2015 general rate case policy - southern california edison€¦ · 2015 general rate case policy...
TRANSCRIPT
Application No.: Exhibit No.: SCE-01 Witnesses: R. Litzinger
M. Marelli
(U 338-E)
2015 General Rate Case
Policy
Before the
Public Utilities Commission of the State of California
Rosemead, CaliforniaNovember 2013
SCE-01: Policy
Table Of Contents
Section Page Witness
-i-
I. INTRODUCTION .............................................................................................1 R. Litzinger
A. SCE’s Commitment To Our Customers ................................................1
B. Our Request In This Proceeding Is Designed To Allow SCE To Continue Providing Safe, Reliable, And Affordable Delivery Of Electricity To 5 Million Customers Across Southern And Central California ...............................................1
C. San Onofre Nuclear Generating Station (SONGS) ................................2
II. STRATEGIC OBJECTIVES .............................................................................5
A. Safety and Compliance Are Core Principles Guiding our Work ......................................................................................................5
1. Public Safety ..............................................................................5
2. Employee Safety ........................................................................5
3. Safety Remains The Paramount Responsibility For SONGS ......................................................................................6
4. Compliance Programs and Progress ..........................................7
B. Customer-Valued Service at Affordable Rates ......................................7
1. Operational Excellence ..............................................................7
2. State Policy Objectives ..............................................................8
a) Environment ...................................................................8
b) Supporting the Communities We Serve .........................9
3. Fuel And Purchase Power Portfolio Optimization .....................9
C. Reliability .............................................................................................10
1. System Reliability And Infrastructure Replacement ...............10
2. PLP Is A New Initiative To Bring All SCE Pole Assets Up To Specified Standards ...........................................11
3. Non-Nuclear Generation Reliability ........................................12
SCE-01: Policy
Table Of Contents (Continued)
Section Page Witness
-ii-
D. Affordability ........................................................................................12
1. System Average Rate Impacts .................................................12
2. Facilitate Grid Investment........................................................17
3. Utilities Must Retain Spending Flexibility ..............................17
4. The Commission Should Adopt A Post-Test Year Ratemaking Mechanism That Allows SCE The Opportunity To Recover The Costs Of System Investments In 2016 And 2017 ................................................18
5. Impact Of Deferred Depreciation On Future Customers ................................................................................19
6. Supplier Diversity ....................................................................20
E. Customer Service .................................................................................21
1. Customer Satisfaction ..............................................................21
2. Outage Communications ..........................................................22
F. People ...................................................................................................23
1. Work Environment...................................................................23
2. Diversity ...................................................................................24
3. Compensation ..........................................................................25
G. Enterprise Risk Management ...............................................................26
1. Business Resiliency and Emergency Response .......................26
2. Cybersecurity ...........................................................................27
3. Enterprise Risk Management Program ....................................29
III. IMPACT OF LATE 2012 GRC DECISION ON BUSINESS OPERATIONS .................................................................................................31
A. A Timely GRC Decision Is In The Best Interest Of Customers ............................................................................................31
SCE-01: Policy
Table Of Contents (Continued)
Section Page Witness
-iii-
B. A Memorandum Account Is Not An Alternative To A Timely GRC Decision ..........................................................................31
C. Authorized Versus Recorded Capital and Expense .............................32
IV. SUMMARY OF SCE'S REQUEST ................................................................34 M. Marelli
A. Introduction and Summary of Proposed Increase ................................34
B. Organizational Structure Of Exhibits...................................................35
C. Organization of Administrative and General Expenses .......................37
D. To Reduce Overall Page Count Of Testimony And Workpapers We Have Consolidated The Presentation Of Some FERC Account Data ..................................................................40
Appendix A Witness Qualifications ................................................................................
SCE-01: Policy
List Of Figures
Figure Page
-iv-
Figure II-1 DART Injury Rates, 2006-2012 ................................................................................................6
Figure II-2 Southern California Edison Comparison of Average Residential Consumption
for the 50 Largest IOUs (Ranked by Sales) .........................................................................................14
Figure II-3 Southern California Edison Comparison of Average Residential Bills for the
50 Largest IOUs (Ranked by Sales) .....................................................................................................16
Figure II-4 J.D. Power Residential And Business – Customer Satisfaction Trend for SCE .....................22
Figure II-5 SCE Detected Intrusion Attempts ...........................................................................................29
SCE-01: Policy
List Of Tables
Table Page
-v-
Table II-1 SCE Workforce Demographics ................................................................................................24
Table III-2 SCE Capital Expenditures ($million) ......................................................................................33
Table III-3 SCE Expenses ($million) .......................................................................................................33
Table IV-4 SCE Capital Expenditures ($million) .....................................................................................34
Table IV-5 SCE 2015 GRC Organizational Structure of Exhibits ............................................................35
Table IV-6 Forecast of Test Year 2015 A&G Expenses in Testimony (Constant 2012
$000) ....................................................................................................................................................38
Table IV-7 Forecast Of Test Year 2015 A&G Expenses In Testimony (All Volumes)
(Constant 2012 $000) ...........................................................................................................................39
1
I. 1
INTRODUCTION 2
A. SCE’s Commitment To Our Customers 3
SCE is committed to our core mission, which is to safely deliver reliable, affordable electricity to 4
our customers, a mission that reflects our core values and our vision for SCE. Our values include: 5
Integrity, 6
Excellence, 7
Respect, 8
Continuous Improvement, and 9
Teamwork. 10
The programs and expenditures you will read about in this 2015 GRC are necessary to carry out 11
our mission of safely delivering reliable, affordable electricity to our customers, while complying with 12
applicable laws and regulations and meeting key State policy goals for energy, environment, and the 13
economy. In this filing, SCE has presented the evidence to demonstrate the need to invest in the 14
infrastructure to deliver on the expectations of our customers. While we have made significant 15
progress in many key operating metrics across the business, we are not yet satisfied with some areas of 16
performance. In this testimony, I will talk about some of the key areas that SCE has identified that 17
require further effort, and explain what SCE is doing to improve on our commitment and core mission 18
to provide safe, reliable, and affordable power to our customers. 19
B. Our Request In This Proceeding Is Designed To Allow SCE To Continue Providing Safe, 20
Reliable, And Affordable Delivery Of Electricity To 5 Million Customers Across Southern 21
And Central California 22
Our request in this 2015 General Rate Case (GRC) contemplates significant investment in the 23
electric infrastructure to replace our aging equipment and to support State energy and environmental 24
policy objectives. The Commission has recognized the need for infrastructure investment in its decision 25
on our 2012 GRC, and all our employees across the 50,000 square mile SCE service territory are 26
diligently working to carry out the investments authorized in that decision. While we, with 27
Commission support, have steadily increased our infrastructure replacement in the last three rate cases, 28
we need to continue replacing major infrastructure until replacement rates equal replacement needs and 29
reliability can be sustained. 30
2
To continue providing these essential services, in this 2015 GRC, we forecast a Test Year 2015 1
revenue requirement of $6.462 billion, an increase of $206 million over revenues at present rates.1 This 2
amounts to a 1.3 percent increase over presently authorized total rates (net of sales), or 3.3 percent over 3
presently authorized revenues. Our 2015 request is followed by proposed increases of $318 million in 4
2016, and $317 million in 2017. 5
Our request in this 2015 GRC builds on the previous infrastructure efforts, makes adjustments 6
based on more recent information, and identifies additional areas where significant investments are 7
needed. Most of these additional programs are initiated in this GRC cycle. However, billions of dollars 8
of continued investment will be required until equilibrium replacement rates (defined as equipment 9
population divided by the mean time to failure for that piece of equipment) are achieved. The testimony 10
we are providing demonstrates the need for these investments. David Mead, Senior Vice President of 11
Transmission and Distribution, discusses these specific infrastructure needs in Exhibit SCE-03. 12
We recognize that infrastructure investment places upward pressure on customer rates. To strike 13
the correct balance between reliability, policy goals, and affordable customer rates, we must optimize 14
other cost drivers such as operating and maintenance (O&M) costs and fuel and purchase power costs. 15
Keeping those costs at optimal levels will moderate customer rate increases. 16
For example, we have significantly reduced our administrative staff, which will be at 17
approximately 2006 levels. Our request in this 2015 GRC continues to focus on O&M expense 18
optimization and employee productivity improvements. Those efforts, along with fuel and purchase 19
power portfolio optimization, will facilitate our needed grid investment. I must add, however, that 20
increased capital investment carries with it some corresponding O&M expense increases. For example, 21
when replacing aging infrastructure, accounting rules dictate that some of the costs be booked as capital 22
expenditures and some as O&M expenses. So the Commission should expect some O&M increases 23
associated with our capital investment program, even in the face of increased productivity. 24
C. San Onofre Nuclear Generating Station (SONGS) 25
Both Units 2 & 3 at SONGS had been out of service since January 31, 2012, when a small leak 26
developed in one of the Unit 3 Steam Generators. On June 7, 2013, we announced we would no longer 27
seek to restart SONGS Units 2 and 3. We formally notified the Nuclear Regulatory Commission (NRC) 28
1 Note that the $206 million increase represents the difference between our 2015 forecast and the currently authorized base
rate revenues. The latter figure reflects Commission authorized revenue requirement for operating SONGS; our 2015 request does not, as is discussed in more detail in Exhibit SCE-02.
