volume 7 of 18 - nv energy · 2020. 9. 4. · sierra pacific power company d/b/a nv energy electric...
TRANSCRIPT
SIERRA PACIFIC POWER COMPANY d/b/a NV Energy
ELECTRIC DEPARTMENT
BEFORE THE
PUBLIC UTILITIES COMMISSION OF NEVADA
In the Matter of the Application by SIERRA PACIFIC ) POWER COMPANY D/B/A NV ENERGY, filed ) pursuant to NRS 704.110(3) and NRS 704.110(4), ) addressing its annual revenue requirement for ) general rates charged to all classes of electric ) customers. ) Docket No. 19-06____ __________________________________________ )
VOLUME 7 of 18 Prepared Direct Testimony of:
Plant In Service John S. Gremp
Danyale Howard Ricardo Becerra Victor Figueredo James DeFrates
William Olsen Scott Talbot
Michelle Follette
Operating and Maintenance Jennifer Oswald
Recorded Test Year ended December 31, 2018 Certification Period ended May 31, 2019
Index
Page 2 of 250
Sierra Pacific Power Company Electric Department
d/b/a NV Energy
Volume 7 of 18
Index Page 1 of 1
Description Page No. Prepared Direct Testimony Of:
Plant In Service:
John S. Gremp 4 Danyale Howard 16 Ricardo Becerra 27 Victor Figueredo 52 James DeFrates 60 William Olsen 67 Scott Talbot 96 Michelle Follette 108
Operating and Maintenance, Administrative and General Expense:
Jennifer Oswald 200
Page 3 of 250
JOHN S. GREMP
Page 4 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
Sierra Pacific Power Company d/b/a NV Energy
2019 General Rate Case Docket No. 19-06___
PREPARED DIRECT TESTIMONY OF
John S. Gremp
Revenue Requirement
I. INTRODUCTION
1. Q. PLEASE STATE YOUR NAME, OCCUPATION, BUSINESS ADDRESS,
AND THE PARTY FOR WHOM YOU ARE FILING TESTIMONY.
A. My name is John S. Gremp. I am the Manager, Transmission Project Delivery for
NV Energy, Inc. (“NV Energy”), Nevada Power Company d/b/a NV Energy
(“Nevada Power”), and Sierra Pacific Power Company d/b/a NV Energy (“Sierra”,
and together with Nevada Power, the “Companies”). I work primarily out of
Sierra’s corporate office, which is located at 6100 Neil Road in Reno, Nevada. I
am filing testimony in this proceeding on behalf of Sierra.
2. Q. PLEASE DESCRIBE YOUR PROFESSIONAL BACKGROUND AND
EXPERIENCE.
A. I have a Bachelor of Science degree from the College of Business Administration
Fordham University Bronx, New York. I began my employment in the energy
industry as a financial planning and analysis intern with Nevada Power in 2006. I
have substantial experience in project management, financial controls and project
controls. In 2006, I was assigned to New Generation as a project controls engineer
during the development of the Ely Energy Center and was assigned to the project
management team for the Clark Peaker Project and the Harry Allen Combined
Gremp-DIRECT 1
Page 5 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
Cycle Project. I transferred to Generation department in 2011 as a Senior
Consultant. I was promoted to Project Controls Supervisor in 2014. I transferred to
Sierra and the Transmission Department in 2014 as a project manager, then was
promoted to Manager of Project Delivery in 2017. I have attached as Exhibit
Gremp-Direct-1 a statement of qualifications that further details my background
and professional experience.
3. Q. MR. GREMP, HAVE YOU PREVIOUSLY SUBMITTED TESTIMONY
WITH THE PUBLIC UTILITIES COMMISSION OF NEVADA
(“COMMISSION”)?
A. No, I have not.
4. Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS
PROCEEDING?
A. I support the prudence of several categories of investment in facilities that are
included in the calculation of Sierra’s revenue requirement. These assets are broken
down into two categories: compliance and transmission technology. Each of the
investments made by the Company in these two categories are used and useful and
providing benefit to customers.
5. Q. HOW IS YOUR TESTIMONY ORGANIZED?
A. My testimony is organized into the following sections:
Section II. Compliance Projects: In this section, I discuss Sierra’s investments in
facilities and equipment required to meet North American Electric Reliability
Corporation (“NERC”) standards. Specifically, Sierra is required by NERC to
Gremp-DIRECT 2
Page 6 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
invest in a more robust cyber security and a physical hardening of key Bulk Electric
Systems (“BES”) assets.1 I describe one compliance project included in this general
rate review, why it was necessary, previous discussion of the project with the
Commission, the total cost of the project, and other information to demonstrate that
Sierra’s investment on behalf of customers was prudent.
Section III. Transmission Technology: In this section, I discuss Sierra’s
investment in two Electric System Control Center (“ESCC”) technology projects
since the end of the certification period in Sierra’s last general rate case, June 1,
2016 through the end of the current certification period on May 31, 2019. I describe
each ESCC technology project, why it was necessary, whether it was previously
presented to the Commission, the total cost of the project, and other information to
demonstrate that Sierra’s investment on behalf of customers was prudent.
6. Q. ARE YOU SPONSORING ANY EXHIBITS TO YOUR PREPARED
DIRECT TESTIMONY?
A. Yes. I am sponsoring one exhibit:
• Exhibit Gremp-Direct-1 Statement of Qualifications
7. Q. WHY ARE ONLY MAJOR PROJECTS SPECIFICALLY DISCUSSED IN
YOUR TESTIMONY?
A. Testimony-style descriptions of each and every project completed by the
transmission project team since June 1, 2016 would take hundreds of pages, and
the documentation surrounding each project is so voluminous that its value at
hearing would be severely diminished. As I understand it, in general rate
1 The Federal Energy Regulatory Commission (“FERC”) issued an order approving CIP-01101.
Gremp-DIRECT 3
Page 7 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
proceedings the Commission wants to see prepared direct testimony addressing the
details of and supporting expenditures on major projects. In recent general rate
cases, the Commission has accepted the $1.0 million demarcation as appropriate
for determining whether a project is “major.” While not addressed in detail in my
prepared direct testimony, my group has prepared project “binders” for smaller
projects completed since June 1, 2016. As has been the Companies’ practice for
many rate case cycles, those binders (now in electronic form) are available for
review on the day this general rate review filing is made.
II. COMPLIANCE PROJECTS
8. Q. DESCRIBE THE PROJECTS INCLUDED IN THIS SECTION.
A. This section discusses investment in one major (over $1.0 million) compliance
initiative as required by NERC. This project has been placed in service since the
end of the certification period in Sierra’s last general rate case and before the close
of the test period for this general rate review, December 31, 2018.
9. Q. PLEASE DESCRIBE THE PROJECT.
A. This project implements physical and cyber security measures for all designated
high-impact and medium-impact facilities across the Companies’ transmission
system. These Critical Infrastructure Protection (“CIP”) measures are put in place
to achieve a robust security posture in keeping with the enforceable requirements
of NERC CIP-002-5 through CIP-011-1. These ten standards are collectively
referred to as the “Version 5 Standards.”2 CIP facilities include four high-impact
2 FERC approved Version 5 of the CIP standards on November 22, 2013. See 145 FERC ¶ 61,160 (iss. Nov. 22, 2013). Many of the Version 5 standards became effective July 1, 2016.
Gremp-DIRECT 4
Page 8 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
control center facilities and 11 medium-impact substations. Full compliance with
the Version 5 Standards was achieved on July 1, 2016.
10. Q. WHY WAS THE PROJECT NECESSARY?
A. The Version 5 Standards are approved by FERC and administered by NERC. In
addition, the Version 5 Standards implement controls that harden the physical and
cyber security posture associated with Sierra’s BES assets. Failure to comply with
the standards results in compliance violations and potential monetary penalties.
