equipment.  Edison did not support expanding its program to smaller customers but would be amenable to including smaller customers in future year programs if a funding source (Edison suggested the use of Public Goods Charge or Energy Commission funds) was utilized to pay for the necessary metering and communications equipment. 

Reporting Requirements

The Energy Commission and ORA both believe that PG&E’s reporting requirements are inadequate and that PG&E should provide at least the same level of information regarding program operations that Edison has agreed to provide.

PG&E agreed to the Energy Commission’s request.

Adoption through Advice Letter Process

The Farm Bureau, citing the scope and complexity of PG&E’s proposal states that it should be approved through the Commission’s more formal application process rather than as an Advice Letter.

PG&E states that it chose the Advice Letter process in order to have a working program in place prior to the summer of 2000.

 Discussion

The Commission Already Approved Demand Responsiveness Programs Last Year 

In Resolutions E-3619 and E-3624, issued at the start of the summer of 1999, the Commission approved, with conditions, the ability of PG&E and Edison to offer demand responsiveness programs to a small subset of their largest customers. In Resolution E-3619 (July 8, 1999) the Commission authorized PG&E to offer its program on a first-come, first served basis to ten of its largest one-hundred customers up to a total of 200 Mw of reduced load.  The Commission also imposed more clearly defined parameters as to when the incentive payments would be triggered and made the program subject to reasonableness review.  In Resolution E-3624 (adopted August 5, 1999), the Commission allowed Edison to offer a similar program.  Resolution E-3624 rejected Edison’s original proposal in which Edison would offer individualized incentives to different customers for up to 2000 Mw of load reductions. 

The Commission gave PG&E and Edison an opportunity to either accept or reject the proposed modifications.  Due to concerns about the programs being subject to reasonableness review and other modifications required by the Commission, neither PG&E nor Edison chose to implement these demand responsiveness programs.

In Resolution E-3624 the Commission also directed the Energy Division to meet with Edison to discuss potential demand responsiveness programs for the year 2000. On July 12, 1999 the Commission held a Roundtable on Demand Price Responsiveness, and on October 18, 1999 the Energy Division held a public meeting for the utilities to present their proposed demand responsiveness programs for the year 2000.  

The Utilities’ Proposals Submitted this Year Address Many of the Commission’s Concerns Regarding Last Year’s Proposals  

The utilities’ design of their programs for this year do much to ensure that the program cannot be used to selectively target individual customers as part of a customer retention program.   The program’s design also does much to ensure that the program will provide ratepayer benefits and be easy to administer.  Design features in this year’s proposal include: clearly transparent price signals to determine when curtailment levels occur; clearly determined calculation of incentive payments; and the utilities’ commitment that customers will participate in the program on a “first come, first served basis.”   

The Utilities’ Proposals Should Allow Interested Parties to Gather Additional Information on How Customers Respond to Hourly Prices

Adoption of the utilities’ proposals should give interested parties additional information on how customers are willing to change their load in response to hourly prices.  As Resolution E-3624, which addressed Edison’s proposed 1999 demand responsiveness program concluded, however, much of this information may already be available through the utilities’ other real-time and time-of-use pricing options.   Since this is an experimental program we will require both PG&E and Edison to conduct a detailed economic study on the total costs of the program and its economic benefits.  This should include detailed information on the effect of the program, if any, in lowering the day-ahead PX price; an economic study of the reasons for the high PX prices during the hours the program is in operation; the effect of the program on all other energy markets operated by the ISO (particularly the effect of customers who voluntarily commit, and then fail to curtail, upon the imbalance energy market); an economic study (including elasticity estimates) of the price-responsiveness of load to energy prices; the available operating reserves (calculated both before and after subtracting out customers on interruptible rate schedules) during times of program operation; and any other information useful in evaluating the program.  

The Utilities’ Proposals Should Put Some Downward Price Pressure on the Market Clearing Prices of the Power Exchange.

Adoption of the utilities’ programs should have some positive effect on lowering the market price of the PX although to date we have no empirical support for this proposition.  The degree of this reduction will depend upon the elasticity of the supply market in responding to reduced demand.  As Resolution E-3624 concluded, the “last megawatt” can have an effect on the market price.  In the workshops on demand responsiveness held by the Commission in July, several participants noted the benefits that demand responsiveness would have in reducing energy prices.  In Resolution E-3624 Edison estimated that its demand responsiveness program for the summer of 1999 would provide net benefits.  Although Edison’s currently proposed program is smaller than the program it proposed last year (2000 MW of reduced load last year versus 500 MW proposed for this year) the price caps in the wholesale energy market have been subsequently lifted from last year’s $250/mWh to $750/mWh.  While there should be program benefits, the actual level of savings is clearly dependent upon how high energy prices go this summer. Results for PG&E should be similar.  Lower energy costs should also translate into increased recovery of the utilities’ transition costs, although these programs will have a minimal effect on shortening the length of the transition period.   It is because of the uncertainty regarding program benefits that we are requiring PG&E and Edison to do a detailed economic study of the programs’ operations. 

The Utilities’ Proposals Should Improve the Operation and Efficiency of the Wholesale Energy Market 

One of the major, although admittedly intangible benefits of the utilities’ proposals, is the potential to improve the operation and efficiency of the wholesale energy market.  The inability of most retail customers to respond to higher prices may be affecting the working of California’s wholesale energy market.  Both the Market Monitoring Committee of the PX and the Market Surveillance Committee of the Independent System Operator (ISO) have issued reports on market structure problems in the various energy markets.  Both the ISO and PX have identified the need for more demand responsiveness from retail customers as an important factor in ensuring a competitive energy market.
 