3
of this decision on June 13, 2013 by submitting a Certificate of Permanent Cessation of Power 1
Operations. 2
There is no greater responsibility than protecting the health and safety of the public and our 3
employees. This includes operating and maintaining vital systems in the shutdown condition for as long 4
as nuclear fuel remains on the SONGS site. Our GRC request therefore includes our forecast of costs 5
required to safely maintain these vital systems in a shutdown condition and transition into the formal 6
decommissioning phase after receiving the required regulatory approvals. 7
As part of managing the shutdown process and preparing for decommissioning, we will 8
commence a detailed analysis of our shutdown operating and capital expenses, to determine what 9
expenses should be funded through GRC rates and what expenses can be funded by the Nuclear 10
Decommissioning Trust. Given our recent decision to retire SONGS, this study is not yet available, but 11
we do intend to submit the study when it is available and include it as part of the record in this 2015 12
general rate case. Costs that can be funded by the Nuclear Decommissioning Trust will not be included 13
in GRC forecasts. Jack Huson, Director of Finance for Generation, discusses the GRC forecast for 14
SONGS projects and activities in detail in Exhibit SCE-02. 15
The Commission is proceeding with an Order Instituting Investigation (OII) to review SONGS-16
related rate base, operating expenses, and replacement power costs in 2012. The Commission will also 17
be reviewing the prudency of the Steam Generator Replacement Project (SGRP). This OII is currently 18
divided into four phases: 19
Phase I, to examine the recorded costs for 2012, as well as the reasonableness and 20
effectiveness of SCE’s actions and expenditures for community outreach and emergency 21
preparedness related to the SONGS outages. Phase I will also determine a methodology to 22
quantify the replacement energy and capacity attributable to the SONGS outages; 23
Phase II, to decide whether any reductions to SCE’s rate base and 2012 SONGS revenue 24
requirement are warranted or required due to the SONGS outages; 25
Phase III, to review the cause of the damage to the replacement steam generators and 26
allocation of responsibility, whether the SGRP expenses are reasonable, and any utility-27
proposed repair and/or replacement cost proposals; and 28
Phase IV (if needed), to determine whether the 2013 revenue requirement should be adjusted. 29
The associated activities and costs to safely transition into the formal decommissioning phase 30
over the GRC period appear to be outside the current scope of the OII, and therefore form the basis for 31
4
this GRC request. Although these proposed GRC-funded activities appear to be outside the current 1
scope of the OII, SCE would be open to considering those issues in the OII proceeding rather than this 2
GRC, if the Commission believes that would be more efficient. 3
5
II. 1
STRATEGIC OBJECTIVES 2
A. Safety and Compliance Are Core Principles Guiding our Work 3
1. Public Safety 4
Our public safety responsibility is one of the guiding principles at SCE. Our request in 5
this proceeding includes funding key maintenance and inspection activities in compliance with 6
Commission General Order (GO) 165. Our infrastructure replacement investments are also critical, 7
because a reliable grid significantly reduces public exposure to hazardous conditions such as downed 8
power lines. We have also carried out a comprehensive public safety advertising campaign in 2012 to 9
educate the public about the danger of downed power lines. The year-long campaign was delivered in 10
six languages through multiple paid media outlets and supported by media relations efforts. SCE 11
customer awareness about powerline safety increased significantly—from 39 percent in 2011 to 47 12
percent in 2012.2 13
2. Employee Safety 14
I and the entire SCE management team are committed to an injury-free workplace. 15
Although we’re not yet there, we aspire to nothing less. 16
One of the most widely used measures of workplace safety is known as the “Days Away, 17
Restricted or Transferred” rate, commonly referred to as the “DART” rate. The DART rate is calculated 18
by taking the sum of all injuries that result in lost-time or restricted duty or transfer, multiplying by 19
200,000 (which is the base number of work hours for 100 employees in a year), then dividing by the 20
total number of actual hours worked.3 21
Figure II-1, below, depicts the SCE DART rate over the period 2006-2012. It shows that 22
over the 2006-2012 period, we have improved from a DART rate of around four to less than two. This 23
means that while four out of every 100 of our employees experienced days-away, restricted duty or 24
transfer in 2006-2007, less than two did in 2012. While I welcome the improvement, this result is still 25
not acceptable. We continue to drive towards a completely injury-free workplace. Dana Kracke, our 26
2 See Exhibit SCE-09, Chapter 1, pp. 23-25.
3 The calculations used to determine the DART rate “normalize” the data to facilitate comparisons among workforces of different sizes.
6
Vice President of Safety, Security and Compliance, and other witnesses from that operating unit, discuss 1
our efforts to achieve an injury-free workforce in Exhibit SCE-07. 2
Figure II-1 DART Injury Rates, 2006-2012
2006 2007 2008 2009 2010 2011 2012
DART Injury Rate 3.71 3.80 3.19 2.69 2.34 2.37 1.82
0.00
0.50
1.00
1.50
2.00
2.50
3.00
3.50
4.00
DA
RT
In
jury
Ra
te
Note : DART Injury Rate = (Sum of Lost‐Time and Restricted Duty Injury Counts)*200,000/Total Hours Worked(200,000 worked hours represent 100 employee‐years of work)
3. Safety Remains The Paramount Responsibility For SONGS 3
There is no greater responsibility for a nuclear operator than protecting the health and 4
safety of the public and our employees. This responsibility remains in place with the plant in a 5
shutdown condition as we transition to decommissioning. Nuclear fuel remains on-site and we must 6
maintain portions of the plant in service and safely store and protect the fuel on-site until a suitable 7
offsite long-term storage facility is developed by the federal authorities. Our request in this proceeding 8
will allow us to carry out that responsibility. 9
7
4. Compliance Programs and Progress 1
We are subject to numerous laws and regulations. Complying with them and with our 2
own internal conduct rules is, like safety, a guiding principle. Early identification of potential issues 3
often leads to early resolution of those issues before they become more significant concerns. We are 4
continuing our dual goals of: (1) operating with no significant non-compliance events; and (2) building 5
and maintaining a comprehensive Ethics and Compliance program, based on Federal Sentencing 6
Guidelines, which outline the elements of an effective ethics and compliance program. We emphasize 7
strengthening compliance, encouraging values-based behavior, and fostering a “speak-up” culture in 8
which employees feel comfortable raising issues. All employees should demonstrate legal and ethical 9
conduct and feel empowered to raise concerns about ethics, compliance, work environment, security, 10
and safety. J.P. Shotwell discusses our ethics and compliance efforts in Exhibit SCE-07. 11
B. Customer-Valued Service at Affordable Rates 12
1. Operational Excellence 13
Operational Excellence is the framework we have established to deliver on our mission of 14
providing safe, reliable, and affordable power for our customers. Operational Excellence builds off our 15
core value – Continuous Improvement. SCE has rededicated itself to exploring every opportunity to 16
improve the operations across the company. Continuous improvement means improving everything 17
from the way we set and communicate goals approved by our Board of Directors to challenging all 18
employees to find ways of becoming more efficient and effective in their daily jobs. It also means being 19
self-critical in all efforts across the company and asking ourselves what we do, why we do it, and 20
whether there are ways to do it more efficiently. This involves looking at other companies to see if we 21
are performing up to industry best practices. We describe this process as: Measure, Benchmark, 22
Improve, and Repeat. Repeat is critical, as the industry will continue to improve. 23
In this GRC, a significant impact of implementing an Operational Excellence framework 24
can be seen in the significant reductions in O&M expenses, particularly in the Administrative and 25
General (A&G) accounts. We have committed to reducing almost every area of A&G spending across 26
the company. The most significant reductions have occurred in Information Technology, Human 27
Resources, Financial Services, and Operational Services. While some of these reductions have been 28
implemented in 2013, more are expected between now and the end of 2015. Those reductions are 29
reflected in our test year estimates. 30
8
The drivers for the reductions and the specific opportunities that led to them are discussed 1
in many areas of testimony. However, all the productivity savings are summarized in Dr. Paul Hunt’s 2
testimony in Exhibit SCE-10. Cost reductions are also targeted. Current efforts have not impacted line 3
organizations that directly serve customers, such as line crews and customer representatives at our call 4
center. Funding for certain targeted and critical organizations such as safety, compliance, security and 5
cybersecurity will also be increased appropriately. Cost efficiency is not looked at in isolation, as we 6
must also consider the consequences of reducing costs. For example, the lowest cost could result in 7
lower reliability and customer service. Rather, we examine our performance across all of our strategic 8
operational goals, including safety, reliability, and customer satisfaction. 9
2. State Policy Objectives 10
a) Environment 11
SCE has a long history of environmental leadership and it will remain a key 12
component of our future efforts. We are well aware that our customers and all Californians have an 13
interest in improving the environment. An ongoing aspect of this is providing regulators with quality 14
data regarding the cost of policy options and the environmental benefits of those options, so that 15
policymakers can make informed decisions based on complete information. Once a policy decision is 16
made, our focus shifts to implementing the policy in the most effective manner and with the least 17
disruptive transition. Many of the environmental programs that we pursue show up in programs outside 18
the GRC, but some of the environmentally driven projects that affect our request are described below. 19
Starting in January 2013, the California Air Resource Board began a cap and trade 20
program for Greenhouse Gas (GHG) emissions. SCE participates in this program in various ways. The 21
cost of GHG emissions has become, like natural gas fuel, a cost associated with operating or purchasing 22
power from fossil generating plants. SCE now buys and sells emissions allowances to hedge its market 23
cost in much the same way that we deal with natural gas. We must monitor the GHG market and deal 24
with its market design, as well as the impact it has on electricity markets. The new costs and systems to 25
deal with this new responsibility are captured in our trading function, as well as in environmental policy 26
and market monitoring. 27
Market and policy forces continue to accelerate the connection of many types of 28
transportation technologies to the electric grid and the use of electricity as a new transportation fuel. We 29
continue to develop policies and strategies to realize the customer, system operation, air quality, and 30
greenhouse gas reduction benefits associated with this transformation, and at the same time prepare for 31
9
the potential impacts to our infrastructure, operations, and customers. The majority of the costs 1
associated with these efforts are captured in the testimony submitted on behalf of the integrated 2
planning/environmental affairs, distribution, and customer service areas of the Company. 3
b) Supporting the Communities We Serve 4
The Commission’s longstanding policy is that corporate charitable contributions 5
are not recoverable from customers, and, should be funded solely by shareholders. I mention our 6
charitable contributions only in the context of our overall efforts to be a good corporate citizen. 7
Giving to the community is a time-honored SCE tradition. Our employees find 8
many ways to donate both their time and money. In 2012, our employees and retirees recorded over 9
190,000 volunteer hours helping their communities. SCE employees are also actively involved in their 10
communities through service on many non-profit boards. 11
Funded entirely by shareholders, we donated $19.2 million in 2012 to help build 12
stronger communities, with 86 percent of our donations supporting underserved populations. Our 13
donations are focused in four areas: (1) Education – 50 percent of our contributions went to education 14
programs; (2) Environment – our contributions funded at-risk youth job training in environmental arenas 15
such as residential energy assessments; (3) Public Safety and Preparedness – our parent company Edison 16
International, joined the American Red Cross and committed $1.5 million to launch Prepare SoCal, a 17
three-year emergency preparedness campaign to prepare Southern Californians for catastrophic 18
disasters; and, (4) Civic Engagement – we made grants to 1,300 community-based organizations and 19
partnered with local non-profit and faith-based organizations to inform underserved communities about 20
our programs and services. 21
3. Fuel And Purchase Power Portfolio Optimization 22
SCE procures approximately two-thirds of the electricity needs of our customers from 23
third-party independent power producers via both short-term (less than 1-year) and long-term (up to 20-24
year) contracts, with the remainder coming from our utility-owned generation resources. Our fraction of 25
utility-generated power will only decrease with the SONGS units retired. Additionally, we procure all 26
fuel for our gas-fired generating resources and for some of our contracts. This contracted generation and 27
