TITLE



PACIFIC GAS AND ELECTRIC COMPANY

CHAPTER 8

ELECTRIC DISTRIBUTION RELIABILITY

Introduction

1 Scope and Purpose

The purpose of this chapter is to demonstrate that Pacific Gas and Electric Company’s (PG&E or the Company) expense and capital expenditure forecasts for the Company’s Electric Distribution System Reliability Program (Reliability Program) are reasonable and should be adopted by the California Public Utilities Commission (CPUC or Commission). The Reliability Program: (1) addresses customer-related issues due to recurring outages; (2) performs cost-effective mitigation work to prevent customers from experiencing 12 or more sustained outages over a 12-month period; (3) remedies system protection deficiencies; (4) analyzes and investigates trends in overall distribution system reliability performance; (5) makes appropriate capital investments to improve reliability consistent with the direction the CPUC provided in Decision 04-10-034 from PG&E’s 2003 General Rate Case (GRC); (6) invests in the installation of overhead and underground fuses that protect the mainline and mitigate the affects of outages; and (7) identifies and invests in specific circuits in communities where reliability is worse than average as compared with similar communities.

PG&E’s Reliability Program is critical for improving service reliability and for preventing customers from experiencing excessively frequent or prolonged outages. The expense and capital expenditure forecasts this chapter describes are intended to achieve and maintain the reliability incentive mechanism (RIM) targets[[1]] adopted in Decision 04-10-034.

2 Summary of Dollar Request

PG&E requests that the Commission adopt its Distribution System Reliability Program capital expenditure forecast of $19.6 million in 2005,[[2]] $24.2 million in 2006, $26.0 million in 2007, $21.2 million in 2008 and $21.2 million in 2009.

3 Support for Request

PG&E’s expenditure forecasts for the Distribution System Reliability Program are reasonable and fully justified because the Company:

• Forecasts a level of work that is intended to provide reliable service (under typical weather conditions) consistent with the RIM the Commission adopted in Decision 04-10-034; and

• Manages and controls cost by: (a) analyzing system performance to identify trends in system service reliability; and (b) measuring the program’s unit costs to gauge the Company’s success in cost control.

4 Organization of the Remainder of This Chapter

The remainder of this chapter is organized as follows:

• Program Management;

• Estimating Method;

• Activities and Costs by Major Work Category (MWC);

• Translation of Program Expenses to Federal Energy Regulatory Commission (FERC) Accounts; and

• Cost Tables.

Program Management

This section provides an overview of the Reliability Program. The Reliability Program addresses overall system performance and specific customer-related reliability issues. Distribution system reliability work includes installing protective devices to limit the extent of future service interruptions, rebuilding overhead lines to prevent recurring service interruptions, installing automation equipment to provide real-time monitoring and control of the electrical distribution lines, and providing support for distribution automation activities.

This section is organized as follows:

• Reliability Goals and Issues;

• The Storm and Reliability Phase of the 2003 GRC;

• Recent Reliability Performance;

• Variation In SAIDI and SAIFI Values;[[3]] and

• Planning and Budgeting Process.

1 Reliability Goals and Issues

In Decision 04-10-034, the CPUC directed PG&E to improve reliability. The information in this chapter explains the role that the Reliability Program has in improving reliability. Before proceeding, it is useful to articulate PG&E’s reliability goals and important reliability-related issues.

PG&E believes improving reliability, particularly SAIDI, is possible and appropriate. PG&E’s goal is to achieve the SAIDI and SAIFI targets in the RIM adopted in Decision 04-10-034. However, within the framework of striving to improve reliability and meet the RIM targets, there are four important issues to discuss.

First, SAIDI and SAIFI performance varies. While PG&E is striving to deliver SAIDI and SAIFI results that reflect the improvement the Commission and PG&E desires, it is important to understand that anticipated benefits in SAIDI and SAIFI values from various projects are small relative to the variation in SAIDI and SAIFI that typically occurs from year-to-year. This is particularly true for SAIDI because of the influence of large storm events. Section B.4, Variation in SAIDI and SAIFI Values of this chapter addresses this issue in detail.

Second, expenditures to replace aging assets will not necessarily yield a measurable reduction in SAIDI and SAIFI. Some investments, while characterized as having reliability-related implications (for example, replacing tie-cable circuits in San Francisco and East Bay Divisions), may only help to maintain existing levels of SAIDI and SAIFI. Other investments may yield more observable results. Whether investments maintain or improve reliability depends on a variety of factors such as the asset, the amount of the money spent, and the time frame of the expenditure. Quantifying the effects of aging asset replacement on SAIDI and SAIFI is not an exact science.

