Application No.: Exhibit No.: SCE-03, Vol. 1 Witnesses: D. Mead

(U 338-E)

2015 General Rate Case

Transmission and Distribution (T&D) Volume 1 - T & D Policy

Before the

Public Utilities Commission of the State of California

Rosemead, CaliforniaNovember 2013

SCE-03: Transmission and Distribution Volume 01 – T&D Policy Overview

Table Of Contents

Section Page Witness

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I.  INTRODUCTION .............................................................................................1 D. Mead 

A.  Our Operations Are Driven By Three Fundamental Priorities .................................................................................................3 

1.  SAFETY – “Be Safe” ................................................................3 

a)  Underground Structures Inspection and Replacement ...................................................................5 

b)  Pole Loading Assessment and Remediation ..................6 

2.  RELIABILITY – “Keep The Lights On” ..................................8 

a)  SCE Needs to Operate and Maintain a Grid That is Simultaneously Expanding, Getting Older, Becoming More Complex, and Facing More Regulatory Requirements .........................8 

b)  We Have an Obligation to Serve Our Existing Customers as Their Electricity Usage Increases, Provide Services to New Communities, and Adapt Our Grid to Meet California’s Policy Goals ...............................................9 

c)  SCE Is Committed to a Reasonable Program to Replace Distribution Infrastructure to Support Reliability and Reduce Overall Customer Costs ..............................................................9 

3.  AFFORDABILITY – “Spend Our Customers’ Money Wisely” ........................................................................11 

a)  Management Has to Prioritize and Shift Funds to Meet Authorized Rate of Return and Maintain Adequate Service Levels .......................12 

b)  We Implemented Improved System Planning Methodologies to Minimize Capital Expenditures on Load Growth and Better Leverage Past Investments ................................12 

SCE-03: Transmission and Distribution Volume 01 – T&D Policy Overview

Table Of Contents (Continued)

Section Page Witness

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c)  We Evaluated Our Processes for Executing Work to Improve Throughput and Quality ..................13 

II.  ANALYSIS OF T&D O&M EXPENSES AND CAPITAL EXPENDITURES ............................................................................................15 

A.  O&M Expenses ....................................................................................15 

B.  Capital Expenditures ............................................................................18 

C.  T&D Testimony Organization .............................................................22 

III.  REGULATORY MECHANISMS FOR RELIABILITY AND SAFETY PROGRAMS ...................................................................................23 

A.  Reliability and Safety Investment Mechanism ....................................23 

1.  Background ..............................................................................23 

2.  Proposal....................................................................................24 

a)  Infrastructure investment .............................................24 

b)  Critical Workforce .......................................................26 

B.  Pole Loading Balancing Account ........................................................28 

IV.  CONCLUSION ................................................................................................30 

Appendix A Witness Qualifications ................................................................................ 

SCE-03: Transmission and Distribution Volume 01 – T&D Policy Overview

List Of Figures

Figure Page

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Figure I-1 Southern California Edison Service Territory ............................................................................2 

Figure I-2 T&D Safety Metrics, 2008-2013 ................................................................................................4 

Figure II-3 T&D O&M Expenses for 2012 – Authorized versus Recorded (2012 constant

$millions, CPUC and FERC jurisdictional costs) ................................................................................15 

Figure II-4 T&D O&M Expenses 2008-2012 Recorded Adjusted/2013-2015 Request

(2012 Constant $million, includes FERC and CPUC jurisdictional costs) .........................................16 

Figure II-5 2015 T&D O&M Expense Request By Work Category (2012 Constant

$millions) .............................................................................................................................................17 

Figure II-6 T&D Capital Expenditures for 2012 – Authorized versus Recorded

($millions, CPUC-Jurisdictional costs only) .......................................................................................18 

Figure II-7 T&D Capital Expenditures 2008-2012 Recorded and 2013-2017 Forecast

($million, includes CPUC-Jurisdictional costs only) ...........................................................................19 

Figure II-8 Total 2013 to 2017Capital Expenditure Forecast by Work Category $millions

(includes CPUC-Jurisdictional forecasts) ............................................................................................20 

SCE-03: Transmission and Distribution Volume 01 – T&D Policy Overview

List Of Tables

Table Page

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Table I-1 SCE Key Physical Assets Owned And Operated by T&D ..........................................................1 

Table II-2 Capital Expenditure by Major Work Categories 2008-2012 Recorded/2012

Authorized/2013-2017 Forecast (Nominal $millions, CPUC-Jurisdictional only) .............................21 

Table II-3 Request by Testimony and Witness Includes CPUC and FERC Jurisdictional

Costs .....................................................................................................................................................22 

Table III-4 2015 RIIM Categories and Capital Expenditure Forecasts .....................................................25 

Table III-5 2015 RIIM High-Priority Categories and Capital Expenditure Forecasts ...............................26 

Table III-6 RIIM Workforce Classifications .............................................................................................27 

1

I. 1

INTRODUCTION 2

SCE’s Transmission and Distribution (T&D) is responsible for planning, engineering, 3

constructing, operating, and maintaining transmission and distribution facilities required to safely and 4

reliably deliver electricity to SCE’s five million customers throughout our 50,000 square-mile service 5

territory. 6

Figure I-1 below is a map of our service territory. It is quite diverse, stretching from the cooler 7

coast areas bordering the Pacific Ocean to the hot and dry inland deserts; from the agricultural areas of 8

California’s central valley to the densely populated urban areas of Los Angeles and Orange counties. 9

T&D is the steward of a vast infrastructure of assets – about $19 billion worth. Roughly $12 10

billion of this amount is for distribution assets, $5 billion for substation assets, and $2 billion for 11

transmission assets. 12

Table I-1 SCE Key Physical Assets Owned And Operated by T&D

Asset Type Count (as of 12/31/2012)Transmission Lines 12,782 milesDistribution Lines 90,401 milesSubstations 844Poles 1,433,336Substation Transformers 2,959Distribution Transformers 720,800Underground Structures 413,220Underground Distribution Cables 50,179 milesStreetlights 704,592

Table I-1 above summarizes some of the key assets that SCE owns and operates. The costs 13

related to the bulk transmission system are, for the most part, recovered through rates set by the Federal 14

Energy Regulatory Commission (FERC). All other costs fall within the jurisdiction of this Commission. 15

To operate and maintain this large and complex system, T&D employs almost 8,600 dedicated 16

men and women, including over 1,400 contract employees and 700 contract crew personnel, making it 17

SCE’s single largest operating unit. 18

2

Figure I-1 Southern California Edison Service Territory

3

A. Our Operations Are Driven By Three Fundamental Priorities 1

I have worked with T&D leadership teams to provide our workforce with clear and 2

straightforward guidance regarding the priorities that must drive our work every day. While there are 3

thousands of complex tasks to be performed for the benefit of our customers, we believe that they can all 4

be captured within three areas of focus – safety, reliability, and affordability. We layer onto these three 5

areas of focus the cornerstone values of compliance and operational excellence. These concepts 6

represent the foundation for all of the decisions we make and actions we take within T&D. 7

