6. Rotating Outage Programs

6.1 Modifications for Equity

6.1.1 Study Narrowing Exempted Load by Reconfiguring Circuits

Many customers are exempt from rotating outages because they share a circuit with an essential customer. For example, PG&E has approximately 2.0 million customers who receive service on a circuit exempt from rotating outage, even though less than 1,700 are essential customers.

PG&E estimates that there are approximately 5,000 essential customers statewide subscribed to service from respondent utilities. If the same relationship applies statewide as in PG&E's service area, over 5.8 million non-essential customers are exempt from outage only because they share a circuit with an essential customer.

Inclusion of these non-essential customers in the rotating outage pool would increase the amount of load available for emergency curtailment by thousands of megawatts.¹⁸ This could significantly reduce the frequency and duration of outages all other customers will face, and would more equitably distribute the burden of outages. Further, it would ensure 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.

Therefore, we adopt the Energy Division recommendation, and order respondent utilities to study reconfiguring circuits to narrow exempted load to more nearly match only the load of essential customers. We recognize objections from respondent utilities that it will be far too costly to rewire circuits to isolate only essential customers. For example, PG&E claims it can cost between $500,000 and $1,000,000 per circuit to construct a new circuit to isolate the essential customer. Equity, and the practical need to reasonably increase the available pool to get California through this crisis, however, require that this matter be carefully studied.

PG&E suggests, for example, that a limited number of circuits might be rewired when an essential customer is located close to a sub-station by installing SCADA-controlled circuit switching devices between the essential and non-essential customers.¹⁹ We are convinced that these and other options must be studied.

Therefore, by June 1, 2001, each respondent utility shall file and serve a report. This report (and other reports discussed below) shall be filed in this docket, and served on the service list. Except for service on the Commission, each respondent utility may serve a Notice of Availability on the service list, even if the report is less than 75 pages (unless a party has previously informed respondent utility of its desire to receive a complete copy).²⁰

The report shall state the results of a study 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. The study shall list the amount of additional load added to the rotating outage pool, the time required to complete the reconfiguration, and the cost. Respondent utilities may limit the study to projects costing $500,000 or less per individual reconfiguration since we expect the study to be of the most cost-effective alternatives.

The report shall sort the list of projects in three ways: by amount of additional megawatts added to the rotating outage pool, by date the reconfiguration can be accomplished, and by cost. Each report shall include a recommendation on whether or not to implement any or all reconfigurations, and, if reconfigurations are ordered even over a respondent utility's objection, the most efficient and least costly way to proceed. If it is not possible to study all candidate circuits given limited time, the study may focus on those circuits most likely to produce cost-effective additions contributing the most additional megawatts to the rotating outage pool.

Each report shall also state the results of studying alternative means to achieve the same goal less expensively. For example, it may be less costly to assist essential customers acquire and install backup generation than reconfigure circuits to isolate the essential customer.

Each respondent utility shall implement all cost-effective, reasonable projects. If a respondent utility believes Commission authority is needed to implement a project, respondent utility may seek approval from the Energy Division Director for projects up to a cumulative total of $5 million for PG&E and SCE, and $1 million for SDG&E. The Energy Division Director shall have delegated authority to authorize cost-effective, reasonable projects to these totals. These totals shall be included in the total program limits addressed below (e.g., $200 million for PG&E, $275 for SCE, and $25 million for SDG&E). If a respondent utility believes Commission authority is needed to implement its recommendation over the cumulative totals above delegated to the Energy Division Director, respondent utility shall file and serve an application or advice letter, as appropriate, seeking such authority. Any request, however, either to the Energy Division Director or Commission, must convincingly show why Commission authorization is needed.

6.1.2 Include Most Transmission Level Customers in Rotating Outages

Few customers were served at transmission voltage when the Commission first established procedures for rotating outages. As a result, adopted rotating outage procedures generally do not include transmission level customers.²¹ Now, however, a significant number of large customers receive service at transmission level.

Equity between customers is compromised by treating customers differently for purposes of rotating outages based solely on service voltage. Further, 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. Customers exempt from rotating outages also have less incentive to participate in interruptible or OBMC programs designed to prevent rotating outages.