Third, estimating actual SAIDI and SAIFI results from investments is confounded by numerous variables, not the least of which is the weather. Taking estimated values from an improvement initiative and subtracting them from a single year of system performance (or an average of system performance) is overly simplistic. A distribution system consisting of 124,000 miles of distribution lines that interact with virtually every element in nature and society is a dynamic entity. PG&E does not have the ability to “dial-in” specific SAIDI and SAIFI values for any given year.

Fourth, because PG&E is now subject to the RIM, the Company felt it was prudent to understand how accurately it was calculating SAIDI and SAIFI values. Prior to the RIM, PG&E did not expend resources to audit reliability values because SAIDI and SAIFI were not subject to financial rewards and penalties. Personnel familiar with outage reporting were generally of the opinion that the reporting process, while not error free, was adequate to produce numbers and trends that were useful for decision making purposes. PG&E anticipated that a review would reveal some amount of error in both indices and a greater amount of error for SAIDI[[4]] than SAIFI. PG&E’s preliminary analysis validated this thinking. PG&E is currently performing a detailed analysis and anticipates completing this work by the end of August 2005. The result of this analysis may affect PG&E’s ability to meet the RIM targets.

2 The Storm and Reliability Phase of the 2003 GRC

In December 2002, a series of four storms brought heavy rains and hurricane-force gusts causing significant damage to PG&E’s electric distribution facilities and causing 1.97 million customer interruptions. On February 13, 2003, Commissioner Peevey, the Commissioner assigned to PG&E’s 2003 GRC, issued an Assigned Commission Ruling seeking supplemental testimony concerning PG&E’s electric distribution service during both normal and storm conditions. This portion of the 2003 GRC is generally known as the “Storm and Reliability” phase of the 2003 GRC and culminated in Decision 04-10-034. With respect to “normal reliability,”[[5]] Decision 04-10-034 adopted the following:

• A reliability incentive mechanism;

• Increased reliability data reporting requirements;

• Required reporting when systemwide and division reliability metrics vary from the 5-year average by 5 or 10 percent or more, respectively;

• Workshops to address definitions of Excludable Major Event, Major Outage, and Measured Event; and

• An Order Instituting Rulemaking (OIR) into standardizing the reliability metrics for California’s regulated utilities.

The decision also ordered PG&E to conduct a new value of service (VOS) study and to install as many additional sets of overhead fuses in 2003 as needed to fully utilize the GRC requested amount of $5.4 million in MWC 49.

This chapter addresses the “normal reliability” items from Decision 04-10-34. Chapter 11 of this exhibit addresses customer communication issues and Chapter 12 of this exhibit addresses storm and other emergency response items from that decision.

1 RIM

The two primary system metrics the CPUC uses to measure reliability performance are SAIDI and SAIFI. SAIDI is the annual average amount of time (in minutes) that electric service is interrupted to a customer due to sustained outages. SAIFI is the annual average number of service interruptions experienced by a customer due to sustained outages.

While Decision 04-10-34 found that “the level of service reliability provided by PG&E during normal conditions from 1999 through 2002, as measured by SAIDI and SAIFI, is consistent with the reliability performance standards identified in Decision 00-02-046” (Finding of Fact #4), the Commission encouraged further improvements in system reliability by adopting a RIM. Table 8-1 summarizes the parameters of the RIM.

Table 8-1

Pacific Gas and Electric Company

Reliability Program

Reliability INcentive Mechanism – Decision 04-10-034

|Line No. |Description |SAIDI |SAIFI |

|1 |2005 Target |165 |1.40 |

|2 |2006 Target |161 |1.33 |

|3 |2007 Target |157 |1.24 |

|4 |Deadband |+/- 10 |+/- 0.10 |

|5 |Liveband |+/- 15.8 |+/- 0.15 |

|6 |Unit per charge |1 minute |0.01 outages |

|7 |Maximum Incentive |+/- $12 million |+/- $12 million |

|8 |Per Unit Incentive |$759,494 |$800,000 |

| | | | |

Table 8-1 shows the SAIDI and SAIFI targets becoming more stringent each year between 2005 and 2007. PG&E’s 2007 GRC expenditure forecast for the Reliability Program is intended to achieve the RIM targets. However, even a few significant storm events that do not meet the exclusion criteria from Decision 96-09-045 can cause significant variability, particularly in SAIDI.

