SDG&E's Energy Storage and EV Proposed Rate Case

Application of San Diego Gas & Electric Company (U902M) for authority to update its gas and electric revenue requirement and base rates effective on January 1, 2012.

Application No. 10-12-___ Exhibit No.: (SDG&E-11-CWP)

CAPITAL WORKPAPERS TO

PREPARED DIRECT TESTIMONY

OF THOMAS O. BIALEK, Ph.D., P.E.

ON BEHALF OF SAN DIEGO GAS & ELECTRIC COMPANY

BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA

DECEMBER 2010

TOB-CWP-1

CAPITAL PROJECT WORKPAPER Page 2 of 27

PROJECT TITLE Smart Grid Portfolio

SBUDGET NO. 10261

WITNESSLee Krevat/Tom Bialek

IN SERVICE DATE

various

PROJECT COST ($000 in 2009$)

PRIORYEARS 2009 2010 2011 2012 REMAINING

YEARS TOTAL

DIRECT LABOR 0 0 0 9696 15093 0 24789

DIRECT NONLABOR 0 0 0 26872 42176 0 69048

TOTAL DIRECT CAPITAL 0 0 0 36568 57269 0 93837

COLLECTIBLE

NET CAPITAL 0 0 0 36568 57269 0 93837

FTE 0 0 0 129.3 201.2 0 330.5

BUSINESS PURPOSE

This project portfolio incorporates smart grid technologies into the electric system infrastructure

with a goal of maintaining and/or improving system performance and operational flexibility and

reliability. As the penetration levels of renewables and electric vehicles increase relative to the

local load on the system, they are expected to impact system operations and reliability and this

portfolio will provide implementation of effective measures to mitigate these impacts. Relative

to infrastructure expansion, projects that involve building completely new large scale elements of

the distribution network such as new substations and new circuits shall be designed with a

perspective that strives to incorporate smart grid concepts and equipment where applicable.

This project portfolio also integrates with system improvement work being done to reduce the

fire threat in the overhead electric system located in the very high/extreme fire threat zone as this

hardening work provides a unique opportunity to incorporate smart grid elements to achieve the

most overall effective and superior solution. Smart grid and the fire hardening rebuilding

projects are particularly synergistic as the projects can be designed with a goal of providing more

operational flexibility, improved reliability and at the same time reduce fire risk. Smart grid

sensor technology, advanced system monitoring and control features can be integrated into the

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various

operation of the system which is especially valuable during storms and extreme fire risk weather

events. In addition to maintaining and/or improving reliability, the circuit hardening work with

smart grid technologies should facilitate integration of distributed energy resources such as solar

and wind, as well as energy storage for back up of important community infrastructure such as

cell phone networks, communications devices and small water pumps used to supply drinking

water and fill small storage tanks that otherwise may lose power during extreme conditions. This

project portfolio should provide the ability to incorporate technologies that can keep more

customers and critical infrastructure safely in service during extreme fire risk weather events as

well as during storm periods and times when the electric system is stressed due to high operating

loads or operational emergencies. Specific categories of technologies to be provided by this

project are listed below.

PROJECT DESCRIPTION AND JUSTIFICATION

The description and justification for each of the Smart Grid technologies included in this capital

project are given below:

RENEWABLE GROWTH

�Energy Storage (ES) - A cost forecast is provided for two types of energy storage systems to assist

in addressing intermittency issues created by the variable output of renewable energy resources.

One solution will place distributed energy storage systems on circuits with high penetration of

customer photovoltaic systems. Additionally, energy storage systems will be strategically located

in substations to mitigate the impact of multiple circuits with PV as the second budget item.

�Dynamic Line Ratings – A cost forecast is provided for implementation of dynamic ratings for

distribution circuits. The implementation of dynamic line ratings has the potential for increasing

circuit capacity and accommodating new renewable generation.

�Phasor Measurement Units – A cost forecast is provided for implementation of phasor

measurement units on the electric distribution system. Installation of phasor measurement units

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IN SERVICE DATE

various

on the electric distribution system are expected improve reliability by employing high speed, time

synchronized measurement devices. These devices will be utilized in conjunction with energy

storage devices to create a closed loop control system to mitigate the impact of intermittent

renewables.

�Capacitor SCADA – A cost forecast is provided to implement SCADA control of all capacitors on

SDG&E’s distribution system and is distinct from the SCADA expansion for switches discussed

below. Benefits of SCADA for capacitors should include: better voltage and VAr control,

reduced maintenance, and better system diagnostics. When coupled with energy storage,

dynamic line ratings and phasor measurements new control schemes can be implemented which

will mitigate the impact of PV system output fluctuations on system voltage.

�SCADA Expansion – A cost forecast is provided for expansion of SCADA to expand remote

operability and automated operation of distribution SCADA capable switches. This will continue

SDG&E’s goal of providing faster isolation of faulted electric distribution circuits and branches,

resulting in faster load restoration and isolation of system disturbances.

ELECTRIC VEHICLE GROWTH

�Smart Transformers – A cost forecast is provided for the installation of sensors and technology on

distribution transformers so that they can monitor and report loading, and the state of the

transformers. This project has the potential to allow increased transformer capacity utilization

and accommodate future loads such as electric vehicle charging.

�Public Access Charging Facilities – A cost forecast is provided for the installation of utility owned

public charging facilities for electric vehicles. SDG&E will install and own the charging facilities

in under-served areas in order to broaden the coverage of public charging stations within its

service territory. This project will also help to develop the services offered by 3rd parties to

support vehicle charging facilities.

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SBUDGET NO. 10261


IN SERVICE DATE

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RELIABILITY

�Wireless Faulted Circuit Indicators - A cost forecast is provided for implementation of wireless

faulted circuit indicators. This system is expected to provide rapid identification and location of

faulted distribution circuits resulting in reduced outage and repair times.

�Phase Identification – A cost forecast is provided for accurate identification of phasing for

implementation in the new distribution operating system. This project should enable improved

worker safety, more accurate fusing, improved system planning, and reduced system losses.

�Condition Based Maintenance Expansion – A cost forecast is provided for expansion of CBM to

include distribution substation transformers at 4 kV substations. This project should reduce the

risk of catastrophic failures and improve customer satisfaction.

SMART GRID DEVELOPMENT

Integrated Test Facility – A cost forecast is provided to construct facility upgrades and

purchase and install equipment to create an integrated test facility. This will allow testing of the

integration of multiple complex hardware and software systems comprising smart grid

technologies.

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SBUDGET NO. 10261


IN SERVICE DATE

various

RENEWABLE GROWTH: ENERGY STORAGE

A cost forecast is provided for two types of energy storage systems to assist in addressing

intermittency issues created by the variable output of renewable energy resources. One solution will

place distributed energy storage systems on circuits with high penetration of customer photovoltaic

systems. Additionally, energy storage systems will be strategically located in substations to mitigate

the impact of multiple circuits with PV as the second budget item.

Energy storage systems will be used to demonstrate the ability to enhance the value of energy

from renewable distributed generation in at least two fundamental ways: minimize the

intermittency problem of renewables by installing storage and if appropriate and possible, use

storage so that electric energy generated during times of lowest system need can be “time-

shifted” and used during time of greatest need to the electric system.

As the penetration of distributed energy resources, DER, continues to increase, the need for

distributed storage will also increase in order to mitigate intermittency problems at the local 12

kV feeder level. This project will install energy storage in two forms: 1) distributed storage in

the form of community energy storage, CES, devices in those circuits where the penetration of

distributed PV is 20% or more of the circuit load at times of high photovoltaic system output and

low circuit loads, and 2) substation energy storage of utility scale, size anticipated to be 1 MW or

greater, which will be installed to mitigate the effects of utility scale (up to 2 MW) PV projects

that will be installed in various locations.

Storage devices will be installed at substations with identified large PV additions (Creelman,

Pala, Valley Center, Lilac) and substations with high forecasted PV growth (Border, Kyocera,

Middletown, Poway). Unit-cost estimates for substation Storage are based on price quotation

obtained from Bulk Storage providers in September, 2009.

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IN SERVICE DATE

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Energy Storage, installed in conjunction with the appropriate sensors, control and

communication systems should provide a solution for the mitigation of intermittency via the

management and discharge of stored energy in a controlled and coordinated way.

Based on the historical and forecasted penetration of distributed PV in the SDG&E service

territory, CES devices, which are small, 50kW batteries, will be installed on 11 circuits in 2011,

and on 14 more circuits in 2012. In addition to the CES devices, substation energy storage

amounting to 4 MW will be installed in 2011 and another 4 MW will be installed in 2012.

A prioritized list of circuits that are good candidates for distributed storage, based on PV growth

projections, has been developed. CES unit-cost estimates were obtained from the EPRI Storage

System Cost Workbook, published in March, 2010.

Cash Flow:($000 in 2009$) Year: 2010 2011 2012 TotalDirect Labor: 0 6281 7427 13708Direct Non-labor: 0 18912 22363 41275Total Capital: 0 25193 29790 54983

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SBUDGET NO. 10261


IN SERVICE DATE

various

ELECTRIC VEHICLE GROWTH: SMART TRANSFORMERS

A cost forecast is provided for the installation of sensors and technology on distribution transformers

so that they can monitor and report loading, and the state of the transformers. This project has the

potential to allow increased transformer capacity utilization and accommodate future loads such as

electric vehicle charging.