Transmission level customers cite safety and financial concerns with being included in rotating outages. These are legitimate concerns, but must be put in perspective. All customers, including those at transmission level, face the risk of periodic outages unrelated to supply shortages (e.g., weather, individual transmission line failures, individual transformer failures, and operational factors). Further, transmission level customers are in a better position than most to be in contact with a utility account representative, and to monitor other information sources (e.g., ISO web site), to increase their knowledge about possible outages. Transmission level customers are not unique in their responsibility to share the burden of outages, but, like many customers, may be in a position to moderate the effect.

As a result, we generally adopt Energy Division's recommendation, with some modifications. Respondent utilities shall include transmission level customers in rotating outages, subject to exclusion for essential use customers (e.g., national defense), and those participating in an OBMC program.

We also exclude transmission level customers who are supplying power to the grid in excess of their load at the time of the outage. Exclusion from rotating outages is an important and valuable benefit. In exchange, however, the transmission level customer must provide power to the grid in excess of its load at the time of the outage. Utilities shall give such customers a reasonable opportunity to become net suppliers at the time of the outage, since the customer may or may not at any particular moment be a net supplier. Failure to become a net supplier in a reasonable amount of time shall result in the customer loosing the exemption.

PG&E points out that about 75% of its transmission level customers cannot be easily curtailed without extensive interaction with, and cooperation from, the customer. We acknowledge PG&E's concern, and adopt PG&E's recommended remedy. That is, we clearly state that transmission level customers-except those who are essential use, OBMC participants, or net suppliers to the grid-must respond promptly to utility requests to drop load. If the customer refuses to cooperate, the respondent utility may install automatic switching equipment, controlled by the utility, at the customer's expense. A customer who refuses to drop load before the switch is installed shall be assessed a penalty of $6/kWh for all kWh taken off the grid. This level of penalty is consistent with the penalty adopted in the BIP and OBMC programs. The penalty will not apply if the customer's generator suffers a verifiable, and verified, forced outage. It will also not apply during times of scheduled maintenance, as long as the maintenance is scheduled with, and agreed to, by both the ISO and the serving respondent utility. The ISO and respondent utility may not unreasonably withhold agreement of the customer's proposed scheduled maintenance.

At the same time, our instructions to include transmission level customers in rotating outages is not to result in compromising the integrity of the transmission and distribution systems. Respondent utilities, in cooperation with the ISO, shall assess system integrity on a case-by-case basis before including a transmission level customer in the rotating outage pool, and shall decline to include any such customer if system integrity is jeopardized by inclusion of that customer in the rotating outage pool.

6.1.3 Essential Customers

Some essential customers (e.g., hospitals, prisons) are now enrolled in interruptible programs. Other customers with vital public health, safety or welfare characteristics, even if not essential customers (e.g., schools), are similarly enrolled in interruptible programs.

There may be an apparent or actual conflict with an essential or other similarly situated customer being eligible for, and enrolled in, an interruptible program. That is, a customer seemingly cannot both be essential and thereby excused from interruption, but be able to interrupt load and enjoy a rate discount.

The Commission has not previously required utilities to screen interruptible program participants. This is based on the assumption that each customer, rather than the utility, is in the best position to determine whether or not it can reasonably and responsibly interrupt some or all load upon request. For example, some customers have backup generation or other ways to participate with part or all of their load.

We partly address this apparent or actual conflict by allowing reasonable flexibility for SCE customers to opt out or change firm service level during a 15-day window. This opt-out is for both essential and non-essential customers on SCE's interruptible tariffs.

Further, however, we clarify for all respondent utilities that essential customers may participate in interruptible tariffs, but eligibility must now be screened by the utility. PG&E points out that utilities may or may not now use consistent criteria for determining whether essential customers should be exempt from rotating outages, and states that any Commission guidance or direction would be helpful. (February 26, 2001 Reply Comments, page 8.)

To provide this guidance, we direct that utilities discuss with each present and future essential customer enrolled in an interruptible program whether or not that customer is reasonably eligible for an interruptible program. The customer should demonstrate, for example, sufficient backup generation or other means to meet its essential load if interrupted.

This demonstration and screening may be accomplished by respondent utilities requiring a declaration under penalty of perjury from the customer. The declaration must state that the customer is, to the best of that customer's understanding, an essential customer under Commission rules and exempt from rotating outages. It must also state that the customer voluntarily elects to participate in an interruptible program for part or all of its load based on adequate backup generation or other means to interrupt load upon request by respondent utility, while continuing to meet its essential needs. Absent such declaration, respondent utilities may find the essential customer ineligible to participate in one or more interruptible tariffs.