11. Q. HAS THIS PROJECT BEEN PRESENTED TO THE COMMISSION?
A. Yes. This project was previously presented to the Commission in Docket No. 17-
06003, Nevada Power’s last electric general rate review case. Investments made to
comply with Version 5 Standards were discussed in the prepared direct testimony
of Jack M. Wickersham III, and can be found in Volume 2 of 6 of the certification
filing.
12. Q. WHAT WAS THE TOTAL COST OF THE PROJECT?
A. This project was required to support both Nevada Power and Sierra. The project
contains some elements that are allocated 100 percent to one or the other utility
based on asset location, and as well as elements that are allocated between Nevada
Power and Sierra using the Common Product allocation methodology.3 The
estimated total cost of the project for both Companies’ was $2,800,890 (without
AFUDC), based on an estimated in-service date of April 1, 2016. The final cost of
the CIP Version 5 Standards (“CIPv5”) upgrades was $3,322,314 (without
3 Refer to the prepared direct testimony of Ms. Erika McLean for a description of this and other allocations used.
Gremp-DIRECT 5
Page 9 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
AFUDC) with an actual in-service date of July 1, 2016. Sierra’s share of CIPv5
implementation costs as of December 31, 2018 is $1,456,010 (with AFUDC). No
additional costs have been incurred during the certification period.
III. TRANSMISSION TECHNOLOGY
13. Q. PLEASE DESCRIBE THE PROJECT.
A. This section discusses the investments in Sierra’s ESCC greater than $1.0 million.
These projects have been placed in service since the end of the certification period
in Sierra’s last general rate case and prior to the end of the current certification
period, May 31, 2019. These projects directly impact the operations of Sierra’s
transmission and distribution grids, and are used and useful in providing utility
service.
1. Distribution SCADA
14. Q. PLEASE DESCRIBE THE PROJECT.
A. This project involved adding Distribution Supervisory Control and Data
Acquisition (“DSCADA”) function to Distribution Management System (“DMS”)
currently utilized by ESCC. This project also included upgrading DMS to new
software version as well as new hardware environment.
15. Q. WHY WAS THE PROJECT NECESSARY?
A. Adding automation to the DMS was necessary to increase distribution grid
reliability. Distribution Automation, Conservation Voltage Reduction, volt/VAR
optimization, Distribution Line Capacitor Control, and Substation Automation, all
require a modern, centralized DMS capable of automatic operation of controllable
devices in the field. This can only be accomplished through usage of DSCADA.
Gremp-DIRECT 6
Page 10 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
16. Q. HAS THIS PROJECT BEEN PRESENTED TO THE COMMISSION
PREVIOUSLY?
A. Yes. This project was previously presented to the Commission in Docket No. 17-
06003, Nevada Power’s last general rate review proceeding. Investments in the
Distribution SCADA project were discussed in the prepared direct testimony of
Jack M. Wickersham III, and can be found in Volume 2 of 6 of the certification
filing.
17. Q. WHAT WAS THE TOTAL COST OF THE PROJECT?
A. This project supports both Nevada Power and Sierra, and the costs were allocated
between the Companies based on the Common Product Allocation Methodology.
The estimated total cost of the project was $2,808,232 (without AFUDC) with an
estimated in-service date of September 9, 2016. The final cost of DSCADA Project
was $3,322,314 (without AFUDC) with an actual in-service date of May 25, 2017.
The cost of Sierra’s portion of the DCSADA project included in the gross plant
additions at December 31, 2018 is $1,472,251 (with AFUDC). No additional cost
have been incurred during the certification period.
2. ESCC Video Wall Replacement
18. Q. PLEASE DESCRIBE THE PROJECT.
A. This project required the installation of a new video wall in the ESCC to improve
system operation through situational awareness. The video wall replaced the then-
existing one-line diagram taped onto wall board.
Gremp-DIRECT 7
Page 11 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
19. Q. WHY WAS THE PROJECT NECESSARY?
A. The transmission wallboard in the ESCC was a taped one-line diagram of the
regional transmission system, to which power circuit breakers statuses for the
transmission substations in northern Nevada were manually marked. This
antiquated technology was limited in capacity, and did not provide situational
awareness to operators under either normal operations or emergency system
operations. The video wall provides the versatility needed for state-wide
transmission system operations, automated circuit breaker statusing, and improved
situational awareness. The video wall technology enables the ESCC to implement
digital and real-time visualizations of the system. This aids in decision support
which can improve reliability and safe operation of the transmission system
20. Q. HAS THIS PROJECT BEEN PRESENTED TO THE COMMISSION?
A. No, this is the first time the Commission has been asked to review and approve the
costs associated with this project.
21. Q. WHAT WAS THE TOTAL COST OF THE PROJECT?
A. The estimated total cost of the project was $2,372,464 (without AFUDC), based on
an estimated in-service date of December 31, 2016. The final cost of the project
was $1,812,497 (without AFUDC), and the actual in-service date was March 16,
2017. The total cost of the project included in gross plant additions at December
31, 2016 is $1,855,468 (with AFUDC). No additional costs have been estimated
for the certification period.
Gremp-DIRECT 8
Page 12 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
IV. CONCLUSION
22. Q. DOES THIS COMPLETE YOUR TESTIMONY?
A. Yes, it does.
Gremp-DIRECT 9
Page 13 of 250
Gremp Exhibit Direct-1
BACKGROUND AND EXPERIENCE
John S. Gremp Manager, Transmission Project Delivery
NV Energy 6100 Neil Road Reno, NV 89511 (775) 834-4029
Mr. Gremp began employment in the energy industry as a financial planning and analysis intern with Nevada Power in 2006. He has substantial experience in project management, financial controls and project controls. Mr. Gremp have a Bachelor of Science degree from the College of Business Administration Fordham University Bronx, New York.
Employment History
• Manager, Transmission Project Delivery, 2017 • Project Manager, Transmission, 2015 • Supervisor Project Controls, Generation Operations, 2014 • Sr. Consultant, Generation Operations, 2011 • Project Controls Consultant, New Generation, 2007 • Student Intern, Financial Planning and Analysis, 2006
Education • Bachelor of Science degree from the College of Business Administration Fordham
University Bronx, New York.
Page 14 of 250
Page 15 of 250
DANYALE HOWARD
Page 16 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Sier
ra P
acifi
c Po
wer
Com
pany
and
Nev
ada
Pow
er C
ompa
ny
d/b/
a N
V E
nerg
y
BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
Sierra Pacific Power Company d/b/a NV Energy
2019 General Rate Case Docket No. 19-06__
PREPARED DIRECT TESTIMONY OF
Danyale Howard
Revenue Requirement
1. Q. PLEASE STATE YOUR NAME, OCCUPATION, BUSINESS
ADDRESS AND PARTY FOR WHOM YOU ARE FILING
TESTIMONY.
A. My name is Danyale Howard. I am the Director of Distribution Design
Services for the Northern Nevada Region, a department within the Electric
Delivery Division of Sierra Pacific Power Company d/b/a NV Energy
(“Sierra” or the “Company”). My business address is 1 Ohm Place, Reno,
Nevada. I am filing testimony on behalf of Sierra.
2. Q. PLEASE DESCRIBE YOUR BACKGROUND AND EXPERIENCE IN
THE UTILITY INDUSTRY.
A. I have 22 years of experience in the utility industry in a variety of positions. I
have been in my current position since April 2018. I have held various
positions within Distribution Design Services (“DDS”) and all roles have
included increased responsibilities including progressive leadership from
supervisor to my present role as Director.
Howard-DIRECT 1
Page 17 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Sier
ra P
acifi
c Po
wer
Com
pany
and
Nev
ada
Pow
er C
ompa
ny
d/b/
a N
V E
nerg
y
3. Q. PLEASE DESCRIBE YOUR RESPONSIBILITIES AS DIRECTOR OF
DDS.
A. As Director of DDS, my responsibilities include overseeing the customer
service, engineering, and project coordination for line extensions, facility
relocation projects and services for Rule 9 and Company-sponsored reliability
projects. I am responsible for the business processes followed to bring any new
customer onto the northern Nevada system, whether governmental,
commercial, residential developers, or individual homeowners) from the
application to the delivery of the line extension agreement.
4. Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE PUBLIC
UTILITIES COMMISSION OF NEVADA (“COMMISSION”)?
A. No.
5. Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY?
A. I support the investment made by Sierra in new line extension facilities
pursuant to Rule 9 of Sierra’s electric tariff.
6. Q. ARE YOU SPONSORING ANY EXHIBITS?
A. Yes. I am sponsoring the following Exhibits:
Exhibit Howard-Direct-1 Statement of Qualifications
7. Q. PLEASE DESCRIBE THE DDS DEPARTMENT AND ITS
RESPONSIBILITIES.
A. As I state in Q&A 3 above, the DDS department provides customer service,
engineering and project coordination for line extensions, facility relocation
Howard-DIRECT 2
Page 18 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Sier
ra P
acifi
c Po
wer
Com
pany
and
Nev
ada
Pow
er C
ompa
ny
d/b/
a N
V E
nerg
y
projects and Company-sponsored reliability projects. DDS endeavors to
provide excellent customer service to customers, the development community,
local governmental entities and permitting agencies such as the Nevada
Department of Transportation (“NDOT”). To facilitate these objectives,
members of DDS regularly participate in industry organization meetings and
conduct periodic planning meetings with governmental entities such as
NDOT.
DDS handles all sizes and types of electric residential projects, from a single
service, to custom homes, subdivisions, apartments and condominiums, and
all types and sizes of commercial and industrial projects. DDS maintains staff
in five district offices in northern Nevada, where customers requesting electric
distribution services can meet with design specialists and initiate their projects
under Sierra’s Tariff Rule 9. The DDS coordinates or prepares all the
requirements to provide the requested service including distribution planning,
the acquisition of governmental permits and land rights, the project design,
estimation of construction costs as well as the preparation of the required
agreements.
8. Q. PLEASE DESCRIBE THE DIFFERENT TYPES OF PROJECTS DDS
ADMINISTERS.
A. The projects the DDS department administers can be grouped into three major
categories:
(1) Line Extensions That Serve Increased Demand. These projects
normally involve new load and result in new distribution facilities, or in some
cases, the modification to the existing distribution facilities. Projects in this
Howard-DIRECT 3
Page 19 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Sier
ra P
acifi
c Po
wer
Com
pany
and
Nev
ada
Pow
er C
ompa
ny
d/b/
a N
V E
nerg
y
grouping include custom homes, residential apartments or condominiums,
residential subdivisions, small commercial, large commercial, master planned
communities, and government projects. Occasionally, a line extension
involves not just “normal” distribution facilities, but also the installation of
High Voltage Distribution (“HVD”) facilities and/or a substation. When a
project requires HVD facilities, the HVD portion is turned over to the
Customer Solutions – Delivery group who will prepare the costs and contracts
for the HVD. The distribution portion will remain with the DDS department.
In these cases, separate agreements are prepared and delivered to the customer.
The agreements are reviewed, signed and formally executed pursuant to the
established chart of authority for DDS and the Customer Solutions – Delivery
departments.
Depending on the circumstances, Rule 9 may require the collection from an
applicant of a refundable advance and/or a non-refundable contribution in aid
of construction (“CIAC”) advance. Both types of advances are calculated
based on the estimated project cost, net of any allowance granted. An
allowance is a credit toward construction costs for new loads and is based on
the number of units, meters or kilovolt-ampere (“kVA”) load that will be
served by the line extension facilities. As the name implies, an “advance
subject to refund” may be refunded to the customer over time, depending on
the ultimate load served from the Rule 9 facilities. In cases where separate
agreements are required to address HVD and/or substation installations
separate than standard distribution line extensions, payment of advances are
made separately to the respective agreements satisfying total advances due.
Howard-DIRECT 4
Page 20 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Sier
ra P
acifi
c Po
wer
Com
pany
and
Nev
ada
Pow
er C
ompa
ny
d/b/
a N
V E
nerg
y
(2) Relocation and Modification of Existing Distribution Facilities.
These projects involve an alteration of existing distribution facilities, usually
at the request of governmental entities, but occasionally at the request of a
residential or commercial customer. For relocation and modification projects,
Rule 9 requires non-governmental applicants, and depending on who has prior
rights, NDOT, RTC and governmental applicants throughout Sierra’s territory,
to pay the entire cost through a non-refundable CIAC, with no allowance to
the applicant unless the alterations directly contribute to a net increase in
demand.
Pursuant to its franchise agreements with local governments and agency
permits (e.g., NDOT), Sierra is allowed to install electric facilities in public
rights of way with no easement costs. For both Company-initiated and
applicant-initiated projects, this is a valuable benefit as it reduces both the
project schedule and cost by reducing the requirements to obtain third-party
easements. However, the franchise agreements and permits require that Sierra
relocate facilities installed in government rights of way if requested by the
franchisor or permit issuer, except in situations where Sierra holds a pre-
existing property right in the right of way. Relocation work must follow the
schedules described in the agreements or those dictated by the governmental
entity’s project timeline. The costs associated with these relocations are not
funded by CIACs, and are instead recovered from all customers through
general rates.
Howard-DIRECT 5
Page 21 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Sier
ra P
acifi
c Po
wer
Com
pany
and
Nev
ada
Pow
er C
ompa
ny
d/b/
a N
V E
nerg
y
(3) Distribution System Improvements for System Reliability. These
projects are usually initiated internally by the Distribution Planning
department to address distribution system improvements needed to maintain
safe and reliable service to customers under normal load growth from existing
customers. They are not performed under Rule 9 because they do not involve
an applicant.
9. Q. WHAT RULES GOVERN THE COST OF LINE EXTENSION PLANT
INVESTMENT?
A. Rule 9 projects that are expected to increase demand are eligible to receive an
Allowance against construction costs, with the amount dependent on the type
of service that will be provided to the new load and the number of units,
meters, or amount of new kVA demand that is expected to be served by the
project. Some or all of the Allowance can be granted before the construction
of the project, where there is a reasonable expectation that the supporting
number of units, meters and/or kVA demand will be initiated within the 12-
month period following the completion of construction of the line extension
facilities.
Allowances that are not provided in advance of construction can be received
by the applicant after construction in the form of refunds, based on the actual
number of unit, meters or kVA demand that are initiated between the
completion of construction and the expiration of the Rule 9 agreement. The
amount of the refund is calculated through the performance of an allowance
true-up.
Howard-DIRECT 6
Page 22 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Sier
ra P
acifi
c Po
wer
Com
pany
and
Nev
ada
Pow
er C
ompa
ny
d/b/
a N
V E
nerg
y
If the estimated cost of the project exceeds the amount of the Allowance
granted to the applicant before construction, the applicant must advance or pay
the difference. There are two types of advances. The advance subject to refund
is the amount that the applicant may receive back in the form of refunds based
on the number of units, meters or amount of new kVA demand that is served
on the project. An advance not subject to refund is the portion of the project
cost that is not eligible for refund and is considered a CIAC. Under Rule 9,
certain types of costs are treated as CIAC and may not be offset by the
Allowance.
In basic terms, the Company’s investment is the amount of the project cost that
is not paid for by the applicant through either a CIAC or an advance subject to
refund. Stated differently, advances paid by the line extension applicant in the
form of either a non-refundable CIAC advance, or as any remaining balance
of an advance subject to refund that does not qualify for a refund by the
expiration of the Rule 9 agreement, become CIACs and are a permanent offset
to plant in service. If a project qualifies for a refund after it is constructed, the
amount refunded essentially becomes Sierra’s utility plant in service.
10. Q. HOW MUCH INVESTMENT IN DDS PROJECTS HAS SIERRA
MADE SINCE ITS LAST GENERAL RATE CASE?
A. The cost of DDS Rule 9 related projects including Street and Highway less
New Business expired advances booked to plant in service between June 1,
2016 and May 31, 2019 total $63,658,317.