�

Distribution line transformers can be converted into smart devices by installing monitoring

equipment on the secondary bushings. These monitors will provide information to engineers and

operators about the state of the grid including distributed resources and loads at the location of

the transformers. This data will be especially valuable for monitoring the load and condition of

transformers feeding plug-in electric vehicles. It will also provide information about the state

and condition of the transformer. Transformer monitors will facilitate dynamic ratings for the

transformers, the ability to verify energy consumed or generated by new distributed resources or

loads for potential management applications, and the ability to assess detailed transformer

conditions in order to proactively troubleshoot customer or secondary voltage problems.

This project will install transformer monitoring devices on all transformers serving customers

with plug-in electric vehicles. Sensing devices attached to transformers will be used to monitor

real-time loading and establish accurate load profiles. This information will be available to

system operators to alert them to possible overloads, imbalances, voltage excursions or other

operational issues. Additionally, engineers will use this information to revise transformer

loading guidelines which may lead to optimizing the number of customers that may be served

from an individual transformer and reducing transformer loading problems.

One transformer monitoring device will be installed on every distribution transformer that serves

a customer with a PEV and associated charge stations. The number of PEV charge stations is

anticipated to be:

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SBUDGET NO. 10261


IN SERVICE DATE

various

Year: 2010 2011 2012 Total

PEV Charge Stations: 600 2150 700 3450

This estimated number of charge stations is based on the expected sales of battery electric

vehicle and plug-in hybrid electric vehicle sales in the San Diego area. This estimate is based

upon a DOE sponsored program with partnership by ECOtality and Nissan to deploy up to 5,000

electric vehicles and charging infrastructure in San Diego and four other U.S. cities.

This project will begin in 2011, therefore the number of transformer monitors installed in 2011

will match the number of charge stations installed in 2010 and 2011. The cost estimate for this

project is derived from an estimated average cost of $744 per transformer monitor installed on

2750 transformers in 2011 and on 700 transformers in 2012. The average cost estimate per

transformer was based on information provided by a manufacturer of transformer monitoring

equipment that could be used for this project.


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SBUDGET NO. 10261


IN SERVICE DATE

various

ELECTRIC VEHICLE GROWTH: PUBLIC ACCESS CHARGING FACILITIES

A cost forecast is provided for the installation of utility-owned, public access charging facilities

for electric vehicles. SDG&E will install and own the charging facilities in under-served areas in

order to broaden the coverage of public charging opportunities within its service territory. This

effort will allow SDG&E to continue the momentum of the stakeholder charging facility siting

and installation process established by ECOtality as part of their government funded EV Project

between 2010 and mid-2011. As planned, this project will increase the number of charging

facility services offered by 3rd parties, specifically to provide PEV charging facilities in locations

that are not necessarily commercially or economically desirable, but needed to serve the broader

and growing PEV charging needs of the public.

SDG&E will work with the CPUC to develop broad criteria for evaluating the installation of

“public access charging facilities” with the objective to ensure a network of public charging

facilities is developed in the public interest over time that would provide sufficient support for

the adoption and use of PEVs

The number of 240V Level 2 charges installed will be approximately 1% of the cumulative plug-

in hybrid electric vehicles, PHEVs, anticipated in the 2012 through 2015 period, and the number

of DC Fast Chargers will be approximately 0.1% of the cumulative PHEV’s in the 2012-2015

period (see table below). PEV charging facility users will pay for the use of these charging

facilities through an applicable PEV tariff that will be developed in accordance with policy

established in the CPUC’s Alternative Fueled Vehicle Order Instituting Rulemaking.

Year: 2010 2011 2012 Total240V Level 2 Charge Stations 0 0 129 129480V DC Fast Charger Stations: 0 0 13 13

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The cash flow below reflects the public access charging facilities funding requirements for the

entire SDG&E system taking place over a four year period (2012-2015) with the work beginning

in 2012. The cash flow below reflects the public access charging facilities funding requirements

taking place over a four year period (2012-2015). This cost estimate is derived from an

estimated average cost of approximately $33,000 per 240V charging facility times 129 such

facilities per year, plus approximately $71,000 per 480V charging facility times 13 such facilities

per year.


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SBUDGET NO. 10261


IN SERVICE DATE

various


SUMMARY CASH FLOW

A summary table of the cash flows for all projects in this workpaper is provided below.

TOB-CWP-27

SDGE Doc #249440

Application of San Diego Gas & Electric Company (U902M) for authority to update its gas and electric revenue requirement and base rates effective on January 1, 2012.

Application 10-12-____ Exhibit No.: (SDG&E-11)

PREPARED DIRECT TESTIMONY OF

THOMAS BIALEK, Ph.D., P.E.

ON BEHALF OF SAN DIEGO GAS & ELECTRIC COMPANY

BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA

December 2010

SDGE Doc #249440 TOB-i

TABLE OF CONTENTS I. INTRODUCTION...................................................................................................................... 1

A. Purpose of Testimony ................................................................................................................ 1

B. Overview of Operations ............................................................................................................. 3

C. Challenges Facing Operations .................................................................................................. 4

C. Reliability .................................................................................................................................. 14

D. Smart Grid Development ........................................................................................................ 15

E. Summary of Request ................................................................................................................ 16

II. NONSHARED SERVICES ..................................................................................................... 17

A. Introduction .............................................................................................................................. 17

1. Smart Grid Team ............................................................................................................... 17

B. Discussion of O&M Activities ................................................................................................. 17

1. Smart Grid Team Salaries and Benefits .......................................................................... 17

III. CAPITAL.................................................................................................................................. 18

A. Introduction .............................................................................................................................. 18

B. Capital Request Detail ............................................................................................................. 20

1. Renewable Growth: Energy Storage (Budget Codes: 10261) ....................................... 20

2. Renewable Growth: Dynamic Line Ratings (Budget Codes: 10261) ........................... 21

3. Renewable Growth: Phasor Measurement Units (PMU) - Synchrophasors (Budget

Codes: 10261) ..................................................................................................................... 22

4. Renewable Growth: Capacitor SCADA (Budget Codes: 10261) ................................. 24

5. Renewable Growth: SCADA Expansion (Budget Codes: 10261) ................................. 25

6. Electric Vehicle Growth: Plug-In Electric Vehicles ...................................................... 26

7. Electric Vehicle Growth: Smart Transformers (Budget Codes: 10261) ...................... 27

8. Electric Vehicle Growth: Public Access Charging Facilities (Budget Codes: 10261) 28

9. Reliability: Wireless Fault Indicators (FCI) (Budget Codes: 10261) .......................... 31

10. Reliability: Phase Identification (Budget Codes: 10261) ............................................... 32

11. Reliability: Condition Based Maintenance (CBM) Expansion

(Budget Codes: 10261) ....................................................................................................... 33

12. Smart Grid Development: Integrated Test Facility (Budget Codes: 10261) ............... 35

IV. CONCLUSION ........................................................................................................................ 35

V. WITNESS QUALIFICATIONS ............................................................................................. 37

SDGE Doc #249440 TOB-1

PREPARED DIRECT TESTIMONY OF 1

THOMAS BIALEK, Ph.D., P.E. 2

ON BEHALF OF SAN DIEGO GAS & ELECTRIC COMPANY 3

4 5 I. INTRODUCTION 6 7

A. Purpose of Testimony 8

1. New Projects Incremental to Historical Activities 9

The purpose of this testimony is to sponsor the Smart Grid capital forecasts for 10

San Diego Gas & Electric Company, SDG&E, for the years 2010, 2011 and the test 11

year 2012. The Smart Grid portfolio of projects that are presented in this immediate 12

general rate case, GRC, application also have a life span that extend beyond the test 13

year. Additionally, this GRC funding request is not to be viewed as the entirety of 14

Smart Grid projects that SDG&E may request since other projects may be necessary in 15

the future as requirements change and as new technologies and solutions become 16

available. 17

As discussed in the Smart Grid policy testimony of Mr. Lee Krevat, Exhibit 18

SDG&E-10, there are many drivers for SDG&E’s Smart Grid activities. Based upon 19

these drivers, SDG&E has developed a limited portfolio of projects with the goal of 20

applying Smart Grid technologies to effectively integrate intermittent renewable 21

generation sources and plug-in electric vehicles, and includes other capabilities 22

designed to maintain and/or improve system reliability. The projects included in this 23

general rate case include only the distribution component of each project. The 24

information technology, IT, capital portions associated with these projects are 25

necessary to provide the communication devices, IT infrastructure and applications 26

required to derive the functionality envisioned with the individual project. The IT 27

components required for the Smart Grid portfolio of projects, while need-justified 28

within the scope of this testimony, are presented in the testimony of Mr. Jeff Nichols, 29

Exhibit SDG&E-18. What might be described today as the conventional or on-going 30

capital and operations and maintenance forecasts are presented in the testimonies of 31

Mr. Alan Marcher, Exhibit SDG&E-06 and Mr. Scott Furgerson, Exhibit SDG&E-05 32

respectively. 33


A list of the Smart Grid projects by categories and testimony sponsors is shown below: 1