An expanded demand responsiveness program, as the PX and ISO have noted in their reports, should also help improve the competitiveness of energy pricing in the wholesale energy market.  This should benefit all customers, both direct access and bundled service.  

The Utilities’ Proposals May Minimally Improve the Reliability of the Electric System to the Extent that the Program Attracts New Customers Who Are Not Already on an Utility’s Existing Interruptible Rate Schedule

The Energy Commission states that while we should be strongly concerned about the potential anti-competitive effect of the utilities’ proposals “overriding concerns about system adequacy and reliability justify temporary implementation of the program(s).”  The Energy Commission, in their July, 1999 staff report, reviewed the strain that abnormally high summer temperatures during the summer of 1998 had on the operation of the electric system, particularly as it related to the amount of system reserves.  Although a similar pattern did not occur in the summer of 1999, and may or may not occur in the summer of 2000, the Energy Commission appears to view the utilities’ programs as an additional safeguard to maintain adequate generating supplies should unexpected weather or facility outages occur. PG&E, in their response to the Farm Bureau’s protest, describes its program as “an inexpensive insurance policy” given the risk of supply inadequacy.  

The major purpose of the utilities’ programs is to mitigate price spikes in the wholesale market and not to ensure reliability.  The utilities’ proposals may minimally improve reliability to the extent that they identify an additional pool of customers (those who are not already on interruptible rate schedules) that would be willing to curtail during times when both energy prices are high and system reserves are low.  The magnitude of this benefit is likely to be quite low.  PG&E estimates the load reduction expected from its program as only 200 Mw, 2/3rds of which they are predicting will come from existing interruptible customers.  This means that PG&E’s program may only identify an additional 60 Mw of new load willing to be curtailed.  Edison predicted a similar outcome, noting that it was 1) unlikely to hit the program cap of 500 Mwh until late in the program’s operation, if it all; and that a substantial portion of its program participation would come from customers already on its existing interruptible rate schedules. 

As discussed further below, existing interruptible customers already provide reliability benefits.  Allowing them to participate in the demand responsiveness programs, while it may have price benefits, does nothing to improve system reliability.  

The ISO, at its March meeting, noted that under certain scenarios of a “hot summer” there could be a mismatch between energy supply and demand of about 1,100 Mw even after all customers on existing interruptible rate schedules were curtailed.  While the purpose of the demand responsiveness programs is to provide price benefits, we strongly encourage the utilities to seek out new customers who are not on existing interruptible rate schedules to participate in the demand responsiveness program.  Combined with the pricing incentives discussed further below, this will allow the program to provide not only potential price benefits but also some additional reliability benefits. 

Are the utilities’ programs anti-competitive?

Much of the debate over the utilities’ proposals focuses on the potential anti-competitive effects of the utilities’ proposed programs.  As the Energy Commission states:

The ability of [the utilities] to offer this program rests solely on [their] unique position as the incumbent utility with a large number of customers and a large aggregate load. The [utilities] can identify a subset of its customers that are willing to participate in such a program and derive benefits for all of its remaining bundled service customers…No ESP can accomplish the same result. 

This statement is partially correct.  It is the incumbent utilities relatively large share of the marketplace, not their status as incumbent utilities, that enables them to successfully engage in demand responsiveness programs.  

In order for demand responsiveness programs such as the utilities are proposing to work, a firm must be able to; 1) control enough load that is able to curtail in order to reduce the market-clearing price; and 2) still retain enough load to receive the benefits of the market-clearing price.  In economic terms, this is analogous to the difference between a firm being a “price maker” (i.e. a firm whose decision to increase or decrease output can affect the market price) or a “price taker” (i.e. a firm that is so small that their decision to increase or decrease output does not affect the market price.)   Therefore, ESPs, if large enough, could offer similar programs. 

Although ARM, Edison, and CLECA all have different viewpoints on the desirability and structure of demand responsiveness programs, all three parties seem to implicitly agree that these programs have “free rider” problems. All three parties agree that all customers in the marketplace benefit from the reduced prices brought about by demand responsiveness programs even if they do not contribute to paying the program’s cost.  Edison argues that to the extent its program is successful in lowering prices, all customers (including non-Edison customers) benefit.  ARM makes the same argument that an ESP’s demand responsiveness program would benefit not only its customers but Edison’s customers as well. CLECA also concurs that successful programs should benefit all customers.    

Secondly, as the utilities note, an ESP that served only one customer could offer a demand responsiveness program.  This is true to the extent that an ESP could pay a customer something less than the market price to curtail and then resell the energy to someone else at the market price.  An ESP with only one customer, however, could not pay that customer to curtail and hope to enjoy the benefits of reduced market prices for the remaining load that it serves. 

Third, although the utilities may have some advantages due to their size, the ESPs have a greater degree of flexibility to structure demand responsiveness programs.  Unlike the utilities that must purchase all of their energy needs from the PX, ESPs can structure their energy purchases through the use of hedging, long-term contracts and other financial instruments that enhance their ability to compete with the utility.  Direct access customers who are not on interruptible rate schedules may also be able to participate in some of the load reduction programs that may be developed by the ISO such as its proposed Participating Load Agreements (PLA) and Emergency Demand Responsiveness (EDR) programs.  Additionally, while the utility proposals require that all customers be paid the same price for curtailing, an ESP can structure its curtailment programs to offer different prices to different customers.  As the utilities note, direct access participation rates are highest among the largest industrial customers who are likely to have the greatest ability, at least in the short-term, to participate in demand responsiveness programs. 