1. SAFETY – “Be Safe” 8

Safety is our first priority when we make decisions on what to do and how to do it. Our 9

field forces build, operate, and maintain high voltage equipment every day. Often, they must work only 10

inches from equipment or hazards that can cause serious injury or worse. In fact, much of the 11

distribution work they do today uses high voltage rubber gloves, allowing them to work directly with 12

energized conductors. They heroically work through storms, fires, and all manner of other challenges, 13

sometimes around the clock. Our goal every day is to send each employee back to his or her family safe 14

and sound. In the last several years we have not met this important objective nearly as well or 15

consistently as we should have. We have had far too many employee injuries in T&D, and my senior 16

leadership team and I consider this to be unacceptable performance. 17

As a consequence, we have increased our focus on doing everything we can to improve 18

and sustain our safety record. We have been able to achieve some modest improvements, as shown 19

below in Figure I-2. For example, the change in the DART injury rate1 of 4.46 in 2008 to 2.32 by April, 20

2013 represents almost a 50 percent improvement. This is a job that never ends, and no other goal ever 21

takes priority over safety. Mr. McDonald discusses our safety programs in detail in Exhibit SCE-03, 22

Volume 9. 23

1 The Days Away, Restricted, or Transferred (DART) Rate is the incident rate explaining the frequency of occurrence of

injuries or illnesses that result in days away, job restrictions, or transfers. This rate is intended to roughly provide the number of employees out of one hundred experiencing this type of injury. The mathematical expression for this ratio is: (# of DART Injuries X 200,000) / Actual Work Hours = DART Injury Rate.

4

Figure I-2 T&D Safety Metrics, 2008-2013

 

This very same concern and rigor we apply to employee safety are applied to public 1

safety. Members of the public, whether our customers or not, rely each day on electricity to power 2

critical needs in their lives and businesses. In a very real sense, reliability equates directly to safety, 3

since it is the power we deliver that keeps the traffic lights, police and fire stations, hospitals, and 4

schools up and running safely. The public also relies on us to see that our facilities and work practices 5

do not expose them to unreasonable risks. This means: 6

Monitoring the system to avoid outages; 7

Restoring power as efficiently as possible; 8

Proactively and efficiently replacing failing equipment; 9

Inspecting and maintaining equipment in a safe condition; 10

Designing system components so they are safer to work on in the first place; and 11

Maintaining a focus on keeping the work area safe when we are close to where people 12

live, play, learn, or drive. 13

5

For example, given the potential impact of downed wires on the public, we have started a 1

program to evaluate splice, connector, and overhead conductor strength, and assess the impact of 2

operational, environmental and mechanical conditions on the integrity of these critical components. As 3

with employees, public safety is, and must be, an overarching consideration in all we do. 4

SCE seeks to continuously improve its existing safety programs and to add new programs 5

to address emerging risks. Those improvements often come as a result of discussions – both formal and 6

informal – with regulatory agencies that have jurisdiction over SCE’s facilities and operations. For 7

example, SCE has improved its pole loading processes and procedures, and has designed a program to 8

inspect poles for compliance to minimum loading requirements and to perform remediation as 9

necessary. These refinements were guided by the discussions arising out of the Infrastructure Safety 10

Rulemaking (R.08-11-005). 11

In 2009, based on field and engineering observations, SCE also increased its inspections 12

of underground structures to include those structures that do not appear to have equipment. We have 13

disclosed this to regulators in our GO 165 report and have had discussions with SED engineers. 14

Through those inspections, we identified a number of structures in our territory that showed various 15

degrees of deterioration. We have designed a program to address the volume of structures in need of 16

replacement. Both of these programs are described further in the sections below. Improvements to the 17

Rule 21 generator interconnection process also benefited greatly from the involvement of dedicated 18

CPUC staff with knowledge of the FERC processes. 19

Other program changes and improvements have resulted from engagement with the 20

California Independent System Operator (CAISO), CalFire, North American Electric Reliability 21

Corporation (NERC), and Western Electricity Coordinating Council (WECC), including changes and 22

updates to our vegetation management program. SCE values the expertise and dedication to safety that 23

its regulators bring to these discussions. We look forward to continuing our program improvements 24

with input from the regulators who oversee our operations. 25

As mentioned above, I would like to highlight two programs that are directly driven by 26

employee and public safety concerns. 27

a) Underground Structures Inspection and Replacement 28

In 2009, SCE undertook an Underground Structure Inspection project to assess 29

the condition of vaults and manholes that do not fall under the GO 165 inspection criteria. The vaults 30

and manholes did not come under GO 165, primarily because they did not house electrical equipment. 31

6

To date, we have identified that over 400 of these structures must be repaired or 1

replaced due to deterioration of the structure itself. The deterioration is caused primarily by age and 2

water intrusion resulting in exposed reinforcing bar, crumbling concrete, etc. The list of vaults that 3

require attention continues to grow as our inspection programs and detailed field investigations continue. 4

In its Test Year 2012 GRC, SCE anticipated the need for increased structure replacements, and had 5

requested 50 structure replacements per year. Since then, the number of structures identified as 6

requiring repairs or replacements has grown significantly. The considerable lead times required to plan 7

and obtain the necessary permits for the repair and replacement work have necessarily delayed our 8

ability to execute all of the planned work in 2011 and 2012. We have created a targeted program, 9

commencing in 2013, that has accelerated the rate of repairing and replacing the structures, in order to 10

reduce the backlog. 11

We are mindful of the impact on ratepayers if we replace all deteriorated vaults 12

when we find them. But we are also acutely aware of the reliability and safety implications of not 13

making sufficient progress in addressing the deteriorated vaults. We are prioritizing the work based on 14

location, age and construction of the structures, and we propose replacing approximately 1,000 15

structures over the next five years. This will reduce the backlog to approximately 300 deteriorated 16

structures. We respectfully urge the Commission to authorize funding for this work. 17

b) Pole Loading Assessment and Remediation 18

SCE has more than 1.4 million poles in its transmission and distribution system. 19

The average service life of these poles is 45 years.2 To maintain a steady state replacement, we should 20

be replacing over 31,000 poles every year. Instead, we replace approximately 14,000-18,000 poles each 21

year as part of various programs. Approximately half of these poles replacements are based on GO 165-22

driven pole inspections. We also replace poles as part of routine maintenance, such as when they are 23

physically damaged by vehicles, or when the pole has to support heavier equipment. In the last five 24

years, we have replaced approximately 8,000 poles per year (on average) as a part of these programs. 25

This is simply not enough. 26

In the past, we have restricted deteriorated pole assessments to the levels required 27

to meet GO 165 compliance. This model cannot continue in the future. If it does, very soon we will be 28

facing the prospect of having to replace very large numbers of poles in a very short period of time. 29