We are further persuaded to limit the amount of load an essential customer may commit to interruptible programs to no more than 50% of the customer's average peak load. We seek to prevent an essential customer from committing more than it reasonably can, even if it has good intentions to help California through the current difficulties. Essential customers have special needs and responsibilities to the State. This limitation will better balance some contribution by an essential customer to interruptible programs (when it is feasible for the customer to do so) with the customer's essential status.

6.1.4 Fossil Fuel Producers

Electric utility facilities are currently exempt from rotating outages, along with supporting fuel and fuel transportation systems (e.g., pipelines) critical to the continuity of the electric power system. (See Attachment B.) This exemption applies only to fuel needed for electric generation and does not apply to fuel used in motor vehicles or for other purposes. The CEC has responsibility to coordinate state actions regarding motor vehicle fuel usage. In response to a request from the CEC we recently granted limited wavier of penalties for two utility pipeline companies transporting the majority of California's gasoline and diesel fuel. This was in response to a recommendation from the CEC based on a threat to public health and safety. Public health and safety were at risk due to the effect on the availability and price of all petroleum products as a result of recent curtailments of electricity under interruptible programs.

We encourage the CEC to continue its vital oversight and regulatory role with respect to fossil fuel producers so that outages and interruptions can be coordinated to minimize disruptions. The ability of many fossil fuel producers to either participate in the OBMC program or utilize the exemption from outages for net electricity producers²² should address much of the CEC's concerns. Fossil Fuel producers might reasonably be on an interruptible electricity tariff (e.g., based on backup generation), but outages must be reasonably coordinated between producers and pipelines transporting the final product to ensure that no unacceptable jeopardy occurs to public health and safety. For example, it was the voluntary participation of pipelines in utility interruptible programs that contributed to the tight supply situation that concerned the CEC.

We invite the CEC to report to us on any changes needed in our interruptible tariffs or curtailment priorities to further protect public health and safety. Finally, we authorize utilities to coordinate interruptions, to the extent feasible, between fossil fuel producers, pipelines and users to minimize any disruption to public health and safety. For example, if a refinery, oil pipeline, and bulk distribution terminal are in three different outage blocks, then the integrated fossil fuel system might be disrupted for an extended period of time. If, instead all three entities are in the same outage block, then outages can be coordinated and down time minimized. In this way, fossil fuel producers can continue to provide needed fossil fuels while playing their part in helping maintain reliability of the electric system.

6.1.5 SCADA and Non-SCADA

Implementing rotating outages by blocks allows circuits to be curtailed widely throughout a service area, and not solely by geographic zones or substations. Circuits are controlled either remotely (SCADA) or manually (non-SCADA). Manually controlled circuits must be disengaged by substation personnel to implement a controlled curtailment. The need for manual operation increases the time to implement a curtailment. This, in turn, affects the total amount of load that may be curtailed in any particular period.

PG&E has an especially large service territory with many unstaffed substations. The ISO may give very short notice (e.g., 10 minutes) of a Stage 3 mandatory curtailment. As a result, Energy Division recommends that PG&E be ordered to assign staff up to 24 hours per day at all potentially affected substations when a Stage 2 alert is declared in order to be ready to implement a Stage 3 rolling outage.

PG&E objects, pointing out that it has successfully included both remotely and manually controlled circuits in each rotating outage over the last eight months. PG&E states that it has dispatched personnel as needed to substations with adequate lead time to ensure interruptions were completed consistent with ISO orders. PG&E says its approach is equitable to customers on both SCADA and non-SCADA controlled circuits, and provides for rapid response. According to PG&E, ordering potentially thousands of hours of staff time to non-SCADA substations is unsupportable. SCE states that SCE's approach to automated and manual substations is equally efficient and equitable.

SDG&E reports that its current Stage 3 curtailment plan is designed almost entirely around the use of SCADA controlled 12 kV circuits, but that it will attempt to add a proportional mix of non-SCADA circuits for Summer 2001 to promote increased equity. (February 22, 2001 Comments, page 20.) SDG&E asserts that the use of SCADA-controlled circuits remains preferable, however, given the short amount of time to respond to an ISO curtailment order, and the cost of assigning personnel to non-SCADA substations. It is also preferable, according to SDG&E, because use of non-SCADA circuits cause additional complications for its Distribution Operations Department, and additional time to execute the customer call process to warn customers of outages. SDG&E urges Commission consideration of cost and efficiency as well as equity.

