9. Implementation

We are persuaded by parties that we must implement today's decision without delay. Quick implementation is needed to allow reasonable opportunity for programs to be finalized and marketed, customers to be subscribed, and meters and other equipment to be installed (to the extent feasible and necessary).

To facilitate implementation, Assigned Commissioner Wood issued a ruling on March 1, 2001 directing respondent utilities to begin crafting advice letters and tariffs. Consistent with that ruling, respondent utilities filed and served draft advice letters and tariffs on March ___, 2001 implementing the decisions in Commissioner Wood's DD. Comments and reply comments on the draft advice letters and tariffs were included in comments and reply comments on the DD.

As a result, we direct that within 5 days of today respondent utilities file and serve advice letters and tariffs to implement today's orders. Those advice letters and tariffs will become effective in 5 days, unless suspended by the Energy Division Director. The Director may require that respondent utilities file and serve amended advice letters and tariffs at his direction to implement today's order. Further, the Director may require each respondent utility to file and serve individual advice letters and tariffs as needed to separately implement portions of today's order.

Findings of Fact

1. Interruptible programs are not inexpensive, and in some cases cost the same or more than prices charged in the dysfunctional electricity wholesale market, with current interruptible programs costing about $220 million per year for about 2,200 megawatts of available interruptible load.

2. D.00-10-066 suspended until March 31, 2001 the portion of SCE's interruptible tariffs that allowed customers to either opt-out of the program, or change their firm service levels, during a 30-day window beginning November 1, 2000.

3. D.01-01-056 suspended further assessment of penalties that customers on interruptible schedules would otherwise incur for failing to curtail upon request, along with the tolling of hours and number of curtailments.

4. SCE interruptible customers have received more than $900 million in reduced rates since the beginning of 1996.

5. Over 78% of all customers on SCE's interruptible program signed up for 99% of their load being subject to interruption.

6. Allowing SCE interruptible customers to opt out or adjust firm service levels without consequence would reward customers who made bad judgments, and transfer the responsibility of bearing outages from the interruptible customers to all other ratepayers.

7. The underlying premise of SCE's program was that interruptible customers were allowed to opt out or adjust firm service level with advance notice of 5 years.

8. During January 2001, there was almost continuous use of interruptible programs, substantially exhausting the programs for the rest of 2001.

9. Electricity market experience during January 2001 was far from the normal expectation.

10. An opt-out in November 2001 if not suspended would have otherwise taken effect for most customers by January 1, 2001.

11. A calendar year basis for opt-out promotes reasonable administrative ease.

12. Public and private schools, colleges, universities, hospitals and prisons are customers upon whom public health, safety and welfare depend.

13. If an existing interruptible customer cannot perform in the existing program the customer is unlikely to successfully perform in another similar program.

14. Restricting transfer among programs for non-performing interruptible customers will minimize unreasonable turnover from one program to another without benefit to the state.

15. The need for existing programs is unlikely to end by March 31, 2002.

16. Limiting existing program use to one 6 hour event per day, and 40 hours total per month, will extend program availability.

17. Current interruptible tariffs do not limit a customer's right to continue using electricity during curtailment periods, subject to substantial penalty for failing to curtail.

18. Caliber One does not claim to be a public utility regulated by the Commission, no party claims that Caliber One is a public utility regulated by the Commission, and no evidence is presented that Caliber One is a public utility regulated by the Commission.

19. Caliber One and parties had several opportunities to raise and address Caliber One's issue concerning whether or not interruptible customers have the right to willfully refuse to comply with an interruption notice without breaching their obligations.

20. An interruptible customer's willful refusal to curtail may defeat the public purpose goal of the interruptible program in the specific instance where the customer shifts the risk of penalties from itself to others by use of insurance.

21. Interruptible programs have been largely exhausted for 2001 based on extensive use in January 2001.

22. A replacement fixed payment for capacity interruptible program is necessary.

23. A reasonably simple approach is needed for the VDRP to be successful.

24. Most customers state that their business is conducting their business, not buying and selling electricity, and not constantly monitoring the electricity market to make decisions about buying electricity or curtailing their operations.

25. A fixed rate for the VDRP, subject to limited modification as needed, is efficient and simple.

26. The Energy Division's recommendation of $0.15/kWh is too low given prices in the current dysfunctional market, but the Joint Parties recommendation of $0.50/kWh to $0.75/kWh is too high, reflecting prices at the unreasonable levels in today's dysfunctional wholesale market.