2 Value of Service Study

As noted above, Decision 04-10-34 ordered PG&E to conduct a VOS study. The decision directed PG&E to work with Office of Ratepayer Advocates (ORA) and other interested parties to prepare a VOS study approach and cost estimate. PG&E did this and on April 21, 2005, the CPUC approved a resolution (Resolution E-3922) directing PG&E to conduct a survey-based VOS study per the proposal submitted by Freeman, Sullivan and Company.

PG&E did not use information from the VOS study to develop forecasts for the Reliability Program because: (a) the information from the study was not available when PG&E was preparing its testimony; and (b) PG&E does not use VOS as the sole decision tool when determining to proceed with reliability work.

3 Energy Division Workshops

Decision 04-10-034 ordered the Energy Division to conduct workshops to address definitions of “excludable major event,” “major outage,” and ”measured event,” as well as the restoration performance standard included in Standard 12 of G.O. 166.[[6]] The Energy Division conducted a workshop on February 8, 2005. At the workshop, PG&E suggested that parties consider IEEE Standard 1366-2003, IEEE Guide for Electric Power Distribution Reliability Indices, as a possible replacement for Appendix A of Decision 96-09-045. While parties discussed the standard, no decision was made regarding its adoption.

Since the February 8, 2005 workshop, the Energy Division has issued a number of data requests, but has not conducted any further workshops, nor has it communicated any decisions regarding the definitions it is required to address. The workshop did not influence PG&E’s expenditure forecast for the Reliability Program.

4 Reliability OIR

Decision 04-10-034 also ordered Commission staff to prepare an OIR into standardizing the reliability metrics for California’s regulated utilities, to be available for Commission vote within nine months of the decision. The Commission has yet to vote out this OIR.

3 Recent Reliability Performance

As stated above, the primary measures the CPUC uses to evaluate reliability performance are SAIDI and SAIFI. In Decision 00-02-046, in PG&E’s 1999 GRC, the Commission used these indices to define the adequate service standard and found that PG&E’s performance in the 1996 to 1998 time period was reasonable and consistent with historically accepted levels of service.[[7]] In Decision 04-10-034, the CPUC evaluated PG&E’s performance from 1999 through 2002 and found that the Company’s performance had either improved or was consistent with historical levels (see also FOF #4 from Decision 04-10-034). Specifically, Decision 04-10-034 states:

In D.00-02-046 we stated that PG&E’s performance during the 1996-1998 period was reasonable, consistent with historically accepted levels of service. In this phase of the proceeding, we are conducting a high level review of PG&E’s performance during the period from 1999 through 2002, including, but not limited to, the December 2002 storms. We find that PG&E’s overall reliability performance during normal conditions, as measured by SAIDI, SAIFI, and MAIFI performance reported in PG&E’s annual reliability reports, has either improved relative to 1996-1998 levels or has remained consistent with 1996-1998 levels. (p. 73.)

Table 8-2 compiles SAIDI and SAIFI values from the time periods evaluated by Decisions 00-02-046 (1996 to 1998) and 04-10-034 (note this decision evaluates two time periods, a 3-year period of 1999 to 2001 and a 4-year period of 1999 to 2002).[[8]] Table 8-2 also includes average values for 2002-2004 (consistent with the 3-year averages used in Decisions 00-02-046 and 04-10-034) and average values for 2000-2004 (for the sake of providing current information).

Table 8-2

Pacific Gas and Electric Company

Reliability Program

Average T&D SAIDI and SAIFI VAlues

|Line No |Time Period |SAIDI |SAIFI |

| | |T&D |Distribution |T&D |Distribution |

|1 |3 year 1996-1998 (D.00-02-046) |170 |153 |1.64 |1.50 |

|2 |3 year 1999-2001 (D.04-10-034) |179 |163 |1.44 |1.31 |

|3 |4 year 1999-2002 (D.04.10.034) |169 |155 |1.36 |1.24 |

|4 |3 year 2002-2004 |176 |159 |1.26 |1.14 |

|5 |5 year 2000-2004 |182 |164 |1.33 |1.21 |

| | | | | | |

Figure 8-1 graphically depicts 2000-2004 SAIFI data.

Figure 8-1

Pacific Gas and Electric Company

Reliability program

2000-2004 T&D SaIFI Values (Excluding Major Events)

[pic]

Figure 8-2 graphically depicts 2000-2004 SAIDI data.