RENEWABLE GROWTH 2

Energy Storage (ES) Capital Thomas Bialek, Exhibit SDG&E-11 3

IT Mr. Jeff Nichols, Exhibit SDG&E-18 4

Dynamic Line Ratings Capital Thomas Bialek, Exhibit SDG&E-11 5


Phasor Measurement Units Capital Thomas Bialek, Exhibit SDG&E-11 7


Capacitor SCADA Capital Thomas Bialek, Exhibit SDG&E-11 9


SCADA expansion Capital Thomas Bialek, Exhibit SDG&E-11 11


13

14

ELECTRIC VEHICLE GROWTH 15

Plug-in Electric Vehicles Capital Mr. Alan Marcher, Exhibit SDG&E-06 16


Smart Transformers Capital Thomas Bialek, Exhibit SDG&E-11 18


Public Access Charging Facilities Capital Thomas Bialek, Exhibit SDG&E-11 20


22

RELIABILITY 23

Wireless Faulted Circuit Indicators Capital Thomas Bialek, Exhibit SDG&E-11 24


Phase Identification Capital Thomas Bialek, Exhibit SDG&E-11 26


Condition Based Maintenance 28 Expansion Capital Thomas Bialek, Exhibit SDG&E-11 29


31

32


SMART GRID DEVELOPMENT 1

Integrated Test Facility Capital Thomas Bialek, Exhibit SDG&E-11 2


4

2. Smart Grid Team 5

This testimony also sponsors the ongoing funding of the cost center for the 6

Smart Grid Team. This small group of individuals: a Director, Chief Engineer, Lead 7

Architect, Policy Manager, Customer Manager and Administrative Associate; are 8

responsible for developing SDG&E’s Smart Grid strategy and policy. The organization 9

is also responsible for aligning the strategy and policy across SDG&E. 10

11

Table TOB -1 12

Summary of TY2012 Change 13

(Thousands of $2009) 14

15 Functional Area: SMART GRID

Description 2009 Adjusted-Recorded

TY2012 Estimated

Change Testimony Reference

Total Non-Shared 330 1,003 673 Section II Total Shared Services (Book Expense)

0 0 0

Total O&M 330 1,003 673 Total Capital 0 57,269 57,269 Section III 16

B. Overview of Operations 17

Smart Grid is a new activity. A special cost-center function has been created to deal 18

just with this topic, and that cost center’s role is to provide steering and strategic guidance 19

throughout the organization to coordinate the adoption and implementation of Smart Grid 20

related technologies. 21

22

23

24


C. Challenges Facing Operations 1

As described in the testimony of Mr. Lee Krevat, Exhibit SDG&E-10, SDG&E is 2

committed to meeting California policy goals of promoting increased levels of renewable 3

energy resources and the deployment of electric vehicles to meet greenhouse gas reduction 4

targets. However, with advancements in environmentally friendly technologies such as solar 5

and wind generation, plug-in electric vehicles, and energy storage, as well as the deployment 6

of new customer empowering Smart Meter technology, the electric system is in the midst of 7

significant change. SDG&E recognizes the need to leverage equally advancing information 8

and communication technologies, ICT, to ensure the continued safety, reliability, security, and 9

efficiency of the electric grid as utilization of intermittent energy resources and demand for 10

plug-in electric vehicle, PEV, increases. 11

In addition to the traditional grid management and customer-facing projects utilities 12

have undertaken in the past, environmental policy and legislation encouraging customer 13

empowerment over energy management is driving the need to accelerate the integration of 14

digital and communications technology with the electric delivery system, creating a smarter 15

grid. The public policy objectives of California and the situation faced in San Diego create a 16

need to move forward with the implementation of advanced technology in order to meet the 17

State’s ambitious energy policy goals. 18

The seven characteristics or performance features of a Smart Grid as developed by the 19

Department of Energy’s, DOE, Smart Grid Task Force and referenced by the CPUC are1: 20

• Anticipating and responding to system disturbances in a 21 self-healing manner; 22

• Enabling active participation by consumers; 23

• Operating resiliently against physical and cyber attack; 24

• Accommodating all generation and storage options; 25

• Enabling new products, services, and markets; 26

• Optimizing asset utilization and operating efficiently; and 27

• Providing the power quality for the range of needs in a 28 digital economy. 29

30 1 CPUC R.08-12-009, Order Instituting Rulemaking to consider Smart Grid Technologies Pursuant to Federal Legislation and on the Commission’s own Motion to Actively Guide Policy in California’s Development of a Smart Grid System, p 11.


SDG&E’s current portfolio of T&D Smart Grid projects focus on four specific areas: 1

renewable generation growth, electric vehicle growth, reliability and Smart Grid development. 2

In the first area SDG&E is focused on mitigating the impact of renewable photovoltaic, PV, 3

distributed generation. For the second area, SDG&E is deploying new Smart Grid 4

technologies as well as traditional infrastructure to mitigate reliability issues due to customer 5

adoption of PEVs. The third area focus is to mitigate the reliability impacts of an aging 6

electric infrastructure by implementing advanced sensors and associated systems. For the last 7

area, SDG&E is planning to create an integrated test facility to put various emerging 8

technology solutions together to test for interoperability and provide proof-of-concept 9

demonstrations. 10

As indicated by Mr. Lee Krevat, Exhibit SDG&E-10, SDG&E needs to mitigate the 11

impacts of renewable generation development that is planned and occurring in the San Diego 12

region to satisfy California’s 33% Renewable Portfolio Standard, RPS. Additionally, San 13

Diegans have installed more total systems and nameplate capacity of distributed photovoltaic 14

generation than consumers in any city in the state based on 2009 data2. The arrival of 1,000 15

Nissan Leaf all-electric vehicles starting in December of 2010 will also increase the immediate 16

need for Smart Grid technologies on the electric grid in San Diego. 17

Increased situational awareness enabled by sensors, communications, data, analysis and 18

remote control allows the system to be operated with increased reliability and safety. Dynamic 19

measurement of system characteristics and improved distribution management also increases 20

the capabilities and resiliency of energy delivery. However, as a result, the complexity of grid 21

operations is increased significantly. 22

23

1. San Diego Drivers 24

The specific drivers of Smart Grid investments in the San Diego Gas & Electric 25

service territory are the growth of distributed photovoltaics, PV, the expected growth of 26

plug-in electric vehicles, PEVs and SDG&E’s aging infrastructure. 27

28

29

2 “California’s Solar Cities: Leading the Way to a Clean Energy Future”; Environment California Research and Policy Center, Summer 2009; accessed July 15, 2010 at http://www.environmentcalifornia.org/reports/energy/energy-program-reports/californias-solar-cities


a. Distributed Photovoltaic Growth 1

At year end 2009 distributed PV accounted for approximately 65 MWac 2

of generating capacity on the SDG&E system. As of the same timeframe, 3

SDG&E has ten primary distribution circuits with over 20% of the load served 4

by PV at times of low circuit loading as shown in Figure TOB-1.3 Figure TOB-5

2 illustrates both the actual recorded PV installations and the California Energy 6

Commission, CEC, forecast based on past PV growth.4 Applying the CEC 7

forecast to existing installations on circuits produces Figure TOB-3 which 8

shows the circuits with levels of over 20% PV generation at year end 2020. 9

This figure shows sixty circuits meet this criteria, which SDG&E believes is an 10

appropriate threshold to conduct more detailed studies to determine if the circuit 11

can accommodate these levels of PV without impacting grid voltage operating 12

limits or creating any operations and maintenance issues. 13

14

15

3 While SDG&E’s Rule 21 places an emphasis on percentage nameplate capacity as a function of peak line section rating, for PV systems the maximum output at times of lower system load (no air conditioning) are more critical. 4 CEC CALIFORNIA ENERGY DEMAND 2010-2020 December 2009, CEC-200-2009-012-CMF, ADOPTED FORECAST , Form 1.4, Page 149.