fuel procurement makes up our Fuel and Purchase Power portfolio. 28
In 2011, we intensified our focus on optimizing our fuel and purchase power portfolio to 29
better match our customer needs to our current and future generation contracts. As a result, we took 30
actions to reduce customer costs including selling excess generation, negotiating price reductions, 31
10
negotiating deferrals of the start date of contracts, and terminating or replacing contracts. The portfolio 1
optimization we undertook in 2011 and 2012 will achieve savings of hundreds of millions of dollars 2
over the years 2011-2015. We will continue this increased focus for the foreseeable future. While this 3
does not directly impact our GRC request, it is another example of looking at all opportunities to reduce 4
costs to facilitate grid infrastructure investments while keeping rate increases modest. 5
C. Reliability 6
1. System Reliability And Infrastructure Replacement 7
Our customers expect electric power to be available at their homes and businesses 24 8
hours a day, 7 days a week. Reliably providing that service requires a vast infrastructure of 9
transformers, circuit breakers, overhead and underground lines, other critical equipment, and employees 10
to operate and maintain it. 11
Much of our infrastructure was installed in the 1950s and 1960s and continues to age. 12
There is a relationship between the age of equipment and its likelihood of failure. Reducing the 13
frequency with which this aged infrastructure fails in service requires a sustained increase in 14
infrastructure investment compared to what we have spent in the past. 15
In our 2006 and 2009 GRCs, we proposed a stepped-up program of infrastructure 16
replacement spending. However, for the most part, the Commission limited our authorized 17
infrastructure replacement spending in those cases to what we had spent in the past. As the average age 18
of our equipment begins to approach the mean time to failure for that class of equipment, it becomes 19
critical to achieve replacement rates at levels at or above the “equilibrium replacement rate,” which is 20
defined as the equipment population divided by the mean time to failure. 21
In our 2012 GRC, the Commission did recognize our need to increase spending on aging 22
infrastructure. However, those problems cannot be remedied over a single GRC cycle; they require a 23
sustained commitment over multiple rate case cycles. In fact, most equipment replacement rates remain 24
below the equilibrium rate for many of our distribution asset classes (underground cable, poles, 25
switches, and transformers). To facilitate this investment we must prioritize infrastructure replacement. 26
Even within infrastructure replacement programs themselves, we must prioritize and focus on equipment 27
types that have the greatest safety concern and contribution to the frequency and duration of system 28
interruptions, e.g., underground cable. 29
In this GRC, we have once again proposed investment programs to address the reality of 30
an increasingly aging infrastructure. These programs include our Pole Loading Program (PLP), which I 31
11
separately discuss in the following section, our various inspections and maintenance programs, which 1
are designed to identify and repair incipient problems, and our infrastructure replacement program, 2
which is designed to replace infrastructure based on its age before it fails in service. David Mead, our 3
Senior Vice President of Transmission and Distribution, and other witnesses in that operating unit, 4
discuss these programs in detail in Exhibit SCE-03. 5
2. PLP Is A New Initiative To Bring All SCE Pole Assets Up To Specified Standards 6
Poles that do not meet minimum regulatory and safety requirements may break or fail at 7
wind speeds that are below the minimum design wind speeds for that geographic location, resulting in 8
an increased risk to public safety and reliability. Our design and construction standards require that 9
newly constructed poles meet the safety factors specified in GO 95 at the time of installation, plus 10
enhanced standards that have been established to account for local high wind or high fire conditions. 11
The intrusive inspection program is designed to identify and replace poles showing signs of 12
deterioration. Nonetheless, SCE has found that when poles are tested using modern methods to 13
calculate the safety factor, a percentage of in-service poles do not meet minimum GO 95 requirements, 14
even when deterioration is excluded from the calculation. 15
The main reasons poles may have inadequate safety factors are: (1) changes made to the 16
configuration of the pole after construction but before the late 1990s, when the process for calculating 17
pole loading became computerized; (2) the rapid growth of telecommunications attachments made by 18
companies (joint owners or tenants) when pole loading calculations were either not undertaken or were 19
inadequately performed, or when we and the communications company use different assumptions or 20
methodologies for performing pole loading; and, (3) changes over time to the methodology for 21
performing pole loading, which has resulted in poles that passed under an old methodology not passing 22
today using current methodologies. 23
Just as we conduct GO 165 inspections to identify and remediate visible GO 95 non-24
conformances on overhead and underground facilities, we have designed a PLP that will test each of our 25
over 1.4 million poles over a seven-year period to identify and then remediate those poles that do not 26
meet the current standards. While inspecting over 200,000 poles per year is a significant logistical 27
challenge, the seven-year inspection program is guided by our best estimate of replacement rates driven 28
by the inspections and the specified time frames for repair in the regulations. Pole replacement rates for 29
the seven-year program are estimated to be 25,000 poles per year. This is near the equilibrium 30
replacement rate of 31,000 poles per year (over 1.4 million poles with a 45-year life ). As part of PLP, 31
12
we will engage regulators and those who attach equipment to our poles to: perform benchmarking, 1
establish best practices for performing pole loading, and improve data sharing among all companies in 2
SCE’s service territory who perform pole attachments. PLP will be a significant driver of pole 3
replacements and preventive maintenance expense, as discussed by Ken Trainor, our Director of Pole 4
Assessment and Remediation, in Exhibit SCE-03. As we address loading issues, we will be 5
concurrently and proactively replacing aging equipment like pole top transformers and pole switches, 6
thereby realizing an increased benefit for our Infrastructure Replacement program. 7
The full magnitude of the PLP investments we will need to make is difficult to predict 8
until we have more experience with the program. At the same time, it is crucial that we replace those 9
poles that need to be replaced to protect system reliability. Therefore, in this GRC we are proposing a 10
two-way balancing account for PLP. Doug Snow discusses the ratemaking details of the PLP balancing 11
account in Exhibit SCE-10. 12
3. Non-Nuclear Generation Reliability 13
In addition to grid reliability, we must also focus on the reliability of our non-nuclear 14
electric generation resources. We track non-nuclear generation reliability with a Generation Reliability 15
Index, which measures reliability performance of our hydroelectric and natural gas fired facilities, 16
including both planned and forced outages. Our goal is to achieve a Generation Reliability Index of 82 17
points or higher on average from 2015-2017. This is an ambitious goal, one that requires our generating 18
assets to perform at or above historic reliability levels. 19
To achieve this goal, our power plant employees must manage maintenance and capital 20
project work within aggressive planned outage durations. During the upcoming three-year rate cycle, 21
this work includes turbine overhauls at our Mountainview power plant and refurbishment work at 22
several of our hydroelectric dams and other generation infrastructure. Some of the challenges we face in 23
doing this work include handling any unforeseen equipment problems and other emergent repairs that 24
we encounter, obtaining sufficient contractor resources, and getting timely delivery of parts and 25
materials. Tom Ware discusses this further in Exhibit SCE-02. 26
D. Affordability 27
1. System Average Rate Impacts 28
In each general rate case, much attention is put on the utility’s unit cost of providing 29
service, which in our case is the cents per kilowatt-hour rate. What matters much more to customers, 30
however, is their total bill, because that is what they ultimately pay for electricity. A customer with a 31
13
lower cents/kilowatt-hour rate but with higher energy usage can end up paying the same total bill as one 1
with a higher rate but lower usage. Compared to most other utilities around the nation, our residential 2
customers consume less energy. This is due in part to our weather and in part to California’s energy 3
efficiency efforts. Figure II-2, below, compares the consumption of an average SCE customer to that of 4
customers of the largest 50 investor-owned utilities around the U.S. 5
14
Figure II-2 Southern California Edison
Comparison of Average Residential Consumption for the 50 Largest IOUs (Ranked by Sales)
976.57
590.27
0
1,000
2,000
3,000
4,000
5,000
6,000
Mon
thly kWh
Source: EIA's Form 826 Data Monthly Electric Utility Sales and Revenue Data (2012)
AVERAGE
15
As you can see from Figure II-2, the average electricity consumption of our residential 1
customers is very low compared to that of our peers. This is what helps keep our overall residential 2
customer bills low. But there is another effect of our customers’ lower usage. Electricity is largely 3
billed based on kilowatt-hours consumed, that is, on a variable basis. But many of our costs are 4
relatively fixed. For example, the cost of installing and maintaining a meter does not vary directly based 5
on how many kilowatt-hours a customer uses. However, the less energy our customers consume, the 6
smaller the base is over which we can spread our fixed costs. So, lower energy consumption can have 7
the effect of increasing the per kilowatt-hour rate. The combined effects of rates and consumption come 8
together in the monthly bill. 9
Figure II-3, below, compares the average bill of an SCE residential customer to those of 10
customers of the largest U.S. investor-owned utilities. As you can see from Figure II-3, the average 11
SCE residential customer’s total electric bill is far below the median. Because the customer’s total bill 12
is what affects his or her pocketbook, this is the most meaningful benchmark to use when comparing 13
utilities. 14
The average bill of our commercial customers was approximately at the national average, 15
$724.56 for SCE commercial customers versus $724.43 nationally. Because of the wide differences 16
between industrial customers in our service territory compared to those in other states, comparing the 17
average bills of our industrial customers to those of other utilities is difficult. 18
16
Figure II-3 Southern California Edison
Comparison of Average Residential Bills for the 50 Largest IOUs (Ranked by Sales)
120.43
94.12
$‐
$25
$50
$75
$100
$125
$150
$175
$200
$225
$250
$275
$300
$325
$350
$375
$400
$425
$450
$475
$500
$525
$550
$575
$ per M
onth
Source: EIA's Form 826 Data Monthly Electric Utility Sales and Revenue Data (2012)
AVERAGE
17
2. Facilitate Grid Investment 1
As noted earlier, significant infrastructure investment is required to meet reliability 2
concerns and State policy objectives. Infrastructure investment puts upward pressure on rates. Modest 3
rate increases can be obtained provided O&M expenses are optimized. As noted above, SCE has 4
implemented an Operational Excellence framework that has increased productivity and significantly 5
reduced expenses. Prioritization of capital investment and operating cost reduction are key steps we 6
have taken to facilitate infrastructure investment and maintain affordable rates. Every dollar of 7
operating and maintenance expense that can be reduced yields significantly greater dollars for capital 8
investment. Further operating cost optimization efforts are targeted in this request. Fuel and purchased 9
power portfolio optimization efforts have a similar leveraged impact for facilitating capital investment 10
while moderating customer rate increases. 11
3. Utilities Must Retain Spending Flexibility 12
Emerging priorities may require a utility to spend differently than forecast.4 That is, 13
recorded amounts may differ from the particular O&M expense and capital expenditure amounts that 14
form the basis of the adopted test year revenue requirement. The Commission has long held that under 15
forecast test-year ratemaking the utility retains spending flexibility. For example, in a 2002 decision on 16
the general rate case of California-American Water Company, the Commission recognized that “actual 17
rate base and expenditures can and do change between the time rates are set and the time events occur” 18
and that “there is no requirement of the utility to spend exactly, or only, the projected amount on each 19
rate base or expenditure component used to set rates.”5 That decision also left “the fine-tuning of a 20
utility’s operation to the discretion of its management” such that management discretion is exercised in 21
allocating total dollars for capital and expense items to those areas where the capital and expense is most 22
necessary, as dictated by constantly evolving priorities.6 23
Due to several reasons, most importantly the delay in SCE’s 2012 general rate case 24
decision, the amounts recorded in 2012 differed from those the Commission adopted, both in total and in 25
terms of the specific categories. I discuss this further in Chapter III of this testimony. 26
4 For instance, more customers that SCE has an obligation to serve may request new service than we forecast in the GRC
proceeding. It would not be prudent or consistent with customer expectations to refuse new service until the next GRC proceeding authorizes those non-forecast expenditures.