27. A dual rate for the VDRP (between day ahead and day of) is needlessly complex, and will encourage customers to withhold supply, waiting for the higher rate.

28. A minimum payment to VDRP participants provides compensation for at least some of their cost and inconvenience for participation.

29. Satisfaction and participation in an air conditioner cycling program will decline if the program is overused by the utility.

30. The CEC estimates that 14,000 MW of air conditioning load (28% of total load) occurs during the state's summertime peak demand of 50,000 MW, with about 7,000 MW commercial, and about 7,000 MW residential.

31. Comverge Technologies, Inc. can assume full responsibility for turnkey projects, take the financial risk on a pay-for-performance basis, and use existing paging companies for radio communication.

32. Comverge can use radio signals in an interruptible program with a wide range of appliances (from air conditioners to electric water heaters, pool pumps, or other electric motors) in residential, commercial or industrial settings.

33. Failure to account for recent conservation efforts reduces the incentive to participate in an OBMC program, while failure to recognize reasonable growth in demand over time similarly penalizes participation.

34. Measuring 5% OBMC increments against usage over the last 10 days is the most up-to-date measurement reflecting current conditions when actual system conditions otherwise require mandatory curtailments.

35. Measuring 20% OBMC total reduction against the prior year's average peak usage for the same month recognizes yearly variations, and does not penalize customers for near term demand reduction efforts.

36. It will facilitate further study of SDG&E's HVAC program to provide meters and communication equipment without charge to customers who participate in the VDRP.

37. Many customers are exempt from rotating outages because they share a circuit with an essential customer.

38. Inclusion of non-essential customers who are now on exempt circuits in the rotating outage pool increases the amount of load available for emergency curtailment by thousands of megawatts, thereby significantly reducing the frequency and duration of outages all other customers may face, and more equitably distributing the burden of outages.

39. Inclusion of non-essential customers in the rotating outage pool ensures that all non-essential customers experience the same incentive to voluntarily curtail use before mandatory curtailments are initiated, thereby assisting the entire State weather the current crisis.

40. Isolating essential from non-essential customers must be carefully studied to promote equity between customers, and to cost-effectively increase the available pool for mandatory curtailment.

41. Equity between customers is compromised by treating customers differently for purposes of rotating outages based solely on service voltage.

42. Limiting the pool of customers subject to rotating outages increases the likelihood of outages for those in the rotating outage pool, while the excluded customer is protected.

43. About 75% of transmission level customers cannot be easily curtailed by the utility without extensive interaction with, and cooperation from, the customer.

44. Fossil fuel producers are critical to the electric system, as well as the overall public health and safety of California, and outages affecting producers, pipelines, and users, if not coordinated, can cause unacceptable jeopardy to public health and safety.

45. The ISO may give very short notice (e.g., 10 minutes) of a Stage 3 mandatory curtailment.

46. Cost-effective utility treatment of remotely and manually controlled circuits can likely be improved to promote efficiency and equity.

47. It is important to study and implement all reasonable steps for SCADA and non-SCADA execution of rotating outages to ensure that forced outages are accomplished with optimal equity and efficiency, as well as within reasonable cost.

48. PG&E provides electric service to approximately 48,000 medical baseline customers, of whom about 22,000 are classified as "life support" customers, while SCE has about 27, 000 medical baseline customers, of whom about 2,200 are critical care customers.

49. An infrastructure currently exists in the medical community and industry to supply and inspect backup devices for vital medical equipment that need not be duplicated by utilities.

50. All customers who qualify for medical baseline have a special need for electricity.

51. The number of calls to medical baseline customers may be a problem if such calls are required during all Stage 3 events but not all Stage 3 events result in a rotating outage.

52. Rotating electrical outages cause particular concern for public health and safety when they involve underground transit systems, such as BART and MUNI.

53. It is technically feasible to exempt BART from rotating outages without significant negative effects on PG&E's overall emergency response plan, and PG&E asks that the underground component of MUNI be similarly exempt.

54. PG&E includes a rotating outage block number on customer bills, but neither SCE nor SDG&E notify their customers of the rotating outage block to which the customer is assigned.

55. Customers need and expect reasonable, timely and accurate information on rotating outages, and public health and safety may depend upon it.

56. Sixteen 16 of 28 rural counties do not have a hospital with more than 100 beds.

57. Severity of sickness or injury is not a function of the geographic location of the patient.

58. Water and sewage treatment utilities have backup generation or other capacity for operation and storage during power interruption, and have reasonably prepared for power interruptions which may occur from a number of causes.