Howard-DIRECT 7
Page 23 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Sier
ra P
acifi
c Po
wer
Com
pany
and
Nev
ada
Pow
er C
ompa
ny
d/b/
a N
V E
nerg
y
The residential and commercial line extension projects that serve increased
demand grew 46% or $20 million over the amounts filed in the 2016 GRC.
The residential projects increased 63% and the commercial projects increased
33%. The backbone facilities to serve several large residential Master Planned
Communities have been installed and design work is currently being done for
several more large projects that are in the Discovery and Planning stages.
The total cost for the relocations and modification of existing distribution
facilities booked to plant in service does not reflect the actual amount of work
performed. Payments received for project charges incurred in the previous
GRC amounted to $2.18 million and projects with current charges included in
this GRC amount to $2.29 million.
The above mentioned projects are included in the plant additions provided by
Ms. Ellen Fincher in Exhibit Fincher-Direct-2. None of these projects involve
an expenditure of $1 million or more. Distribution system improvements for
system reliability projects that were designed by the DDS are included in the
plant additions provided by Mr. Ricardo Becerra.
11. Q. DOES THIS COMPLETE YOUR TESTIMONY?
A. Yes, it does.
Howard-DIRECT 8
Page 24 of 250
Exhibit Howard-Direct-1 Page 1 of 1
STATEMENT OF QUALIFICATIONS
My name is Danyale M. Howard. My business address is 1 Ohm Place, Reno, Nevada. I am the Director of Distribution Design Services for Sierra Pacific Power Company, d/b/a NV Energy (“Sierra”).
Since April 2018, I have been employed as the Director of Distribution Design Services for Northern Nevada. I am responsible for directing the electric and gas design engineering and project coordination for distribution line extensions as well as facility relocation projects subject to the purview of Rule 9 and local government franchise agreements. I direct five district offices and work closely with large customers, governmental entities and principal land owners to facilitate Discovery requests and subsequently guide all stakeholders through the utility development process. I work closely with internal and external economic development bodies to track northern Nevada economic growth forecasts and actual results as well as with distribution planning to identify and prioritize areas of growth. I am responsible for all the design and estimated costs for planned electric capital maintenance projects for Northern Nevada. I currently serve as a Board of Director for the Builders Association of Northern Nevada.
From January 2016 to April 2018, I was employed as the Manager of Distribution Design Services for Northern Nevada. My responsibilities were similar to previously described responsibilities of Director, Distribution Design Services.
From March 2013 to January 2016, I was employed as the Supervisor of Distribution Design Services for the Truckee Meadows and Carson City regions of Northern Nevada. I was responsible for the design engineering and project coordination of electric distribution lines extensions and our gas distribution system.
From January 2011 to March 2013, I was employed as the Field Services Team Leader for Northern Nevada. I was responsible for developing, implementing and supervising procedures for reading and data collections and accurate and cost effective installation of electric meters and gas AMI modules. Ensured that all credit and collection Field Services field actions were executed according to Rule 6, Rule 8 and the Customer Bill of Rights (CBOR). At the same time, I also supervised the Northern Nevada Resolution Center that was established as part of the AMI smart meter installation program and participated in the approval of AMI credit/collection remote connect/disconnect (RCDC) business requirements.
From October 2004 to January 2011, I was employed as a Utility Design Administrator for Truckee Meadows. I was responsible for performing all design and project management functions for electric and gas designs for distribution line extensions. During 2009 and 2010, I was also assigned to the Enterprise Work Asset Management (EWAM) project, participating in the implementation of Maximo. In 2009, I received a paralegal certificate from the University of Nevada Reno.
From December 1997 to October 2004, I was employed as a Revenue Protection Analyst II by preparing and submitting exhibits, reports and legal documents related to utility theft and fraud. I was the 2004 past president of the Western States Utility Theft Association (WSUTA), serving a 425 membership of utility investigators across North America by providing annual CEU training related to utility theft.
From May 1996 to December 1997, I was employed as a Meter Reader for Truckee Meadows.
Page 25 of 250
Page 26 of 250
RICARDO BECERRA
Page 27 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
Sierra Pacific Power Company d/b/a NV Energy
2019 General Rate Case Docket No. 19-06___
PREPARED DIRECT TESTIMONY OF
Ricardo Becerra
Revenue Requirement
1. Q. PLEASE STATE YOUR NAME, OCCUPATION, BUSINESS ADDRESS
AND PARTY FOR WHOM YOU ARE FILING TESTIMONY.
A. My name is Ricardo Becerra. My current position is Manager, Delivery Assurance
Financial Reporting for Sierra Pacific Power Company d/b/a NV Energy (“Sierra
or the “Company”) and Nevada Power Company d/b/a NV Energy (“Nevada
Power,” and together with Sierra, the “Companies”). My business address is 6226
West Sahara Ave. in Las Vegas, Nevada. I am filing testimony on behalf of Sierra.
2. Q. PLEASE DESCRIBE YOUR BACKGROUND AND EXPERIENCE IN THE
UTILITY INDUSTRY.
A. I joined the Companies 13 years ago, and have since worked in the areas of electric
operations, maintenance, capital planning, and financial reporting. In my time at
the Company, I have actively participated in the planning and execution of large
scale Transmission and Distribution major projects, capital maintenance programs,
and operations maintenance plans. I have a Bachelor of Science Degree in
Mechanical Engineering and a Master’s Degree in Business Administration, both
from the University of Nevada, Las Vegas. My background and experience are
more fully described in my statement of qualifications, attached as Exhibit Becerra
Direct-1.
Becerra-DIRECT 1
Page 28 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
3. Q. PLEASE DESCRIBE YOUR RESPONSIBILITIES AS MANAGER,
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
DELIVERY ASSURANCE FINANCIAL REPORTING.
A. I provide direct leadership and guidance to a team that: (1) develops, coordinates,
and administers capital maintenance, new business, and operation and maintenance
(“O&M”) budgeting activities for the Electric Delivery organization across the
Companies service territories; (2) monitors budget expenditures and identifies and
analyzes budget variances; (3) works closely with operations leadership to develop
capital and O&M plans across the Companies’ northern and southern electric
service territories; and (4) identifies and recommends opportunities to improve
operational efficiency and gain cost savings. I also lead cross-functional teams in
the implementation of improvement initiatives.
4. Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE PUBLIC
UTILITIES COMMISSION OF NEVADA (“COMMISSION”)?
A. No, I have not previously testified before the Commission.
5. Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY?
A. I support the prudence of the Company’s investments in capital maintenance
projects. For the period June 1, 2016 through December 31, 2018 (actuals), and the
period January 1, 2019 through May 31, 2019 (estimates), those investments are
identified in Table Becerra Direct-1 below. Certification period estimates will be
updated up as part of the Company’s certification filing.
Becerra-DIRECT 2
Page 29 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Table Becerra Direct-1 Capital Maintenance Investment
$ in millions
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
Project Category Actuals Through December 31, 2018
Estimated Through May 31, 2019 Total
Equipment Failure Projects $ 26.7 $ 4.5 $ 31.2 Regional Overhead Rebuilds $ 16.9 $ 4.1 $ 20.9 4 kV to 25 kV Conversion Program $ 12.7 $ 4.3 $ 17.0 SAIDI Improvement Initiative Program $ 9.1 $ 7.8 $ 16.9 Regional Underground Rebuilds $ 9.6 $ 0.9 $ 10.5 Spare Equipment Program $ 6.3 $ 0.0 $ 6.3 Avian Protection Program $ 4.6 $ 0.4 $ 5.0 Substation Breaker Replacements $ 3.4 $ 0.1 $ 3.5 Tools Replacement Program $ 1.9 $ 0.6 $ 2.6 Telemetry/PI Addition Program $ 1.9 $ 0.0 $ 1.9 Pole Treatment Program $ 1.8 $ 0.0 $ 1.8 Line Sensor Program $ 0.3 $ 0.9 $ 1.2 Other $ 2.9 $ 1.5 $ 4.4 TOTAL $ 98.0 $ 25.2 $ 123.2
6. Q. WHY ARE THESE MAINTENANCE PROJECTS ACCOUNTED FOR AS
CAPITAL INVESTMENT?