Figure 8-2

Pacific Gas and Electric Company

Reliability program

2000-2004 T&D SaIDI Values (Excluding Major Events)

[pic]

The data in Table 8-2 and Figures 8-1 and 8-2 show that SAIDI is trending upward and SAIFI is trending downward. This divergence means that the customer average interruption duration index (CAIDI)[[9]] is increasing. Figure 8-3 shows the increasing trend in CAIDI.

Figure 8-3

Pacific Gas and Electric Company

Reliability program

2000-2004 T&D CAIDI Values (Excluding Major Events)

[pic]

Chapter 12 of this exhibit describes steps PG&E is taking to address the increasing CAIDI value.

4 Variation in SAIDI and SAIFI Values

In its 2003 GRC testimony, PG&E described how electric transmission and distribution (T&D) performance is susceptible to significant storm conditions. The Company provided data regarding the number of “cluster outage days” (days when the number of sustained outages exceed 150), demonstrating how days with a significant number of sustained outages negatively affect reliability index performance.[[10]] Figure 8-4 shows the daily number of outages in 2004. This figure illustrates how the number of outages occurring in a single day can spike dramatically and is similar to the graphic PG&E provided in its 2003 GRC testimony.

Figure 8-4

Pacific Gas and Electric Company

Reliability program

Sustained OUtages by day for 2004 (T&D)

[pic]

Table 8-3 provides five years of data for cluster outage days and the effect those days have on annual SAIDI and SAIFI values.

Table 8-3

Pacific Gas and Electric Company

Reliability program

The Affect of Cluster Outage Days on SAIDI & SAIFI

|Line No. |Description |2000 |2001 |2002 |2003 |2004 |Average |Std. Deviation|

|1 |Total Number of Days > 150 SO’s and non |10 |22 |7 |13 |15 |13.4 | |

| |ME | | | | | | | |

|2 |Total Number of Days > 150 SO’s and ME |0 |1 |10 |1 |0 |2.4 | |

|3 |Total Number of Days > 150 SO’s |10 |23 |17 |14 |15 |15.8 | |

|4 |Annual SAIDI (Excluding ME days) |167.9 |211.8 |139.7 |178.8 |195.8 |178.8 |27.5 |

|5 |Annual SAIFI (Excluding ME days) |1.410 |1.439 |1.114 |1.289 |1.354 |1.321 |0.129 |

|6 |SAIDI for Days > 150 SO’s and non ME |43.6 |92.9 |19.1 |36.1 |63.2 |51.0 |28.3 |

|7 |SAIFI for Days > 150 SO’s and non ME |0.24 |0.40 |0.094 |0.182 |0.322 |0.247 |0.119 |

|8 |% of Days > 150 SO’s and non ME |2.7% |6.0% |1.9% |3.6% |4.1% |3.7% | |

|9 |% of SAIDI due to days > 150 |26.0% |43.9% |13.7% |20.2% |32.3% |27.2% | |

|10 |% of SAIFI due to days > 150 |17% |28% |8% |14% |24% |18.2% | |

|11 |SAIDI for Days 10,000 | | | | |

| |Customers | | | | |

|7 |2004 System AIFI |1.214 | | |5,285,579 |

| |value | | | | |

|8 |2004 System AIDI |173.7 | | |5,285,579 |

| |value | | | | |

|________________ |

|Note: AIDI and AIFI values are for distribution system only. |

| | |

There are 90 communities in PG&E’s system with more than 10,000 customers. Almost 70 percent of the customers PG&E serves are in these communities. Not surprisingly, the average AIDI and AIFI values for these communities are less than the system values. This is attributable to factors common to distribution systems in more populated areas such as: (a) circuits are shorter; (b) circuits are generally more interconnected; (c) the proximity of service centers and workers; and (d) generally less exposure to vegetation.

PG&E reviewed this data and decided to focus on cities with AIDI and AIFI values much worse than the average of cities with more than 10,000 customers. The Company selected six cities located in the bay area whose average AIDI and AIFI values where higher than the average from Table 8-9 above. In addition to having worse than average performance, the selected communities had persistent poor performance (PG&E did not want to focus on a city whose average performance was driven by a single-year of poor reliability). Table 8-10 below lists the cities that PG&E is focusing on in 2005.