2 See Exhibit SCE-10, Volume 2.

7

In addition, recent events have highlighted the need to revisit how well the poles 1

in our system meet pole loading safety standards.3 Poles that do not meet minimum requirements may 2

break or fail at wind speeds that are below the expected for that geographic location. This results in an 3

increased risk to reliability and public safety. When we assessed a sample of poles using modern 4

methods for calculating the safety factor, SCE found that a percentage of in-service poles did not meet 5

the required GO 95 safety factors, even when deterioration is excluded from the calculation. 6

Over time, several factors have contributed to poles not meeting the adequate 7

safety factors – growth in electric and telecommunications infrastructure resulting in additions to pole 8

attachments, unauthorized attachments, changes in pole-loading methodology and design standards, and 9

new technology for pole loading assessments. 10

SCE is committed to addressing this issue on behalf of our customers and the 11

public. Poles are found along streets, in front of homes, and close to public places. They support 12

energized conductors, transformers, and other equipment. A fallen pole can result in substantial safety 13

and reliability risks. We want to take reasonable actions to minimize those risks. 14

The Commission has acknowledged the pole loading issue.4 We have undertaken 15

a multi-year program to evaluate all SCE poles for pole loading factors by year 2020, and perform the 16

necessary remediations by 2025. Mr. Trainor discusses this program in greater detail in Exhibit SCE-03, 17

Volume 6, Part 2. The Commission should authorize the funding needed for this important program. 18

The Commission has repeatedly recognized the importance of safety in the work 19

we do and the obligations we have to serve. We actively work with regulatory agencies to address 20

safety challenges. Doing things safely is always the right thing to do – but in some instances, 21

particularly in the short run, it may not be the cheapest thing to do. It not only requires complying with 22

safety regulations, training employees properly, fully analyzing incidents, and implementing safety 23

procedures, but also inspecting, maintaining, replacing and upgrading the infrastructure. Throughout the 24

volumes of T&D’s testimony in this GRC, you will read numerous examples about how safety affects 25

our operations and our costs. For example, in Exhibit SCE-03, Volume 9, Mr. McDonald discusses our 26

3 General Order 95 specifies that at the time of installation, a newly-constructed utility pole containing both electric and

communications equipment (known as Grade A or a combination pole) must be built with a safety factor of 4.0. Once the pole is in-service, General Order 95 specifies that Grade A poles must be replaced before the safety factor falls below 2.67 as a result of pole deterioration or as a result of the addition of facilities or attachments to the pole.

4 D. 12-11-051, pp. 181-182.

8

safety and training activities. Mr. Grigaux discusses how our troublemen support public safety as first 1

responders during times of emergency in Exhibit SCE-03, Volume 7. 2

2. RELIABILITY – “Keep The Lights On” 3

This is our core business. We exist to provide the lifeblood that modern society relies on 4

– to power people’s homes, businesses, community centers, hospitals, schools, streets, phones, 5

computers, and now their cars. We have to maintain, renew, and expand our system in reasonable 6

fashion based on the needs of our customers so that we can provide them adequate service. We have 7

several rigorous programs aimed at reducing the number of unplanned outages through inspection and 8

preventive maintenance, predictive engineering analyses, and proactive grid upgrades. We cannot 9

prevent every equipment breakdown (and the resulting outages) given the age of our system and the 10

impact of outside factors like weather. We work hard at restoring power as quickly as possible through 11

more automation, greater ability to isolate equipment failures from the rest of the system, and faster field 12

response. 13

a) SCE Needs to Operate and Maintain a Grid That is Simultaneously 14

Expanding, Getting Older, Becoming More Complex, and Facing More 15

Regulatory Requirements 16

SCE’s electrical equipment, and structures that house or support them, undergo 17

regular inspection to detect degradation or potential malfunction. We perform preventive maintenance 18

based on the priority assigned to the results of the inspections. All our field personnel are trained to 19

notice potential problems that can lead to safety or reliability issues, and repairs and replacements are 20

sometimes driven by issues that crews and supervisors discover in the field outside the inspection 21

programs. 22

Details of our inspection programs can be found in Exhibit SCE-03, Volumes 6 23

and 8. The cost of inspections has increased as we have more assets to inspect and more regulations to 24

comply with. At the same time, repair expenses and replacement expenditures are increasing, as our 25

system continues to deteriorate faster than we can renew it. 26

Our greatest asset to meet customer expectations is our people. We need system 27

operators to monitor the grid and detect problems prior to or soon after an outage; we need troublemen 28

to respond to these situations, isolate the problem, and restore power if possible; and we need crews to 29

inspect and maintain the equipment and structures. Maintaining an appropriately-sized and reasonably 30

9

well-trained workforce, one that can keep up with the size, health, and complexity of the grid, is 1

essential to safe and reliable service. 2

b) We Have an Obligation to Serve Our Existing Customers as Their Electricity 3

Usage Increases, Provide Services to New Communities, and Adapt Our Grid 4

to Meet California’s Policy Goals 5

As new communities are built in our service territory, we have to construct 6

infrastructure to get the power to all parts of the community. This requires new lines to bring in power 7

from the transmission grid, substations to transform it to appropriate voltages, and new circuits and 8

distribution facilities to get the power to where it is needed. As electricity needs increase in existing 9

communities, we have to upgrade and add to our facilities to make sure we are ready to handle the 10

increased load. This can be as discrete a job as replacing a small distribution transformer with a larger 11

one, which will require a larger pole. Or it can be as big a job as increasing the transformer capacity of 12

an entire substation from 28MVA to 56MVA, or building a new substation. 13

Additionally, as California marches towards renewable generation and Renewable 14

Portfolio Standards, utilities have to invest in building new transmission lines interconnecting the 15

generation to the rest of the grid, and update the flexibility of the grid to detect issues, contain problems, 16

and allow for alternate paths for electrical flow during emergent conditions. These needs are immediate, 17

and these activities require funding. We discuss this in greater detail in Mr. Ferree’s testimony in 18

Exhibit SCE-03, Volume 5, and Mr. Woods’ testimony in Exhibit SCE-03, Volume 3. 19

c) SCE Is Committed to a Reasonable Program to Replace Distribution 20

Infrastructure to Support Reliability and Reduce Overall Customer Costs 21

The equipment and structures that make up our electric system continue to age 22

every day. All infrastructure, no matter how robust, has a finite life expectancy, and must be replaced 23

eventually. A significant portion of SCE’s distribution infrastructure was constructed in the years 24

immediately following World War II, when Southern California experienced unprecedented growth. 25

This growth drove the development of large and vibrant suburban communities in areas which were 26

once farmland, orchards, or simply open space. In these new communities, SCE installed the essential 27

electrical facilities needed to provide electrical service to families and businesses in the 1950s and 28

1960s. Those facilities, however, have now reached or exceeded the ends of their useful lives. 29

Like most American utilities, we have managed our assets to get the most use out 30

of them before replacing them. For equipment that has lower public or employee safety implications, 31