A final issue regarding competitiveness raised by the parties is whether or not ESPs are currently offering demand responsiveness programs. 

ARM states that demand responsiveness programs are “exactly the type of service that is being offered by ESPs in the marketplace.  CLECA, by contrast, takes issue with this statement, replying that;

…[M]arketers have not yet come up with programs of their own to allow customers to curtail demand in the event of high market prices, even though such programs are needed and obviously beneficial to the market.  Individual CLECA members are working with certain suppliers on this sort of product but none has been made available to a CLECA member as of yet.  

It appears that the market for demand responsiveness by the ESPs is still in a nascent state and in the process of evolving.  Programs being developed by the ISO and PX may enhance development of this market.
 
In conclusion, it appears that adoption of the utilities’ proposals may give them a competitive advantage, but this appears to be due more to the utilities’ size then directly to their status as default providers.  Larger ESPs may be able to offer similar programs.  Countering this advantage is the flexibility that the ESPs have in structuring their contracts and in product offerings to customers.  Given our concerns about having some demand responsiveness programs in place for this summer, we will approve the utilities’ proposals.  The ability of the ESPs to compete with the utilities, coupled with the modifications to the utilities’ programs we are proposing and the limited duration of the utilities’ program help address the concerns raised by the protestants.  We continue to encourage ESPs to refine and develop their programs. 

Will The Utilities’ Program Encourage Customers to Switch Back to Bundled Service

Because the utilities’ programs are only available to bundled customers, we must be concerned that some customers may switch back to bundled utility service from direct access in order to take advantage of the utilities’ demand responsiveness program.  

In response to the Energy Commission’s protest, Edison stated that the amount of savings a customer would receive under its program are likely to be only a small component of the customer’s total energy bill.  For a 1 mWh baseload customer, Edison stated that their total bill would be around $425,000 per year (7 cents/kWh at a 70% load factor) and that they might receive around $3,600 per year in incentive payments if they curtailed.  The magnitude of the incentive payment is quite sensitive to both the expected frequency of curtailment and the market price.  For customers who can easily curtail their load, the level of incentive payments could be much higher, perhaps in the range of $10,000-$15,000.

Although these numbers appear small relative to a customer’s total bill, they must be compared against the competitive alternatives available to customers.  Of this customer’s $425,000 bill, only the energy portion of this bill of about $200,000 is subject to competition (assuming a PX price of 3 to 3.5 cents/kWh).  A customer choosing direct access might only save 5-10% off of their PX price or annual savings of $10,000 to $20,000.

Therefore, depending on the number and severity of curtailment events, the incentives available to a customer under the utilities’ curtailment programs could be roughly comparable to the level of savings a customer could achieve through direct access.  Payments under the utilities’ curtailment program would be much more speculative and harder to predict, however.  Nonetheless, for those customers who can easily curtail their load, there may be an incentive for them to switch back to bundled service.  The magnitude of this potential switching is too difficult to determine.  One option not raised by the parties to address this problem would be to have the utilities’ programs available to all of their customers. 

The Utilities Programs should be approved for the year 2000 only

We agree with all of the parties that any demand responsiveness program approved by the Commission should be effective only for the year 2000.  We share the concerns of ARM that we do not want to "“grandfather” these programs for future years.  The longer-term issues associated not only with demand responsiveness but also all other procurement issues need to be fully debated in the Commission’s Post-Transition Ratemaking Proceeding and other Commission forums. However, we would encourage the utilities to file demand responsiveness programs for the summer of 2001 but only if the Commission has not reached a decision in its Post-Transition Ratemaking proceeding by December 31, 2000.
Notification to customers of future rate changes should not occur until after the Commission issues its decisions on the relevant issues.  

Allocation of Start-Up and Administrative Costs

The purpose of the utilities’ demand responsiveness programs is to reduce the market-clearing price of the PX and therefore the costs of these programs should be considered as generation-related costs.  As the Commission concluded in D.97-08-056 (also known as the “Unbundling decision”) generation-related costs should be collected in the generation component of rates and not collected through distribution rates to avoid giving the existing utilities an unfair advantage relative to ESPs.   Accordingly, the start-up and administrative costs of the utilities’ demand responsiveness programs should be allocated to the PX component of each customer’s bill.  Direct access customers should not have to pay for the utilities’ programs, and all customers should have the total cost of energy reflected in their PX charge or credit.

We reject ARM’s argument that the utilities’ program costs should only be collected from program participants.  As noted above, demand responsiveness programs have “free rider” concerns in that all customers in the marketplace are likely to benefit from programs that successfully lower the energy price.  Arguably, this logic would support the utilities’ contention that since all customers benefit from reduced energy prices, all of the utilities’ customers (both bundled and direct access) should contribute to the programs’ costs. Carrying this argument to its logical conclusion, however, would require that we go even further and allow for ESPs to collect their program costs from bundled service customers, since the ESPs’ programs also lower overall energy costs.  We believe that requiring that bundled service customers pay for the cost of the utilities’ programs while direct access customers pay for the cost of any ESP programs fairly balances the competitive and equity concerns. 
 
Edison states that it will recover its program costs from its existing revenue requirement and therefore there will be no cost to its ratepayers.  This statement is partially correct.  Edison’s distribution revenue requirement is covered by a Performance-Based Ratemaking mechanism adopted by the Commission in D.96-08-025.  The additional costs of Edison’s program will affect the level of earnings (or losses) that are subject to sharing between the utility’s shareholders and its ratepayers.  Since the administrative costs are more appropriately classified as generation costs, Edison should track its costs separately and assign them to the PX component of their bill.  