Table 8-10

Pacific Gas and Electric Company

Reliability Program

Summary of Reliability Indices for Cities with More than 10,000 Customers

|Line No. |City Name |Division |Number of Customers |AIDI Value |AIFI Value |

|1 |Pleasant Hill |Diablo |16,777 |144.7 |1.77 |

|2 |San Pablo |East Bay |11,200 |161.9 |1.56 |

|3 |Saratoga |De Anza |11,968 |160.7 |1.44 |

|4 |Foster City |Peninsula |13,873 |166.2 |1.24 |

|5 |Lafayette |Diablo |11,453 |132.5 |1.53 |

|6 |Burlingame |Peninsula |19,553 |125.9 |1.44 |

|_______________ |

|Note: AIDI and AIFI values are for distribution system only. |

| |

PG&E’s 2007 GRC forecast includes $2.9 million in 2005 for reliability related work for the cities listed in Table 8-10. The amount for each city ranges from $333,000 for work in Foster City to $600,000 each for Pleasant Hill and San Pablo.

To ensure that funds are reasonably spent, PG&E’s Reliability project manager met individually with each Division Supervising Engineer to review data associated with circuit configurations, the nature of the reliability issues and proposed work. As the workpapers show, the work generally involves installing fuses, reclosers and SCADA devices (the workpapers also list the specific distribution circuits that are the target of these activities).

PG&E proposes continuing the program in 2006 and beyond at a level of $3.0 million each year. The Company will use the most current outage information and continue to select communities with AIDI and AIFI values that are higher than communities with a similar number of customers.

2 Expenditures to Improve Reliability Per Decision 04-10-034

Decision 04-10-034 directed PG&E to improve reliability. The decision also declined to adopt additional annual revenue requirement for improvements in reliability metrics,[[19]] finding that that PG&E has sufficient incentive to provide “adequate” service through the cost-based rates the CPUC authorized in Decision 04-05-055.[[20]]

However, SAIDI was 192 minutes in 2003 and 196 minutes in 2004. As of June 2005, PG&E anticipates the year-end SAIDI value will be 183 minutes. All these values are higher than the 2005 RIM target of 165 minutes. They are also higher than the 2005 upper dead band value of 175 minutes.

In-light of these facts, PG&E plans to spend $2.5 million in 2006 and $2.3 million in 2007 in MWC 49 on additional work to improve reliability. This spending is specifically intended to improve reliability per Decision 04-10-034.

The general approach PG&E plans on pursuing is to allocate funding to target the 100 worst performing circuits in the last five years. Most of these circuits are in rural areas with long overhead lines, many of which are exposed to heavy vegetation. PG&E anticipates the improvement work will consist of measures such as the installation of SCADA equipment, reclosers and fuses. To identify specific projects, division personnel are currently developing plans for circuits in their corresponding divisions. PG&E anticipates prioritizing work using existing guidelines to calculate benefit to cost ratios or a ratio of potential customer-minutes saved to expenditure (i.e., potential customer-minutes saved/dollar).

3 San Francisco Targeted Reliability

On December 20, 2003, a cable failure inside of Mission Substation in San Francisco caused a fire that led to the interruption of service to over 100,000 customers. After completing its investigation of this event, PG&E went a step further and hired KEMA, a transmission and distribution consulting firm, to perform a high-level assessment of distribution system reliability in San Francisco. KEMA began working on their assessment in June 2004 and submitted a final report in November 2004.

KEMA concluded that “The reliability experience of customers in San Francisco is not unlike the reliability experience of customers in comparable cities.”[[21]] However, KEMA also states that “San Francisco is not without its reliability challenges. Recent trends indicate that preset levels of reliability may be difficult to maintain, and the risk of major outages is likely to rise.”[[22]] Consequently, their report made numerous recommendations that PG&E is currently implementing.[[23]] Unfortunately, their conclusion regarding the risk of major outages came true all-to-soon.

On December 17, 2004, the FY-1 tie cable between Larkin Substation and Marina Substations in San Francisco was de-energized to allow construction personnel to rearrange tie cable circuits as part of a project that is addressing seismic issues at Station I. While personnel were performing their work, the FY-2 cable failed. This resulted in an outage to over 13,000 customers. Another outage at Marina Substation on December 27, 2004, interrupted service to approximately 9,000 customers.

Then, on March 26, 2005, a circuit breaker at Mission Substation failed while interrupting a fault due to a network cable failure. The failure interrupted electric service to approximately 1,800 customers, and started a fire inside the circuit breaker cabinet. Fire suppression efforts led to interruptions in service to a total of 23,423 customers, ranging from a momentary outage for about 4,100 customers to 4 hours and 42 minutes for about 700 customers.