We are persuaded that respondent utilities are now treating, or plan to treat, customers on SCADA and non-SCADA circuits with reasonable efficiency and equity, but believe improvements can be made. The issue is of sufficient importance to cost, efficiency and equity that we encourage continued study by respondent utilities.

In particular, the current best forecast is that rotating outages will become a common occurrence in Summer 2001, and may also be common in Summer 2002. If so, it is imperative that all reasonable steps have been studied and undertaken to ensure equitable implementation of forced outages that are efficient and within reasonable cost.

Therefore, we direct each respondent utility to file and serve a report by June 1, 2001. The report shall state the cost of dispatching personnel versus installing automated equipment in remote locations to implement forced outages. The cost study may be based on a reasonable sample of manually controlled substations. Each report shall state any changes each respondent utility has made, or is making, to promote increased efficiency and equity, and the costs of those changes. If respondent utility believes Commission authority is needed before it can implement changes, respondent utility shall file and serve an application or advice letter, as appropriate, seeking such authority.

6.1.6 Notification Regarding Reclassifications

By ACR dated March 27, 2001, Assigned Commissioner Wood ordered respondent utilities to provide written notice to customers regarding reclassifications between essential and non-essential categories. (See Attachment E.) We approve and confirm the ruling. (Pub. Util. Code Section 310.)

The ACR requires respondent utilities to provide written notice of the reclassification to any customer reclassified between June 1, 2000 and the date of notice, with the notice served within 15 days of the date of the ACR. Further, before implementing any future reclassification, utilities must provide advance written notice to the customer, with the reclassification effective no sooner than 15 days after the date of notice.

The notice must explain the Commission's priority system, how the system is implemented by the utility, and include excerpts from relevant Commission decisions. It must advise the customer that questions regarding the reclassification should first be discussed with the utility within 15 days of the date of notice. It must state that, absent written objection served on the utility within 15 days of the date of the notice, the reclassification shall be considered undisputed.

Further, the notice must state that unresolved disputes may be brought to the Commission by customer-filed complaint. The notice is also required to state that a complaint brought to the Commission must allege and show that the utility has acted or failed to act in violation of law, or in violation of any order or rule of the Commission, by the utility improperly implementing, or failing to follow, the Commission's adopted priority system. The burden is then on the utility to defend its implementation and reclassification.

The ACR is reasonable. Utilities review customer classification as necessary, including as part of each annual action plan. Necessary customer reclassification based on updated or new information has always been important, but was of less consequence when the probability of rotating outages was small. The consequences of reclassification, however, can now be great, given the experience of rotating outages in 2000 and 2001, and the increased likelihood of rotating outages through the rest of 2001 and possibly beyond.

Respondent utilities have reclassified many customers within the last year as part of ongoing reviews, and annual action plan updates. Individual customer notice was not provided. Coverage in the news media and elsewhere, however, has resulted in both customer confusion, and questions regarding whether or not the reclassifications comply with Commission orders.

Each reclassified customer deserves the right to be notified of an important change affecting service. Each reclassified customer has the right to question an important change to ensure that the change complies with law, as well as Commission rules and orders. Each reclassified customer has the right to file a complaint if the customer believes the change is in error.

We agree with the ACR that notice is required only on the customer who is reclassified, not on each customer whose service was, or is, changed because it shares a circuit with a reclassified customer. Wider notice is not required because circuits may be reclassified at any time for any number of operational reasons. For example, an essential customer might be transferred from one circuit to another due to operational factors, with resulting effects on all other customers on the two circuits. The only customer with standing to address the reclassification, however, is the customer whose status is reclassified between essential and non-essential, not each customer whose service changes as a consequence.

Further, we agree with the ACR that the utility is not required to automatically reverse the reclassification of any customer upon customer complaint to the utility, but may reverse the reclassification if the customer presents sufficient evidence to convince the utility to do so. The utility shall, however, reverse the reclassification upon direction from the Commission staff or the Commission if the customer files a complaint with the Commission, and the complaint is resolved either informally or formally.