5 Re California-American Water Co., D.02-07-011, (mimeo), pp. 6-7, 2002 Cal. PUC LEXIS 423, 220 P.U.R. 4th 556.
6 Id.
18
4. The Commission Should Adopt A Post-Test Year Ratemaking Mechanism That 1
Allows SCE The Opportunity To Recover The Costs Of System Investments In 2016 2
And 2017 3
As we have in prior GRCs, in this 2015 GRC we are providing testimony supporting 4
planned system investment for the entire forecast period between our last recorded year (2012) and the 5
next Test Year (2018), that is, for the five-year period 2013-2017. As we have also done in prior GRCs, 6
we have proposed a Post-Test Year Ratemaking Mechanism that would provide us a reasonable 7
opportunity to recover the costs of those investments during the two Post-Test Years, 2016 and 2017. 8
Dr. Paul Hunt describes our Post-Test Year Ratemaking proposals in Exhibit SCE-10. Our proposed 9
Post-Test Year capital expenditures are found throughout the testimony accompanying this GRC 10
submission. 11
Our capital expenditure testimony gives the Commission the facts necessary to make 12
findings on the reasonableness of our proposed Test Year and Post-Test Year capital investments. It is 13
crucial that we have the Commission’s guidance on the overall amount of system investment it expects 14
us to make, not just for the Test Year, but for the entire GRC cycle. However, I also recognize that in 15
recent GRCs the Commission has declined to review our testimony on Post-Test Year capital 16
expenditures and has instead adopted a formulaic approach to setting rates for those years. If the 17
Commission decides to choose that path again in this 2015 GRC, then I would caution against adopting 18
a mechanism that precludes us from a reasonable opportunity to recover the costs of our system 19
investments. 20
Although the Post-Test Year Mechanism adopted in our 2012 GRC did not specifically 21
address our 2013 and 2014 expenditures, it was constructive in that it included a reasonable escalation 22
rate and a mechanism to adjust rate base for capital additions that we made subsequent to the Test Year. 23
This is very important when you have a significant capital investment program such as what we are 24
proposing in this GRC. In contrast, the mechanism adopted in our 2009 GRC merely escalated the 25
bottom line revenue requirement. That approach did not even allow us to recover all of the capital 26
investments pending in Construction Work in Progress as of the 2009 Test Year, even though the 27
Commission had found those amounts reasonable.7 While I urge the Commission to review for 28
7 While O&M expenses can usually be deemed proportional to the overall revenue requirement, and therefore quantifiable
in the post-test years, the same is not true of capital-related items such as depreciation, deferred taxes, etc.
19
reasonableness all our capital expenditure estimates for the entire 2013-2017 period, if it instead opts for 1
a formulaic approach I caution against the kind of mechanism adopted in our 2009 GRC. Such a 2
mechanism will not support the post-test year program proposed. 3
5. Impact Of Deferred Depreciation On Future Customers 4
Throughout our testimony we’ve identified the capital expenditures we need to make to 5
continue providing safe and reliable electric service to our customers. Those capital investments 6
provide service over many years and our investors recover their costs of those investments over the 7
assets’ service lives. The amount of annual recovery of those investments is known as depreciation 8
expense. It is typically calculated by first determining a rate by class of plant asset, which is then 9
multiplied by the investment balance to yield depreciation expense. 10
Several parameters determine the depreciation rate, principally the service lives of the 11
investments and the cost to remove them. In each GRC, we submit a depreciation study that presents 12
our analyses of those parameters. The primary driver of our increasing depreciation rates is the cost to 13
remove assets at the end of their service lives. In our 2012 GRC, we proposed depreciation rates 14
designed to moderate this growth in removal costs over several GRC cycles. The Commission’s 15
decision in the 2012 case adopted some increases in depreciation rates, acknowledging the evidence of 16
increasing removal cost. In this 2015 GRC, we are once again asking the Commission to revise our 17
authorized depreciation rates based on an up-to-date depreciation study, which our consultant, Dane 18
Watson, and SCE witness Rick Fisher present in Exhibit SCE-10. 19
But beyond the results of those analyses, the depreciation rate also presents an important 20
policy decision for the Commission. The depreciation rate affects both the utility’s earnings and its cash 21
flow. For a given level of capital investment, the lower the depreciation rate the longer the investment 22
will remain in rate base, where it earns a rate of return. So a lower depreciation rate contributes to 23
higher utility earnings (and a higher customer cost over time). On the other hand, the higher the 24
depreciation rate, the less time the investment remains in rate base (and lowers customer cost over time). 25
So a higher depreciation rate contributes to lower utility earnings, but increases cash flow as the original 26
investment costs are recovered more rapidly. That cash flow provides the lowest cost source of funds 27
for the utility to reinvest in the system. 28
Of course, the Commission must strike the right balance in setting depreciation rates. 29
Intergenerational equity is an important factor in striking this balance. This fundamental ratemaking 30
principle requires that capital asset cost recovery be borne by the customers who receive the service that 31
20
asset provides. If the Commission sets depreciation rates too high, then current ratepayers would pay 1
more than their fair share. Conversely, if depreciation rates are set too low, then future customers will 2
still be paying the original cost of assets that have already been retired. In addition to considering the 3
impact on current rates, the Commission should keep in mind this intergenerational equity issue when it 4
adopts depreciation rates in this proceeding. 5
6. Supplier Diversity 6
The Commission’s GO 156 addresses California utilities’ efforts to provide business 7
opportunities to women, minority, and disabled veteran business enterprises (WMDVBEs). An 8
expanded and diverse supplier base will increase competition, and over time, decrease price and increase 9
quality for goods and services provided. Our outreach efforts to diverse suppliers include ethnic trade 10
associations and community-based business organizations, to which we provide financial support, in-11
kind donations, and technical assistance. We have been reaching out to diverse suppliers for more than 12
30 years. While we are never satisfied with our achievements and strive for continuous improvement, I 13
am pleased to highlight some of the progress we’ve made in this area over the past few years. 14
Since 2008, our total annual procurement outlays increased by 57 percent; procurement 15
from WMDVBEs rose nearly 200 percent, a total spend of $5.3 billion to diverse suppliers. In 2012, our 16
percentage of WMDVBE spending was 38 percent, surpassing the GO 156 target of 21.5 percent and 17
approaching the Commission’s aspirational goal of 40 percent. Our WMDVBE spending percentage 18
ranked second among California investor-owned energy utilities. In 2011, our spending was 27 percent 19
and ranked fourth among the energy utilities. Supplier diversity is an excellent example of our 20
Operational Excellence framework – we measured, we benchmarked, we improved, and we are 21
repeating. 22
Our commitment to WMDVBEs also shows in our subcontracting. Spending with 23
diverse subcontractors grew to over $550 million in 2012, a 16.9 percent increase from 2011. We added 24
43 new WMDVBEs subcontractors in 2012. We also contributed to capacity building by awarding 600 25
diverse suppliers with contracts under $1 million; 238 of these 600 diverse suppliers were smaller 26
enterprises with total revenues under $1 million. We have also pursued arrangements with minority-27
owned firms for investments in our pension and nuclear decommissioning trusts and to underwrite our 28
long-term debt and preferred stock offerings. 29
In 2012, over 145 diverse suppliers participated in our technical assistance and capacity 30
building programs. One program boosted diverse enterprises in three different ways – dedicated 31
21
mentorship programs, comprehensive readiness workshops, and increased networking opportunities 1
such as our Veterans and Edison Teaming Successfully (VETS) program. We also partnered with the 2
Los Angeles Chapter of the National Association of Women Business Owners for a grant to fund its 3
Peak Leadership Program. This program provided courses on innovative problem-solving for women 4
business owners, and offered how-to classes to assist diverse enterprises in growing their businesses. 5
Finally, we sought and contracted with diverse suppliers for natural gas and electricity for the first time 6
in 2012 and generated $34 million in procurement opportunities for these companies. Joe Alderete 7
discusses our supplier diversity efforts in greater detail in his testimony in Exhibit SCE-08. 8
E. Customer Service 9
1. Customer Satisfaction 10
In keeping with our Operational Excellence framework, we regularly assess our 11
customers’ satisfaction with our service. Figure II-4, below, charts our Customer Satisfaction Index, or 12
CSI, over the period 2007-2012. Surveys conducted by J.D. Powers show that both our residential and 13
business customers ranked us in the First Quartile in 2012, despite challenges such as new dynamic 14
pricing rates for business customers, planned outages driven by infrastructure improvements, and rate 15
increases. While we are proud of the work our employees have done to achieve this rating, we are not 16
content to rest on our laurels. Our core value of continuous improvement means that we continue our 17
efforts to improve customer satisfaction. Erwin Furukawa and other witnesses in our Customer Service 18
organization discuss this more in Exhibit SCE-04. 19
Additionally, to increase accessibility of our facilities and systems to customers with 20
disabilities, we jointly developed a proposal with the Center for Accessible Technology. J.P. Shotwell 21
discusses this proposal in Exhibit SCE-12. 22
22
Figure II-4 J.D. Power Residential And Business – Customer Satisfaction Trend for SCE
1st
2nd
3rd
4th
0%
25%
50%
75%
100%
2007 2008 2009 2010 2011 2012 2013
J.D. Power Business
J.D. Power Residential
2. Outage Communications 1
SCE is currently first quartile among US utilities with regards to frequency of sustained 2
interruptions to customers and is second quartile for duration of these interruptions. Favorable weather 3
conditions drive some of this performance. Continued infrastructure replacement, as noted earlier, will 4
be necessary to stem the declining trend in these reliability measures. Despite these favorable statistics, 5
we continue to struggle with customer perceptions of our reliability. The apparent driver for this 6
perception is the timeliness and accuracy of our estimated restoration times when an outage occurs. To 7
counter this perception, we are continuing our efforts to improve our outage communications for both 8
planned and unplanned outages. 9
Business customers now receive automated messages when they experience an outage. 10
During unplanned outages, business customers will now receive a message that we are aware that they 11
are affected by an outage. We will also provide status updates and service restoration notices when 12
available. 13
During planned outages, customers will now receive automated alerts of the scheduled 14
maintenance, a reminder the day before, and notices of any cancellations, reschedules, or delays. 15
Previously, customers received single notifications three to five days before the scheduled date. With 16
23
the new automated communications systems customers now receive an initial notice ten days before the 1