Faced with this series of events, PG&E decided that the steps it was taking to implement the recommendations of the KEMA report, and those that came out of the Mission and Marina Substation outages were insufficient. Consequently, PG&E is taking a more proactive approach and will spend an additional $2.5 million annually in 2006 and 2007 for reliability related work in San Francisco. While specific plans are currently under development, a preliminary scope of work entails the installation of 117 sets of fuses, 16 overhead line reclosers and 56 underground fuses and interrupters. PG&E will install these devices on a variety of different circuits in San Francisco based on factors such as circuit performance and system configuration. PG&E will also replace six automatic transfer schemes.

PG&E considers the additional spending appropriate because: (1) San Francisco has more customers than any other city in PG&E’s service territory; (2) the distribution equipment in San Francisco is generally older than the equipment in other divisions; and (3) reliability issues in San Francisco generate a lot of attention, from media, the City and County of San Francisco, and the CPUC.

PG&E has a long and proud tradition of providing San Francisco with reliable service and the Company is taking steps to address these recent issues and maintain that tradition.

4 Summary of MWC 49 Request

Table 8-11 presents the 2000 through 2004 actual and 2005 through 2009 forecast capital expenditures for MWC 49.

Table 8-11

Pacific Gas and Electric Company

Reliability Program

MWC 49 Actual and forecast Capital Expenditures Summary

($000)

|Line No. |

| | | | | | | | | | | | |

3 MWC 09: Distribution Line Automation

MWC 09 involves replacing, installing and upgrading DA equipment such as primary distribution alarm and control (PDAC) equipment, SCADA equipment, and remote terminal units, and metering. This equipment performs or enables remote control operation of equipment and/or monitoring and recording system information. This section of testimony describes MWC 09 capital expenditures for distribution line automation. This means MWC 09 includes expenditures for distribution circuits and excludes distribution automation work within substations. Chapter 11, Electric Distribution Operations, describes capital expenditures for distribution automation relating to electric distribution system operations (specifically, replacing/upgrading master stations). Chapter 4, Substation Asset Management, of this exhibit addresses expenditures for MWC 09 work within substations. Chapter 4 also contains tables summarizing all MWC 09 expenditure forecasts.

PG&E’s 2007 GRC forecast for line DA expenditures has four categories: (1) Replacing line PDAC devices with SCADA devices; (2) Converting existing reclosers for SCADA operation; (3) Replacing and/or upgrading communication equipment; and (4) distribution area automation. Each of these categories are briefly described below.

1 Replacing Line PDAC With SCADA

PG&E’s existing PDAC systems are obsolete, unreliable, and not repairable. PG&E has used all spare parts available. Communication carriers have virtually eliminated support and are encouraging PG&E to convert to an alternate communications method. Presently PG&E has 54 PDAC wire centers that support over 874 PDAC leased lines serving more than 755 field devices such as line reclosers, line switches and interrupters. Therefore, each wire center serves an average 14 field devices. When a wire center is unavailable the control center loses its ability to determine the status of and to control 14 line devices. By the nature of the original deployment of PDAC, these devices are typically located at important circuit junctures.

During the past five years, PG&E has spent $3.95 million replacing obsolete and inoperative PDAC devices with modern SCADA equipment and establishing new communication links via the Company’s existing radio communications system. This is an average of $780,000 per year. PG&E’s forecast for this work activity is $150,000 million annually for 2005 to 2009. The forecast is based on addressing approximately five sites each year at an average cost of $30,000 each.

2 Converting Existing Reclosers for SCADA Operation

Some of the reclosers in PG&E’s distribution system have controllers that are obsolete. Replacing the obsolete controller with a SCADA-capable controller is an effective way of upgrading these devices. In addition to improving the performance of the recloser, other benefits include the ability to operate remotely, and obtain load reads and indications of line faults. PG&E’s forecast for this work activity is $200,000 annually for 2005 to 2009 and is based on replacing five reclosers each year at an average unit cost of $40,000 each.

3 Replacing/Upgrading Communication Equipment

Current automation communication systems are based on PDAC lines, lease lines, radio, microwave or cellular. Many of the existing distribution communication systems are obsolete and in some cases not functional or maintainable. Additionally, the conversion of existing line reclosers for SCADA operation in recent years (as described above) has contributed to overloading many existing communication systems. To accommodate additional SCADA line devices, PG&E must address the communication infrastructure. Addressing this issue will also provide opportunities to convert expensive leased line communications to radio communications (if radio capacity is available) or other mediums such as fiber optics or cellular. In addition, PG&E is spending $1.8 million in 2004 and 2005 to refurbish the fiber-optic communication system the Company uses to monitor the network distribution systems in Oakland and San Francisco. PG&E forecasts it will spend a total of $6.6 million between 2006 and 2009 to replace and/or upgrade distribution communication systems.