1 Figure TOB-1 – PV Penetration YE 2009 as a Percentage of Circuit Load on April 1, 2009, 1 2

pm 3

4

5

6


1 Figure TOB-2 – Actual Historical PV Installations and CEC PV Forecast 2


1 Figure TOB-3 – Impact of Increasing PV Penetration versus year with CEC Forecast Installations 2

3

SDG&E has been able to instrument a circuit with a high PV nameplate capacity at a time of 4

low circuit loading. Figure TOB- 4 shows the impact of a 1 MWac PV system on SDG&E’s primary 5

voltage for one day recorded with this instrumentation. The upper set of curves shows the impact of 6

fog burning off on the output of the PV system and the commensurate changes in primary voltage 7

during the day. The lower set of curves is a magnified view, 10 minutes of one particular change in 8

the PV system output data. Operational issues that are noted from these curves include the following: 9

high primary voltage coincident with PV system output and an approximately 15% swing in primary 10

voltage coincident with PV system output change. These measured and changes in values are outside 11

SDG&E’s design tolerance limits. Therefore, from the data and forecast currently available, SDG&E 12

believes investment in mitigation of intermittent photovoltaic generation is necessary. 13

14

15


1 Figure TOB-4 – PV System Output Variability Impact on Primary Voltage 2

3

One component of a solution to this problem is to incorporate energy storage as a grid device. 4

With energy storage, given its cost today, it is necessary to accrue benefits associated with multiple 5


value streams in order to provide a least-cost solution. The value streams for energy storage are as 1

follows: 2

• Grid operation to islanded system operation 3

• Smoothing electrical transition 4

• Power quality 5

• Power leveling / regulation on grids with connected variable, renewal energy sources, 6

such as Wind, PV, etc. 7

• Peak load shifting / shaving 8

• As needed 9

• Daily 10

• Energy storage for off-peak / on-peak energy arbitrage 11

• Energy regulation / ancillary services related to CAISO operations 12

• T&D capacity deferral 13

14

SDG&E has utilized a report published by Sandia National Labs as a reference guide for 15

energy storage applications which states5: 16

"The work documented in this report represents another step in the ongoing investigation of 17

innovative and potentially attractive value propositions for electricity storage by the United 18

States Department of Energy (DOE) and Sandia National Laboratories (SNL) Energy Storage 19

Systems (ESS) Program. This study uses updated cost and performance information for 20

modular energy storage (MES) developed for this study to evaluate four prospective value 21

propositions for MES. The four potentially attractive value propositions are defined by a 22

combination of well known benefits that are associated with electricity generation, delivery, 23

and use. The value propositions evaluated are: 1) transportable MES for electric utility 24

transmission and distribution (T&D) equipment upgrade deferral and for improving local 25

power quality, each in alternating years, 2) improving local power quality only, in all years, 3) 26

electric utility T&D deferral in year 1, followed by electricity price arbitrage in following 27

years; plus a generation capacity credit in all years, and 4) electric utility end-user cost 28

management during times when peak and critical peak pricing prevail." 29 5 Sandia National Laboratory, SANDIA REPORT SAND2008-0978, Unlimited Release Printed, February 2008, Benefit/Cost Framework for Evaluating Modular Energy Storage, A Study for the DOE Energy Storage Systems Program, Susan M. Schoenung and Jim Eyer.


1

The summary results of the SNL study are shown below. 2

“Figure 17 shows the present worth of benefits and costs for lead-acid battery storage used for 3

the four value propositions investigated. Most notably: value proposition 1 (T&D deferral plus 4

PQ), value proposition 2 (PQ/reliability only) and value proposition 3 (high value T&D 5

deferral plus arbitrage and generation capacity credit) show promise as they have a benefit/cost 6

ratio greater than 1. 7 8

9 10

Other components of the multi-faceted solution include dynamic line ratings, phasor 11

measurement units and supervisory control and data acquisition, SCADA, expansion to enable remote 12

control of capacitor banks and other switches on the system. 13

14

B. Plug-In Electric Vehicle (PEV) Growth 15

As also discussed in the testimony of Mr. Lee Krevat, Exhibit SDG&E-10, the impact 16

of PEVs on SDG&E’s system is expected to be significant. He discussed the US Department 17

of Energy, DOE, and California Energy Commission, CEC, grants awarded to ECOtality6 as 18

6 ECOtality is a San Francisco based company specializing in the development and commercialization of electric transportation and storage technologies.


well as the large loads that these vehicles will impose on the system as a result of the rapid 1

deployment of PEVs and residential, commercial and public charging facilities in the SDG&E 2

service territory beginning in 2010. He also mentioned the need to make infrastructure 3

investments to empower customers and to minimize barriers that would be created without 4

immediate action taken to ensure the deployment of adequate charging infrastructure. This 5

position is also supported by the Commission as described in the testimony of Ms. Kathleen 6

Cordova, Exhibit SDG&E-15 (SDG&E’s Electric Clean Transportation Program). In January 7

2010, the Commission recognized the importance of early action to support the electric 8

transportation market in defining the scope for the alternative-fueled vehicles rulemaking and 9

stated that it will follow the directive set forth in Senate Bill 626 to evaluate policies to develop 10

infrastructure sufficient to overcome any barriers to the widespread deployment and use of 11

plug-in hybrid and electric vehicles.7 12

Figure TOB-5 shows SDG&E’s estimates of PEV sales in its service territory. This 13

estimate of PEV sales was based upon several independent analysts’ forecast of light duty 14

vehicles PEV penetrations adjusted to be applicable to SDG&E’s service territory and related 15

impacts. By 2012 approximately 15,000 PEVs are estimated to be owned by customers in 16

SDG&E’s service territory. With an estimated load of 3 kW per vehicle this equates to 45 MW 17

of new load, that if not managed properly could have a significant impact on the local 18

distribution system and potential generation needs. It should be noted that the Commission 19

approved in June of 2010 the use of three experimental PEV time-of-use rates, each with 20

varying differences between on-peak and off-peak pricing to explore the degree to which rates 21

(and enabling PEV technology) impacts consumer time-of-day charging decisions and 22

behavior.8 23

One of many challenges associated with PEV growth rates will be with customers who 24

purchase these vehicles and are located in the older coastal areas of SDG&E’s service territory. 25

In most instances these homes are smaller, do not have air conditioning and the number of 26

customers connected per transformer is greater than in the inland valleys. A 3 kW charging 27

7 January 12, 2010 Scoping Memo in R.09-08-009, Commission Rulemaking on alternative-fueled vehicle tariffs, infrastructure and policies to support California's greenhouse gas emissions reduction goals. 8 http://docs.cpuc.ca.gov/word_pdf/AGENDA_RESOLUTION/119477.pdf Res.E-4334 – The CPUC approved SDG&E’s request to establish three new temporary experimental residential rate schedules for plug-in electric vehicle (PEV) charging to be used coincident with the EV Project (ECOtality’s deployment of home, commercial and public charging facilities in collaboration with Nissan’s deployment of the Leaf PEV in SDG&E’s services territory). This Resolution approves implementation of the experimental rate schedules beginning January 1, 2011. The temporary rates will remain in effect until November 30, 2012 (or until completion of the related pricing pilot research project.)


load is comparable to an air conditioner load which now suddenly is placed onto the grid. 1

SDG&E is currently involved in an Electric Power Research Institute, EPRI, project9 to further 2

understand the impact of PEVs on the grid. Proactively, SDG&E believes it is imperative to 3

fund three areas of activities: existing facility upgrades, smart transformers and public charging 4

infrastructure in order address the coming PEV consumer demand and to reduce potential 5

market barriers to PEV adoption due to inadequate charging infrastructure. 6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

Figure TOB-5 – SDG&E’s Estimate of PEV Sales 21

22

C. Reliability 23

As discussed at length in the testimony of Mr. Alan Marcher, Exhibit SDG&E-06, 24

SDG&E has an aging infrastructure and a need to continue to improve its fire preparedness. 25

Seventy-eight percent of SDG&E’s 4 kV substation transformers have been in-service 50 years 26

or more while only thirty seven percent of 12 kV substation transformers have been in-service 27

40 years or more. It is not just transformers but basic equipment such as poles, wire and cable. 28

Putting this in context, these pieces of equipment have to handle not only existing historical 29

loads but now also the intermittent power flows associated with PV systems that have been 30

installed and the PEV loads that are poised to make an appearance at the end of 2010. 31 9 EPRI Project ID No. 065939.

Cumulative and annual PEV sales (2010 to 2020)BEVs and PHEVs (x 1,000)

24.138 .6

56 .9

79.3

106.1

140 .1

183 .6

236.6

2 .63 .7

5.6

8.4

12 .01

16 .5

21.6

27.5

1 .1 5.2 13.10 .2 2.1 2.2

20.2 25.230.5

38.448.7

58.9

1.3 6.111.4

7.915.60

50

100

150

200

250

300

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Cumulative B EVsCumulative PHEVsAnnual PEV s ales


1

As SDG&E works to further reduce the risk of fires and strive to improve its ability to 2

respond and restore electrical service as quickly as possible, it is leveraging advances in 3

technology and systems. SDG&E believes that by putting the “smarts” in the grid it should be 4

possible to maintain and/or improve reliability in the face of these challenges. Therefore, 5

SDG&E has developed cost forecasts for three Smart Grid projects for incorporation in this 6

general rate case: wireless faulted circuit indicators, phase identification and an expansion of 7

condition based maintenance. 8

9

D. Smart Grid Development 10

As the Commission has noted in its recent Smart Grid OIR decision, D.10-06-047, 11

“…that deployment plans should include a discussion of an IOU’s Smart Grid strategy, 12

and that the strategy should offer a sense of direction and guidance, rather than setting rigid 13

requirements. This is clearly a reasonable approach since there are significant uncertainties 14

surrounding future technologies that may be part of a Smart Grid.” 10 15

also 16

“There is a consensus among those parties providing comments that a 17

roadmap can provide useful information concerning technologies and their 18

deployment, even though they will remain subject to change.”11 19

20

and finally 21

“In addition, there is near universal agreement that it is difficult to provide a reliable cost 22

estimate based on future and unknown technologies and infrastructure investments….but the 23

Commission does not find that it would be possible to require detailed, projected cost estimates 24

for technology that is undergoing dramatic changes in costs and technology today, or has yet to 25

be invented.”12 26

Given that Smart Grid technologies, solutions and standards are rapidly evolving and it 27

is difficult to estimate costs and requirements in the next five years, there is a need, as pointed 28