A. These projects involve the replacement, retirement, and/or addition of
Transmission, Distribution, or Substation assets. For this reason, the costs are
properly capitalized.
7. Q. PLEASE DESCRIBE THE CAPITAL MAINTENANCE PROJECTS THAT
WERE PERFORMED DUE TO EQUIPMENT FAILURE.
A. The Company separately accounts for equipment replacements that are necessitated
by equipment failure that results in, or imminent failure that could result in, a loss
of electrical service. These so-called “Failure” projects include:
• Transmission equipment, including transmission poles, overhead
conductor, and associated hardware;
• Substation equipment (transmission and distribution), including
Becerra-DIRECT 3
Page 30 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
apparatuses, structures, and associated hardware;
• Overhead distribution equipment, including distribution poles, overhead
conductor, and associated hardware;
• Underground and pad mounted distribution equipment, including switches,
structures, cable, and associated hardware;
• Transformers, including overhead service transformers, pad mounted
service transformers, and associated hardware; and
• Services, including underground secondary/service cable, overhead
secondary/service conductors and associated hardware.
Since June 1, 2016, Sierra completed 2,696 Failure projects through December 31,
2018 at a total cost of $26,684,099. Estimated expenditures for this program for the
period January 1, 2019 through May 31, 2019 are $4,549,136.
8. Q. WHY WERE THE FAILURE PROJECTS NECESSARY?
A. The capital maintenance projects performed on transmission facilities, substation
facilities, overhead distribution facilities, underground distribution facilities, and
transformers were required to effect immediate replacement to failed facilities
and/or restore electrical service to customers. Capital maintenance projects on
services (low voltage conductor or cable) were performed either (1) to restore
electrical service to customers; (2) because the cable or conductor had reached or
exceeded the end of its service life; or (3) to correct violations of various National
Electric Safety Code (“NESC”), Occupational Safety and Health Administration
(“OSHA”), and Company safety standards.
Becerra-DIRECT 4
Page 31 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
9. Q. PLEASE DESCRIBE THE REGIONAL OVERHEAD REBUILD
PROGRAMS
A. These are projects that replace and/or retrofit existing overhead infrastructure and
include the replacement of transmission and distribution poles, the stubbing of
poles, capital replacements that were necessary to affect the installation of lateral
fusing and avian protection apparatuses, the replacement of overhead conductor,
installation and replacement of line capacitor banks, line upgrades, re-insulation of
overhead lines, voltage improvements, rectifying conditions where the overhead
facilities become non-compliant with NESC, OSHA, and/or Company safety
standards, and other reliability improvement projects.
Sierra completed 450 Regional Overhead Rebuild Program projects from June 1,
2016 through December 31, 2018 at a total cost of $16,850,964. The largest
overhead rebuild projects were: (1) the 634 Line Rebuild project ($1,921,369); (2)
the East Mt. Rose 210 Reconductor project ($1,510,860); (3) the 2302
Transmission Line Uprating project ($740,103); (4) the Pinenut 1253 Rebuild
project ($652,748); and (5) the East Lovelock 7.2 Conversion project ($481,380).
Estimated expenditures for this program for the period January 1, 2019 through
May 31, 2019 are $4,050,965.
10. Q. WHY WERE THE REGIONAL OVERHEAD PROGRAM PROJECTS
COMPLETED BY THE COMPANY NECESSARY?
A. Projects performed under this program were necessary to address at least one of the
following concerns:
• Equipment that has reached or exceeded the end of its service life is replaced to
improve the reliability of the transmission and distribution system.
Becerra-DIRECT 5
Page 32 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
• Equipment is replaced to provide for the acceptance of renewable energy
infrastructure upgrades and is needed to compensate for reverse power flow
situations. For example, reverse power flow can cause regulators and reclosers
to operate abnormally.
• Equipment is installed or replaced to maintain adequate system voltage.
• Replacements and improvements also bring facilities into compliance with new
NESC, OSHA, and Company safety manual rules.
11. Q. PLEASE DESCRIBE THE 4 KILOVOLT (“KV”) TO 25 KV CONVERSION
PROGRAM.
A. This budget category captures costs incurred to continue to convert portions of the
4 kV electric distribution system in Sierra’s service territory to northern Nevada’s
modern 25 kV standard. Last reviewed in Sierra’s 2016 general rate review
proceeding, these conversion projects involve replacing substation equipment,
distribution poles, overhead conductor, underground cable, overhead and pad
mounted service transformers, overhead and pad mounted switches, capacitor
banks, and associated hardware.
The Company completed 40 4 kV to 25 kV conversions projects through December
31, 2018 at a total cost of $12,742,870. The largest 4 kV conversion projects were:
(1) Sparks Industrial Sub 25 kV Conversion ($2,530,515); (2) University #1
Northwest project ($1,485,859); (3) Moana #2 North project ($1,153,619); (4)
Moana #2 South project ($964,526); (5) El Rancho #2 West A project ($834,564);
(6) Hunter Lake #6 Sharon West B project ($915,013); (7) El Rancho #1 West
project ($602,698); and (8) El Rancho #1 North A project ($478,571). Estimated
Becerra-DIRECT 6
Page 33 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
expenditures for this program for the period January 1, 2019 through May 31, 2019
are $4,276,851.
12. Q.
A.
WHY ARE THE 4 KV TO 25 KV CONVERSION PROJECTS PERFORMED
BY THE COMPANY NECESSARY?
The 4 kV to 25 kV conversion program provides multiple benefits to customers and
employees in improved safety, reliability, and reduced operating costs:
Safety: The 4 kV conversion will improve the overall safety of the distribution
system as the deteriorating 4 kV equipment is removed from service.
Operations and Reliability: The 4 kV equipment is some of the oldest distribution
equipment in the Truckee Meadows system. Operational and safety issues are
expected to increase as it reaches and surpasses its normal operating life.
Additionally, the 4 kV system is essentially electrically “isolated” from the rest of
the distribution system, meaning back-up and service restoration options are
limited. Back-up and switching capability continues to deteriorate due to forced
conversions in different areas of the system to accommodate new customer
services. This creates increased labor and outage hours due to the complex
switching orders required to isolate and restore the 4 kV circuits.
Protection and Coordination: The conversion of the system to 25 kV allows for the
application of modern protective schemes in line with current standards.
Voltage Regulation: Voltage regulation normally becomes an issue on long feeders
with small conductor, high load, and low source voltage. Most of the Truckee
Becerra-DIRECT 7
Page 34 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
Meadows distribution system is either 24.9 kV or 4.16 kV. Most of the transformers
are 22.9 kV / 4.36 kV, with 24.1 kV being the highest primary tap available. This
results in high voltages on the 4 kV system and low voltages on the 25 kV buses
that serve the 4 kV substations. Additionally, adjustments to 4 kV voltage is
impossible because the 4 kV load tap changers cannot be repaired or maintained
(14 out of 18 substations had voltage regulators blocked).
Capacity: There is the potential for additional load growth in areas that are
currently served at 4 kV. Some 4 kV transformers are loaded to their full nameplate
ratings during peaks, with no back-ups or replacements available. This impacts
system reliability.
Maintenance: The 4 kV system has reached or exceeded the end of its service life,
requiring increased regular inspection and maintenance to ensure its operability.
Newly installed assets require less frequent and less costly maintenance.
Material: While the varieties of 4 kV materials that are currently stocked in the
warehouse can support the Northeast and Northwest districts, the quantities of these
materials could be reduced significantly, resulting in 4 kV inventory savings.
13. Q.
A.