4 Distribution Area Automation Pilot

The purpose of the distribution area automation pilot is to develop and implement a fully integrated distribution automation infrastructure that encompasses all system protection, line and substation equipment and automation components.

The electric utility industry has used various forms of SCADA for the past 30 years. The industry is now gradually moving towards developing distribution automation systems that integrate advanced features such as automatic load restoration and dynamic circuit monitoring/ switching to prevent overloads and optimize voltage. More importantly, this new approach uses a technology and industry standard protocol so future enhancements are more easily adapted for system expansion.

PG&E is investigating this approach and has contracted with KEMA Consulting to perform a business case study with emphasis on reliability improvement. The estimated average cost to apply the new technology is approximately $250,000 per circuit, including hardware and communication infrastructure. The work involves modifying or installing “intelligent” switches, substation feeder breaker automation and associated communication infrastructure such as lease line, radio, pilot optic, or cellular technology, depending on the available communication in the circuit vicinity.

PG&E plans to pilot this technology on two circuits in 2006 for an estimated total cost of $500,000. PG&E is anticipating a successful pilot as the Company is using technology based on a similar installation at Calgary Utility (Canada) that proved successful. Following a successful pilot, PG&E will gradually implement the technology on other circuits between 2007 and 2009. Depending on the costs and performance of these applications, the Company may request additional funds in the next general rate case.

Table 8-12 summarizes PG&E’s 2000 through 2004 expenditures and 2005 through 2009 forecast of capital expenditures for MWC 09, distribution line automation.

Table 8-12

Pacific Gas and Electric Company

Reliability Program

MWC 09 Capital Expenditures for Distribution line-Related SCADA Work

($000)

Line No. |Distribution System Reliability |2000 Actual |2001 Actual |2002 Actual |2003 Actual |2004 Actual |2005 Forecast |2006 Forecast |2007 Forecast |2008 Forecast |2009 Forecast | |1 |Replace Line PDAC   with SCADA |$405 |$1,263 |$892 |$722 |$673 |$150 |$150 |$150 |$150 |$150 | |2 |Converting Existing   Reclosers for   SCADA Operation |108 |1,219 |393 |636 |95 |200 |200 |200 |200 |200 | |3 |Replace/upgrade   communication   equipment |225 |274 |369 |1,021 |1,376 |1,390 |1,500 |1,600 |1,700 |1,800 | |4 |Distribution   Automation |0 |0 |0 |0 |0 |0 |500 |1,100 |1,500 |2,000 | |5 |Total |$738 |$2,756 |$1,654 |$2,379 |$2,144 |$1,740 |$2,350 |$3,050 |$3,550 |$4,150 | | | | | | | | | | | | | | |

4 Expense MWC HX: System Automation Equipment Maintenance

MWC HX includes the maintenance activity for distribution automation equipment expenses for the Company’s enhanced outage notification, system that records momentary outage events, the SCADA historian (a database that captures distribution system data such as loads, voltages, etc.), and general distribution automation support. These expenses are necessary to support the reliable operation of DA line equipment. Maintenance expenses for DA line equipment on distribution feeders are charged to MWC BF Line Patrols and Inspections or MWC BG Preventive Maintenance. PG&E charges maintenance expenses for substation-related DA equipment to MWC GC – Operate and Maintain Substations. Finally, maintenance expenses for maintaining existing SCADA master stations and lease line expenses are discussed in Chapter 11, Electric Distribution Operations, of this exhibit.

Table 8-13 summarizes PG&E’s historical expenditures and the forecasts for 2005 through 2007 for MWC HX.

Table 8-13

Pacific Gas and Electric Company

Reliability Program

MWC HX Expenses for Distribution Automation

($000)

Line No. |MWC |Title |2000 Actual |2001 Actual |2002 Actual |2003 Actual |2004 Actual |2005 Forecast |2006 Forecast |2007 Forecast | |1 |HX | Electric Outage   Notification

(EON)   system |$495 |$605 |$570 |$595 |$553 |$640 |$640 |$640 | |2 |HX |SCADA Historian   Platform |369 |179 |190 |103 |31 |0 |100 |100 | |3 |HX |General Distribution   Automation Support |452 |268 |235 |241 |138 |0 |260 |160 | |4 | |Total |$1,316 |$1,052 |$995 |$939 |$722 |$640 |$1,000 |$900 | | | | | | | | | | | | | |

Translation of Program Expenses to FERC Accounts

As discussed in Chapter 2 of Exhibit (PG&E-1), PG&E’s program managers manage their program costs using the SAP view of cost information, not the FERC account view. Thus, for presentation in this GRC, certain SAP dollars must be translated to FERC dollars. This is not an issue for capital costs where the SAP and FERC view are identical.[[24]]

Cost Tables

The capital requests for the Reliability Program are summarized in the following tables:

• Table 8-14 lists the capital expenditures by MWC, showing 2004 recorded expenditures, and 2005 through 2009 forecast expenditures. The cost tables for MWCs 09 and HX are in Chapter 4, Substation Asset Management, of this exhibit.