10 R.08-12-009, Order Instituting Rulemaking to Consider Smart Grid Technologies Pursuant to Federal Legislation and on the Commission’s own Motion to Actively Guide Policy in California’s Development of a Smart Grid System, D.10-06-047 (Decision Adopting Requirements For Smart Grid Deployment Plans Pursuant To Senate Bill 17 (Padilla), Chapter 327, Statutes Of 2009)., pg. 47. 11 Ibid, pg. 64. 12 Ibid, pg. 68.


out by Mr. Lee Krevat Exhibit SDG&E-10, for SDG&E to test the function of new consumer 1

focused technologies on the installed smart meters and associated systems to enable two Smart 2

Grid characteristics. These characteristics are enabling active participation by consumers and 3

new products, services, and markets. Therefore, SDG&E has developed a cost forecast for an 4

integrated Smart Grid test facility to address standard, integration and interoperability 5

challenges for these technologies. 6

7

E. Summary of Request 8

9 Table TOB - 2 10

O&M Non-Shared Services 11 Testimony Section II 12

(Thousands 2009 dollars) 13 14 SMART GRID Categories of Management 2009 Adjusted-

Recorded TY2012 Estimated

Change

A. Smart Grid Electric Distribution 330 1,003 673 Total 330 1,003 673 15

16 17

Table TOB - 3 18 Capital Expenditures 19

(Thousands 2009 dollars) 20 21

SMART GRID Category Description 2009

Recorded 2010

Estimated 2011

Estimated 2012

Estimated1. Smart Grid Portfolio $0 $0 $36,568 $57,269

Total Capital: $0 $0 $36,568 $57,269 22

23

24

25

26

27

28


II. NONSHARED SERVICES 1

A. Introduction 2

1. Smart Grid Team 3

This testimony also sponsors the ongoing funding of the cost center for the 4

Smart Grid Team. This small group of individuals: a Director, Chief Engineer, Lead 5

Architect, Policy Manager, Customer Manager and Administrative Associate; are 6

responsible for developing SDG&E’s Smart Grid strategy and policy. The organization 7

is responsible for aligning the strategy and policy across SDG&E. 8

9

Table TOB - 4 10 O&M Non-Shared Services 11 (Thousands of 2009 dollars) 12

13 SMART GRID A. Smart Grid Electric Distribution 2009 Adjusted-

Recorded TY2012 Estimated

Change

1. Smart Grid Electric Distribution 330 1,003 673 Total 330 1,003 673 14 15

B. Discussion of O&M Activities 16

1. Smart Grid Team Salaries and Benefits 17

This funding covers the salaries and incidental O&M expenses of the Smart 18

Grid Team. This small team was first formed in 2009 as a result of the significant 19

activities at both the Federal and State level with regards to Smart Grid. It was 20

recognized that with Federal legislation and the DOE driven activity in this area that a 21

team was required to specifically focus on this topic; driving SDG&E’s strategy and 22

vision in this important area. As a consequence, in June 2009, a Director, Chief 23

Engineer, Lead Architect and an Administrative Associate were brought together to 24

begin work. In 2010, a Policy Manager and Customer Manager were also brought into 25

the team completing the staffing goals. 26

The team spent most of 2009 developing a SDG&E strategy and vision and 27

subsequently communicating both internally and externally. The Commission’s Smart 28

Grid Rulemaking was also underway at this time and the team participated in 29


workshops and commented on Commission questions. The DOE released its funding 1

opportunity notice for Smart Grid and the team spent the summer developing proposal 2

for both the investment grant and regional demonstration solicitations. 3

In 2010 the work on the Smart Grid OIR continued with a decision being 4

released regarding the implementation of SB17. Work has also begun to deliver the 5

SDG&E Smart Grid vision and roadmap by the required July 1, 2011 deadline. The 6

team directed SDG&E’s effort in the EPRI-led California utilities Smart Grid 2020 7

Vision activity in response to the CEC solicitation of the same name. An internal 8

stakeholder effort also occurred to align and drive SDG&E’s strategy and policy across 9

the organization. 10

Future work activities will include the SB17 mandated yearly updates to 11

SDG&E’s Smart Grid roadmap, responding to other Commission rulings, other pending 12

legislation and driving Smart Grid solutions to system problems to name but a few 13

activities. 14

15

III. CAPITAL 16

A. Introduction 17

This project portfolio incorporates Smart Grid technologies into the electric system 18

infrastructure with a goal of maintaining and/or improving system performance and operational 19

flexibility and reliability. As the penetration levels of renewables and electric vehicles increase 20

relative to the local load on the system, they are expected to impact system operations and 21

reliability and this portfolio will provide implementation of effective measures to mitigate 22

these impacts. Relative to infrastructure expansion, projects that involve building completely 23

new large scale elements of the distribution system such as new substations and new circuits 24

shall be designed with a perspective that strives to incorporate Smart Grid concepts and 25

equipment where applicable. 26

This project portfolio also integrates with system improvement work being done to 27

further reduce the fire threat in the overhead electric system located in the very high/extreme 28

fire threat zone. As discussed in the testimony of Mr. Alan Marcher, Exhibit SDG&E-06, this 29

system hardening work provides a unique opportunity to incorporate Smart Grid elements to 30

achieve the most overall effective and superior solution. Smart Grid and the fire hardening 31


projects are particularly synergistic as the projects can be designed with a goal of providing 1

more operational flexibility, improved reliability and at the same time further reduce fire risk. 2

Smart Grid sensor technology, advanced system monitoring and control features can be 3

integrated into the operation of the system which is especially valuable during storms and 4

extreme fire risk weather events. In addition to maintaining and/or improving reliability, the 5

circuit hardening work with Smart Grid technologies should facilitate integration of distributed 6

energy resources such as solar and wind, as well as energy storage for back up of important 7

community infrastructure such as cell phone networks, communications devices and small 8

water pumps used to supply drinking water and fill small storage tanks that otherwise may lose 9

power during extreme conditions. This project portfolio should provide the ability to 10

incorporate technologies that can keep more customers and critical infrastructure safely in 11

service during extreme fire risk weather events as well as during storm periods and times when 12

the electric system is stressed due to high operating loads or operational emergencies. 13

The Smart Grid portfolio is divided into four principal categories. These are Renewable 14

Growth, Electric Vehicle Growth, Reliability and Smart Grid Development. Individual 15

projects comprising the portfolio are grouped into these categories: 16

17

RENEWABLE GROWTH 18

Energy Storage (ES) 19

Dynamic Line Ratings 20

Phasor Measurement Units 21

Capacitor SCADA 22

SCADA Expansion 23

ELECTRIC VEHICLE GROWTH 24

Plug-in Electric Vehicles 25

These costs are incorporated in the testimony of Mr. Alan Marcher, Exhibit SDG&E-06. 26

Smart Transformers 27

Public Access Charging Facilities 28

RELIABILITY 29

Wireless Faulted Circuit Indicators 30

Phase Identification 31

Condition Based Maintenance (CBM) Expansion 32


SMART GRID DEVELOPMENT 1

Integrated Test Facility 2

3

CAPITAL SUMMARY REQUEST 4 5 6

Table TOB - 5 7

Capital Expenditures 8 (Thousands of 2009 dollars) 9

10

Category Description 2009

Recorded 2010

Estimated 2011

Estimated 2012

Estimated1. Smart Grid Portfolio $0 $0 $36,568 $57,269

Total Capital: $0 $0 $36,568 $57,269 11

B. Capital Request Detail 12

1. Renewable Growth: Energy Storage (Budget Codes: 10261) 13

A cost forecast is provided for two types of energy storage systems to assist in 14

addressing intermittency issues created by the variable output of renewable energy 15

resources. One solution will place distributed energy storage systems on circuits with high 16

penetration of customer photovoltaic systems. Additionally, energy storage systems will be 17

strategically located in substations to mitigate the impact of multiple circuits with PV as the 18

second budget item. 19

Energy storage systems will be used to demonstrate the ability to enhance the value 20

of energy from renewable distributed generation in at least two fundamental ways: 21

minimize the intermittency problem of renewables by installing storage and if appropriate 22

and possible, use storage so that electric energy generated during times of lowest system 23

need can be “time-shifted” and used during time of greatest need to the electric system. 24