PLEASE DESCRIBE THE SYSTEM AVERAGE INTERRUPTION
DURATION INDEX (“SAIDI”) IMPROVEMENT INITIATIVE
PROGRAM.1
The various projects under the SAIDI Improvement Initiative Program are projects
1 SAIDI is one of several industry standard measures that electric utilities use.
Becerra-DIRECT 8
Page 35 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
that replace and/or retrofit overhead and underground infrastructure. This includes
the replacement of transmission and distribution poles, capital replacements that
were necessary to affect the installation of lateral fusing and avian protection
apparatuses, the replacement of overhead conductor and underground cable,
installation and replacement of line capacitor banks, line upgrades, re-insulation of
overhead lines, and the replacement of pad mounted or subsurface facilities. In
addition to the activities typical of overhead and underground rebuilds, the SAIDI
Improvement Initiative may include grid hardening, installation of sectionalizers
and/or reclosers and circuit ties.
Sierra completed 54 SAIDI Improvement Initiative projects through December 31,
2018 at a total cost of $9,107,390. The largest projects were: (1) the Spring Valley
Parkway UG Rebuild Phase 6 project ($1,288,464); (2) the Spring Valley Parkway
UG Rebuild Phase 5 project ($1,146,916); (3) the Avian protection –Anaconda 204
project ($865,594); (4) the Avian protection – Anaconda 204-Grant View Dr.
project ($636,634); and (5) the Last Chance 211 Rebuild Phase 5 project
($529,576). Estimated expenditures for this program for the period January 1, 2019
through May 31, 2019 are $7,776,923.
14. Q. WHY WERE THE SAIDI INITIATIVE PROGRAM PROJECTS
COMPLETED BY THE COMPANY NECESSARY?
A. A study performed in April 2017 concluded that the top 25 high-risk feeders out of
317 feeders in the northern distribution network were contributing the most outage
hours and thus were the most unreliable circuits. These 25 high-risk feeders
constitute about 25 percent of total feeder length in the northern distribution system
and contributed 45 percent of the outage hours. As such, these projects will
Becerra-DIRECT 9
Page 36 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
significantly improve reliability to customers on these worst performing circuits by
reducing the frequency and duration of outages. The scope of work is similar to the
replacement and/or retrofitting of overhead and underground infrastructure and
provide the following benefits:
• Equipment that has reached or exceeded the end of its service life is replaced
to improve the reliability of the transmission and distribution system.
• Equipment is installed or replaced to maintain adequate system voltage.
• Replacements and improvements also bring facilities into compliance with
new NESC, OSHA, and Company safety manual rules.
• Allows Sierra to quickly isolate electrical faults allowing for rapid
restoration to customers.
• Harden the electric system to better resist outage incidents.
15. Q. PLEASE DESCRIBE THE REGIONAL UNDERGROUND REBUILD.
A. The various Regional Underground Rebuild Program projects involve replacing
and/or retrofitting underground infrastructure. This includes the replacement of
underground cable, the replacement of switches, vaults, and secondary boxes prior
to failure or after temporary repair was affected to restore service and includes other
reliability improvement projects.
The Company completed 302 Regional Underground Rebuild Program projects
through December 31, 2018 at a total cost of $9,570,952. The largest underground
rebuild projects were: (1) the Long Street Submersible Transformer Change out
project ($802,391); (2) the Spring Valley Replacement project ($734,196); and (3)
the South Virginia Street – U.S. Bank project ($489,836). Estimated expenditures
for this program for the period January 1, 2019 through May 31, 2019 are $940,123.
Becerra-DIRECT 10
Page 37 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
16. Q. WHY WERE THE REGIONAL UNDERGROUND REBUILD PROGRAM
PROJECTS NECESSARY?
A. The projects replacing and/or retrofitting underground infrastructure were
performed for a variety of reasons:
• Equipment that has reached or exceeded the end of its service life is replaced
to improve the reliability of the distribution system.
• Additional underground infrastructure is installed to create a “looped
system,” which provides greater operational flexibility through outage
restoration contingencies and decreases the duration of service disruptions.
• Equipment is installed or replaced to maintain adequate system voltage.
Typical projects include the replacement of cable with deteriorated
concentric neutral. This equipment corrects power factor and increases line
capacity.
• Replacement or construction of new vaults and boxes is required to replace
those that have structurally failed.
• Replacements and improvements are required to bring facilities into
compliance with changes in NESC, OSHA, and Company safety standards.
17. Q. PLEASE DESCRIBE THE SPARE EQUIPMENT PROGRAM.
A. This program provides for the acquisition of system critical spare substation
apparatus to provide reliable electric service and mitigate the risk of extended
customer outages. This equipment either fills an existing vacancy in spare
equipment or directly replaces a spare that was installed as the result of a failure.
The Company completed five projects, totaling $6,279,739, which consist of the
purchase of:
• One 345/230 kV, 300 MVA system spare transformer $2,676,686;
Becerra-DIRECT 11
Page 38 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
• One 280 MVA, 345 kV - 120 kV auto transformer $2,030,633;
• One 230 kV, 25 MVAR, reactor $937,260;
• One 345 kV breaker $579,423; and
• One 12.5/34.5kV, 2 MVA step up pad mount transformer $55,737.
Estimated expenditures for this program for the period January 1, 2019 through
May 31, 2019 are $0.
18. Q. WHY WAS THE SPARE EQUIPMENT PROGRAM NECESSARY?
A. Standard utility practice requires that the Company maintain sufficient quantities
of long-lead spare equipment such as large power autotransformers, medium power
transformers, and substation breakers for all common voltage and capacity classes.
The typical lead-time on delivery of medium power transformers is 12 to 18 months
after placement of an order (depending on factory loading); similarly, the lead-time
for high-voltage breakers is 6 to 8 months. The number of spares on hand varies
based on the number of devices operational in the field, access and/or availability
to acquiring new equipment, age of transformer fleet, and the reliability of critical
load. These units are called upon for an unforeseen or urgent project where the
project timeline is not adequate to order and procure replacement equipment.
Normally, the Company should maintain one or more spare units for each of these
assets. Additional justification for the acquisition of each spare is provided below:
D2416: 300 MVA 345/230 kV Autotransformer. Sierra did not have a spare 300
MVA 345/230 kV transformer to back up three transformers at Hilltop and Gonder
substations. An extended loss of the Gonder or Hilltop 345/230 kV transformers
could result in derating of interconnection path ratings, an increase in must run
generation, noneconomic dispatch and load curtailment.
Becerra-DIRECT 12
Page 39 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
TM299: 280 MVA 345/120 kV Autotransformer. This purchase replaced the
spare 280 MVA 345/120 kV transformer that was used to replace the Humboldt
345/120 kV transformer, which failed catastrophically on July 6, 2014. After the
failure of the Humboldt transformer, Sierra did not have a spare 345/120 kV 280
MVA transformer to back up the 11 transformers at various substations.
TM265: 25 MVAR 230 kV Shunt Reactor. Sierra did not have a spare 25 MVAR
230 kV shunt reactor to back up six reactors at Anaconda Moly, Austin, Gonder,
and Osceola substations. An extended loss of the existing reactors could result in
voltage excursions, exceeding equipment ratings, and derating of interconnection
path ratings.
TM287: 345 kV Power Circuit Breaker. Sierra did not have a spare 345 kV power
circuit breaker to back up many similarly rated breakers. An extended loss of the
existing breakers would result in the significant degradation of reliable transmission
service.
D2417: 2 MVA 12.5/34.5 kV Transformer. Sierra did not have a spare 12.5/34.5
kV transformer to back up the existing Southside Substation feed to Fallon Naval
Air Station (“FNAS”). An extended loss of the existing transformer would result in
an extended loss of service to FNAS.
The Company’s older transformers are more susceptible to failure, even when
maintained pursuant to manufacturer recommendations. Additionally, catastrophic
damage caused by external forces such as weather and vandalism or other
unanticipated incidents poses risks to service reliability that are reduced or
Becerra-DIRECT 13
Page 40 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
mitigated with essential spares. This practice provides the Company with the ability
to quickly respond when unexpected failures occur, avoiding extended service
interruptions.