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[[1]] Decision 04-10-034 uses the term benchmarks. While having the same meaning in the context of the RIM, PG&E uses the term targets in this chapter, as that connotes a goal, as opposed to benchmarks which connotes a basis of comparison.

[[2]] These capital and expense costs are stated in current year (or nominal) SAP dollars, as are all dollars referenced in this chapter unless stated otherwise.

[[3]] SAIDI is system average interruption duration index and SAIFI is system average interruption frequency index.

[[4]] PG&E anticipates a greater amount of error in SAIDI because the process to determine the total number of customer minutes (the value needed to calculate SAIDI) is more complicated than determining the total number of customer interruptions (the value needed to calculate SAIFI).

[[5]] Decision 04-10-034 uses the words “normal” and “abnormal” through-out the decision. For the purpose of this testimony, PG&E defines “normal reliability” as SAIDI and SAIFI values excluding days that meet the definition of an excludable major event from Appendix A of Decision 96-09-045. PG&E believes this definition is consistent with the language of Decision 04-10-034.

[[6]] Chapter 12 of this exhibit, Electric Emergency Recovery, contains information regarding how the workshop is addressing the definitions of “major outage,” ”measured event” and the restoration performance standard included in Standard 12 of G.O. 166.

[[7]] D.00-02-046, p. 491.

[[8]] D.04-10-034, pp. 73-74.

[[9]] CAIDI, or average restoration time, is the total customer minutes of interruption divided by the total number of customer interruptions. CAIDI can also be calculated by dividing SAIDI by SAIFI.

[[10]] Exhibit PG&E-2, Chapter 8, pp. 8-7 through 8-9.

[[11]] “We believe that while the record demonstrates that the outages and damages caused by the storms were reasonable considering the severity and the back-to-back nature of the storms, given the many outage communication and call center problems that occurred during the storms, we cannot find that PG&E’s storm response was reasonable.” (D.04-10-034, p. 98, emphasis added).

[[12]] Exhibit 301, Review of PG&E’s Supplemental Testimony on Reliability Performance, dated May 2, 2003, p. 8.

[[13]] The phrase “distribution automation,” (DA) is synonymous with supervisory control and data acquisition (SCADA).

[[14]] PG&E distribution engineers review monthly outage data to identify customers that are on a trend have more than 12 sustained outages. Customers who have already experienced more than 12 sustained outages are also identified.

[[15]] The heating of the conductor due to fault current, then subsequent cooling, can cause the conductor to become softer and sag more.

[[16]] At a unit cost of $36/circuit foot, an initial allocation of $35,000 replaces 970 circuit feet of conductor. This amounts to approximately three or four spans if the average span length is 250 to 350 feet.

[[17]] The workpapers also include a copy of Bulletin Number 2004PGM-1, Annealed Conductor Replacement Program.

[[18]] As noted in Chapter 6 of this exhibit, that the majority of cable replacement work will likely involve smaller conductor sizes normally found on tap lines as opposed to mainline replacement.

[[19]] D.04-10-034, p. 82.

[[20]] D.04-10-034, p. 90.

[[21]] November 10, 2004, “2004 Reliability Performance Assessment of San Francisco,” p. 1.

[[22]] November 10, 2004, “2004 Reliability Performance Assessment of San Francisco,” p. 5.

[[23]] Some of the projects that PG&E describes in Chapter 4, Substation Asset Management, and Chapter 6, Underground Asset Management, of this exhibit are a direct outcome of the KEMA report. For example, PG&E’s plans to accelerate the replacement of aging tie-cables in San Francisco and the east bay are an outcome of the KEMA report.

[[24]] Capital costs are typically shown in rate case filings with overheads (i.e., SAP “adders”) included, such as capitalized employee benefits and payroll taxes.

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8-21

8-24

8-33

8-37

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(PG&E-4)

(PG&E-4)

(PG&E-4)

(PG&E-4)

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