10

getting the most out of the equipment means “run to failure.” For other equipment, we must use 1

standard maintenance techniques to assess, test, and predict equipment failure as close to “end of life” as 2

we can. In some instances, it is easy to be somewhat nearsighted, since the failure rate will not increase 3

in the immediate future. Prior to 2009, our replacement rate was curtailed due to lack of funding, lack of 4

resources, emergence of shorter-term priority work (such as higher customer growth), or some 5

combination of all three factors. Eventually, however, the probability and incidence of failures spiral 6

upward. On our system, the probability of failure of key assets over the next several years is increasing, 7

and if we do not continue to aggressively address proactive infrastructure replacement, it will be 8

impossible for us to keep up with asset failures and breakdowns in the future. 9

The basic concept we follow is fairly straightforward: accurately predicting 10

failure of components allows replacement before failure. Replacement before failure improves safety as 11

the consequences of failure can be dangerous either directly – as in a vault explosion – or indirectly, as 12

in the case of traffic signals that don’t work. Replacing equipment before failure also improves 13

customer service. Unplanned outages usually last longer and are more disruptive to customers’ lives 14

than planned outages. Finally, replacement before failure reduces total costs. It allows us to optimize 15

scheduling and implement longer-term fixes. This also helps eliminate consequential damages to nearby 16

or connected components that are in acceptable shape. 17

I would like to highlight one area that we are particularly focusing on in our 18

operations in the coming years – underground cables. 19

Our distribution system has over 50,000 conductor-miles5 of underground primary 20

cable. This cable is aging and an increasing volume is reaching the end of its service life each year. 21

Over 9,700 conductor-miles of cable are already older than their mean time to failure, with 22

approximately 700 more miles on average being added to that each year. Of particular concern to us is a 23

portion of our cable population of a type of construction known as cable-in-conduit, or CIC. This type 24

of cable, constituting about 25 percent of our cable population, is especially difficult to replace. Failures 25

of CIC typically result in outages lasting over 20 hours. Without increased investment in the preemptive 26

replacement of cable, in-service failures will result in a significant decline in our system reliability. 27

5 The term conductor-miles refers to length of physical cable installed. A mile of conduit housing a three-phase

underground cable will translate to three conductor-miles of cable.

11

From 2009 to 2012, we asked this Commission for funding to replace nearly 1

1,000 miles of cable. The Commission authorized 440 miles (with a relatively large increase in year 2

2012,6 where the Commission recognized the issue and SCE’s commitment to solving it). SCE has 3

replaced over 900 miles of cable between 2009 and 2012, despite the disallowances in the 2009 GRC, 4

because we think this is important for maintaining long-term service reliability. In the current GRC, we 5

are requesting funding to replace over 2,000 miles of cable in total between years 2013-2017. Mr. Lee 6

discusses this in further detail in Exhibit SCE-03, Volume 4. 7

We view this as a difficult choice the Commission must make to protect the long-8

term health of the system. We are fully cognizant of what our request means for ratepayers, and the 9

challenge it poses for us to get the work done. But this work cannot be avoided. It can be performed in 10

planned conditions at a controlled rate, or can be performed under emergency conditions with unplanned 11

outages and higher costs. 12

3. AFFORDABILITY – “Spend Our Customers’ Money Wisely” 13

We have an obligation to spend the money we collect in rates in an appropriate manner. 14

It is our responsibility to: 15

Prioritize the work to meet ratepayer requirements; 16

Identify reasonable-cost options; 17

Closely monitor the expenditures, schedules, quality, safety and compliance of our 18

actions; and 19

Correctly record and report our expenditures and expenses. 20

We have renewed our focus on operational excellence – specifically as it relates to prioritizing work, 21

and improving productivity. 22

We recognize that our request is substantial. But through operational excellence, we are 23

proactively evaluating all aspects of our operations to incorporate changes that can enable the work to be 24

performed more effectively and efficiently, within the immovable constraints of safety and compliance. 25

We continue to impose additional rigor around work prioritization to facilitate the thoughtful use of 26

limited funding and labor resources. In addition, we appraised each segment of T&D work’s value 27

6 276 miles of mainline cable replacement and 36 miles of CIC replacement were authorized in D.12-11-051, pages 151

and 153, respectively.

12

chain – system planning, design, execution, and work-order closing – to identify and implement 1

improvements up and down the chain. 2

a) Management Has to Prioritize and Shift Funds to Meet Authorized Rate of 3

Return and Maintain Adequate Service Levels 4

In the normal course of business, unexpected costs arise in some areas, while 5

anticipated expenses do not materialize in other areas or must be postponed. We have to make tough 6

decisions about optimizing our labor and financial resources every day, as our system, customer needs, 7

and regulatory requirements are dynamic and cannot be precisely predicted. A certain degree of 8

flexibility, founded upon analyses, experience, and expert judgment, will always be a critical part of our 9

business – and of our successes or failures. We base our rate case request years in advance of the actual 10

work. During the interim period, circumstances can change, and management has to reprioritize work to 11

address these changes while continuing to provide adequate service to our ratepayers in the short and 12

long term. 13

To cite just one example, in 2009 we decided to spend more funds on our 14

Infrastructure Replacement program, and less on our Load Growth program, compared to the levels the 15

Commission had authorized in our 2009 GRC. This was the right thing to do, because the actual load 16

growth was lower than forecast, and spending money just to meet authorized amounts would not be a 17

prudent use of ratepayer funding. 18

b) We Implemented Improved System Planning Methodologies to Minimize 19

Capital Expenditures on Load Growth and Better Leverage Past Investments 20

Load growth planning is the process of forecasting of electrical load growth 21

distribution across the service territory, and evaluating the ability of existing assets to provide sufficient 22

capacity to meet the peak demand of our customers. When load growth is expected to exceed the 23

capabilities of existing assets, we propose capital expenditure projects to upgrade or add new assets. 24

Since SCE’s peak load happens during summer, load growth planning is largely 25

driven by the ability to evaluate the impact of temperature on electrical demand. In 2012, SCE made 26

changes to the tools we use to analyze area temperatures when planning for peak loads. These changes 27

are designed to improve our ability to plan for load growth using our planning criteria. In addition, SCE 28

also modified its planning processes and methodology to focus on increasing usage of existing assets 29

and upgrades we have already made. In some cases, this allows us to make smaller capital upgrades to 30

balance electric power from highly loaded substations and circuits to less loaded substations and circuits 31

13

located in the same area. The results in a more uniform utilization of our field assets. Based on this new 1

methodology, we have been able to defer or cancel several large projects, and replace others with 2

smaller upgrades. This is discussed in more detail by Mr. Woods in Exhibit SCE-03, Volume 3. 3

In addition SCE has also incorporated the effects of distributed generation in our 4

load forecast by accounting for photovoltaic cells that can offset load growth. 5

c) We Evaluated Our Processes for Executing Work to Improve Throughput 6

and Quality 7

Given the increases in work we anticipate in the future, we have been gearing up 8

our field organizations to get more work done with the same level of resources and to minimize cost 9

increases. We evaluated the end-to-end value chain of planning, scheduling, executing, and closing 10

work in the field to identify potential areas of improvement, develop tools that would facilitate achieving 11

these improvements, and implement the necessary changes. This was a significant undertaking given 12

the large numbers of employees working out of various work locations spread across our service 13

territory, with each location having a certain degree of unique attributes and challenges. 14