planned event, giving them twice the time to plan, plus the day before reminder. 2
In Section H, below, I discuss some of the steps we have taken since the 2011 San 3
Gabriel Valley windstorm event to improve our response to emergencies. Those efforts include 4
improvements in how we communicate outage information to our customers. First, for our Medical 5
Baseline customers, we have added automated phone messages to our previously existing email, text, 6
and TTY messaging. If we estimate that an outage will last more than 12 hours, we now contact any 7
impacted Medical Baseline customers who could not be contacted by phone by sending a field employee 8
to their residence. We also changed our process so that all impacted Medical Baseline customers will 9
now receive an outage alert unless they have actively opted out of the notification process. 10
Customers experiencing an outage now receive a Forecasted Estimated Restoration Time 11
(FERT) for 80 percent of our impacted customers within the first hour of the outage. Previously, the 12
system would generate an estimate using a default of 4 hours during normal operations and 24 hours 13
during a storm, or there would be no estimate until a visual inspection was performed by our field crews 14
so that an estimate could be established, which often took several hours. Our new FERT is calculated 15
based on historical outage restoration times during normal operation and storms by the affected device 16
type and the geographic location. Our crews still provide an update once visual inspection is completed 17
and replace the FERT with an actual Estimated Restoration Time. We also launched new web and 18
mobile applications that allow customers to view key outage information, report outages, and request 19
status updates via email, text, or phone. Erwin Furukawa and other witnesses in our Customer Service 20
organization discuss these efforts further in Exhibit SCE-04. 21
F. People 22
1. Work Environment 23
Throughout this 2015 GRC testimony, you will read about the efforts we are engaged in 24
to provide safe, reliable, and affordable power to our customers. We would not be able to accomplish 25
any of this without the dedicated people who comprise the SCE workforce. As I mentioned above, one 26
of our core values is continuous improvement. To further improve our work environment we have 27
developed a plan that includes four key areas: 28
Improving our management and leadership expertise and behaviors; 29
Changing our organization structure to reduce layers of management and streamline 30
communications; 31
24
Listening to our employees and resolving issues; and 1
Improving workplace security. 2
Improving our work environment is most important to me and the rest of SCE senior 3
management. In fact, fostering a positive work environment is just as important as safety and 4
compliance. We are developing metrics to measure our effectiveness in improving our leadership 5
quality and work environment. We are also committed to keeping our employees informed of these 6
efforts, which Pat Miller, Vice President of Human Resources, discusses in more detail in Exhibit SCE-7
06. Steps we are taking to improve workforce security are discussed by Don Daigler in Exhibit SCE-07. 8
2. Diversity 9
Our workforce must reflect the communities we serve. As those communities have 10
become increasingly diverse so has our workforce. As of December 2012, minorities made up 54 11
percent of SCE’s employee population. Table II-1, below, shows the make-up of our Executive, 12
Management & Supervision, and Total Workforce populations. 13
Table II-1 SCE Workforce Demographics
25
While we have more work to do, we have made solid progress in this area, including 1
focused recruiting and internal development programs. Pat Miller, our Vice President of Human 2
Resources, describes these efforts more fully in Exhibit SCE-06. 3
3. Compensation 4
To attract, motivate, and retain a qualified workforce, we offer compensation consisting 5
of a mix of base pay, incentive pay, and benefits. All full-time SCE employees are eligible for our 6
incentive compensation program. Our policy is to target employees’ total compensation to the median 7
paid by other employers with which we compete for labor. At the Commission’s direction, in each of 8
our general rate cases we submit a study performed by an outside expert that is jointly selected and 9
managed by us and the Commission’s Office of Ratepayer Advocates. 10
In our 2006, 2009, and 2012 general rate cases, the Total Compensation studies showed 11
that our mix of employee compensation was essentially at market. Despite this evidence, the 12
Commission disallowed 50 percent of our executive officers’ incentive compensation and 100 percent of 13
their long-term incentive pay.8 In our 2012 general rate case, the Commission also decided to cut 10 14
percent off our rank-and-file employee incentive compensation. In my view this result is unfair, 15
illogical, and inconsistent with past Commission decisions and cost of service ratemaking principles. 16
Employee compensation is an essential component of our cost of providing service. If our total 17
compensation package is at market, then we are paying what the market demands for our labor 18
resources. Presumably, if we had chosen to pay our employees the same amount of total compensation, 19
but solely in the form of base pay (i.e., with no benefits or incentive compensation), that compensation 20
would be approved for full recovery from customers. I simply do not understand how our customers are 21
harmed by our decision to offer a mix of compensation that includes incentives, or how they would be 22
better off if we were to shift that incentive compensation to base pay. In fact, in my view customers are 23
better off when part of employee compensation is in the form of incentive pay because it is a better tool 24
to align performance with metrics such as safety and reliability. 25
In this 2015 GRC, I urge the Commission to rethink the policy it adopted in our 2012 26
general rate case and allow full recovery of our employee total compensation. 27
8 Long-term incentives were not an issue in our 2006 general rate case.
26
G. Enterprise Risk Management 1
1. Business Resiliency and Emergency Response 2
On November 30, 2011, Southern California experienced a severe wind storm causing 3
significant electric system damage in the San Gabriel Valley area and interrupting electric service to 4
over 400,000 customers. The storm damage led to power outages to some customers for up to seven 5
days. Our response to this event was not satisfactory. As a result of our post-event assessment, an 6
independent evaluation performed by Davies Consulting, feedback secured through public participation 7
hearings, and a preliminary report by the Commission’s Consumer Protection and Safety Division (now 8
Safety and Enforcement Division), we identified a number of opportunities for improvement. 9
We launched our Corporate Storm Performance Improvement Program in May 2012, 10
aimed at modifying our storm processes and procedures to strengthen restoration response and improve 11
communications performance. We implemented a number of improvements to enhance our awareness 12
of storm events and their potential impact on our electric system, and our ability to quickly gauge the 13
extent of damage post-event and effectively transition to an area-based restoration approach when 14
appropriate. We also put into place processes and programs to ensure that call center personnel are 15
effectively trained, communications with elected officials during an event are improved, and medical 16
baseline and critical care customers are notified in the event of a prolonged interruption in service. 17
These revised processes and procedures, along with the incorporation of Federal Emergency 18
Management Agency’s (FEMA) Incident Command System (ICS), have been included in our Corporate 19
Emergency Response Plan which will be filed as part of our GO 166 submittal by October 31, 2013. 20
We are very much aware of the need to be prepared to take an active role, including a 21
leadership role, in a “whole community response” to large-scale outages and other emergency situations. 22
The improvements we have made to date to our internal systems and processes and those that allow us to 23
integrate with public sector response entities illustrate our commitment to this concept. We also 24
recognize that storms are not the only potential threat faced by the company and our customers. We will 25
continue to advance our corporate resiliency capability to include an all hazards approach as we strive 26
for excellence in providing critical services to our communities. 27
The customers we serve expect us to respond no matter what the circumstances, much in 28
the same way they expect public sector emergency response entities such as Police and Fire to respond 29
regardless of the circumstances. We take this responsibility seriously. As described above, we recently 30
implemented ICS. This system is described by FEMA under the National Incident Management System 31
27
and is recognized and adopted by most of the nation’s first responder communities. The system 1
provides consistency and a scalable framework for managing emergency incidents regardless of size. 2
By taking this step we are more effective in organizing our resources, but even more importantly, the 3
way we respond and the way we communicate is now consistent with other first responder 4
organizations, thus making us a more resilient company. 5
As a further demonstration of this commitment, we conducted a series of drills in 2012 6
that were independently evaluated by agencies such as CalFire, Los Angeles County Fire/Sheriffs, FBI, 7
and Riverside County Office of Emergency Services. Implementing these standard emergency response 8
protocols and taking steps to improve mutual understanding of the respective operations of utility 9
personnel and first responders are significant improvements. However, we need to increase our 10
investment in technology, facilities, and equipment to provide further assurance that we can respond to 11
significant events and adequately manage restoration of electric service no matter what the circumstance 12
may be. Veronica Gutierrez, Vice President of Local Public Affairs and Dana Kracke, Vice President of 13
Safety, Security and Compliance discuss our efforts to work with the communities we serve to prepare 14
for disasters in Exhibits SCE-09 and SCE-07. 15
2. Cybersecurity 16
Providing reliable electricity to our customers requires us to construct, operate, and 17
maintain a vast electric system. The grid is controlled by Supervisory Control and Data Acquisition or 18
“SCADA” systems. The protection of SCADA systems from attack has become increasingly important 19
and is a key focus of federal policy makers who recognize the electrical grid as critical infrastructure and 20
the vulnerability of that system to a potential attack. A significant grid interruption caused by a cyber 21
attack would severely impact customers and the economy. Like other operators of critical infrastructure, 22
we are facing more frequent, more destructive, and more sophisticated cyber threats which threaten grid 23
reliability. In addition to cybersecurity improvements, we are also planning robust physical security 24
systems for critical grid infrastructure and SCADA facilities. 25
Protection of SCADA systems and grid reliability is not the only cyber threat we need to 26
be concerned about. We must also protect our significant business systems to ensure business 27
transactions are not interrupted. Our business systems also include significant customer data and this 28
data must be protected from cyber-attacks to protect customer privacy. 29
The Internet has allowed unprecedented access to information and has dramatically 30
increased the speed at which information can be transmitted. While this has enabled tremendous 31
28
increases in productivity, including the growing dependence on mobile technologies and wireless 1
communication, it has also led to greater risk of security vulnerabilities. According to the U.S. 2
Computer Emergency Readiness Team (US-CERT), reported cyber incidents have been steadily 3