59. Existing rules allow water and sewer utilities to request partial or complete rotating outage exemption, or partial or complete service restoration, based on an emergency.

60. Additional funds not now available from existing rates may be needed for utility implementation of some, but not all, programs and studies ordered herein.

61. ISO rates are set by FERC.

62. PG&E and SCE have approximately the same customer base, SDG&E has a much smaller customer base, and SCE generally had the most interruptible program success.

63. Current interruptible program costs are about $100 per kW per year.

Conclusions Of Law

1. Any SCE interruptible customer who did not elect to opt-out or make an adjustment in firm service level as late as the opportunity to do so in 1999 should be expected to meet its tariff obligations, and be required to remain on the interruptible program, subject to reasonable flexibility.

2. Opt-out or adjustment in firm service level for SCE customers should be allowed to occur in one of four ways during a 30 day window, with the effective date of the opt out or adjustment of firm service level January 1, 2001.

3. SCE interruptible customers upon whom public health, safety and welfare depend should be allowed to opt-out or adjust firm service level during a 30-day window without condition.

4. SCE interruptible customers who opt out in the authorized 30-day window should not be allowed to participate for one year in either any other program that pays a capacity payment, or the ISO Ancillary Load Services Program.

5. Existing interruptible programs should be extended through December 31, 2002, and program use should be limited to one 6-hour event per day, and 40 hours total per month.

6. An interruptible customer's willful refusal to comply with interruption notices does not constitute a breach of SCE's current interruptible Schedule I-6.

7. PU Code Sections 701, 728 and 743(f) give the Commission authority to regulate public utilities, and contracts between public utilities and utility customers.

8. Caliber One is not a public utility regulated by the Commission.

9. The Commission regulates the terms and conditions of interruptible tariffs and contracts between public utilities and customers, but not contracts between non-public utilities, whether or not the agreement references a regulated rate or tariff.

10. Adequate notice and opportunity to comment have been given on the insurance issue raised by Caliber One.

11. An existing or new customer should not be eligible for continued or new subscription to interruptible tariffs unless the customer files an affidavit under penalty of perjury with the utility stating that the customer does not have, and will not obtain, any insurance covering payment of paying non-compliance penalties for willful failure to comply with requests for curtailment.

12. The suspension of penalty provisions imposed by D.01-01-056 should now be removed.

13. The new BIP program should be adopted.

14. The VDRP program should be adopted, with the rate set at $0.25/kWh.

15. SCE's existing air conditioner program should be reopened, and the new program adopted, for all customers at the several cycling options described in this decision.

16. Respondent utilities should notify large customers of the OBMC by May 1, 2001, and coordinate communications between interested customers.

17. Meters should be provided without charge to participants in the SDG&E HVAC program if they also participate in the VDRP.

18. Respondent utilities should study and report on reconfiguring circuits to isolate essential from non-essential customers, and increase the pool of non-essential customers available for rotating outages by Summer 2001, Summer 2002, and beyond.

19. Respondent utilities should include transmission level customers in rotating outages, subject to their exclusion if they are essential use customers, participate in OBMC, supply power to the grid in excess of load, jeopardize system integrity by their inclusion in rotating outages, or are otherwise exempt by the Commission.

20. A respondent utility should install automatic switching equipment, controlled by the utility, at the transmission customer's expense, if the customer refuses to drop load upon request, or should add the customer to the next rotating outage block so the customer does not escape curtailment.

21. Essential customers may subscribe to interruptible tariffs, but eligibility should be screened by the utility, wherein the utility should require an affidavit submitted under penalty of perjury as described in this decision for the purpose of such screening.

22. Respondent utilities should coordinate interruptions, to the extent feasible, between fossil fuel producers, pipelines and users to minimize disruption to public health and safety.

23. Respondent utilities should study and report on the cost of dispatching personnel versus installing automated equipment in remote locations to implement forced outages.

24. Respondent utilities should implement programs to notify each medical baseline customer when a rotating outage likely to affect the customer is imminent, targeting life support or critical care customers first, and should report to the Commission on these programs.

25. Respondent utilities should report on their recent efforts undertaken with OSHA and/or OES to address particular and unique risks to employee and public health and safety from imminent electrical outages to industrial customers in Summer 2001.

26. BART, and the underground portions of MUNI, should be exempt from rotating outages.

27. PG&E should report on the necessary and reasonable mitigation measures to which PG&E and MUNI have agreed, and the measures that PG&E has, or will, implement.