In the future, we will be bundling work that will be performed in the same 15

location. For example, since we will be assessing every pole in our system for pole loading, we will 16

assess the condition of the overhead conductor spans between the poles and document the number of 17

splices. If repairing or replacing the conductors is warranted, we will plan and execute the work at the 18

same time as the pole repair or replacement. This will reduce the number of times crews have to go to 19

the same area, which in turn will reduce costs and lower the impact on customers. 20

We are also improving work-flow among various organizations to aid efficiency. 21

For example, we have modified the yard layouts and the way in which we transport material from 22

storage to prepare the job kits and ultimately deliver them the crews or construction sites. This reduces 23

the amount of time it takes crews to get the material they need before heading out to the job site. In 24

addition, we have updated work scheduling models to reduce driving time. Field supervision and 25

construction coordination roles have also been restructured to reduce costs. 26

Lastly, we have rolled out performance management tools that are more targeted, 27

accessible, and visible, so that we can better focus on efficiency and quality without compromising 28

safety. For example, Distribution Construction and Maintenance (DC&M) has refined performance 29

metrics into a Balanced Scorecard, which measures safety and compliance as prerequisites, along with 30

throughput, cost efficiency, customer satisfaction, and quality. The DC&M scorecard serves as a 31

14

foundation for performance management by utilizing specific metrics aligned with our annual and long 1

term goals. It provides a single overall measure for district and region comparisons and the ability to 2

drive performance expectations to the next level. This has not only improved throughput, but has 3

translated to higher quality or quicker error identification of work completed by planners, crews, and 4

field accountants. This means fewer job cancellations and re-work, which in turn reduces costs and 5

impact on customers. 6

These productivity gains impact numerous areas of T&D’s operations. The 7

specific cost benefits are discussed by Mr. Ferree in Exhibit SCE-03, Volume 5.7 8

7 Another example of significant productivity gains can be found in Mr. Boucher’s testimony regarding the Consolidated

Mobile Solution Project in Exhibit SCE-03, Volume 2.

15

II. 1

ANALYSIS OF T&D O&M EXPENSES AND CAPITAL EXPENDITURES 2

A. O&M Expenses 3

Figure II-3 T&D O&M Expenses for 2012 – Authorized versus Recorded

(2012 constant $millions, CPUC and FERC jurisdictional costs)

($21)

$16 $10

($12) ($13) ($21) ($17)

-

100

200

300

400

500

600

700

2012Authorized

Eng/GridTech

Dist Const Dist Mtce Grid Ops Sub/Trans Safety &Training

Other 2012Recorded

Eng/Grid Tech Dist Const Dist Mtce Grid Ops

Sub/Trans Safety & Training Other Diff from Auth

$626

$570$570$570

$ 570

Figure II-3 above shows the differences between the O&M expenses the Commission authorized 4

in SCE’s 2012 GRC, and what we recorded in spending that year. In our 2012 GRC, T&D requested 5

$676 million in 2012 constant dollars, and the Commission disallowed $50 million of that request. In 6

2012, the authorized expenses were not available till November of that test year. Given the uncertainty 7

in authorized amounts, management necessarily had to restrict spending until the Commission provided 8

its guidance on what we could spend. We delayed many of our Smart Grid-related projects until we 9

received Commission guidance and approval. While meeting our compliance requirements, we had to 10

reduce substation and transmission inspection and maintenance. We did this to the extent possible 11

16

without creating back-logs or impacting reliability, at least in the short term. In addition, we restricted 1

training for employees who are not front-line personnel. In examining our spending in 2012, it is also 2

worth noting that expenses related to storms or weather disturbances were significantly lower than the 3

historical average. 4

Figure II-4 below shows T&D’s recorded O&M expenses for 2008 to 2012, and our forecasts 5

from 2013 to 2015. 6

Figure II-4 T&D O&M Expenses

2008-2012 Recorded Adjusted/2013-2015 Request (2012 Constant $million, includes FERC and CPUC jurisdictional costs)

2008 2009 2010 2011 2012 2013 2014 2015

2012 Constant $ M $494 $594 $629 $607 $570 $618 $638 $641

 $‐

 $100

 $200

 $300

 $400

 $500

 $600

 $700

Our O&M expenses increased significantly from 2008-2009. A significant portion of this 7

increase was driven by increasing inspections and maintenance on the system, along with expenses that 8

are driven by capital work. From 2009-2011, we spent $610 million each year on average. In 2009, 9

expenses recorded at a slightly lower level, as the 2009 GRC Decision was published late first quarter of 10

that year. However, we caught up in performing the work in 2010. 11

Our forecast for the 2012-2014 cycle averages out to $608 million annually. As mentioned 12

previously, 2012 expenses were low due to the timing of the GRC decision. In 2013 and 2014, we need 13

17

to perform additional inspection and maintenance to avoid any backlogs or system impact. The increase 1

in 2015 is primarily to address the pole loading assessments and repairs that I discussed previously. 2

Figure II-5 below shows T&D’s 2015 Test Year O&M request by work category and 3

corresponding Exhibit reference. 4

Figure II-5 2015 T&D O&M Expense Request By Work Category

(2012 Constant $millions)

T&D Engineering and Grid Technology (Volume 2)

$54 8%

Customer Driven Prog & Distr. Con. (Volume 5)

$16 2%

Distribution Maintenance (Volume 6, Part 1)

$190 30%

Pole Loading (Volume 6, Part 2)

$39 6%

Grid Operations (Volume 7)

$112 18%

Transmission & Substation Maintenance (Volume 8)

$86 13%

Safety, Training, and Environmental

Programs (Volume 9)$68

11%

T&D Other Costs and OOR (Volume 10)

$76 12%

18

B. Capital Expenditures

Figure II-6 T&D Capital Expenditures for 2012 – Authorized versus Recorded

($millions, CPUC-Jurisdictional costs only)

$10

($14)

($99) ($3)

$39

($20) ($12)

$7

-

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

2012Authorized

Eng System Plan Infr Repl Cust Req Dist Const Dist Mtce Grid Ops Sub/TransMtce

2012Recorded

Eng System Plan Infr Repl Cust ReqDist Const Dist Mtce Grid Ops Sub/Trans Mtce Diff from Auth

$1,592

$1,500

Figure II-6 above shows the differences between the capital spending the Commission authorized 1

in SCE’s 2012 GRC and what we recorded that year. In our 2012 GRC, the Commission approved total 2

T&D capital expenditures of $1,592 million. We recorded $1,500 million that year, or $92 million less 3

than authorized. Figure II-6 above helps illustrate the primary contributors to that difference. 4