As the penetration of distributed energy resources, DER, continues to increase, the 25

need for distributed storage will also increase in order to mitigate intermittency problems at 26

the local 12 kV feeder level. This project will install energy storage in two forms: 1) 27

distributed storage in the form of community energy storage, CES, devices in those circuits 28

where the penetration of PV is 20% or more of the circuit load at times of high photovoltaic 29


system output and low circuit loads and 2) substation energy storage of utility scale, size 1

anticipated to be 1 MW or greater, which will be installed to mitigate the effects of utility 2

scale (up to 2 MW) PV projects that will be installed in various locations. 3

Energy Storage, installed in conjunction with the appropriate sensors, control and 4

communication systems should provide a solution for the mitigation of intermittency via the 5

management and discharge of stored energy in a controlled and coordinated way. 6

Based on the historical and forecasted penetration of distributed PV in the SDG&E 7

service territory, CES devices, which are small, 50 kW batteries will be installed on 11 8

circuits in 2011, and on 14 more circuits in 2012. In addition to the CES devices, substation 9

energy storage amounting to 4 MW will be installed in 2011 and another 4 MW will be 10

installed in 2012. 11

12

Table TOB - 6 13 Renewable Growth, Energy Storage Capital Expenditures 14

(Thousands of 2009 dollars) 15

16 Description 2009 Adjusted

Recorded 2010

Estimated 2011

Estimated TY2012

Estimated Category 1 $0 $0 $25,193 $29,790

17

2. Renewable Growth: Dynamic Line Ratings (Budget Codes: 10261) 18

A cost forecast is provided for implementation of dynamic ratings for distribution 19

circuits. The implementation of dynamic line ratings has the potential for increasing circuit 20

capacity and accommodating new renewable generation. 21

Dynamic ratings of equipment provide an opportunity to optimize capital 22

investments and operate the grid at higher efficiencies. Dynamic line ratings compare the 23

weather-adjusted, thermal rating of a conductor against the static design rating. The pre-24

calculated static value for the thermal rating of a conductor is developed to protect the 25

conductor from damage due to annealing and from excessive sag during extreme heat. 26

This project will install dynamic line rating technologies on ten distribution circuits 27

per year. Installations will be made on the most critical distribution circuits which include 28

those circuits with significant renewables penetration and energy storage. Sensors on 29

overhead distribution lines will be used to monitor the line conductor tension and determine 30


ground clearances and weather conditions to calculate the amount of current that can be 1

transmitted in real time. This information is then provided to system operators or engineers 2

for their use in safe, reliable and economic system operation. By monitoring wind speed, 3

conductor tension and solar heating, a real-time line rating that is indicative of current 4

conductor capability can be calculated. An advanced human interface will also be 5

developed to assist system operators with managing the information. 6

SDG&E has 995 distribution circuits, and high loading is anticipated on 1% of 7

circuits that will warrant close monitoring and dynamic line rating. Installing dynamic line 8

rating technology on 10 distribution circuits per year will result in the following cash flow. 9

10 Table TOB - 7 11

Renewable Growth, Dynamic Line Ratings Capital Expenditures 12 (Thousands of 2009 dollars) 13


Recorded 2010

Estimated 2011

Estimated TY2012


15

3. Renewable Growth: Phasor Measurement Units (PMU) - 16

Synchrophasors (Budget Codes: 10261) 17

A cost forecast is provided for implementation of phasor measurement units on the 18

electric distribution system. Installation of phasor measurement units on the electric 19

distribution system are expected improve reliability by employing high speed, time 20

synchronized measurement devices. These devices will be utilized in conjunction with 21

energy storage devices to create a closed loop control system to mitigate the impact of 22

intermittent renewables. Phasor measurement technologies are a leading example of a new 23

generation of advanced grid monitoring technologies that rely on high speed, time-24

synchronized, digital measurements. 25

Phasor measurement technologies will help mitigate the intermittency issues 26

associated with distributed renewables by employing high-speed, time-synchronized 27

measurement devices installed in substations and at key points on the distribution system. 28

Using time stamped, digitized waveform measurements, SDG&E can analyze the output of 29


PV systems, indentify changes in PV output and enable the dispatch of energy storage 1

devices to counteract the effects of the PV output fluctuation. 2

Phasor measurement technologies are also needed for understanding potential 3

problems with the grid and are therefore a key component of a stable, self-healing grid. As 4

the penetration of renewables increases, there will be increased voltage and phase-angle 5

fluctuations at various points on the system. PMU data can equip system operators with 6

better real-time information about actual operating margins so that they can better 7

understand and manage the risk of operating closer to the operating limits. Specifically, 8

some of the functionality enabled by PMU technologies include: 9

• monitoring and visualization for improved control room operations 10

• wide-area control and protection 11

• power system restoration 12

• time-synchronized, waveform measurements. 13

14

This project calls for the installation of PMU equipment on 11 distribution circuits 15

with a high penetration of PV: 4 circuits in 2011 and seven circuits in 2012. The equipment 16

will be installed at points on the circuit where there is significant aggregation of PV 17

systems. Additionally, a Phasor Data Collector (PDC) will be installed at each substation. 18

An assessment tool will be developed to provide the ability to record, archive, analyze and 19

display phasor data. The interconnection and link of PMUs into a network will bring time-20

synchronized data to a central location to create a wide-area view of the grid. 21

22

Table TOB - 8 23 Renewable Growth, Phasor Measurement Units Capital Expenditures 24



Recorded 2010

Estimated 2011

Estimated TY2012


27

28

29


4. Renewable Growth: Capacitor SCADA (Budget Codes: 10261) 1

A cost forecast is provided to implement SCADA control of all capacitors on 2

SDG&E’s distribution system and is distinct from the SCADA expansion for switches 3

discussed below. Benefits of SCADA for capacitors should include: better voltage and VAr 4

control, reduced maintenance, and better system diagnostics. When coupled with energy 5

storage, dynamic line ratings and phasor measurements new control schemes can be 6

implemented which will mitigate the impact of PV system output fluctuations on system 7

voltage. 8

SDG&E has been using SCADA (Supervisory Control and Data Acquisition) 9

controlled devices in various types of equipment for many years. SCADA controlled 10

capacitor banks will provide local and remote control, failure prediction and detection, 11

reduced operating cost, and should enhance distribution system performance through 12

improved voltage and reactive power control. As certain elements of Smart Grid evolve, 13

including less predictable DER, the ability to dynamically adjust reactive power flow will 14

become more critical. Presently, SDG&E discovers capacitor issues during the annual 15

capacitor survey or through customer voltage problems. SCADA controlled capacitors will 16

provide SDG&E the ability to be proactive in capacitor maintenance, instead of reactive. 17

Furthermore, SCADA control will provide a faster and more economical way to update the 18

software and to adjust control settings. 19

Installing SCADA on capacitor controllers will yield the following capabilities: 20

SCADA controls offer the ability to over-ride automatic controls of the bank to 21

adjust voltage or reactive support to the distribution system. Reprogramming capability may 22

reduce the need for future field visits by line personnel. 23

• SCADA controls can alert utility personnel of capacitor failures and/or 24

fuse operations. This will increase capacitor bank reliability, minimize 25

downtime, and expedite repair work. 26

• SCADA controls may be used to help facilitate the annual Capacitor 27

Survey for those sites that are on SCADA. 28

• SCADA provides for remote monitoring of the status of the control 29

devices for the bank. 30


• SCADA controls provide monitoring of all power system parameters 1

(i.e. voltage, current, reactive power, real power, power factor, etc…) 2

associated with the capacitor bank. This provides a key diagnostic tool 3

when power quality concerns arise. This is becoming more critical, as 4

the digital economy demands a higher level of power quality. 5

6

• Improved voltage and reactive power control to mitigate the impact of 7

distributed PV. 8

9

At this time there are 1,404 capacitors in the SDG&E service territory, 959 are 10

overhead capacitors and 445 are underground capacitors. The cash flow below reflects 11

adding SCADA to all these capacitors over a seven year period with the majority of work 12

taking place over the 2011-2016 period. 13

14

Table TOB - 9 15 Renewable Growth, Capacitor SCADA Capital Expenditures 16



Recorded 2010

Estimated 2011

Estimated TY2012


19

5. Renewable Growth: SCADA Expansion (Budget Codes: 10261) 20

A cost forecast is provided for expansion of SCADA to expand remote operability 21

and automated operation of distribution SCADA capable switches. This will continue 22

SDG&E’s goal of providing faster isolation of faulted electric distribution circuits and 23

branches, resulting in faster load restoration and isolation of system disturbances. 24

This project provides funding for the installation, upgrades, and expansion of the 25

Supervisory Control and Data Acquisition (SCADA) system at substations and on 26

distribution circuits through the addition of automated switches. SDG&E’s radial, open-27

loop distribution circuit design philosophy incorporates 1.5 SCADA switches per circuit: 28

one at the midpoint, and one at a strong tie. This design philosophy improves system 29

reliability while avoiding a full network design. 30


As the penetration of distributed renewables increases on the distribution system, 1

this SCADA expansion will allow SDG&E to re-configure circuits. By automatically re-2

configuring circuit the amount of PV and load can be balanced to better accommodate areas 3

of high PV penetration. 4

This will be incremental to work being done on existing budgets. In addition, to 5

fully realize the functionality of the line SCADA, the associated feeding substation needs to 6

be on SCADA as well. The scope of work required to achieve the capabilities above will 7

require installation of SCADA at 13 substations serving 76 circuits, and 281 SCADA 8

switches on circuits that lack SCADA line or SCADA tie switches. The cash flow below 9

reflects this scope of work being implemented over a five year period from 2012-2016. 10

Expenditures are expected to begin in 2012 as shown below. 11

12

Table TOB - 10 13 Renewable Growth, SCADA Expansion Capital Expenditures 14



Recorded 2010

Estimated 2011

Estimated TY2012

Estimated Category 1 $0 $0 $0 $5,964

17

6. Electric Vehicle Growth: Plug-In Electric Vehicles 18

This is project is required to upgrade primary and secondary voltage infrastructure to 19

accommodate the rollout of electric vehicles in San Diego County in the 2010, 2011 and 20