increasing year over year, with an astounding 78 percent increase from 2006 to 2012. According to the 4
General Accounting Office, reports of cyber incidents affecting national security, intellectual property, 5
and individuals have been widespread. Reported incidents involve data loss or theft, economic loss, 6
computer intrusions, and privacy breaches. SCE is not immune from these trends. Figure II-5 illustrates 7
the significant growth in detected intrusion attempts into SCE’s network over the period 2008-2012. 8
A robust cybersecurity regime is crucial to maintaining the reliability and resilience of 9
both the nation’s electric grid and SCE’s electric infrastructure. Federal standards are effectively 10
pushing the cost of national defense to the private sector and that challenge must be met. The same 11
defense-in-depth approach we use to protect our corporate computer network and systems is also being 12
applied to the grid network to provide a flexible framework for improving cybersecurity defenses. 13
As our systems become more integrated and business critical, the importance of 14
safeguarding them against cyber threat increases. As technology continues to advance, the complexity 15
of security threats also continues to advance, and SCE’s efforts to defend against them must also 16
advance. Glenn Haddox, Director of Cybersecurity & IT Compliance discusses this important matter in 17
further detail in Exhibit SCE-05. 18
29
Figure II-5 SCE Detected Intrusion Attempts
‐
25,000
50,000
75,000
100,000
125,000
150,000
175,000
200,000
225,000
250,000
275,000
300,000
325,000
350,000
2008 2009 2010 2011 2012
3. Enterprise Risk Management Program 1
Understanding the wide range and magnitude of risks facing our company is critical to 2
our success in meeting customer needs. Our Enterprise Risk Management (ERM) program provides us 3
the tools to characterize our risks and work across our company to develop strategies on how we might 4
address potential impacts. As we move forward, we will be making every effort to better align our risk 5
management efforts with all of our company activities to help make sure that corporate resiliency is part 6
of the SCE culture. By doing so we will be able to more efficiently and effectively provide our 7
customers with safe and reliable electricity at an affordable price. 8
An annual risk identification process is performed jointly by our ERM, Internal Audits 9
and Compliance groups. The process encompasses risks such as public and employee safety, electric 10
30
system reliability, financial stability, and risks associated with a large catastrophic event. Once risks are 1
identified, the ERM process establishes accountability to manage the specific risks and supports the 2
execution of mitigation activities. These mitigation activities may include actions taken to reduce the 3
possibility of the risk occurring, to reduce the impact of the event if it does occur, or to accelerate 4
recovery from the risk event. For example, mitigation activities may include additional inspections on 5
electrical plant to identify physical issues, purchasing insurance to cover losses, or developing a 6
response plan to prepare for an unpredictable event such as an earthquake. Mitigation activities are one 7
of the considerations we use to set our corporate and operating unit goals and to integrate corporate 8
resiliency into our operating culture. 9
We are also looking at our current planning activities to align our plans across each of our 10
operating units and so that the plans are designed to meet the needs of the most catastrophic events. As I 11
stated earlier, our approach will be based on an “All Hazards” convention which will help us be more 12
prepared for any type of event whether man made or an act of nature. We also recognize that a plan, 13
regardless of how well integrated, is of little value if it is not trained to or exercised. To that end, our 14
ERM program and Business Resiliency department are working jointly to develop a set of planning 15
factors that will drive our training and exercise efforts. These efforts will become progressively more 16
complex over the next year and will extend to include all levels of our company as well as our external 17
stakeholders within the private and public sectors. We fully expect to develop evaluation criteria to 18
assess our progress that is based on best practices and national standards. 19
While our ERM program continues to mature, the current state represents prudent 20
management of our resources by providing a structure to manage risks. This process “socializes” the 21
major issues the company faces, provides visibility of key risks to the company and places appropriate 22
mitigation plans in place. Although we have a structured risk management framework to proactively 23
identify and appropriately manage risks across the company, we will continue to look at opportunities to 24
further integrate our risk management efforts with our corporate resiliency efforts. Our efforts will 25
continue to evolve both from lessons learned from within and from benchmarking the activities of other 26
utilities. More information on our ERM program can be found in Exhibit SCE-08. 27
31
III. 1
IMPACT OF LATE 2012 GRC DECISION ON BUSINESS OPERATIONS 2
A. A Timely GRC Decision Is In The Best Interest Of Customers 3
Our GRC filing puts forward an ambitious and necessary infrastructure investment plan building 4
off the 2012 GRC decision and further advancing us to a point required for equilibrium replacement 5
rates to support the electric delivery system long term. This includes a new $1 billion initiative to bring 6
all SCE pole assets up to specified standards, including enhanced standards as may be necessary to 7
account for local high wind or high fire conditions. Support for these investments in the communities 8
we serve is critical for safety and reliability. 9
In order for customers to maximize the benefit from these and other proposed programs, a timely 10
GRC decision is required. A timely decision benefits all parties by clearly spelling out the capital and 11
operating plans prior to the start of the test year. Absent a timely GRC decision, SCE does not have 12
clarity on alignment of our proposals with the Commission and therefore SCE limits spending to critical 13
functions only. This has the result of delaying projects/programs and resulting benefits that both SCE 14
and the CPUC ultimately agree are in the best interest of customers. The only way to obtain clear 15
alignment is to have a timely decision. This also provides the most efficient means to ramp up or ramp 16
down projects or programs consistent with the Commission’s guidance. 17
B. A Memorandum Account Is Not An Alternative To A Timely GRC Decision 18
A memorandum account to track costs in the test year, while providing some help, is not an 19
acceptable alternative to a timely GRC decision. If SCE does not align with the CPUC on project 20
priorities, then we are left guessing on ultimately what we think the CPUC wants us to do. Although a 21
memorandum account may keep the utility and ratepayers reasonably whole in terms of revenue 22
requirement, a memorandum account does not fully offset the effects of a schedule delay. We fully 23
support that a memorandum account can be used effectively for short, unanticipated delays. However, 24
while the memorandum account can track dollars, it does not hold the utility harmless from procedural 25
delays, because the utility cannot move forward on important programs and investments until it knows 26
the Commission-authorized revenue levels. 27
SCE provides a vital service to our customers, and we have the responsibility to provide it in a 28
safe and reliable manner. This implicates our workforce, our many contracts with outside vendors, and 29
ultimately our ability to “keep the lights on.” While we always have the obligation to provide safe and 30
reliable electricity delivery on a day-to-day basis, longer term investments may be re-prioritized until 31
32
there is clarity surrounding our authorized revenue requirement. At SCE we work very hard so that our 1
expenditures are consistent with Commission authorized levels over time. Any delay beyond the start of 2
the test year impacts our business operations, hiring plans, capital project investments and program 3
delivery. We face serious challenges in many areas, including but not limited to replacing aging 4
infrastructure and maintaining grid reliability, handling continued system maintenance, improving safety 5
for our customers, our employees, and the general public, working toward meeting Commission policy 6
objectives such as the renewables goal for our mix of resources, providing for the security of our electric 7
grid, and minimizing SCE’s environmental footprint. The work that needs to be completed to preserve a 8
safe and reliable system requires advance planning and consistent work flows. SCE’s work cannot be 9
toggled “on and off” to conform to regulatory delays. Given the late 2012 GRC Decision we underspent 10
the 2012 authorized level and will need to increase our spending over the last two years of the GRC 11
cycle to make up for the constraints we operated under during 2012. 12
We are willing to do anything reasonably possible to get a timely 2015 GRC decision. We are 13
proposing a schedule consistent with the Commission’s Rate Case Plan that would provide for a timely 14
2015 GRC Decision. We have also established corporate goals to ensure the entire company is 15
responsive to data requests and supportive of the overall GRC process. I look forward to working with 16
the CPUC and intervenors in order to resolve any differences and get to work in order to safely and 17
reliably deliver the products and services our customers expect from us. 18
C. Authorized Versus Recorded Capital and Expense 19
In 2012 SCE did not spend the amounts ultimately authorized in the 2012 GRC decision. This is 20
not surprising given the timing of the decision and the wide range between SCE and intervenor positions 21
on specific costs forecasts and ratemaking proposals.9 This wide dispersion of intervenor proposals 22
significantly increased the risk that SCE would “get it wrong” if we went forward with our spending 23
plans as proposed in the 2012 GRC. However, SCE did spend what was needed in 2012 to provide safe 24
and reliable service in the short term and comply with applicable laws. The fact that we spent less than 25
authorized in 2012 is not a surprising outcome when alignment with the Commission is unknown. 26
While maintaining system safety and reliability in 2012 was a priority for me and for all SCE 27
employees, some projects and programs were not initiated in 2012. Given the ultimate Commission 28
approval for many of the programs and projects in the 2012 GRC, the men and women of SCE are 29
9 The Commission issued D.12-11-051, the final decision in SCE’s 2012 GRC, on December 10, 2012.
33
working across the 50,000 square mile service territory to ramp up these programs and projects so that 1
our customers can receive the benefits the Commission envisioned from that decision. My hope is that 2
the timing of the 2012 GRC decision was an anomaly and that we can come back into alignment with 3
the Commission in this 2015 GRC. My intent is to direct the company activities and deliver the 4
customer benefits envisioned in that decision and our 2015 proposal over the 2012 and 2015 rate case 5
cycles. Table III-2 and Table III-3, below, compare our 2012 authorized and recorded capital 6
expenditures and O&M expenses.10 7
Table III-2 SCE Capital Expenditures
($million)
2012 Recorded 2012 Authorized
CPUC Jurisdictional 2,128 2,539
FERC Jurisdictional 1,307 1,273
Total Company 3,435 3,812
Table III-3 SCE Expenses
($million)
2012 Recorded Costs 2012 Recorded Adjusted 2012 Authorized
2,621 2,409 2,566
10 The “Recorded Adjusted” column reflects various adjustments, principally one-time, non-recurring costs, which we
remove from the recorded base for forecasting purposes. The “2012 Authorized” does not include any O&M expense associated with the Four Corners generating station, as discussed in Exhibit SCE-02.