First, SCE experienced relatively mild storms in 2012; storm-related expenditures in 2012 were 5

approximately $15 million lower than the average of the authorized amounts in years 2005-2009. 6

More significantly, we had to impose constraints on our expenditures, because we did not know 7

what level we were funded at for our activities until the Commission issued the 2012 GRC decision in 8

November 2012. We had to reduce pre-emptive infrastructure replacement that focuses on long term 9

reliability, in order to preserve dollars for more immediate system needs. 10

19

Our lead time for planned T&D work ranges from a few months to a year, because the work 1

requires significant planning, permitting, and scheduling. Accordingly, it was impossible to ramp up 2

work to meet authorized levels in the last few weeks of 2012. The challenge of ramping-up execution 3

continues in 2013, but we are confident that we will be able to meet authorized levels over the 2012-4

2014 GRC period.8 5

Figure II-7 T&D Capital Expenditures

2008-2012 Recorded and 2013-2017 Forecast ($million, includes CPUC-Jurisdictional costs only)

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Nominal $ M $1,152 $1,316 $1,440 $1,492 $1,500 $2,021 $2,295 $2,667 $2,633 $2,473

2012 Constant $ M $1,191 $1,343 $1,429 $1,494 $1,500 $1,980 $2,194 $2,495 $2,411 $2,205

 $‐

 $500

 $1,000

 $1,500

 $2,000

 $2,500

 $3,000

Forecast

Figure II-7 above provides a historical perspective on our capital expenditures - what we 6

recorded during the period 2008-2012, and what we forecast for years 2013-2017.9 It shows the growth 7

in total T&D CPUC-jurisdictional capital expenditures from $1,164 million in 2008 to $1,512 million in 8

2012. Most of this increase has occurred to address aging and deteriorating infrastructure replacement, 9

followed by modest increases in load growth and customer requested (added facilities) projects. Our 10

8 Mr. Litzinger discusses this in Exhibit SCE-01.

9 All capital expenditures shown in this exhibit represent gross expenditures, i.e. they are not net of customer contributions. The customer contribution credits are added in the Results of Operation model prior to calculating revenue requirements.

20

forecast increase in 2015 is largely to address infrastructure replacement associated with compliance, 1

reliability, and safety. Please refer to my testimony above for further discussion of our needed spend in 2

these areas. 3

Figure II-8 Total 2013 to 2017Capital Expenditure Forecast by Work Category

$millions (includes CPUC-Jurisdictional forecasts)

T&D Engineering and Grid Technology (Volume 2), $183 ,

1%

System Planning Capital Projects

(Volume 3), $2,165 , 18%

Infrastructure Replacement

Programs (Volume 4), $2,032 , 17%

Customer Driven Prog & Distr.

Con.(Volume 5), $3,158 , 26%

Distribution Maintenance (Volume

6, Part 1), $2,519 , 21%

Pole Loading (Volume 6, Part 2),

$1,078 , 9%

Grid Operations (Volume 7), $511 ,

4%

Transmission & Substation

Maintenance (Volume 8), $438 , 4%

Figure II-8 above shows T&D’s 2015 Test Year Capital Expenditure request by work category 4

and corresponding Exhibit reference. Table II-2 below provides the capital expenditures by major work 5

categories for 2008 to 2017 as requested by the Commission in Ordering Paragraph 7 in D. 12-11-051. 6

21

Table II-2 Capital Expenditure by Major Work Categories

2008-2012 Recorded/2012 Authorized/2013-2017 Forecast (Nominal $millions, CPUC-Jurisdictional only)

Exhibit Reference Exhibit Name Witness

2008 Recorded

2009 Recorded

2010 Recorded

2011 Recorded

2012 Auth

2012 Recorded

2013 Forecast

2014 Forecast

2015 Forecast

2016 Forecast

2017 Forecast

SCE-03, Vol. 2

Engineering & Grid Technology

K. Payne / D. Kim / T. Boucher

6 8 26 48 49 59 53 43 30 25 32

SCE-03, Vol. 3

System Planning Capital Projects

R. Woods 261 380 452 448 478 464 532 528 529 398 177

SCE-03, Vol. 4

Infrastructure Replacement Programs

R. Lee 77 122 172 208 266 167 271 351 460 469 482

SCE-03, Vol. 5

Customer Driven Programs and Distribution Construction

G. Ferree 411 384 325 314 306 342 458 559 660 730 753

SCE-03, Vol. 6, Pt. 1

Distribution Maintenance

M. Stark / K. Trainor

304 313 352 353 378 357 516 596 461 472 478

SCE-03, Vol. 6, Pt. 2

Pole Loading Program

K. Trainor 0 0 0 0 0 1 0 40 338 345 355

SCE-03, Vol. 7

Grid Operations P. Grigaux 46 55 59 65 63 51 111 101 97 99 102

SCE-03, Vol. 8

Transmission & Substation Maintenance

T. Kedis 48 54 55 56 52 59 81 76 93 94 95

TOTAL 1,152 1,316 1,440 1,492 1,592 1,500 2,021 2,295 2,667 2,633 2,473

22

C. T&D Testimony Organization 1

Table II-3 Request by Testimony and Witness

Includes CPUC and FERC Jurisdictional Costs

Exhibit Reference Exhibit Name Witness2015 O&M

Forecast (2012 Constant $)

2013 - 2017 Capital Expenditure Forecast

($ Millions)

SCE-03, Volume 2Engineering & Grid Technology

K. Payne / D. Kim / T. Boucher

54 242

SCE-03, Volume 3System Planning Capital Projects

R. Woods 0 4,145

SCE-03, Volume 4Infrastructure Replacement Programs

R. Lee 0 2,144

SCE-03, Volume 5Customer-Driven Programs and Distribution Construction

G. Ferree 16 3,158

SCE-03, Volume 6, Part 1

Distribution MaintenanceM. Stark / K. Trainor

190 2,531

SCE-03, Volume 6, Part 2

Pole Loading Program K. Trainor 39 1,093

SCE-03, Volume 7 Grid Operations P. Grigaux 112 522

SCE-03, Volume 8Transmission & Substation Maintenance

T. Kedis 86 837

SCE-03, Volume 9Safety, Trakining, and Environmental Programs

G. McDonald 68 0

SCE-03, Volume 10 Other Costs & OOR T. Reeves 76 0TOTAL 641 14,672

23

III. 1

REGULATORY MECHANISMS FOR RELIABILITY AND SAFETY PROGRAMS 2

A. Reliability and Safety Investment Mechanism 3

1. Background 4

In SCE’s 2006, 2009, and 2012 GRCs, the Commission adopted the Reliability 5

Investment Incentive Mechanism (RIIM). RIIM replaced previous reliability mechanisms that had 6

focused on reliability metrics that are largely beyond the control of the utility in the short run, and that 7

did not provide incentives for long-term investment in the power system’s health. 8