Accounting Issues

Edison proposes to track its incentive payments under its program through its Transition Revenue Account but does not make any changes to its preliminary statement to reflect this.  This is inconsistent with the Commission’s goal, as mandated by AB1890, that utility rates be unbundled into their respective components.  As the Commission concluded in PG&E’s 1997 Rate Design Window (D.97-09-047) the utilities are legally precluded from discounting the energy, public purpose, or competitive transition charge portion of their bills.  Edison should create a separate account to record its incentive payments and separately identify these payments to its program participants.  This clarifies that Edison is making these payments as part of its demand responsiveness program and is not discounting either the energy or transition cost components of its bill.  PG&E should further revise its accounts if necessary to conform to this guidance.

Incentive payments made by the utilities (although tracked separately) and their administrative program costs (as they are booked to the appropriate memorandum accounts) should both be included in calculation of the PX credit.  The utilities should make any necessary tariff changes to accomplish this.

Need for reasonableness review

The demand responsiveness programs proposed by the utilities this year contain transparent price signals that should make them easy to administer and limit the utilities’ discretion in operation of the program.  As an experimental program we do not see a need for reasonableness review of the program’s operations.  The start-up and administrative costs of the program should be subject to reasonableness review primarily to ensure that recorded funds were actually spent.   

Treatment of Interruptible Customers

The utilities propose to allow customers on their interruptible rate schedules to participate in their demand responsiveness programs. There are approximately 2,800 megawatts of load currently operating under interruptible rate schedules.  In exchange for a significant discount off of the otherwise applicable rate, these customers agree that their service may be interrupted or curtailed under certain conditions for a number of times per year.

The magnitude of the rate reduction is significant.  For customers on Edison’s I-6 interruptible tariff, the level of the discount has been relatively fixed since 1992 at a level of $86,000 to $110,000 per megawatt of capacity per year or a reduction off of the otherwise applicable TOU-8 rate of 1 to 1 ½ cents/kWh.  Overall, Edison estimates its interruptible program costs at about $180 million per year.  
Based on the program’s operation over the past two years since the ISO began operation, the cost to ratepayers for each hour that Edison’s interruptible customers were actually curtailed was around $6,000 to $10,000 per Mwh.  This is approximately ten times the ISO’s current price cap of $750/Mwh, which represents the upper limit on what the ISO considers a reasonable cost to acquire an additional Mwh of capacity.

In deciding whether or not interruptible customers should be allowed to participate in the utilities’ proposed demand responsiveness programs we must consider the following; are interruptible customers precluded from participating in the program due to the requirements of PU Code 743.1; what ratepayer benefits exist from allowing their participation; and at what level they should be paid for program participation. 

PU Code 743.1 requires that:

(a)	Electrical corporations shall continue the availability to qualified heavy industrial customers of optional interruptible or curtailable service.  The effective rate for interruptible or curtailable service to qualifying customers shall reflect a pricing incentive for electing to operate under the interruptible or curtailable service option.
(b)	…In no event shall the level of the pricing incentive for interruptible or curtailable service be altered from the levels in effect on June 10, 1996, until March 31, 2002.  (emphasis added).

Since PU Code 743.1 refers to both “interruptible” and “curtailable” service, a first reading of this section would appear to prohibit any change in the “pricing incentive” for this behavior.  The requirements of PU Code 743.1 appear to preclude not only decreasing but also increasing the level of the pricing incentive.  As Edison itself noted in Advice Letter 1163, PU Code 743.1 applies to existing interruptible customers.

PU Code 743(f), however, reserves to the Commission “throughout the term of any of these [interruptible] contracts, the right to amend the contract.”  While the Commission may exercise this right unilaterally, the Commission has usually provided interruptible customers the option to reevaluate their obligations.  In the present case, the demand responsiveness programs represent a shifting in the timing of the interruptible customer’s willingness to curtail.  Rather than curtail in response to events happening for the most part in the hour-ahead or real-time energy markets, the purpose of the demand responsiveness programs is to have interruptible (and other customers) curtail in the day-ahead market.  The benefit to ratepayers is supposed to occur because the reduced demand in the PX market lowers the PX price to all utility customers.  If this curtailment were instead to occur in the hour-ahead or real-time energy markets, this benefit would not materialize.

Allowing interruptible customers to curtail in the day-ahead market therefore is altering the terms of the contract and it is reasonable to authorize an additional payment for varying the terms of the contract by moving the time of curtailment forward and crediting a portion of the savings to these customers.  

Given the large rate discounts that interruptible customers already receive it is not reasonable that these customers receive the full PX price for their participation in the utilities’ demand responsiveness programs.  We believe that they instead should be paid at a rate of 50% of the incentive payment.  

This serves three public policy goals.  First, it reflects the existing discounts that interruptible customers receive.  Second, it still allows interruptible customers to participate in the utilities’ programs and at a level of incentive that should be sufficient to ensure participation.  Depending upon the level of the PX day-ahead price interruptible customers could still receive upwards of 30 cents/kWh.  Third, this provides a larger incentive for new customers not on the utilities’ existing interruptible programs to participate in the utilities’ demand responsiveness programs.  Drawing these new customers into the program not only provides price benefits to customers but also provides an additional reliability benefit.

The rationale for allowing interruptible customers to voluntarily curtail in the day-ahead market also strongly argues against changing the existing prohibition against allowing these same customers to participate in the ancillary services market.  The rationale of the utilities’ demand responsiveness programs is that by curtailing in the day-ahead market the PX price is lowered.  This lowered rate is spread out over the entire PX day-ahead energy market of around 40,000 Mwh or greater.  Allowing these customers to curtail in other markets would not provide the same advantage.  The PX price would be higher, and any savings from reduced prices in the ancillary services market would be spread out over a far smaller market.    