28. The Executive Director should serve a copy of this decision on other rail transit systems under Commission jurisdiction, inviting those transit systems to consider public health and safety issues affecting their systems due to the serious potential of a number of electrical outages in 2001 and 2002.

29. SCE and SDG&E should address in Phase 2 the need, desirability and reasonableness of including a rotating outage block number on each customer bill, with a notice that the block may change without notice based on operational conditions.

30. Sick or injured people in rural hospitals can be just as sick or injured as their urban counterparts, and deserve the same level of protection for electricity services.

31. The essential customer list should be amended to include all hospitals, and respondent utilities should submit information in Phase 2 on the effect this change has had on mandatory curtailments, including the number of circuits and megawatts that are available for rotating outage before and after the change.

32. Each respondent utility should file an updated rotating outage action plan by May 15, 2001.

33. The following should not be authorized at this time: the customer recognition program; modification of the essential customer list for water districts, sewer districts, ancillary government services, or networks; any changes in the notice provided to interruptible customers by respondent utilities; and the SLRP.

34. FERC approval is uncertain regarding ISO funding of utility interruptible programs and the costs for changed curtailment priorities.

35. A surcharge on respondent utility rates to fund new interruptible programs plus the costs for changed curtailment priorities is inconsistent with the current rate freeze.

36. The funding in DWR rates of respondent utility interruptible programs plus the costs of changed curtailment priorities is currently not an option.

37. Each respondent utility should establish a memorandum account to track all dollars it spends above funds authorized in current rates to implement any decision in today's order regarding interruptible programs and curtailment priorities.

38. Each respondent utility should implement today's orders without delay as part of its public utility obligation.

39. Interruptible programs and curtailment priorities should be capped at the following megawatt and annual dollar limits:

INTERRUPTIBLE PROGRAM

AND CURTAILMENT PRIORTY LIMITS

THROUGH DECEMBER 31, 2002

UTILITY	INTERRUPTIBLE PROGRAM LIMIT (MW)	TOTAL ANNUAL PROGRAM DOLLAR LIMIT ($ MILLION)
PG&E	2,000	$200
SCE	2,750	$275
SDG&E	250	$25
TOTAL	5,000	$500

40. The megawatt limits should include currently subscribed megawatts, and should be the total megawatts that may be subscribed to interruptible programs through December 31, 2002.

41. The annual dollar limits should include amounts funded in current rates, plus those recorded in the memorandum account of each respondent utility, for total interruptible program costs, and new costs implementing changes to curtailment priorities.

42. Each respondent utility should report monthly on the programs we order today, and the costs that are being incurred.

43. Each respondent utility should file one or more advice letters with tariffs within 5 days of today to implement today's orders, with those advice letters and tariffs becoming effective in 5 days, unless suspended by the Energy Division Director.

44. This order should be effective today to allow reasonable opportunity for programs to be finalized and marketed, customers to be subscribed, and meters and other equipment to be installed for Summer 2001 program implementation.

INTERIM ORDER

IT IS ORDERED that:

1. Within five days of the date of this order, respondent utilities Pacific Gas & Electric Company (PG&E), Southern California Edison Company (SCE), and San Diego Gas & Electric Company (SDG&E) shall each file and serve an advice letter with revised tariffs. The advice letters with revised tariffs shall implement the directions in this order and Attachment A. Each advice letter with tariffs shall be in compliance with General Order 96-A. The advice letters and tariffs shall become effective five days after filing, unless suspended by the Energy Division Director. The Energy Division Director may require a respondent utility to amend its advice letter and tariffs to comply with the orders herein, and may require a respondent utility to file and serve individual advice letters and tariffs as needed to separately implement portions of today's order.

2. A protest to an advice letter filed and served by a respondent utility to modify the Voluntary Demand Response Program rate shall be filed and served within 10 days of the date the advice letter is filed.

3. The priority system for rotating outages stated in this order and in Attachment C shall supercede the existing priority system 10 days from today, and shall be implemented by each respondent utility. PG&E shall exempt the Bay Area Rapid Transit District, and the underground portions of the San Francisco Municipal Railway (MUNI), from rotating outages. By May 1, 2001, each respondent utility shall notify customers using 500 kilowatts or more (average peak demand) of the adopted Optional Binding Mandatory Curtailment Program, and shall coordinate communication between customers on a circuit when one customer expresses its intent to participate.

4. Respondent utilities shall file and serve the adopted studies and reports shown in Attachment D according to the schedule, terms and conditions stated in this order and in Attachment D. Parties may file and serve comments, responses or protests as provided in Attachment D. Responses or protests to any application or advice letter filed by a respondent utility to implement any matter raised by such study or report shall be filed and served within 10 days of the date the application or advice letter is filed and served. The Assigned Commissioner and Presiding Officer, or the Administrative Law Judge, may change these dates by ruling.