In addition, we also concur with the ACR that the burden shifts to the utility to defend its implementation and reclassification upon the filing of a complaint with the Commission that reasonably alleges the utility has acted or failed to act in violation of law, or in violation of any order or rule of the Commission, by the utility improperly implementing, or failing to follow, the Commission's adopted priority system. These complaints will be proceeded using the Commission's expedited complaint procedure.

6.2 Modifications to Increase Protection

6.2.1 Outbound Calling Program

PG&E provides electric service to approximately 48,000 medical baseline customers,²³ of whom about 22,000 are classified as "life support" customers. Life support customers require electrical equipment to sustain, restore or supplant a vital body function. SCE reports that it has about 27, 000 medical baseline customers, of whom about 2,200 are critical care customers. SDG&E has a similar distribution of such customers.

Neither medical baseline, nor life support, nor critical care customers, however, are defined as essential customers under Commission rules. As with all other customers, respondent utilities are simply required to provide warning and relevant information by mass media, with no special treatment or individual notification required. (See Attachment B.)

Because of the vital role of electricity for these customers, Energy Division recommends that respondent utilities inspect backup generation or battery supplies for life-support equipment. We decline to adopt this recommendation. Rather, we are persuaded by respondent utilities that this would be a difficult task involving expertise that each utility does not necessarily now have. In fact, as SCE says, it could even be dangerous for the utility to certify the functioning of equipment which is designed for special medical uses and which is owned, operated and maintained by the customer or others. As SDG&E states, the logistics of annual or more frequent inspections could be staggering, particularly as the population of customers on life support changes. Further, liability could attach to each utility for injury and death that would be unreasonable under current circumstances. That is, existing infrastructure exists in the medical community and industry to supply and inspect backup devices for vital medical equipment, and we need not order utilities to duplicate that infrastructure.

Energy Division also recommends that respondent utilities be required to notify customers on life support by telephone of rotating outages. In response, utilities report that they have such systems. PG&E has an automated voice response system that initiates outbound calls to all life support customers potentially impacted by rotating outages. (February 22, 2001 Comments, page 17.) SCE has a procedure in place to initiate an automatically dialed call to all medical baseline customers, targeting critical care customers first. (February 22, 2001 Comments, page 34.) SDG&E reports that it has contacted life support customers by telephone and live agent prior to every imminent Stage 3 rotating outage and, immediately after restoration of electricity, plans to call customers on life support and medical baseline to ensure that electric service has been reactivated. (February 22, 2001 Comments, page 24.) We are encouraged by these responses.

Few actual rotating outages were implemented during more than 30 days of continuous Stage 3 emergencies in early 2001.²⁴ We are sympathetic to respondent utilities' concerns about the number of false calls if calls are required for all Stage 3 events. Thus, we direct that the outbound call be made only when a rotating outage is imminent. While we consider this outbound calling program important, we continue to require only that respondent utilities undertake best efforts to notify customers of imminent outages.

Further, improvements in technology may be available to shorten the time between ISO notice to the utility, and utility notice to the customer. We understand SCE can complete the required notification within 10 minutes. We expect respondent utilities to not only establish systems to achieve notice quickly, but to use the best available technology to reduce the time required to execute reasonable notice. We encourage utilities to use automated, recorded messages where not now used, when it is reasonable and efficient to do so. We also urge utilities to explore advanced technologies to increase the number of customers who may be notified in advance of an event, reduce the time to achieve reasonable notice, and reduce long run cost.

To inform the Commission and the public, each respondent utility shall file and serve a report by June 1, 2001. The report shall describe each utility's outbound calling program to customers on life support, critical care or medical baseline when a rotating outage is imminent. The document shall report on the implemented program, including any changes made or planned, to improve the program. If respondent utility believes Commission authority is needed before it can implement such program or changes consistent with this order, respondent utility shall file and serve an application or advice letter, as appropriate, seeking such authority.

This program is not intended to replace utility programs for periodic notification by mail to medical baseline customers of the need to have backup resources or plans for electrical outages. We also consider this a vital piece of communication. We endorse utilities continuing this notification by mail, or expanded to mass media, as often as necessary and reasonable.

6.2.2 Offices of Emergency Services

Electric service to industrial customers may be especially critical to public health and safety. For example, public health and safety may be at increased risk if the curtailment of electricity to an industrial customer causes equipment causes the release of chemicals or toxins.