In approving the participation of interruptible customers into other demand responsiveness programs we must seek to ensure that ratepayers receive the greatest benefit and that there is not a mismatch between individual and societal benefits.  As discussed above, the greatest amount of societal benefits appear to be achievable by allowing participation in the day-ahead PX market.  The incentives of the individual end-user, in contrast, may bias them toward participation in the ancillary services market because prices in these markets tend to be higher during periods of high demand.  Having interruptible customers participate in ancillary services markets also leads back to the “double counting” problem.  Interruptible customers would end up being paid to participate in markets providing reliability benefits, the result of which is to mitigate or avoid curtailments that the interruptible customers already had contractually agreed to undertake in exchange for reduced rates. 

Other Program Modifications

The Energy Commission proposed a number of modifications to the utilities’ programs.  PG&E has already agreed to their request to include more detailed information in its reporting requirements.  We agree with the Energy Commission’s recommendation to require that some smaller customers be allowed to participate in the demand responsiveness programs in order to acquire information on how well they respond to price signals.  PG&E has already agreed to include up to 50 small customers in its program.  We believe that both PG&E and Edison should include at least up to 50 smaller customers to participate, and to allow even more smaller customers to participate if it is cost-effective to do so.   

We also agree with the Energy Commission’s concern regarding the potential for customers to “game the system” and receive curtailment payments from the utility for reductions in load that would have occurred anyway.  The utilities generally propose the use of a 5-day average while the Energy Commission recommends the use of a 15-day average to calculate baseline energy usage.  We believe that a 10-day average strikes a good balance between the need to prevent gaming while ensuring that it is not overly difficult for program participants to volunteer to curtail load.  There is also a further potential for gaming to the extent a customer participates in other demand responsiveness programs in addition to those run by the utilities, since each program appears to use somewhat different formulas and criteria.  This is an additional reason to limit the participation of interruptible customers solely to the utilities’ demand responsiveness programs.  We will also require the utilities, as part of their compliance filings, to identify and/or propose necessary safeguards to prevent customers from receiving more than one payment for the same curtailed load.  

We also agree with ARM’s suggestion that the utilities incentive payments to program participants should be based upon the market clearing price less the otherwise applicable energy price the customer would have paid.  This avoids overpaying the customer for curtailing and helps maintain a competitive balance between the utilities’ and the ESP’s demand responsiveness programs. 

We do not see a need to adopt the Energy Commission’s recommendation to raise the 500 mWh per hour cap that Edison has proposed as the maximum amount of load reduction per curtailment event.   This is a reasonable figure and one that Edison believes it will be unlikely to achieve until late in the program’s operation, if at all.  

PG&E has a limit on the number of program participants, but it does not have any cap on the maximum amount of load reduction per curtailment event.  We will not impose a cap on PG&E but believe it should attempt to operate its program so as not to exceed a “target goal” of 500 Mwh per hour, the same limit applied to Edison.  As PG&E has already noted, its current estimate of program participation is 200 Mwh.  The estimated size of the program, combined with a “target goal” of 500 Mwh should address many of the Farm Bureau’s concerns that PG&E’s program is too large.  Even in the unlikely event that PG&E achieves the target goal of 500 Mwh per hour, PG&E’s program would be only 2 ½ times the size of the program PG&E proposed last year. 

We also do not see a need to terminate PG&E’s program at the end of October, 2000 as the Energy Commission requests, rather than December, 2000 as PG&E proposes.  It is possible, although somewhat unlikely, that high energy prices could occur in the later months of the year and PG&E should have the ability to respond to them if needed.  In their comments to the Draft Resolution, the Energy Commission notes that extension of PG&E’s program through December would delay the filing of PG&E’s report on the program’s operation over the summer months.  This minimizes the time available for interested parties to review the report and develop recommendations on either the need for, or changes to, any demand responsiveness programs that may be considered for summer 2001. The Energy Commission recommends, and we agree, that PG&E should file its report on November 15, 2000 covering the program’s operation over the summer months, with a follow-up report due February 1, 2001 covering the program’s operation over the months of November and December.    

Consideration of Demand Responsiveness Programs Through the Advice Letter Process is Appropriate

Last year the Commission adopted the utilities’ proposed demand responsiveness programs through the Advice Letter process.  It is appropriate to consider this year’s proposals through the Advice Letter process as well, particularly as it allows for these programs to be implemented in time for the summer.    

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 February 15, 2000.  Comments were received from ARM, CLECA, Edison, the Energy Commission, ORA and PG&E.  Comments were also received from the California Industrial Users Intervenor Group (CIU) and New Energy Ventures, two parties that had previously not participated in the Commission’s consideration of this Advice Letter.  As a result of these comments a number of changes, corrections and clarifications have been made to the draft Resolution. 

ARM, the Energy Commission, and ORA all generally support the draft Resolution, stating that although the utilities’ programs have potential anti-competitive effects there is a need for demand responsiveness programs to be in place by the summer of 2000.   

The major issue of contention raised in the comments was on the inclusion or exclusion of interruptible customers in the utilities’ demand responsiveness programs.  CIU, CLECA, Edison, NEV, and PG&E all argue that interruptible customers should be included in the utilities’ programs.  ORA, in its comments, supports the draft Resolution’s exclusion of these customers.    On March 2, 2000 an alternate draft Resolution was issued that would allow interruptible customers to participate in the utilities’ programs.  PG&E, Edison, and CIU filed comments in support of the alternate. 