5. In the event MUNI files a formal complaint regarding mitigation measures to protect MUNI passengers and staff from a rotating outage, MUNI shall serve a copy on PG&E the same day that it is filed with the Commission. PG&E shall file and serve its answer within 10 days of the date the complaint is filed. The Assigned Commissioner and Presiding Officer, or the Administrative Law Judge, may change these dates by ruling.

6. The serving respondent utility shall install, at the transmission customer's expense, automatic equipment controlled by the utility to implement rotating outages if a transmission level customer is not exempt from rotating outages but fails to cooperate and drop load at the request of its serving utility. A transmission level customer who refuses to drop load shall be added to the next rotating outage block so that it does not escape curtailment as a result of nonfeasance.

7. Respondent utilities shall reasonably coordinate interruptions, to the extent feasible, between fossil fuel producers, pipelines and users to minimize any disruption to public health and safety.

8. Each respondent utility shall file and serve an application or advice letter seeking Commission authorization to implement an Occupational Health and Safety Administration (OSHA) or Office of Emergency Services (OES) recommendation regarding the exemption of an industrial customer from rotating outages to protect employee or public health and safety. Respondent utility shall file this application or advice letter only if specific Commission authorization is needed but not yet available. The application or advice letter shall include a statement from OSHA and/or OES in support of the request, showing that no other reasonable means to protect employee or public health and safety are available other than exemption from rotating outage.

9. The Executive Director shall serve a copy of this decision on Los Angeles County Metropolitan Transit Authority, Sacramento Regional Transit District, Santa Clara Valley Transportation Authority, and San Diego Trolley Incorporated. The cover letter shall invite these rail transit systems to evaluate public health and safety concerns on their systems due to the serious potential of a number of electrical outages in 2001 and 2002. It shall recommend that each system discuss the matter with their serving utility, and cooperatively implement any reasonable and necessary mitigation measures. It shall also invite each system to make a joint proposal, in cooperation with its serving utility, other rail transit systems, and the Commission's Rail Safety and Carrier Division, regarding any mitigation measures that should be considered by the Commission, and which require Commission authorization.

10. SCE and SDG&E shall, and other parties may, address in Phase 2 the need, desirability and reasonableness of SCE and SDG&E including a rotating outage block number on each customer bill, with a notice that the block may change without notice based on operational conditions. Parties shall include this issue in any Phase 2 pleadings regarding a list of issues for consideration, along with their recommendations on how and when this issue should be considered.

11. Respondent utilities shall submit information in Phase 2 on the effect of adding hospitals of less than 100 beds to the list of essential customers excluded from mandatory curtailments. The information shall include the effect on the number of circuits and megawatts that are available for rotating outage by excluding all hospitals from rotating outage compared to excluding only hospitals with 100 beds or more. The study regarding the reconfiguration of circuits to narrow exempted load shall include an assessment of isolating hospitals of less than 100 beds.

12. By May 15, 2001, each respondent utility shall update and file its annual rotating outage action plan to include the orders herein.

13. Each respondent utility shall establish a memorandum account consistent with the orders herein. The memorandum account shall track all dollars spent above funds authorized in current rates to implement any program, activity, study, or report ordered herein. The accounting shall separately identify the cost of each program, activity, study or report (e.g., separately track costs for the new Base Interruptible Program, Voluntary Demand Response Program, each curtailment study, each report). Each respondent utility may include interest on the balance. The burden to demonstrate reasonableness for future cost recovery shall be on each respondent utility. Each respondent utility shall implement the orders herein without delay consistent with their public utility obligations and responsibilities.

14. The following limits shall apply to program implementation by respondent utilities:

INTERRUPTIBLE PROGRAM

AND CURTAILMENT PRIORTY LIMITS

THROUGH DECEMBER 31, 2002

UTILITY	INTERRUPTIBLE PROGRAM LIMIT (MW)	TOTAL ANNUAL PROGRAM DOLLAR LIMIT ($ MILLION)
PG&E	2,000	$200
SCE	2,750	$275
SDG&E	250	$25
TOTAL	5,000	$500

The megawatt limits apply to the total megawatts that may be subscribed to interruptible programs through December 31, 2002 without further Commission authorization, including currently subscribed amounts. If a currently subscribed megawatt transfers from an existing program to a new program (e.g., by exercising an opt-out option), that megawatt shall not be counted twice against the program total. The dollar limits apply to the total dollars to be spent by each respondent utility on an annual basis for total interruptible program costs, and new costs implementing changes to curtailment priorities, without further authorization. These limits shall apply separately for January 1, 2001 through December 31, 2001, and January 1, 2002 through December 31, 2002. These dollars include amounts funded in current rates, and those recorded in the memorandum account of each respondent utility.