RIIM comprised two components: 9

(1) Capital spending on reliability-related projects and activities; and 10

(2) Hiring of field personnel directly working on reliability-related projects and 11

programs. 12

In the 2012 GRC, the Commission reauthorized RIIM, but directed that SCE modify the 13

mechanism to address some specific areas: 14

Choose work categories that impact both safety and reliability, not just the latter. 15

Limit the categories identified as “RIIM eligible” to focus attention on specific 16

programs. 17

Provide better means of linking expenditure and impact on long term reliability and 18

safety. 19

SCE shares the Commission’s belief in the importance of a mechanism such as RIIM,10 20

as it focuses the utility’s attention on long-term customer benefit. We also continue to believe that the 21

best way to impact long-term benefits is investing in infrastructure and work-force, not in tracking 22

lagging indicators like SAIDI/SAIFI.11 In the short term, these indicators exist largely outside the 23

utility’s control. 24

10 See D.12-11-051, p. 699 (“We return to our conclusions in 2003 and 2006 to find the RIIM settlement reasonable: our

priority concern for long-term reliability is amplified by SCE’s aging infrastructure, and ratepayers benefit when SCE must spend funds for long-term reliability projects as authorized. Under cost-of-service ratemaking, without RIIM, SCE is otherwise able to redirect unspent funds freely, including to shareholder profits.”).

11 “SAIDI/SAIFI” refers to the System Average Interruption Frequency and the System Average Interruption Duration Index.

24

2. Proposal 1

a) Infrastructure investment 2

Table III-4 below summarizes the programs SCE proposes to include in 2015 3

RIIM, along with certain program attributes. In response to the Commission’s request to include 4

specific programs in RIIM, we are proposing to include seven programs that are specifically designed to 5

address long-term safety and reliability issues. Work performed in these programs is identified by T&D 6

after rigorous inspection, testing and analyses. Under the mechanism, SCE proposes the following: 7

a. The 2015 to 2017 cumulative capital additions authorized for the work 8

categories shown below in Table III-4 and safety programs will serve as the 9

RIIM capital target. If we underspend in actual capital additions in these 10

programs during the same period, the amount underspent will be returned to 11

ratepayers. The expenditures in these programs will not be tracked 12

individually for RIIM, to provide management reasonable flexibility to 13

address emergent needs and challenges. 14

b. If capital additions in high-priority programs that are outside the utility’s 15

control (such as Customer Growth, Storms, and Claims) turn out to be higher 16

or lower than authorized, the target will be adjusted down or up by the 17

difference between the authorized and the actual capital additions. 18

c. The targets for capital additions have to be appropriately adjusted based on the 19

timing of the final decision in the Test Year 2015 GRC, so that T&D has 20

sufficient time to execute on authorized amounts. 21

d. SCE will provide a report to the Commission that provides details of work 22

completed under each program, along with the specifics of how we 23

determined that this work would positively impact long-term reliability and 24

safety. Each program has unique analyses underlying the work-scope 25

development, as indicated below in Table III-4. Examples of these drivers are 26

provided in workpapers.12 27

12 See workpaper titled “RIIM Work Identification Processes and Analyses.”

25

Table III-4 2015 RIIM Categories and Capital Expenditure Forecasts

PROGRAMPRIMARY DRIVER

LEADING INDICATOR OF PROGRAM IMPACT AND

EFFECTIVENESS

2015-2017 CAPITAL

EXPENDITURE FORECASTS ($

million, CPUC Jurisdictional only)

TESTIMONY REFERENCE

Number of circuits improved Miles of cable replaced Historical reliability metrics for each circuit rehabilitated, along with work completed

Miles of cable replaced Results of cable testing for each segment replaced Number of switches replaced Age of switches replaced Number of structures replaced Inspection results for structures replaced Number of circuit breakers replaced Health index of asset (combination of age, performance history, and inspection results) Number of substation transformers replaced Health index of asset (combination of age, performance history, and inspection results)

TOTAL 1,225

SCE-03, Vol 4

SCE-03, Vol 6, Pt 1

SCE-03, Vol 4

SCE-03, Vol 4

SCE-03, Vol 4

SCE-03, Vol 4

SCE-03, Vol 4

Reliability 347

Underground Cable Life

Reliability Miles of Cable Tested 83

Worst Circuit Rehabilitation

CIC Replacement

Reliability 288

Underground Switch

Safety 30

Substation Transformer Replacement

Reliability 167

Underground Structure Replacement

Safety 215

Circuit Breaker Replacements

Reliability 96

26

Table III-5 2015 RIIM High-Priority Categories and Capital Expenditure Forecasts

PROGRAM

2015-2017 CAPITAL EXPENDITURE

FORECASTS ($ million, CPUC Jurisdictional only)

TESTIMONY REFERENCE

Customer Growth

1,211 SCE-03, Vol 5

Storms 143 SCE-03, Vol 7

Claims 81 SCE-03, Vol 5

TOTAL 1,434

b) Critical Workforce 1

SCE believes that no amount of investment in its electrical assets will be 2

successful without investment in our workforce, especially those who respond to restore power, mitigate 3

dangers to public safety, and maintain and construct our system. SCE proposes maintaining a level of 4

2,225 employees in the categories shown below in Table III-6. This is approximately equal to 2012 5

year-end count. If SCE fails to maintain this level, SCE agrees to refund to ratepayers $20,000 for each 6

headcount shortfall, up to shortfall of 50 employees, and refund $80,000 for each headcount shortfall 7

thereafter. 8

27

Table III-6 RIIM Workforce Classifications

Workforce Category

2008 Year

End

Count

2009 Year

End

Count

2010 Year

End

Count

2011 Year

End

Count

2012 Year

End

CountDistribution E-Crew Foreman

158 153 160 173 170

Distribution Lineman 497 545 559 567 614

Distribution Sr. Cable Splicer

33 31 28 27 28

Distribution Apprentice Lineman

228 261 287 244 153

Distribution Groundman A

110 117 160 180 183

Distribution Groundman 129 165 173 159 166

Transmission Lineman 96 104 116 117 137

Transmission Groundman A

30 19 0 0 1

Transmission Apprentice Lineman

59 67 70 68 47

Sr. Patrolman 31 34 34 34 34

Troubleman 176 176 177 177 185

System Operator 101 106 100 105 110

Substation Operator 101 99 108 116 126

Electrician Substation 113 118 125 128 136

Electrician Apprentice Substation

43 35 38 45 32

Technician Test 50 50 49 49 51

Technician Test Supervising

53 53 54 50 53

TOTAL 2,008 2,133 2,238 2,239 2,226

2009-2012 Average 2,209

Approximately a fifth of the RIIM workforce is in apprentice classifications that 1

require extensive training. Therefore, any reductions in the request for training expenses will limit our 2

ability to maintain an appropriate SCE workforce. If authorized amounts for employee training are less 3