Edison argues that its administrative costs will be less than PG&E’s estimated program costs and that given the small amount of money involved it should not be required to separately track these costs in a memorandum account. In its comments, Edison does not address the draft Resolution’s conclusions that under Edison’s PBR mechanisms ratepayers could end up paying for the program’s costs and that generation-related costs should not be collected from distribution customers. Additionally, Edison does not offer any estimate of its own program costs.  Even if Edison’s program costs are less than PG&E’s, the amount of money at issue is comparable to a number of other expense items in which Edison itself has sought memorandum account treatment from the Commission.

ORA raises the issue that it is the ability of the utility to allocate administrative costs over its entire customer base, and to use ratemaking authority to do so, that is another reason why the utilities have an unfair advantage relative to the ESPs.  This advantage is once again primarily a function of the large market share held by the utilities, although the ability of the utilities to seek recovery of administrative costs through ratemaking mechanisms rather than through direct negotiations with customers may also be a factor.

Finally, CLECA requests that the utilities’ programs be made available to all direct access customers.  The utilities propose limiting participation only to bundled service customers.  CLECA’s request was first raised as part of Edison’s proposed demand responsiveness program for the summer of 1999.  In the intervening year it appears that parties have not pursued this idea.  Therefore, we have no basis in this filing to determine the merits, benefits, and implementation details of how such a proposal would work.  Given our desire to have a program in place by this summer CLECA’s request is denied.  We encourage CLECA to pursue this idea with the utilities, ESPs, and other interested parties if it wishes to propose such a program for the Commission’s consideration in future years. 

This alternate version of the draft Resolution was mailed for comment on March 23, 2000.  Comments were received by ____________ on _______________.

Findings

1.	Southern California Edison (Edison) in Advice Letter 1418-E and Pacific Gas & Electric (PG&E) in Advice Letter 1934-E  propose the adoption of two new rate schedules-- Schedule VPRC—Voluntary Power Reduction Credit for Edison and Schedule E-BID—Price Responsive Load Program for PG&E. 

2.	The purpose of these new rate schedules is to identify a group of customers who are willing to voluntarily curtail their energy usage in exchange for monetary compensation during time periods when the day-ahead Power Exchange (PX) price is expected to be equal to or greater than $250/mWh. 

3.	During periods of high energy demand (such as during hot summer afternoons), end-use customers, insulated from the high energy prices of the wholesale PX market due to the rate freeze, have no incentive to reduce their energy usage.

4.	In a competitive marketplace, it is the interaction of supply and demand that sets the price.  During the rate freeze only the supply portion of the above equation operates when energy prices are high. Due to the rate freeze, the demand side of the equation is largely unaffected by higher prices.

5.	Demand responsiveness programs, such as those the utilities are proposing, attempt to instill some pressure on the demand side to reduce the overall price of energy.  During the rate freeze period demand responsiveness programs generally must pay customers to voluntarily curtail their energy usage.

6.	The utilities’ proposals in their current advice letters are similar in many respects to the demand responsiveness programs approved by the Commission for the summer of 1999 but which the utilities chose not to implement. 

7.	The utilities’ design of their programs does much to ensure that their programs cannot be used to selectively target individual customers as part of a customer retention program. 

8.	Adoption of the utilities’ proposals, as modified, should allow the utilities and interested parties to gather additional information for use by interested parties on how customers respond to hourly prices although much of this information may already be available through the utilities’ other real-time and time-of-use pricing options. 

9.	There is a need for an economic study to determine the cost, benefits, and effect on the energy markets that occur as a result of the utilities’ proposals.

10.	The Commission in Resolution E-3624, and several participants in the Commission’s Demand Responsiveness Roundtable stated that demand responsiveness programs should reduce prices.

11.	Adoption of the utilities’ proposals, as modified, should put downward price pressure on the market-clearing prices of the Power Exchange.  At the present time there is no empirical proof of this effect. 

12.	Both the Market Monitoring Committee of the PX and the Market Surveillance Committee of the Independent System Operator (ISO) have identified the need for more demand responsiveness from retail customers as an important factor in ensuring a competitive energy market.

13.	Adoption of the utilities’ proposals should improve the operation and efficiency of the wholesale energy market that should benefit all customers, both direct access and bundled service.  

14.	The major purpose of the utilities’ programs is to mitigate price spikes in the wholesale market and not to ensure reliability.

15.	The utilities’ proposals may provide an additional pool of customers (in addition to those customers already on interruptible rate schedules) that would be willing to curtail during times when both energy prices are high and system reserves are low. 

16.	The utilities’ programs are only available to the bundled customers of the utility and are not available to direct access customers.

17.	It is the incumbent utilities relatively large share of the marketplace, not their status as incumbent utilities, that enables them to successfully engage in demand responsiveness programs.  

18.	In order for demand responsiveness programs such as the utilities are proposing to work, a firm must be able to; 1) control enough load that is able to curtail in order to reduce the market-clearing price; and 2) still retain enough load to receive the benefits of the market-clearing price. 

19.	ESPs, if large enough, could offer demand responsiveness programs similar to the utilities. 

20.	An ESP that served only one customer could offer a demand responsiveness program if it could pay a customer something less than the market price to curtail and then resell the energy to someone else at the market price.  An ESP with only one customer, however, could not pay that customer to curtail and hope to enjoy the benefits of reduced market prices for the remaining load that it serves. 

21.	ESPs have a greater degree of flexibility to structure demand responsiveness programs than the utilities.  ESPs can use hedging, long-term contracts and other financial instruments and can structure their curtailment programs to offer different prices to different customers. 