15. Applicant shall cite applicable authority for Commission action on an emergency basis in any application filed and served by a respondent utility for expedited Commission authorization to increase the megawatt or dollar program limit adopted herein.

16. This proceeding shall remain open for consideration of interruptible programs and curtailment priorities for Summer 2002, and any other issue or issues identified by the Commission, Assigned Commissioner and Presiding Officer, or Administrative Law Judge.

This order is effective today.

Dated ___________, at San Francisco, California.

ATTACHMENT A

CHANGES TO CURRENT INTERRUPTIBLE PROGRAMS,

NEW INTERRUPTIBLE PROGRAMS,

AND ROTATING OUTAGE PROGRAMS

R.00-10-002

1. CHANGES TO CURRENT INTERRUPTIBLE PROGRAMS

1.1 Modified Opt-Out: Southern California Edison Company (SCE) shall notify all affected customers of the opt out options provided by this decision. Customers may opt out of SCE's interruptible program, or change their firm service level, subject to the following.

1.1.1 Customers may elect to opt-out of interruptible tariffs, or change their firm service level, during a one-time 30 day period, in one of four ways. The opt-out or change in firm service level election will become effective retroactive to January 1, 2001.

1.1.1.1 Pay back to SCE the total discounts, or the amount related to the change in firm service level, received in 2000 and 2001, including interest. SCE will establish a payment schedule, but all payments must be received by December 31, 2001.

1.1.1.2 Invest in and install certified energy efficiency equipment by July 1, 2001 equal in price to the total discount, or the discount related to the changed firm service level, received in 2000 and 2001, including interest.

1.1.1.3 Participate in the Voluntary Demand Reduction Program (VDRP) providing the amount of kWh load reductions that would be required in the SCE Schedule I-6 program. Participants will not be paid for load reductions until the required Schedule I-6 obligation is met. If the Schedule I-6 program is not called the entire allowed 150 hours, the requirement will be adjusted downward. If participants do not reduce load the required amount by December 31, 2001, the Schedule I-6 penalties shall apply.

1.1.1.4 Public and private schools, colleges, universities, hospitals, and prisons may elect to opt-out, or increase their firm service level, with no repayment obligation.

1.1.2 Customers who opt-out during the one time 30 day period may not participate for one year in a program that pays per kW or the ISO Ancillary Services Load Program. There is no restriction on participating in other interruptible programs, as long as customers are only paid once for a load reduction.

1.2 Other Changes to Existing utility distribution company (UDC) Interruptible Programs:

1.2.1 Limit program use to one 6 hour event per day.

1.2.2 Limit program to 40 hours per month.

1.2.3 Programs extended to December 31, 2002.

1.2.4 Insurance: Insurance may not be used to pay non-compliance penalties for willful failure to comply. Eligibility for an interruptible program will require that each customer execute an affidavit that it does not have, and will not obtain, such insurance.

1.3 Suspension of Interruptible Programs:

The UDCs shall, within 3 days, notify all interruptible customers that the suspension of interruptible program penalties and the tolling of hours and number of curtailment events has ended. Three days from the date of the notice, the UDCs shall resume operation of the interruptible programs as modified by this decision, including the assessing of penalties and charging the number of hours and events toward the program maximums.

1.4 Participation in Additional Programs:

Participants in the existing interruptible program who have fulfilled the annual maximum obligation under the program, may participate in the Base Interruptible Program without loss of discounts earned through existing program participation.

During the month of November participants in both the existing interruptible program and the Base Interruptible Program may select which program they shall participate in during 2002. If no selection is made, the customer shall participate in the existing program and participation in BIP shall be terminated as of 1/1/02.

2. NEW INTERRUPTIBLE PROGRAMS

2.1 Modified Joint Proposal: New Base Interruptible Program (BIP)

2.1.1 Elements

2.1.1.1 Limit to one 4-hour event per day.

2.1.1.2 Limit to 10 events per month, and 120 hours per year.

2.1.1.3 Annual opt-out option in November.

2.1.1.4 Incentive or $7 per kW-month credit on bill.

2.1.1.5 $6 per kWh penalties for all energy consumption in excess of the customer's firm service level.