2012 timeframe. Transformers, secondary and primary conductors associated with 21

customers who participate in the Nissan Leaf and Chevrolet Volt rollout will be evaluated 22

for adequate capacity. If upgrades are required, they will be covered as part of this project. 23

These costs are incorporated in the testimony of Mr. Alan Marcher, Exhibit SDG&E-06. 24

Large numbers of PEV’s (both battery electric vehicles and plug-in hybrid electric 25

vehicles) are estimated to interconnect to the SDG&E grid over the next 10 years, requiring 26

improvements to the electric distribution system. This may also create opportunities in the 27

future to use PEVs as distributed energy resources by discharging their batteries into the 28

grid during times of system resource needs or economic benefit. The upgrade of services 29

and transformers resulting from residential PEV impacts to the grid occurring over the next 30


3 years (2010-2012) are included in associated capital projects of Mr. Alan Marcher as 1

mentioned earlier. Therefore the costs being included on this Smart Grid capital project 2

associated with impacts due to PEVs, in post test years, will cover distribution feeder 3

upgrades and infrastructure for larger public charging stations. The cost estimates for this 4

timeframe are based on a projection of 8300 residential charging stations and 328 public 5

charging stations 6

7

7. Electric Vehicle Growth: Smart Transformers (Budget Codes: 10261) 8

A cost forecast is provided for the installation of sensors and technology on 9

distribution transformers so that they can monitor and report loading, and the state of the 10

transformers. This project has the potential to allow increased transformer capacity 11

utilization and accommodate future loads such as plug-in electric vehicles. 12

Distribution line transformers can be converted into smart devices by installing 13

monitoring equipment on the secondary bushings. These monitors will provide information 14

to engineers and operators about the state of the grid including distributed resources and 15

loads at the location of the transformers. This data will be especially valuable for 16

monitoring the load and condition of transformers feeding plug-in electric vehicles. It will 17

also provide information about the state and condition of the transformer. Transformer 18

monitors will facilitate dynamic ratings for the transformers, the ability to verify energy 19

consumed or generated by new distributed resources or loads for potential management 20

applications, and the ability to assess detailed transformer conditions in order to proactively 21

troubleshoot customer or secondary voltage problems. 22

This project will install transformer monitoring devices on all transformers serving 23

customers with plug-in electric vehicles. Sensing devices attached to transformers will be 24

used to monitor real-time loading and establish accurate load profiles. This information will 25

be available to system operators to alert them to possible overloads, imbalances, voltage 26

excursions or other operational issues. Additionally, engineers will use this information to 27

revise transformer loading guidelines which may lead to optimizing the number of 28

customers that may be served from an individual transformer and reducing transformer 29

loading problems. 30


One transformer monitoring device will be installed on each distribution transformer 1

that serves a customer with a PEV and associated charge stations. The number of PEV 2

charge stations is anticipated to be: 3

4

Table TOB - 11 5 PEV Charging Stations 6

7

Year: 2010 2011 2012 Total

PEV Charge Stations: 600 2150 700 3450

8

This estimated number of charge stations is based on the expected sales of battery 9

electric vehicle and plug-in hybrid electric vehicle sales in the San Diego area. This 10

estimate is based upon a DOE sponsored program with partnership by ECOtality and Nissan 11

to deploy up to 5,000 electric vehicles and charging infrastructure in San Diego and four 12

other U.S. cities. 13

14

Table TOB - 12 15 Electric Vehicle Growth, Smart Transformers Capital Expenditures 16



Recorded 2010

Estimated 2011

Estimated TY2012

Estimated Category 1 $0 $0 $2,047 $521

19 8. Electric Vehicle Growth: Public Access Charging Facilities (Budget 20

Codes: 10261) 21

A cost forecast is provided for the installation of utility-owned, public access 22

charging facilities for electric vehicles. SDG&E will install and own the charging facilities 23

in under-served areas in order to broaden the coverage of public charging opportunities 24

within its service territory. This effort will allow SDG&E to continue the momentum of the 25

stakeholder charging facility siting and installation process established by ECOtality as part 26

of their government funded EV Project between 2010 and mid-2011. As planned, this 27

project will increase the number of charging facility services offered by 3rd parties, 28

specifically to provide PEV charging facilities in locations that are not necessarily 29


commercially or economically desirable, but needed to serve the broader and growing PEV 1

charging needs of the public. 2

3

Charging Facility Site Selection 4

SDG&E will work with the CPUC to develop broad criteria for evaluating the installation of 5

“public access charging facilities” with the objective to ensure a network of public charging facilities 6

is developed in the public interest over time that would provide sufficient support for the adoption and 7

use of PEVs. 8

As part of the selection process, SDG&E will use an independent entity to assist in the 9

development of site evaluation criteria to be used in a regional stakeholder charging facility site 10

selection process. The process will be led by an independent coordinating entity, such as the San 11

Diego Association of Governments, SANDAG. SDG&E will adapt the process that has been 12

successfully implemented in the deployment of charging facilities by ECOtality, under an ARRA, 13

DOE grant.13 Once ECOtality completes the charging facility installation portion of their EV Project 14

by mid-2011, SDG&E will continue to play a role in working with stakeholders to help determine the 15

location of the charging facilities that will have the least cost, least impact to the electric distribution 16

system. SDG&E will implement this service as part of a long-term process to extend the deployment 17

of public charging facilities as the growth of PEVs continues. 18

To support the development of electric vehicles and to engender the broad public benefits this 19

yields (lower GHG and other harmful emissions, improve local air quality, less reliance on foreign 20

oil), SDG&E will play an important role during the formative years of market development to ensure 21

that electric charging infrastructure develops which can support the rapid adoption of plug-in electric 22

vehicles. Also, because of their limited range, in order to foster market acceptance of these vehicles, a 23

seamless network of charging facilities will be needed. In order to ensure that this network of 24

charging infrastructure does not have significant voids, SDG&E proposes these "public interest" 25

charging facilities. 26

As a result of the development of a more robust availability of charging facilities, this effort 27

will also help to stimulate market growth for PEV related services and equipment in general, and 28

specifically in under-served areas. Although SDG&E will own these charging facilities, it will also 29

contract with 3rd parties to build, operate and maintain the charging facilities. This approach will help 30

13 http://www.ecotalityna.com/pdf/100109_eTec_DOE_Contract.pdf


sustain the PEV related market growth momentum achieved during the ECOtality charging facility 1

deployment. 2

3

Potential Targets Sites or Example Locations 4

• Public parks or sports facilities 5

• National and State Parks and recreation areas (e.g., Level 2 chargers placed at “destination” 6

sites) 7

• Low income neighborhoods 8

• Rural roadside locations or rest stops along highways 9

• Government buildings (i.e., for vehicles owned by the general public) 10

• Densely populated urban areas 11

• Various “trip continuation” locations 12

• Other areas lacking PEV facilities available to the general public where locating a charging 13

facility would be in the public interest and would fill a gap in charging infrastructure (e.g., DC 14

Fast Charge facilities placed at “way-points” on the way to destinations (trip continuation 15

chargers) 16

17

Given the complexity and installation diversity of serving the PEV charging needs of the those 18

in Multi-Unit Dwellings, MUD, SDG&E will request that street-side and public access areas adjacent 19

to MUD facilities be included in the target locations for this offering (note that among all SDG&E 20

residential customers, about 20% are MUDs with 2 to 19 units, and over 13% are MUDs with 20 units 21

or more). 22

The number of 240 V Level 2 charges installed will be approximately 1% of the cumulative 23

plug-in hybrid electric vehicles, PHEVs, anticipated in the 2012 through 2015 period, and the number 24

of DC Fast Chargers will be approximately 0.1% of the cumulative PHEVs in the 2012-2015 period 25

(see table below). PEV charging facility users will pay for the use of these charging facilities through 26

an applicable PEV tariff that will be developed in accordance with policy established in the CPUC’s 27

Alternative Fueled Vehicle OIR, R.09-08-009. 28

29

Table TOB – 13 PEV Charging Needs 30

31 Year: 2010 2011 2012 Total


240V Level 2 Charge Stations 0 0 129 129 480V DC Fast Charger Stations: 0 0 13 13

1

The cash flow below reflects the public access charging facilities funding requirements for the 2

entire SDG&E system taking place over a three year period (2010-2012) with the work taking place in 3

2012. 4

5

Table TOB - 14 6 Electric Vehicle Growth, Public Access Charging Facilities Capital Expenditures 7



Recorded 2010

Estimated 2011

Estimated TY2012


10 9. Reliability: Wireless Fault Indicators (FCI) (Budget Codes: 10261) 11

A cost forecast is provided for implementation of wireless faulted circuit indicators. 12