34
IV. 1
SUMMARY OF SCE'S REQUEST 2
A. Introduction and Summary of Proposed Increase 3
In this GRC application, SCE is requesting a base revenue requirement of $6.462 billion,11 4
effective January 1, 2015. This compares to a current authorized base rate revenue requirement of 5
$6.256 billion; that is, our 2015 request amounts to a 3.3 percent increase over 2014 presently 6
authorized levels. In addition, SCE forecasts its revenue requirement adjustments to be $318 million 7
and $317 million, respectively, for the attrition years of 2016 and 2017. SCE requests that the CPUC 8
authorize the Company to incorporate these attrition adjustments into its annual consolidated rate advice 9
letter filings for 2016 and 2017.12 As further described throughout this testimony, SCE believes that this 10
investment will continue our ability to expand the power delivery system, replace aging infrastructure, 11
and provide safe, reliable, and customer-beneficial service. 12
SCE is requesting authority to spend $15.581 billion in capital on CPUC jurisdictional projects 13
over the five-year period of 2013-2017. The CPUC and FERC jurisdictional capital forecasts are 14
depicted below in Table IV-4. Justification and support for these capital projects can be found 15
throughout the testimony Exhibits as outlined in section B below. 16
Table IV-4 SCE Capital Expenditures
($million)
2013 2014 2015 2016 2017
CPUC
Jurisdictional 2,688 2,931 3,364 3,370 3,228
FERC
Jurisdictional 1,091 720 528 486 564
Total Company 3,779 3,651 3,892 3,856 3,792
11 Unless otherwise stated, all amounts noted in the testimony supporting SCE’s GRC forecast are in nominal dollars
except for O&M which is presented in 2012 dollars.
35
SCE is requesting $2.384 billion per year in authorized expense in this GRC.13 This request 1
includes recovery of costs associated with the day-to-day operations including the money needed to 2
inspect, repair, and replace our aging infrastructure, and for the people we employ that climb the poles to 3
restore electric service in storms and answer customer service calls on a 24/7 basis, and serve our 4
customers in so many other ways. Justification and support for these expenses, historical information on 5
each of these activities and explanation for the 2015 test year forecast can be found throughout the 6
testimony Exhibits as outlined in section B below. 7
B. Organizational Structure Of Exhibits 8
Table IV-5 below provides a listing as well as a summary of the exhibits included in this GRC. 9
Table IV-5 SCE 2015 GRC Organizational Structure of Exhibits
Exhibit Name and Title Summary of Exhibit
SCE-01 – Policy
Includes overall policy testimony on SCE’s request
Provides an executive summary of the case and revenue requirement forecast
Explains the structure of the remaining exhibits
SCE-02 – Generation
Includes testimony on all SCE-owned generation facilities
Describes power procurement activities for bundled customers
Continued from the previous page 12 SCE’s attrition proposal is set forth in Exhibit SCE-10, Post-Test Year Ratemaking.
13 Expense is forecast in constant, 2012 dollars. Escalation is included to expense items as part of the overall revenue requirement calculation and is further described in Exhibit SCE-10.
36
SCE-03 – Transmission & Distribution
Includes testimony on Engineering, System Planning, Infrastructure Replacement, Customer Driven Programs, Distribution Construction & Maintenance, Maintenance & Inspection Programs, Pole Loading, Grid Operations, Transmission & Substation Maintenance, Safety, Training & Environmental Programs, and Other Operating Revenue
SCE-04 – Customer Service Includes testimony on Customer Services
Operations and Customer Service & Information Delivery
SCE-05 – Information Technology Includes testimony on Capitalized Software
projects, O&M to support those projects, and Cybersecurity
SCE-06 – Human Resources Includes testimony on Human Resources
departmental costs, Human Resources Benefits and Compensation
SCE-07 – Safety, Security and Compliance
Includes testimony on Ethics & Compliance, Corporate Environmental Health & Safety, Corporate Security, and Business Resiliency
SCE-08 – Financial, Legal, and Operational Services
Includes testimony on Audits, Financial Services, Property & Liability Insurance, Law, Claims, Worker’s Compensation, and Operational Services
SCE-09 – External Relations
Includes testimony on Corporate Communications, Integrated Planning & Environmental Affairs, Regulatory Operations, Regulatory Policy & Affairs, and Local Public Affairs
SCE-10 – Results of Operations
Includes testimony on Revenue Requirements, Ratemaking, Present Rate Revenues, Sales Forecast, Cost Escalation, Jurisdictionalization, Plant Depreciation Expense & Reserve, Working Capital, Rate Base, Taxes, Property and Ad Valorem Tax, Depreciation, Productivity, Post-Test Year Ratemaking
SCE-11 – Compliance Requirements Includes testimony on Compliance with Decisions and Settlements
SCE-12 – Joint SCE and Center for Accessible Technology Testimony
Includes joint testimony between SCE and Center for Accessible Technology on Accessibility issues
SCE-13 – Differences Shows modifications to the NOI testimony
37
C. Organization of Administrative and General Expenses 1
Table IV-6 and Table IV-7 below summarize SCE’s forecast of A&G expenses for Test Year 2
2015. These tables show, as columns, Test Year 2015 A&G expenses in constant dollars, broken down 3
by FERC account. As rows, we show the various witnesses who are testifying to these expenses and the 4
exhibits in which their testimony may be found. 5
38
Table IV-6 Forecast of Test Year 2015 A&G Expenses in Testimony
(Constant 2012 $000)
920 921 922 923 924 925 926 927 928 930 931 935
SC
E-3
, V
ol.
2
Real Properties 5,279 1,446 - - - - - - - - - - 6,725 K. Payne
Information TechnologyTechnology Delivery & Maintenance 31,274 17,669 - - - - - - - - - - 48,943 J. CastleberryInfrastructure Technology Services 38,762 74,692 - - - - - - - - 4,108 - 117,562 C. CarazoClient Services & Planning 15,440 2,376 - - - - - - - - - - 17,816 B. Sweetser
Enterprise Information Management & Architecture
11,060 5,886 - - - - - - - - - - 16,946 J. Kelly
Cybersecurity & Compliance 7,529 11,494 - - - - - - - - - - 19,023 G. HaddoxIncremental O&M For New Software Projects 5,222 3,682 - - - - - - - - - - 8,904 J. Castleberry
Human ResourcesPension Costs - - - - - - 168,410 - - - - - 168,410 G. HenryPBOPs - - - - - - 44,573 - - - - - 44,573 G. Henry401K - - - - - - 68,997 - - - - - 68,997 M. BennettHealth and Benefits Plans - - - - - - 192,291 - - - - - 192,291 M. BennettHuman Resources 21,538 6,668 - 5,087 - - 7,119 - - - - - 40,412 S. LuExecutive Officers 17,582 1,944 - 1,496 - - - - - - - - 21,022 S. LuResults Sharing 56,897 - - - - - - - - - - - 56,897 M. BennettLong Term Incentives 18,181 - - - - - - - - - - - 18,181 J. Trapp
Safety, Security & Compliance
Ethics & Compliance 4,449 493 - 3,178 - - - - - - - - 8,120 J. Shotwell
Corporate Security 7,605 48,495 - 151 - - - - - - - - 56,251 D. Daigler
Corporate Environment Health & Safety 3,316 1,517 - 475 - 5,199 - - - - - - 10,507 D. Neal Jr.
Financial OrganizationsFinancial Services 23,781 3,467 - 36,941 - - 573 - - - - - 64,762 G. HuckabyAudit Services 7,156 1,502 - - - - - - - - - - 8,658 A. HerreraCapitalized A&G/P&B - - (141,813) - - - (240,818) - - - - - (382,631) G. HuckabyParticipant Credits - - - - - - 22,680 - - 10,415 - - 33,095 G. Huckaby
InsuranceCorp Property Insurance - - - - 22,424 - - - - - - - 22,424 S. KempseyCorp Liability Insurance - - - - - 76,899 - - - - - - 76,899 S. Kempsey
LegalLaw - Corp. Governance & Misc. 25,245 5,294 - - - - - - - 3,210 - - 33,749 E. JennersonLaw - Outside Counsel - - - 23,047 - - - - - - - - 23,047 E. JennersonClaims 3,057 801 - - - 19,424 - - - - - - 23,282 R. RamosWorker's Compensation - - - - - 21,207 - - - - - - 21,207 E. Jennerson
Operational ServicesPlanning & Performance 5,022 2,317 - - - - - - - - - - 7,339 A. RiddleCorporate Real Estate 14,347 11,781 - - - - - - - - 18,106 10,905 55,139 R. ParkSupplier Diversity & Development 549 201 - 1,085 - - - - - - - - 1,835 J. Alderete
External Relations
Corporate Communications & Membership Dues & Fees
5,978 1,829 - 847 - - - - - 13,285 - - 21,939 M. Jordan
Integrated Planning & Environmental Affairs 1,840 1,150 - - - - - - - - - - 2,990 M. NelsonGeneration Planning - PDD - - - - - - - - - - - - - M. NelsonTransportation Electrification - - - - - - - - - - - - - E. KjaerRegulatory Operations and Regulatory Policy & Affairs
14,300 2,161 - - - - - - - - - - 16,461 M. Scott-Kakures
Local Public Affairs 11,404 2,138 - - - - - - - - - - 13,542 V. GutierrezFranchise Requirement - - - - - - - 67,297 - - - - 67,297 V. Gutierrez
356,813 209,003 (141,813) 72,307 22,424 122,729 263,825 67,297 - 26,910 22,214 10,905 1,032,614
Description
SC
E-9
, V
ol.