22.	Direct access customers who are not on interruptible rate schedules may also be able to participate in some of the load reduction programs that may be developed by the ISO.

23.	It appears that the market for demand responsiveness by the ESPs is still in a nascent state.  Few ESPs appear to be currently offering demand responsiveness programs to their customers.

24.	Depending on the number and severity of curtailment events, the incentives available to a customer under the utilities’ curtailment programs could be roughly comparable to the level of savings a customer could achieve through direct access.  Payments under the utilities’ curtailment program would be much more speculative and harder to predict.  

25.	For those customers who can easily curtail their load, there may be an incentive for them to switch back to bundled service.  The magnitude of this potential switching is too difficult to determine.  

26.	The ability of the ESPs to compete with the utilities, coupled with the modifications to the utilities’ programs we are proposing and the limited duration of the utilities’ program help address the concerns raised by the protestants regarding competitive issues. 

27.	One option not raised by the parties to address competitive issues would be to have the utilities’ programs be made available to all of their customers

28.	This Resolution does not pre-judge either the desirability or need for the utility to offer demand responsiveness programs in subsequent years.  The future role of the utility as a provider of energy services should be addressed in the appropriate Commission proceedings.  Approval of this program is not meant to “grandfather” these programs for future years.

29.	The adoption of rate design policies that directly impose the cost of hourly energy prices upon the end-use consumer is a better alternative to the use of demand responsiveness programs but such policies cannot be implemented until after the rate freeze ends.

30.	Issues associated with the end of the rate freeze should be addressed in the Commission’s Post-Transition Ratemaking Proceeding or in other forums.

31.	 Notification to customers of future rate changes should not occur until after the Commission issues its decisions on the relevant issues.

32.	PG&E estimates the administrative costs of its program at approximately $1.5 million, about 20% of which may be recovered from program participants.

33.	 PG&E seeks the establishment of a new account (the E-Bid Memorandum Account or EBIDMA) to track its administrative costs for potential future recovery in rates. 

34.	Edison did not provide any estimates for the administrative costs of its program.  
 
35.	Under Edison’s Performance-Based Ratemaking formulas adopted by the Commission in D.96-08-025 the additional costs of Edison’s program will affect the level of earnings (or losses) that are subject to sharing between the utility’s shareholders and its ratepayers. 
 
36.	Administrative costs of the utilities’ demand responsiveness programs are generation-related costs and should be allocated to the PX component of the utilities’ bill as they are booked to the appropriate memorandum account.  

37.	The start-up and administrative costs of the program for both utilities should be subject to reasonableness review.

38.	Administrative costs should be collected from all of the utilities’ bundled service customers, since these customers are the major beneficiaries of the utilities’ programs.

39.	AB1890 and Commission decisions require that utility rates be unbundled into their respective components and that the utilities are legally precluded from discounting the energy, public purpose, or competitive transition charge portion of their bills. 

40.	PG&E and Edison should modify their accounting and tariffs to separately track both 1) the administrative costs of the program and 2) incentive payments made under its program.  Incentive payments should be separately identified to program participants. 

41.	Incentive payments made under the program are generation-related costs and should be allocated to the PX component of the utilities’ bill.

42.	Other than administrative costs, the utilities’ programs should not be subject  
to reasonableness review.

43.	In exchange for a significant discount off of the otherwise applicable rate, customers on interruptible tariffs agree that their service may be interrupted or curtailed under certain conditions for a number of times per year.

44.	For customers on Edison’s I-6 interruptible tariff, the level of the discount has been relatively fixed since 1992 at a level of $86,000 to $110,000 per megawatt of capacity per year or a reduction off of the otherwise applicable TOU-8 rate of 1 to 1 ½ cents/kWh. 

45.	Based on the program’s operation over the past two years since the ISO began operation, the cost to ratepayers for each hour that Edison’s interruptible customers were actually curtailed was around $6,000 to $10,000 per Mwh. 

46.	PU Code 743.1 requires that  “…In no event shall the level of the pricing incentive for interruptible or curtailable service be altered from the levels in effect on June 10, 1996, until March 31, 2002.  

47.	 Since PU Code 743.1 refers to both “interruptible” and “curtailable” service, this section appears to prohibit any change in the “pricing incentive” for this service. 

48.	PU Code 743 reserves to the Commission “throughout the term of any of these [interruptible] contracts, the right to amend the contract.” 

49.	Demand responsiveness programs represent a shifting in the timing of the interruptible customers’ willingness to curtail.  Rather than curtail in response to events happening for the most part in the hour-ahead or real-time energy markets, the purpose of the demand responsiveness programs is to have interruptible (and other customers) curtail in the day-ahead market. 

50.	Allowing interruptible customers to curtail in the day-ahead market therefore is altering the terms of the contract and it is reasonable to authorize an additional payment for varying the terms of the contract by moving the time of curtailment forward.

51.	Given the large rate discounts that interruptible customers already receive it is reasonable that these customers receive 50% of the incentive payment for their participation in the utilities’ demand responsiveness programs. 

52.	Bringing new customers not on the utilities’ existing interruptible programs to participate into the utilities’ demand responsiveness programs not only provides price benefits to customers but also provides an additional reliability benefit.

53.	New customers (i.e. not on the utilities’ existing interruptible programs) should be paid 100% of the incentive payment.  

54.	The rationale for allowing interruptible customers to voluntarily curtail in the day-ahead market also strongly argues against changing the existing prohibition against allowing these same customers to participate in the ancillary services market.

55.	 In approving the participation of interruptible customers into other demand responsiveness programs we must seek to ensure that ratepayers receive the greatest benefit and that there is not a mismatch between individual benefits and societal benefits. 