This system is expected to provide rapid identification and location of faulted distribution 13

circuits resulting in reduced outage and repair times. 14

Fault Circuit Indicators, FCI, provide detection and indication of electrical faults in 15

the electric power distribution networks of the utility. The status of the indicators (tripped 16

or reset) must currently be checked by visual inspection. Currently it takes a considerable 17

amount of time to drive to the field, patrol the line to find the tripped fault circuit indicator 18

and repair the line. 19

Using wireless FCIs to monitor lines, fault locating can be more efficient and 20

accurate due to more rapid pinpointing of line faults. When coupled with last gasp meter 21

notification sent through the advanced metering infrastructure system, the fault indicator 22

information communicated to distribution system operators will allow them to dispatch 23

electric troubleshooters closer to the exact fault location to more quickly identify and isolate 24

the fault and begin service restoration. 25

The new FCIs should also reduce the need to open manholes, handholes or vaults to 26

check the status of the fault indicator. These substructures may be in high traffic areas 27

where access and traffic control is a problem. Also the substructure may be full of water 28


which might require that the water be pumped out to be able to check the status of the 1

indicator. This should help maintain overall service reliability by providing more accurate 2

information and reducing the time it takes to isolate a fault and begin service restoration. 3

The new wireless FCI system can provide central monitoring with minimal wireless 4

infrastructure, fostering Smart Grid functionality. 5

New fault indicators are employing wireless communications technologies to 6

remotely monitor the status of the FCI. This new wireless technology has proven itself 7

capable of communicating with devices on overhead and underground systems. This 8

project will install wireless FCIs on all non-SCADA switches and all cable poles with 9

switches in the distribution system over a five year-period (2011-2015). 10

11

12 13

Table TOB - 15 14 Reliability, Wireless Fault Indicators Capital Expenditures 15



Recorded 2010

Estimated 2011

Estimated TY2012


18

10. Reliability: Phase Identification (Budget Codes: 10261) 19

A cost forecast is provided for accurate identification of phasing for implementation 20

in the new distribution operating system. This project should enable improved worker 21

safety, more accurate fusing, improved system planning, and reduced system losses. 22

Correct identification of the phases of an electrical system is a critical element of the 23

operation and management of a distribution system. Phasing information affects real-time 24

and planned operations of the system. Capturing and maintaining phasing information will 25

maximize the functionality of the new Distribution Management System and Smart Meters 26

by creating accurate models to analyze the operation and events within the distribution 27

system. Identifying the phase to which each transformer is connected, allows for a more 28

accurate model and provides a clear decision for adding new single phase loads to a circuit. 29

From a safety perspective, it is important to identify the phase of each conductor on 30

a three-phase feeder as well as the individual phases on single-phase branches. Having all 31


phases identified gives the Distribution Operator and the Troubleshooter better information 1

about which lines may present a hazard during an outage situation. 2

An electrical system that captures and maintains accurate phase information 3

provides for the following functionality: 4

• Safety - Better identification of energized and de-energized phases 5

during an outage 6

• Tie Switch - Promotes safe use of tie switches 7

• Fusing - More optimal sizing of fuses to match the load on each phase 8

• System Planning (circuit capacity sizing) - Ability to more accurately 9

model the feeder and branch loads 10

• Outage Analysis - Clearer identification of the transformers and 11

customers affected by a single-phase outage 12

• DMS (Smart Grid) - Load transfer, Load balancing, DER operation 13

• System Protection - Refined settings to further mitigate fire risk 14

• Loss reduction - Reduce losses by identifying and balancing more 15

single-phase loads 16

17

The cash flow below reflects phase identification for the entire SDG&E system 18

taking place over a three year period (2011-2013) with the majority of work taking place in 19

2012 and 2013. 20

21

Table TOB - 16 22 Reliability, Phase Identification Capital Expenditures 23



Recorded 2010

Estimated 2011

Estimated TY2012


26

11. Reliability: Condition Based Maintenance (CBM) Expansion (Budget 27

Codes: 10261) 28


A cost forecast is provided for expansion of CBM to include distribution substation 1

transformers at 4 kV substations. This project should reduce the risk of catastrophic failures 2

and improve customer satisfaction 3

This project provides funding for the installation, upgrades, and expansion of the 4

CBM capabilities at 4 kV substations and further 4 kV to 12 kV conversions. The current 5

Op-Ex 20/20 initiative14 does not address the installation of CBM equipment at these 6

locations. There are currently 50 power transformers residing at 39, 4 kV substations, the 7

majority of which are in poor condition and are more than 40 years old. 8

This funding will be incremental to planned work on other blanket budgets that are 9

used for converting substations from 4 kV to 12 kV. Existing blanket budget funding is 10

inadequate to convert all of these substations; therefore, some 4 kV substations will remain 11

in-service for many years. This project funds addition conversion work and an expansion of 12

CBM to ensure monitoring equipment is installed at strategic locations that will not be 13

converted so that near real-time condition assessments can be performed on these assets. 14

15

The scope of work required to achieve the near real-time condition assessments will 16

require adding CBM at nine, 4 kV substations, and converting another nine substations to 17

12 kV. The cash flow below reflects this work taking place primarily over a five year 18

period from 2012-2016. 19

20

Table TOB - 17 21 Reliability, CBM Expansion Capital Expenditures 22



Recorded 2010

Estimated 2011

Estimated TY2012

Estimated Category 1 $0 $0 $0 $752

25

26

27

28

14 See the testimony of Mr. Richard Phillips, Exhibit SDG&E-19 and Mr. Alan Marcher, Exhibit SDG&E-06.


12. Smart Grid Development: Integrated Test Facility (Budget Codes: 10261) 1

A cost forecast is provided to construct facility upgrades and purchase and install 2

equipment to create an integrated test facility. This will allow testing of the integration of 3

multiple complex hardware and software systems comprising Smart Grid technologies. 4

Smart Grid technologies, communications and systems are rapidly evolving or in 5

some cases do not yet exist. The National Institute of Standards and Technology, NIST, is 6

currently working on consensus standards. New product and services are also being 7

developed. In parallel SDG&E is rolling out its advanced metering infrastructure. It is 8

critical that these new systems and standards allow for interoperability between products. 9

As it develops, the Smart Grid will require the integration of multiple complex 10

hardware and software systems. As part of the effort to integrate technologies to improve 11

electric power systems’ reliability and efficiency, facilities, systems, and personnel will be 12

required to test their interoperability, functionality and effectiveness in meeting 13

requirements. Leveraging space at an existing SDG&E building, the project will implement 14

necessary upgrades and equipment to create an integrated test facility. 15

16

The project will implement necessary upgrades and equipment to create an 17

integrated test facility. The cash flow below reflects constructing this facility primarily over 18

a two year period from 2011 to 2012. 19

20 Table TOB - 18 21

Smart Grid Development, Integrated Test Facility Capital Expenditures 22 (Thousands of 2009 dollars) 23


Recorded 2010

Estimated 2011

Estimated TY2012


25

IV. CONCLUSION 26

The Commission has determined in D.10-06-047 the rules by which Smart Grid deployment 27

plans as envisioned by SB17 will be would be vetted. The Commission has recognized the need for 28

funding requests both in the course of general rate cases as well as special applications, and directed in 29


that same decision that utilities may include cost forecasts for Smart Grid development in future 1

GRCs. As noted in the decision: 2

“Finally, we agree that Smart Grid investments may be best considered in rate cases and prefer 3

that IOUs propose Smart Grid investments as part of their GRCs.”15 4

also 5

“Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas 6

& Electric Company each shall seek approval of Smart Grid investments either through an 7

application and/or through General Rate Cases.”16 8

9

SDG&E’s preliminary list of Smart Grid projects as proposed in this application are needed to 10

empower consumers while addressing the impact of renewables and PEVs on the grid, while 11

simultaneously maintaining and/or improving reliability. An integrated test facility is required to test 12

standards, interoperability and functionality of future Smart Grid technologies and systems. I 13

respectfully request the Commission adopt the cost forecasts for SDG&E’s Smart Grid development 14

as described in this testimony. 15

This concludes my prepared direct testimony. 16

17

15R.08-12-009, Order Instituting Rulemaking to Consider Smart Grid Technologies Pursuant to Federal Legislation and on the Commission’s own Motion to Actively Guide Policy in California’s Development of a Smart Grid System, D.10-06-047 (Decision Adopting Requirements For Smart Grid Deployment Plans Pursuant To Senate Bill 17 (Padilla), Chapter 327, Statutes Of 2009)., pg. 114. 16 Ibid, Ordering Paragraph 14, pg. 114.


V. WITNESS QUALIFICATIONS 1

My name is Thomas O. Bialek, Ph.D., P.E.. My business address is 8316 Century Park 2

Court, San Diego, California 92123. I am employed by San Diego Gas & Electric Company 3

("SDG&E") as a Chief Engineer in SDG&E’s Smart Grid Initiative. My present responsibilities 4

involve developing strategy and policy with regards to T&D Smart Grid initiatives. These 5

activities generally include technical review, policy development and strategic planning of 6

transmission and distribution systems. I am also responsible for the preparation of exhibits and 7

proposals for regulatory proceedings in the Smart Grid areas. 8

I have been employed by SDG&E since 2000 and have held various positions with other 9

North American utilities and equipment manufacturers subsequent to that time. My experience 10

includes electric utility design, planning & operation, and equipment design, development and 11

manufacturing. 12

I received a Bachelor and Master of Science and Degrees in Electrical Engineering from the 13

University of Manitoba in 1982 and 1986 respectively. I received my Ph.D. in Electrical Engineering 14

from Mississippi State University in 2005. I am a registered Professional Engineer, Electrical 15

Engineering, in the State of California. 16

I have previously testified before the California Public Utilities Commission. 17

18