28

than our request, SCE proposes reducing the target headcount by one-fifth of the percentage reduction 1

from request to authorized amounts.13 2

It is also important to note that headcount in any work-group can change at short 3

notice, and backfilling with qualified candidates takes a certain amount of time. For example, SCE 4

determines apprentice groundmen hires based on anticipated linemen needs in the future and forecast 5

linemen attrition. If the actual attrition is higher than our forecasts towards the end of 2017, SCE might 6

be unable to put additional employees in the apprentice pipeline to maintain overall employee levels, as 7

it takes time to hire qualified employees, and build an optimum training class size.14 Therefore, if SCE’s 8

reliability workforce counts decline below 2,225 between September 1, 2017 and December 31, 2017, 9

SCE proposes that it have until March 31, 2018 to fully address the shortfall. 10

B. Pole Loading Balancing Account 11

As discussed earlier, SCE has designed a Pole Loading Program that will assess each of its poles 12

over a seven-year period to identify and then remediate those poles that do not meet the current pole 13

loading safety standards. 14

This program will be a significant driver of pole inspection, maintenance, and replacements, as 15

detailed in Exhibit SCE-03, Volume 6, Part 2. We have developed these forecasts based on the system-16

wide sampling plan mandated in D.12-11-051. In addition, these forecasts might be modified as we 17

develop detailed operational plans for work execution strategy. I highlight below some examples of the 18

factors that might impact the costs, although this is not meant to be an exhaustive list. 19

Proportion of poles that will need remediation - For purposes of estimating costs in 2013-20

2017, we project that approximately 3 percent of the poles will need repairs and 21

approximately 19 percent will need replacements. The actual proportions may turn out to be 22

over or under these estimates. 23

Cost of assessment, planning, repair, or replacement - The cost estimates are based on 24

historical data or limited discussion with vendors. SCE will have to refine these estimates as 25

it refines and improves its contracting strategy for this work. 26

13 So, for example, if the authorized amounts for training is 10 percent lower than our request, the RIIM employee target

will be 2 percent lower than 2,225, or 2,181.

14 Training class sizes vary between 10 and 15 for most apprentice classes. Training in smaller numbers is inefficient and costly.

29

Remediation Methodology – Our current estimates assume that we will replace a pole that is 1

not meeting pole loading standards with another pole of the appropriate strength. Depending 2

on field evaluations and cost benefit analyses, it might be more prudent to underground 3

sections of lines, or rebuild segments to strengthen and fire-harden the distribution system. 4

Overlap with other pole programs – We perform pole replacements and repairs pursuant to 5

other T&D programs such as deteriorated pole replacement, breakdown, storm, preventive 6

maintenance, and line extensions. Our current analysis does not account for the potential 7

overlap between the Pole Loading program and these other programs. We currently do not 8

have sufficient data to precisely map out the boundaries of the Pole Loading program versus 9

the other programs. The actual remediation costs recorded in the Pole Loading Program will 10

only include poles that require repair or replacement solely because the pole fails a pole 11

loading assessment. For instance, if a pole is identified for replacement based on intrusive 12

pole inspection and pole loading assessment, it will not be included in the Pole Loading 13

program. As a second example, if a pole is identified for replacement under Pole Loading, 14

but subsequently needs to be replaced because of third-party damage, SCE will perform 15

appropriate pole loading calculations prior to replacing the pole, but will not charge it to the 16

Pole Loading Program. 17

Regardless of the inherent forecasting error, SCE is committed to using authorized amounts for 18

the Pole Loading program to resolve the pole loading challenge. Therefore, in this GRC, SCE is 19

proposing to establish a new two-way Pole Loading Balancing Account (PLBA) effective on January 1, 20

2015. The PLBA will serve to record the difference between: 21

Recorded O&M incurred for Pole Loading Program assessments and repairs identified as 22

necessary by pole loading assessments, and capital-related revenue requirements 23

associated with replacing poles and making necessary system upgrades specifically 24

identified as part of the Pole Loading program; and 25

The authorized Pole Loading revenue requirement adopted in this GRC. 26

For further details on the PLBA, please see Mr. Snow’s testimony in Exhibit SCE-10, Volume 1, 27

Part 2. 28

30

IV. 1

CONCLUSION 2

I believe we have presented the Commission with reasonably straightforward choices about the 3

reliability and flexibility of the grid today and in the future, the investment required to meet California’s 4

unprecedented and important policy goals, the need for a well-trained and diverse workforce, and the 5

systems and processes we need to do all of these things in a way that is safe, reasonable, and compliant 6

with all applicable laws and regulations. I firmly believe that approving our request is in the best 7

interests of our customers and the communities we serve. Our T&D priorities are the right ones, and we 8

have chosen a prudent path to safeguard the present and build for the future. I thank the Commission for 9

their careful attention to the condition and needs of our power system and the hard-working people that 10

run it. 11

Appendix A

Witness Qualifications

A-1

SOUTHERN CALIFORNIA EDISON COMPANY 1

QUALIFICATIONS AND PREPARED TESTIMONY 2

OF DAVID L. MEAD 3

Q. Please state your name and business address for the record. 4

A. My name is David L. Mead, and my business address is 2244 Walnut Grove Avenue, Rosemead, 5

California, 91770. 6

Q. Briefly describe your present responsibilities at the Southern California Edison Company (SCE). 7

A. I am the Senior Vice President of SCE’s Transmission and Distribution organization. T&D is 8

responsible for planning, engineering, constructing, operating and maintaining all transmission 9

and distribution facilities required to deliver electricity to Southern California Edison’s 5 million 10

customers throughout our 50,000 square mile service territory. 11

Q. Briefly describe your educational and professional background. 12

A. I graduated from California State University at Long Beach in 1986 with a bachelor’s degree in 13

Business Administration. In 2003, I received a master’s degree in Management from the 14

University of Southern California. I joined SCE in 1981 in the Power Supply organization where 15

I held various management positions in the Steam Generation Division. In 1998, I joined the 16

Transmission and Distribution (T&D) organization, where I have held multiple leadership 17

positions across T&D, including Director of Central Programs Management, responsible for the 18

distribution maintenance program, streetlight operations, joint pole administration, distribution 19

design support, and vegetation management. Subsequently I was the Director of Substation 20

Construction and Maintenance. In 2008, I became the Vice President of Engineering and 21

Technical Services, responsible for planning, designing, and engineering SCE’s transmission and 22

distribution grid and substations. I was also responsible for all powerline craft training, T&D 23

safety activities, and generation interconnection policy and contracts. I assumed my current 24

position in 2011. I have not previously testified before this Commission. 25

Q. What is the purpose of your testimony in this proceeding? 26

A. The purpose of my testimony in this proceeding is to sponsor Exhibit SCE-03, Volume 1, 27

entitled Transmission And Distribution - Policy, as identified in the table of contents thereto. 28

Q. Was this material prepared by you or under your supervision? 29

A. Yes. 30

Q. Insofar as this material is factual in nature, do you believe it to be correct? 31

A-2

A. Yes, I do. 1

Q. Insofar as this material is in the nature of opinion or judgment, does it represent your best 2

judgment? 3

A. Yes, it does. 4

Q. Does this conclude your qualifications and prepared testimony? 5

A. Yes, it does. 6