56.	Having interruptible customers participate in ancillary services markets leads to  “double counting” where interruptible customers could end up being paid to participate in markets providing reliability benefits, the result of which is to mitigate or avoid curtailments that the interruptible customers already had contractually agreed to undertake in exchange for reduced rates. 

57.	Allowing some smaller customers (defined as those customers with a maximum demand of less than 500 kW) to participate in the utilities’ program should provide useful information on how smaller customers participate in demand responsiveness programs and respond to hourly price signals.

58.	PG&E and Edison should expand their programs to allow at least up to 50 smaller customers to participate if they meet the necessary metering and communication requirements, and should allow even more smaller customers to participate if it is cost-effective to do so.

59.	The utilities’ baseline calculations do not adequately reflect either normal fluctuations in energy load or circumstances where a customer’s load is trending downward due to declining business conditions.  As a result some customers will be able to game the system and earn curtailment payments for reductions in load that would have occurred anyway. 

60.	The Energy Commission recommends that the utilities use a 15-day average rather than the 5-day average proposed by the utilities.

61.	The use of a 10-day average to calculate baseline energy usage strikes a balance between the need to prevent gaming while ensuring that it is not overly difficult for program participants to volunteer to curtail load.

62.	There is a further potential for gaming to the extent a customer participates in other demand responsiveness programs in addition to those run by the utilities, since each program appears to use somewhat different formulas and criteria. x

63.	Edison and PG&E should subtract the “otherwise applicable energy charge” in determining the level of incentive payment. This avoids overpaying the customer for curtailing and helps maintain a competitive balance between the utilities and the ESPs. 

64.	PG&E should seek to limit its maximum total load reduction for any one curtailment event to a target goal of 500 mWh per hour.   

65.	PG&E should provide the same level of detail in its reporting requirements that Edison has already agreed to provide. 

66.	25 cent/kWh is an appropriate price to trigger the initiation of a curtailment event under the utilities’ programs. 

67.	PG&E’s program should expire on December 31, 2000 giving PG&E the ability to use its program should high energy prices occur in the later months of the year. 

68.	It is appropriate to consider the utilities’ proposals through the Advice Letter process.

69.	The protests of the Alliance for Retail Markets, California Energy Commission, California Farm Bureau Federation and the Office of Ratepayer Advocates are granted in part, and denied in part as discussed in this Resolution.

Therefore it is ordered that:

1.	The request of Southern California Edison Company (Edison) in Advice Letter 1418-E and Pacific Gas & Electric (PG&E) in Advice Letter 1934-E to establish demand responsiveness programs are approved as modified.

2.	Should either Edison or PG&E choose to implement their programs as modified in this Resolution, they shall file a supplemental advice letter with tariff sheets consistent with the Resolution within 20 days.  The tariff sheets shall be effective after Energy Division has reviewed them for compliance with this Resolution.

3.	Edison’s and PGE’s supplemental advice letter filing, should they choose to submit one, shall contain the following modifications to its current proposals:

•	PG&E and Edison shall expand their programs to allow up to at least 50 smaller customers (defined as customers with a maximum demand under 500 kW) to participate if they meet the necessary metering and communication requirements, and to increase this number if it is cost-effective to do so; 
•	PG&E shall provide the same level of detail in its reporting requirements that Edison has already agreed to provide;
•	PG&E shall seek to limit the maximum total load reduction for any one curtailment event to a target goal of 500 mWh per hour;  
•	The administrative costs of the program for both utilities shall be subject to reasonableness review; 
•	The baseline for calculating energy reductions shall be changed from 5 days to 10 days;
•	PG&E and Edison shall identify and/or propose necessary safeguards to prevent customers from receiving more than one payment for the same curtailed load; 
•	Edison shall modify its accounting and tariffs to separately track both 1) the administrative costs of the program and 2) incentive payments made under its program; 
•	Edison and PG&E shall assign all costs of their program (both administrative and incentive payments made under the program) to the PX component of their customers’ bills.
•	Edison and PG&E shall assign administrative costs to the PX component of their rates as they are billed to the appropriate memorandum accounts;
•	Edison and PG&E shall subtract the “otherwise applicable energy charge” in determining the level of incentive payment; 
•	Customers on existing interruptible rate schedules may participate in the program but shall be paid only 50% of the incentive payment; and,
•	New customers (those who are not an existing interruptible rate schedule) shall receive 100% of the incentive payment for their participation.
•	Edison and PG&E’s demand responsiveness programs shall expire no later than December 31, 2000. 

4.	Should PG&E and Edison implement a demand responsiveness program they shall provide to the Commission’s Energy Division and other interested parties a detailed economic study on the total costs of the program and its economic benefits.  This study shall include detailed information on the effect of the program, if any, in lowering the day-ahead PX price; an economic study of the reasons for the high PX prices during the hours the program is in operation; the effect of the program on all other energy markets operated by the ISO; elasticity estimates of the price-responsiveness of load to energy prices; the available operating reserves (calculated both before and after subtracting out customers on interruptible rate schedules) during times of program operation; and any other information useful in evaluating the program.  This report shall be due no later than December 15, 2000 and cover the program’s operation through the summer of 2000. 

5.	The protests of the Alliance for Retail Markets, California Energy Commission, California Farm Bureau Federation and the Office of Ratepayer Advocates are granted in part, and denied in part as discussed in the Findings section of this Resolution. 

6.	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 April 6, 2000; the following Commissioners voting favorably thereon:

					___________________
		                                                    WESLEY M. FRANKLIN							                     Executive Director