We have confidence in the efforts of national and state offices of Occupational Safety and Health Administration (OSHA), and regional Offices of Emergency Services (OES). We support these and other government agencies working with electricity customers and electric utilities to ensure all reasonable steps are taken to protect public health and safety during probable forthcoming electrical outages in Summer 2001 and Summer 2002.

To assure ourselves and the public that reasonable efforts are undertaken, we direct each respondent utility to file and serve a report by June 1, 2001. The document shall report on any recent efforts undertaken by respondent utility with OSHA and/or OES to address particular and unique risks to public health and safety from imminent electrical outages to industrial customers in Summer 2001. In particular, each report shall identify any measures that have been implemented for one or more industrial customers required for public health and safety after the customer and/or respondent utility consults with OSHA and/or OES.

6.2.3 BART and MUNI

Rotating electrical outages may cause particular concern for public health and safety when they involve underground transit systems, such as the Bay Area Rapid Transit District (BART), and the San Francisco Municipal Railway (MUNI). Energy Division recommends an exemption from rotating outages for BART, and implementation of mitigation measures to ensure safety of MUNI passengers and staff.

PG&E states that it is technically feasible to exempt BART from rotating outages without significant negative effects on its overall emergency response plan, and that such exemption is in place. PG&E asks that the underground component of MUNI be similarly exempt. We authorize PG&E to exempt both BART, and the underground portion of MUNI, from rotating outages.

PG&E reports that it supports adequate mitigation measures to protect MUNI passengers and staff. PG&E asks, however, that it not be placed in the position of determining what is and is not adequate mitigation. Rather, PG&E asks that the Commission review requests for exemption by public transportation providers, and provide necessary direction to utilities.

We will give direction as necessary, but this record does not contain adequate information to do more than we do here. We are confident, however, that PG&E can, and will, work out necessary and reasonable mitigation with MUNI.

To provide reasonable information to the Commission and the public that this is accomplished, and provide a vehicle to resolve disputes, PG&E shall file and serve a report by May 1, 2001 on this matter. The report shall state the necessary and reasonable mitigation measures to which PG&E and MUNI have agreed, and the measures that PG&E has, or will, implement. MUNI may file a complaint if unresolved disputes remain.

If PG&E believes Commission authority is needed before it can implement mitigation measures for MUNI, PG&E shall file and serve an application or advice letter, as appropriate, seeking such authority. If the application or advice letter is supported by MUNI, PG&E shall seek to expedite matters by including a statement from MUNI in partial or full support of the request.

6.2.4 Other Rail Transit

Energy Division recommends that other rail transit systems participate in this rulemaking for the purpose of presenting a joint proposal with utilities to implement other necessary mitigation measures, or seek complete exemption from rotating outages.

We note that no other transit system has brought any concerns to our attention. SDG&E points out that the San Diego Trolley is entirely above ground. It is served by a large number of different circuits. Exempting the entire Trolley system would exempt a large number of circuits from rolling outages, and reduce SDG&E's ability to implement forced outages.

Nonetheless, because of the potential importance of this issue to public health and safety, we direct the Executive Director to serve a copy of this decision on other rail transit systems under our jurisdiction.²⁵ The cover letter shall invite those transit systems to consider public health and safety on their systems due to the serious potential of a number of electrical outages in 2001 and 2002. It will 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 systems, and the Rail Safety and Carrier Division, regarding any mitigation measures that should be considered by the Commission, and which require Commission authorization.

6.2.5 Utility Outage Notification Plans

Energy Division recommends that respondent utilities implement rotating outage notification plans that are more accessible, and expand these plans to include customers with special needs. Energy Division also recommends that press release notifications should be multilingual, outgoing notifications should be implemented for all essential customers, and the adequacy of inbound calls and procedures be reassessed given likely call volumes during outages.

Respondent utilities generally report adequate multilingual notification procedures, and reasonable outbound and inbound calling capabilities. All three utilities are unclear regarding the definition of "special needs" groups and ask for clarification before the Commission imposes additional burdens and costs.

We are generally satisfied with current notification plans. We will study notification needs of special customers further in Phase 2. We especially invite any special needs customers to come forward and make their needs known.

PG&E includes a rotating outage block number on customer bills, with a note stating: "rotating outage blocks are subject to change without advance notice due to operational conditions." Neither SCE nor SDG&E notify their customers of the rotating outage block to which the customer is assigned. SCE points out that rotating outage blocks can change frequently as loads are transferred between circuits and substations to balance load, and ensure that circuits do not exceed 550 amps.