1S
CE
-8,
Vo
l. 1
, 2
& 3
SC
E-7
, V
ol.
2,
3 &
4
WitnessTotal
SC
E-5
, V
ol.
1S
CE
-6,
Vo
l. 1
& 2
FERC Account
39
Table IV-7 Forecast Of Test Year 2015 A&G Expenses In Testimony (All Volumes)
(Constant 2012 $000)
500 501 517 549 557 561 588 903 905
SC
E-3
, V
ol.
2
Real Properties - - - - - - - - - - 6,725 6,725 K. Payne
Information TechnologyTechnology Delivery & Maintenance - - 2,618 - - - - - 2,618 48,943 51,561 J. CastleberryInfrastructure Technology Services - - 3,073 - - - - - 3,073 117,562 120,635 C. CarazoClient Services & Planning - - - - - - - - - - 17,816 17,816 B. SweetserEnterprise Information Management & Architecture - - - - - - - - - - 16,946 16,946 J. KellyCybersecurity & Compliance - - - - - - - - - - 19,023 19,023 G. HaddoxIncremental O&M For New Software Projects - - - - - - - - - - 8,904 8,904 J. Castleberry
Human ResourcesPension Costs - - - - - - - - - - 168,410 168,410 G. HenryPBOPs - - - - - - - - - - 44,573 44,573 G. Henry401K - - - - - - - - - - 68,997 68,997 M. BennettHealth and Benefits Plans - - - - - - - - - - 192,291 192,291 M. BennettHuman Resources - - - - - - - - - - 40,412 40,412 S. LuExecutive Officers - - - - - - - - - - 21,022 21,022 S. LuResults Sharing 10,708 - - - - 57,262 - 22,993 90,963 56,897 147,860 M. BennettLong Term Incentives - - - - - - - - - - 18,181 18,181 J. Trapp
Safety, Security & Compliance - Ethics & Compliance - - - - - - - - - - 8,120 8,120 J. ShotwellCorporate Security - - - - - - - - - - 56,251 56,251 D. DaiglerCorporate Environment Health & Safety - - - - - - - - - - 10,507 10,507 D. Neal Jr.
Financial OrganizationsFinancial Services - - - - - - - - - - 64,762 64,762 G. HuckabyAudit Services - - - - - - - - - - 8,658 8,658 A. HerreraCapitalized A&G/P&B - - - - - - - - - - (382,631) (382,631) G. HuckabyParticipant Credits - - - - - - - - - - 33,095 33,095 G. Huckaby
InsuranceCorp Property Insurance - - - - - - - - - - 22,424 22,424 S. KempseyCorp Liability Insurance - - - - - - - - - - 76,899 76,899 S. Kempsey
LegalLaw - Corp. Governance & Misc. - - - - - - - - - - 33,749 33,749 E. JennersonLaw - Outside Counsel - - - - - - - - - - 23,047 23,047 E. JennersonClaims - - - - - - - - - - 23,282 23,282 R. RamosWorker's Compensation - - - - - - - - - - 21,207 21,207 E. Jennerson
Operational ServicesPlanning & Performance - 7,339 7,339 A. RiddleCorporate Real Estate - - - - - - - - - - 55,139 55,139 R. ParkSupplier Diversity & Development - - - - - - - - - - 1,835 1,835 J. Alderete
External Relations - Corporate Communications & Membership Dues & Fees - - - - - - - - - - 21,939 21,939 M. JordanIntegrated Planning & Environmental Affairs - - - - 6,227 - - - - 6,227 2,990 9,217 M. NelsonGeneration Planning - PDD - - - 6,303 - - - - 6,303 - 6,303 M. NelsonTransportation Electrification - - - - - - 5,595 - - 5,595 - 5,595 E. KjaerRegulatory Operations and Regulatory Policy & Affairs - - - - - - - - - - 16,461 16,461 M. Scott-KakuresLocal Public Affairs - - - - - - - - - - 13,542 13,542 V. GutierrezFranchise Requirement - - - - - - - - - - 67,297 67,297 V. Gutierrez
10,708 - 5,691 6,303 6,227 - 62,857 - 22,993 114,779 1,032,614 1,147,393
SC
E-7
, V
ol.
2,
3 &
4S
CE
-6,
Vo
l. 1
& 2
SC
E-5
, V
ol.
1S
CE
-9,
Vo
l. 1
SC
E-8
, V
ol.
1,
2 &
3
DescriptionFERC Account
Sub-Total Accounts 920-935 Total Witness
40
Each witness justifies his or her own Test Year forecast in the individual sections of testimony. I 1
only summarize the forecasts here for the reader’s convenience in viewing all A&G accounts across the 2
GRC request. 3
D. To Reduce Overall Page Count Of Testimony And Workpapers We Have Consolidated 4
The Presentation Of Some FERC Account Data 5
One of our goals for this 2015 GRC was to streamline the presentation of the evidence. In prior 6
GRCs, Commission staff and intervenors have commented that the task of reviewing our showing was 7
challenging due to the sheer number of pages of testimony and workpapers. For example, in our 2012 8
GRC we submitted approximately 6,300 pages of direct testimony. Responding to those concerns, for 9
this 2015 GRC, we are submitting approximately 4,200 pages of prepared testimony with our NOI, a 10
significant reduction from the 2012 GRC. We hope that this reduced page count will facilitate review of 11
the evidentiary record by Commission staff, intervenors, and the Assigned Administrative Law Judge. 12
One of the ways we were able to achieve this reduced page count was by consolidating the 13
presentation of the Operations and Maintenance (O&M) expense accounts. The FERC’s Uniform 14
System of Accounts, which is also used by this Commission, contains a series of account numbers used 15
by utilities to present their capital, revenue, and expense data. In some cases, the expense data contained 16
in a particular account is considerably smaller than that in other accounts. Recognizing that, and with a 17
goal of reducing the overall page count of our prepared testimony for the benefit of the reader, we 18
consolidated the data contained in some individual accounts into a single account. For example, for 19
hydroelectric generation, we consolidated FERC Accounts 536 and 540. This approach maintains 20
sufficient level of detail for reviewing the O&M expense data but also reduces the overall page count of 21
prepared testimony and workpapers. 22
Appendix A
Witness Qualifications
A-1
SOUTHERN CALIFORNIA EDISON COMPANY 1
QUALIFICATIONS AND PREPARED TESTIMONY 2
OF RONALD L. LITZINGER 3
Q. Please state your name and business address for the record. 4
A. My name is Ronald L. Litzinger, and my business address is 8631 Rush Street, Rosemead, 5
California 91770. 6
Q. Briefly describe your present responsibilities at the Southern California Edison Company. 7
A. I am President of Southern California Edison Company (SCE). 8
Q. Briefly describe your educational and professional background. 9
A. I hold a Bachelor of Science degree in Chemical Engineering from the University of 10
Washington and a Master of Arts degree in Management from the University of Redlands. 11
I joined Southern California Edison in 1986 and held a variety of plant maintenance and 12
engineering positions before transferring to Edison Mission Energy (EME) in 1995. I was 13
elected Vice President of EME in 1998, Senior Vice President of EME’s Worldwide 14
Operations in 1999, and Senior Vice President and Chief Technical Officer in 2002. In 15
2004, I was elected Vice President of Strategic Planning for SCE’s parent company, Edison 16
International. In 2005, I was elected Senior Vice President of SCE’s Transmission and 17
Distribution Business Unit. In 2008, I was elected Chairman, Chief Executive Officer, and 18
President of Edison Mission Group. I assumed my current position as President of SCE in 19
2011. 20
Q. What is the purpose of your testimony in this proceeding? 21
A. The purpose of my testimony in this proceeding is to sponsor portions of Exhibit SCE-01, 22
Policy, as identified in the Table of Contents of that exhibit. 23
Q. Was this material prepared by you or under your supervision? 24
A. Yes. 25
Q. Insofar as this material is factual in nature, do you believe it to be correct? 26
A. Yes, I do. 27
Q. Insofar as this material is in the nature of opinion or judgment, does it represent your best 28
judgment? 29
A. Yes, it does. 30
Q. Does this conclude your qualifications and prepared testimony? 31
A-2
A. Yes, it does. 1
A-3
SOUTHERN CALIFORNIA EDISON COMPANY
QUALIFICATIONS AND PREPARED TESTIMONY 1
OF MICHAEL R. MARELLI 2
Q. Please state your name and business address for the record. 3
A. My name is Michael R. Marelli, and my business address is 8631 Rush Street, Rosemead, 4
California 91770. 5
Q. Briefly describe your present responsibilities at the Southern California Edison Company. 6
A. I am the General Rate Case (GRC) Director. My responsibilities include overseeing the 7
development and approval of SCE’s 2015 GRC. 8
Q. Briefly describe your educational and professional background. 9
A. I earned a Bachelor of Science degree in Mechanical and Aeronautical Engineering from 10
the University of California at Davis in 1985. I am a registered professional engineer in the 11
State of California. I was employed by Sempra Energy (and predecessor companies) from 12
1991 to 2000 and PA Consulting Group from 2000 through 2004. I joined SCE’s Energy 13
Supply & Management Department as Manager of Power Contracts in late 2004. In 2007, I 14
was responsible for the contract origination and analysis groups in the Renewable and 15
Alternative Power Department. In 2010, I was promoted to Director of Contracts for the 16
Renewable and Alternative Power Department. In 2011, I was responsible for managing 17
the risk control activities as the Director of Risk Control. I assumed responsibilities for my 18
current position in 2012. My responsibilities at Sempra Energy and PA Consulting Group 19
involved many different areas including business development, marketing and wholesale 20
energy market activities. 21
Q. What is the purpose of your testimony in this proceeding? 22
A. The purpose of my testimony in this proceeding is to sponsor the portions of Exhibit SCE-23
01, entitled Policy, as identified in the Table of Contents thereto. 24
Q. Was this material prepared by you or under your supervision? 25
A. Yes, it was. 26
A-4
Q. Insofar as this material is factual in nature, do you believe it to be correct? 1
A. Yes, I do. 2
Q. Insofar as this material is in the nature of opinion or judgment, does it represent your best 3
judgment? 4
A. Yes, it does. 5
Q. Does this conclude your qualifications and prepared testimony? 6
A. Yes, it does. 7