19. Q. PLEASE DESCRIBE THE AVIAN PROTECTION PROGRAM PROJECTS.
A. The Avian Protection Program projects involve the installation of bird guard
apparatus and, where necessary, the design and rebuild of structures and associated
hardware such as cross arms and insulators to meet avian safe standards.
The Company completed 20 Avian Protection Program projects through December
31, 2018 at a total cost of $4,613,702. The largest Avian Protection Program
projects were: (1) the North 5th Street project ($527,867); (2) the Dutch Flat 208
project - 726868 ($516,715); (3) the Dutch Flat 208 project - 726234 ($492,553);
(4) the Bridge Street 206 project - 1023878 ($470,699); and (5) the Bridge Street
206 project – 3102 ($456,808). Estimated expenditures for this program for the
period January 1, 2019 through May 31, 2019 are $415,173.
20. Q. WHY WERE THE AVIAN PROTECTION PROGRAM PROJECTS
NECESSARY?
A. As a core corporate value, the Company practices responsible stewardship of the
environment. To this end, the Company has implemented an avian protection plan.
The Avian Protection Plan, also known as an APP, is a voluntary, utility-specific
plan for reducing risks to birds and system reliability that result from avian
interactions with power lines and electric utility facilities with the overall goal of
reducing avian mortality.
Becerra-DIRECT 14
Page 41 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
Federal compliance and public safety are the primary drivers behind the Avian
Protection Plan; there are three primary laws in the United States that protect birds
from injury and death. They are:
• Migratory Bird Treaty Act of 1918 that currently protects 1,007 bird
species;
• Bald and Golden Eagle Protection Act of 1940; and
• Endangered Species Act of 1973.
In addition to these federal laws protecting birds, collisions and interactions with
power lines and distribution facilities can cause service interruptions.
The APP captures the costs incurred to affect the various engineering and field
modifications and replacements necessary to comply with the Company’s Avian
Protection Plan.
21. Q. PLEASE DESCRIBE THE SUBSTATION BREAKER REPLACEMENT
PROGRAM.
A. The Substation Breaker Replacement Program projects involve the replacement of
breakers and disconnects that are unreliable, have reached or exceeded the end of
their service lives, are difficult and/or expensive to maintain due to the
unavailability of spare parts, or are potentially hazardous to operate due to slow or
non-clearing faults.
Through December 31, 2018, the largest Substation Breaker Replacement Program
project was the North Truckee Breaker Replacement project ($3,380,256).
Estimated expenditures for this program for the period January 1, 2019 through
May 31, 2019 are $0.
Becerra-DIRECT 15
Page 42 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
22. Q. WHY WERE THE BREAKER REPLACEMENT PROGRAM PROJECTS
PERFORMED BY THE COMPANY NECESSARY?
A. Circuit breakers are devices that automatically operate to protect an electrical
circuit from damage caused by overcurrent/overload or short circuit. It
accomplishes this by interrupting current flow after protective relays detect a fault
condition. Circuit breakers can be reset (either manually or automatically) to
resume normal operation. These projects were necessary to avoid extended
disruptions to service, reduce future maintenance costs, and mitigate heightened
risks associated with obsolete equipment deemed unsafe to operate.
23. Q. PLEASE DESCRIBE THE TOOLS REPLACEMENT PROGRAM.
A. This program captures the costs associated with the acquisition, repair, or
replacement of tools that are properly unitized as assets in accordance with the
capitalization policy. Tools include items such as hot sticks, relay test equipment,
power system simulators, Panduit printers, mirrored bits testers, multi-meters, and
other items.
The Company completed 208 projects under the Tools Replacement Program
through December 31, 2018, at a total cost of $1,928,092. The largest project was
the Crimp Tool replacement project ($220,552). Estimated expenditures for this
program for the period January 1, 2019 through May 31, 2019 are $625,972.
24. Q. WHY ARE REGULAR TOOL REPLACEMENTS NECESSARY?
A. Regular replacement of tools ensures that operations and maintenance staff have
access to the proper tools to execute projects and programs. These tools are
typically acquired as a technician/crew safety improvement, to reduce expenses,
Becerra-DIRECT 16
Page 43 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
increase work efficiency, and/or maintain compliance. For example, the crimp tool
replacement identified above is manufactured by AFL Telecommunications LLC
and includes the crimpers, bus gauge, and other accessories. Called a swage fitting,
it is the Companies’ current standard tool for bus connections. The connections
require a very specific kind of tooling for bus work at new substations. The tools
make up a hydraulic pump that compresses the connectors on to the bus. Every
crew assembling a bus will need access to these tools at some point in the
construction process. Currently, the three complete sets of crimpers purchased are
shared by six substation crews in northern Nevada.
25. Q. PLEASE DESCRIBE THE TELEMETRY/PI ADDITION PROGRAM.
A. The Telemetry/PI Addition Program involves the installation of
telecommunications and substation equipment necessary to monitor and report
voltage, current, and power, and to provide breaker or recloser status and control
for substations for system control operators.
The Company completed 31 projects under the Telemetry/PI Addition Program
through December 31, 2018, at a total cost of $1,850,384. The largest single project
was the Antelope Valley PI Addition project ($249,232). Estimated expenditures
for this program for the period January 1, 2019 through May 31, 2019 are $9,947.
26. Q. WHAT ARE THE TELEMETRY/PI ADDITION PROGRAM PROJECTS?
A. Telemetry addition projects provide for automated communications through which
measurements are made and other data collected at remote locations and transmitted
to receiving equipment for monitoring and provide multiple benefits.
Becerra-DIRECT 17
Page 44 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
Telemetry is a basic requirement for a functional Supervisory Control and Data
Acquisition (“SCADA”), a core utility system. SCADA systems allow operators in
control rooms to monitor the flows in the power system and to remotely control
substation equipment, issuing control commands via the utility’s communication
network. Other fundamental components of a SCADA system include functionality
to alarm abnormal conditions, tag devices for safety and information purposes, and
archive real-time data.
The SCADA system communicates with Remote Terminal Units (or substation data
concentrators fed by substation intelligent electronic devices) located within
substations. Currently, SCADA systems have been used to monitor and control
equipment on the transmission and sub-transmission network as well as distribution
transformers and feeder head devices located within the substations.
27. Q.
A.
WHY WERE THE TELEMETRY/PI ADDITION PROGRAM PROJECTS
NECESSARY?
For several reasons, which are summarized below.
Operational Benefits and Cost Savings. Collecting power data from sites that lack
telemetry requires field resources to travel to the site to retrieve a chart. These charts
are not as reliable as real-time telemetry since they can become illegible, damaged
or lost. Simply put, it takes time and resources to collect data manually;
consequently, manually-gathered charts are sometimes severely dated and lose their
analytical value.
Becerra-DIRECT 18
Page 45 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
Energy Management. The energy management system manages the operation of
the bulk power grid. It is considered a critical system since the potential
consequences of losing visibility and control of bulk power grid operations are so
severe. The SCADA system retrieves real-time measurements and status conditions
of the power system and power network applications such as state estimation,
power flow, and contingency analysis.
Distribution and Outage Management. Telemetry is required for advanced
distribution management system power applications such as unbalanced power
flow, distribution state estimation, integrated Volt/Var control, fault location,
isolation, and service restoration to manage, operate, optimize, and restore the grid
in real-time.
Future Utilization – Smart Grid Technologies. The addition of telemetry is
prerequisite for the introduction of smart grid technologies. The proliferation of
new technologies on the customer side of the meter (e.g., electric vehicles,
distributed generators, and energy storage technologies) make the distribution
network increasingly more complex to operate. Smart grid technologies allow the
Company to safely operate and better optimize its network assets with consideration
to these new customer technologies.