2.1.1.6 The bill credit is based on the difference between each month's average peak demand and a customer selected firm service level.

2.1.2 Program open to customers who can commit to curtail at least 15% of load, with a minimum load drop of 100 kW per event.

2.1.3 Load can only be committed to one program, and participants paid only once for a load reduction. Customers may, however, split total load between programs (i.e. if customer reduces more than required under BIP, customer may be paid from the Voluntary Demand Response Program for additional committed load reductions). Customers currently enrolled in a UDC interruptible program, or the ISO's DRP, must complete all obligations to that program before being eligible for this program.

2.1.4 New program participants receive an interval meter and communication equipment without charge, if needed. Costs will be charged as a program expense. Participants receiving free equipment will be required to remain in the program through one full year.

2.1 Voluntary Demand Response Program (VDRP)

UDC operated program that pays for performance with no reservation payment and no penalties.

2.2.1 Payment is $0.25/kWh.

2.2.2 Baseline for evaluating load response will be the average of the immediate past 10 similar days, business or weekend days. The 10 similar days will exclude days when the customer was paid to reduce load.

2.2.3 The program is open to customers who can commit to curtail at least 15% of load, with a minimum load drop of 100 kW.

2.2.4 When the ISO notifies UDCs that load relief is needed, customers are notified of need and bids are requested (bids are for offered kWhs for a specific time). Customers respond with offered kWhs and the UDC either agrees or rejects the bids. Requests may be made the day before or for the same day. UDCs can request bids multiple times for the same hours as conditions change. In their tariffs, UDCs will specify a criteria for accepting bids. The primary factor should be first come first serve, but consideration of time needed versus time bid, and past non-compliance can be included in the criteria.

2.2.5 Once a bid is accepted, if the interruption is cancelled by the UDC the customer is paid the lesser of the hours bid, the hours requested, or 2 hours.

2.2.6 New program participants receive an interval meter and communication equipment without charge if needed. Costs will be charged as a program expense. Participants receiving free equipment will be required to remain in the program through one full year and to bid in at least 10 events. If participants fail to meet requirements they will be charged the cost of installing any meter and communication equipment provided without charge.

2.3 Air Conditioner Cycling Programs - Commercial and Residential Agricultural and Pumping Programs

2.3.1 SCE shall reopen its current air conditioner cycling program at all cycling options.

2.3.2 SCE shall offer a new air conditioner cycling program paying twice the existing rates for an unlimited number of events. Events are limited to 6 hours in any one day.

2.3.3 SCE shall explore load control programs for electric uses other than air conditioning (e.g. electric water heaters) and file an advice letter proposing any program it determines is reasonable.

2.3.4 Pacific Gas & Electric Company (PG&E) and San Diego Gas & Electric Company (SDG&E) shall explore the most reasonable options for implementing an air conditioner cycling program, or other electric interruption program, targeted to residential and small commercial customers. PG&E and SDG&E shall each file an advice letter by May 1, 2001 which analyzes the alternatives, and seeks approval of the alternative that will produce the greatest verifiable load reduction at the least cost.

2.3.5 SCE shall reopen its current agricultural and pumping interruptible tariff, and extend the tariff through December 31, 2002.

2.3 Optional Binding Mandatory Curtailment Program

Elements of Optional Binding Mandatory Curtailment (OBMC) Program.

2.4.1 The OBMC program exempts participants from rotating outages if they can reduce the load on their entire circuit by the required amount for the entire duration of every rotating outage.

2.4.2 The OBMC program operates only when firm load reductions are required (i.e., concurrent with rotating outages).

2.4.3 The baseline used to determine if the required load reduction has been obtained will be the average of the immediate past 10 similar days, business or weekend days. The 10 similar days will exclude days when the customer was paid to reduce load, or the OBMC program operated.

2.4.4 Load reductions will be requested in increments of 5%.

2.4.5 Participants must have the ability to reduce circuit load by 20%. The baseline used to determine if the 20% reduction can be met is the prior year's, same month, average peak usage, adjusted for major changes in facilities. However, the customer must be able to produce at least a 10% load reduction based on the criteria in 2.4.3.

2.4.6 UDCs are required to facilitate circuit aggregation when requested by customer.

2.4.7 The failure to reduce load as required will result in penalties equal to $6/kWh for all excess energy. If a participant fails to reduce circuit load to within 5% of the required amount on two occasions in any one year the customer's participation in the program shall be terminated and the customer shall be prohibited from participating in an OBMC program for 5 years.