We will study further in Phase 2 the desirability and reasonableness of SCE and SDG&E including a rotating outage block number on customer bills. Rotating outage experiences in 2001 and 2002 are unlikely to be pleasant. Customers need and expect reasonable, timely and accurate information. Public health and safety may depend upon it.

We think it reasonable to give customers fair warning when their electricity is about to be curtailed, with as much specificity as possible. Rotating outage block numbers on customer bills meets that objective. It allows the utility to alert mass media so that affected customers get reasonably specific, accurate, and timely warning.

We direct SCE and SDG&E, and invite other parties, to 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 Phase 2 pleadings regarding a list of issues for consideration, along with their recommendations on how and when this issue should be considered.

6.2.6 Hospitals

The Regional Council of Rural Counties (RCRC) asks that rural hospitals and acute care facilities be classified essential customers, and excluded from rotating outages.²⁶ RCRC points out that hospitals with 100 beds or more are exempt from rotating outages,²⁷ but that the majority of rural hospitals are less than 100 beds. RCRC provides a list of counties and hospitals showing that 16 of 28 counties do not have a hospital with more than 100 beds, and would therefore be subject to rolling outages.

We must balance the need to have as many circuits available for rotating outage as possible against the need to protect essential customers. We are persuaded to modify the essential customer list to include all hospitals. Sick or injured people in rural hospitals can be just as sick or injured as their urban counterparts. They deserve the same level of protection for electricity services.

At the same time, we have little specific information on the effect of this change. We order this change because we are persuaded by the limited information we now have that rural hospitals have an immediate need for protection during the crisis we face for Summer 2001. We will revisit this issue in Phase 2, however. We direct that respondent utilities submit specific information in Phase 2 on the effect this change has had on mandatory curtailments, and the effect on the number of circuits and megawatts that are available for rotating outage. Further, the study ordered above regarding the reconfiguration of circuits to narrow exempted load should include an assessment of isolating the rural hospitals added here.

By ACR dated March 23, 2001, Assigned Commissioner Wood partially granted emergency motions filed by Memorial Health Services and Catholic Healthcare West. (See Attachment F.) We approve and confirm the ruling. (Pub. Util. Code Section 310.)

The ruling required PG&E and SCE to immediately classify all hospitals with 100 beds or more as essential customers exempt from rotating outages, regardless of the status of backup or standby generation. The ruling found this to be consistent with the priority system for rotating outages adopted in D.91584. It cited the Commission's definition of minimal essential uses for hospitals. It found the uncontroverted testimony presented at hearing demonstrated that the backup or standby generation required by Office of Statewide Health Planning and Development regulation does not satisfy Commission requirements for minimal essential uses for hospitals. Further, it found that the exemption would not disturb or compromise the Commission's determination to maintain at least 40% of available load for rotating outages. In addition, the ruling declined to extend the exemption to skilled nursing facilities, absent a showing of the effect on maintaining at least 40% of available load for rotating outages.

The ruling is reasonable. Moreover, consistent with our modification above, all hospitals in the service areas of PG&E, SCE and SDG&E shall be classified as essential customers exempt from rotating outages, regardless of the status of backup or standby generation.

This decision, however, does not disturb utility evaluation of the adequacy of backup or standby generation for other essential customers, and utility consideration of removing such customers from their lists of essential use customers. (D.82-06-021 (June 2, 1982), Cal. PUC LEXIS 537.) Also, absent more information, it does not extend to skilled nursing facilities.

We direct respondent utilities to provide specific information no later than in Phase 2 on the effect of extending this exemption to skilled nursing facilities, including the number of circuits and megawatts removed from rotating outages. The evaluation will include an estimate of the resulting effect, if any, on mandatory curtailments, and the 40% criterion. Finally, respondent utilities must also consider circuit reconfigurations in Phase 2 that would narrow exempted load by isolating skilled nursing facilities.

6.3 Update Utility Action Plans

By June 30 each year, respondent utilities file annual rotating outage action plans, with verification of their essential customer list. (Energy Division Report, page 68.) The changes we order herein, and the need to ensure updated plans are in place and consistent with these orders, require that these action plans be updated and filed more quickly. Therefore, respondent utilities shall implement changes consistent with the orders herein, and file updated action plans within 45 days of the date this order is served.