2.4.8 Program participants shall pay the cost of any equipment required to participate in the program.

2.5 SDG&E's HVAC Program

No specific funding for this program, but HVAC participants who enroll in the Voluntary Demand Response Program are eligible for free meters and communication equipment, and to the incentives contained in that program.

3. ROTATING OUTAGE PROGRAMS: EQUITY

3.1 Reconfiguring Circuits

3.1.1 By May 1, 2001, PG&E, SCE and SDG&E shall each file and serve a report. The report shall list circuits capable of being reconfigured to increase the amount of load available for rotating outages and the least cost method to achieve that load reduction. The list shall include the amount of additional load added to the rotating outage pool, the time required to complete the reconfiguration, a description of the reconfiguration, and the cost of the reconfiguration. Individual reconfigurations on the list shall be limited to those that do not exceed $500,000. Reconfiguration means any change to a circuit including creating new circuits, installing switching devices, or other adjustments that result in an increase in load available to rotating outages. PG&E, SCE and SDG&E shall sort the list in three ways: by cost, by amount of additional megawatts added to the rotating outage pool, and by date the reconfiguration can be accomplished. Each report shall also identify any alternative means of achieving the goal less expensively. PG&E, SCE and SDG&E shall each make a recommendation on whether or not to implement any or all reconfigurations and or alternatives.

3.1.2 In the reconfiguration study ordered in 3.1.1, respondent utilities shall include the reconfiguration of circuits containing rural hospitals.

3.2 Include Most Transmission Level Customers in Rotating Outages

UDCs shall include transmission level customers in rotating outages, subject to the exclusions permitted for essential use customers and customers participating in OBMC. Transmission level customers who are supplying power to the grid in excess of their load shall be excluded from rotating outages. In addition, if any transmission customers cannot be included in the rotating outage pool because of system integrity concerns, the UDC shall report to the Energy Division on those exclusions.

3.3 Hospitals

UDCs shall include all hospitals on the list of essential customers, and exempt them from rotating outages.

3.4 Essential Customers

Essential customers may participate in interruptible tariffs, but eligibility shall require a demonstration of either back-up generation or a reasonable ability to meet essential needs when interrupted. This may be accomplished by an affidavit under penalty of perjury submitted to the utility.

3.5 SCADA and Non-SCADA

UDCs shall file and serve a report by June 1, 2001 stating the cost of dispatching personnel versus installing automated equipment in remote locations to implement rotating outages. The report shall state any changes the utility has made or is making.

4. ROTATING OUTAGE PROGRAMS: PROTECTIONS

4.1 OUTBOUND CALLING PROGRAM

UDCs are required to operate an outbound calling program to notify medical baseline customers of imminent rotating outages, giving priority to customers on life support or critical care. UDCs are required to undertake their best efforts to contact medical baseline customers once a rotating outage is called. In addition, UDCs shall file and serve a report by June 1, 2001 describing their outbound calling program, including any changes they have made to improve the outbound calling program and the program's operations. As part of the report, UDCs shall identify the time required to notify all required customers for an outage of 1%, 5%, 10%, 15% and 20% of peak load.

4.2 Offices of Emergency Services (OES)

UDCs shall file and serve a report, by June 1, 2001, describing any recent efforts undertaken to address risks to public health and safety from electrical outages to industrial customers.

4.3 BART and MUNI

PG&E shall exempt BART and the underground portion of MUNI from rotating outages. PG&E and MUNI shall also jointly identify any additional measures necessary to ensure the safety of MUNI passengers and staff. PG&E shall file and serve a report by May 1, 2001 on measures taken to implement safety of MUNI passengers and staff.

4.4 Other Rail Transit

The Executive Director shall serve a copy of this decision on other rail transit systems under our jurisdiction (i.e., Los Angeles County Metropolitan Transit Authority, Sacramento Regional Transit District, Santa Clara Valley Transportation Authority, and San Diego Trolley Incorporated). The Executive Director shall invite each transit agency to make a joint proposal with its serving utility, other rail systems, and the Rail Safety and Carrier Division regarding any rotating outage mitigation measures that should be considered by the Commission.

4.5 Utility Outage Notification plans:

Additional changes to notification plans (e.g., outbound calling to customers with special needs, inbound calling for information, call center response, notice to cities, information on bills including rotating outage block number on SCE and SDG&E customer bills) shall be studied further in Phase 2. The definition of special groups shall also be studied in Phase 2.

(End of Attachment A)