Telemetry provides for rapid response to service interruptions and the restoration
of service as electrical information pertaining to a device’s status is readily
available to System Control Operators. Further, smart grid technologies require
telemetry to automate field devices on distribution networks to pick up customers
on unfaulted sections of the feeders more quickly, thus minimizing customer
Becerra-DIRECT 19
Page 46 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
outages in what is commonly referred to as Distribution Automation and ‘self-
healing’ systems.
28. Q. PLEASE DESCRIBE THE POLE TREATMENT PROGRAM.
A. This program treats and reinforces overhead line wood poles to extend the life of
the poles. Treatment includes the inspection, sounding, boring, and treatment of
deteriorated wood poles. A successful program includes:
• Identifying decay and measuring defects;
• Estimating the pole’s remaining strength to determine pass/fail; and
• Applying effective remedial treatments to extend the safe, reliable service-
life of the pole.
Additionally, pole reinforcements are included in this program when additional
load is added to the pole and the strength is no longer adequate (usually driven by
joint use attachments for telecommunications companies) or it is no longer deemed
to be structurally sound.
The Company completed 91 Pole Treatment projects through December 31, 2018
at a total cost of $1,818,638. The largest project was the Grass Valley - 2517 project
($94,115). Estimated expenditures for this program for the period January 1, 2019
through May 31, 2019 are $0.
29. Q. WHY WAS THE POLE TREATMENT PROGRAM NECESSARY?
A. Pole treatment programs are the cornerstone for overhead circuit reliability
programs. This program allows for optimized maintenance, life extension, and
replacement decisions that lower overall ownership costs. Furthermore, pole steel
reinforcement trusses are specifically designed, engineered, and manufactured to
Becerra-DIRECT 20
Page 47 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
add decades of useful life to wood poles. When fully implemented, this program
provides a reduction in customer average interruption duration index minutes,
reduces pole failures, and reduces pole replacements. The treatment and reinforcing
of poles significantly improve the pole structure that supports overhead circuits and
improve the reliability of service to the customers who are served by overhead
distribution circuits. The data collected from this program is also used for pole
replacements, circuit inspections, and overhead rebuild activities associated with
poorly performing circuits.
30. Q. PLEASE DESCRIBE THE LINE SENSOR PROGRAM.
A. Initiated in 2014, the Intelligent Line Sensor program utilizes advanced technology
to measure and monitor voltage, current, power, and phase angle at critical points
on overhead conductors such as substation getaways, important sectionalizing
points, and line recloser locations. The Company selected Aclara (formerly
Tollgrade) to supply the sensors through a competitive bidding process, and now
has more than 600 sensors installed on single-phase and three-phase lines
throughout the Companies transmission and primary distribution systems. The
information provided by these sensors is transmitted mainly via cellular
communications and can be accessed via Aclara’s Sensor Management System
software.
The Company completed one Line Sensor Program project, the light House
Distribution Sensor project, by December 31, 2018 at a total cost of $313,363. The
estimated expenditures for this program for the period January 1, 2019 through May
31, 2019 are $856,174.
Becerra-DIRECT 21
Page 48 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
31. Q. WHY WAS THE LINE SENSOR PROGRAM NECESSARY?
A. The Company was seeking effective alternatives to provide telemetry on many of
its transmissions lines and distribution feeders where no metering existed to
improve grid awareness at a cost lower than that of traditional telemetering
equipment. The sensors provide loading information for planning and operating
purposes, fault information to aid in service restoration, and, as the Companies’
electric system transitions to a modern era with increased penetration of distributed
energy resources, will help facilitate the safe and reliable planning and operation of
the system going forward.
32. Q. DOES THIS CONCLUDE YOUR PREPARED TESTIMONY?
A. Yes.
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
Becerra-DIRECT 22
Page 49 of 250
Becerra Exhibit Direct-1
BACKGROUND AND EXPERIENCE
Ricardo D. Becerra Manager, Delivery Assurance Financial Reporting
NV Energy 6226 West Sahara Avenue
Las Vegas, NV 89151 (702) 402-2768
Mr. Becerra became an employee of NV Energy thirteen years ago. His work experience is largely focused in electric operations and maintenance planning, forecasting, and reporting. He has guided Electric Delivery’s capital and O&M cost reporting for eleven years and has contributed to a variety of operations and maintenance program analysis. Mr. Becerra joined in the company as a mechanical engineering intern in 2006. Mr. Becerra has a Mechanical Engineering bachelor’s degree and a Master’s in Business Administration degree from the University of Nevada, Las Vegas.
Employment History
• Manager, Delivery Assurance Financial Reporting, 2017 • Sr. Operations Analyst, Delivery Assurance, 2015 • Sr. Project Controls Consultant, Project Controls, 2014 • Student Intern, Project Controls, 2008
Education • Bachelor of Science in Mechanical Engineering, December 2008, University of Nevada,
Las Vegas • Masters of Business Administration, May 2016, University of Nevada Las Vegas
Page 50 of 250
Page 51 of 250
VICTOR FIGUEREDO
Page 52 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
Sierra Pacific Company d/b/a NV Energy
2019 General Rate Case Docket No. 19-06__
PREPARED DIRECT TESTIMONY OF
Victor Figueredo
Revenue Requirement
I. INTRODUCTION
1. Q. PLEASE STATE YOUR NAME, OCCUPATION, BUSINESS ADDRESS,
AND PARTY FOR WHOM YOU ARE FILING TESTIMONY.
A. My name is Victor Figueredo. I am the Director of Electric Delivery Support for
NV Energy, Inc. (“NV Energy”), Sierra Pacific Power Company d/b/a NV
Energy (“Sierra” or the “Company”) and Nevada Power Company d/b/a NV
Energy (“Nevada Power” and, together with Sierra, the “Companies”). I work
primarily out of NV Energy’s operating center complex office, which is located
at 7155 Lindell Road in Las Vegas, Nevada. I am filing testimony in this
proceeding on behalf of Sierra.
2. Q. PLEASE BRIEFLY DESCRIBE YOUR PROFESSIONAL
BACKGROUND AND EXPERIENCE.
A. I joined the Companies in May 1995 after spending 11 years in the automotive
manufacturing industry. As Director of Electric Delivery Support, I am currently
responsible for the functional areas of vehicle/equipment fleet management,
vegetation/tree trimming maintenance, and materials/logistics warehouse
Figueredo– DIRECT 1
Page 53 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
operations. I have attached as Exhibit Figueredo-Direct-1 a statement of
qualifications that further details my background and professional experience.
3. Q. HAVE YOU SUBMITTED PREPARED TESTIMONY WITH THE
PUBLIC UTILITIES COMMISSION OF NEVADA (“COMMISSION”)?
A. Yes, I have testified in a number of proceedings before the Public Utilities
Commission of Nevada (“Commission”). My most recent general rate case
(“GRC”) testimony was in Nevada Power’s 2017 GRC , Docket No. 17-06003.
4. Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY?
A. My testimony addresses vehicle replacement investment costs completed since
Sierra’s 2016 GRC, Docket No. 16-06006. Specifically, I discuss investment in
vehicles since the close of the certification period in the 2016 GRC through the
end of the test period for this GRC (June 01, 2016 – December 31, 2018), as well
as vehicle replacements completed in January and February of 2019, and
estimated through May 31, 2019, the close of the certification period. I provide
specific information regarding the largest categories of investments for the Fleet
Services department, the buyout of vehicle lease financial arrangements at the
point of lease contract expirations, and the acquisition of new vehicles to replace
units that have exceeded their life cycles. Combined, these expenditures represent
approximately $2.3 million in plant investment allocated to Sierra through May
31, 2019.
Figueredo– DIRECT 2
Page 54 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
Table Figueredo Direct-1below provides costs for the test period as of December
31, 2018 and costs for the certification period of January 1, 2019 through May
31, 2019.
TABLE FIGUEREDO DIRECT-1
Division Additions Jun-16 to
Dec-18
Additions Jan-19 to May-19
Total Fleet Additions
Fleet Investments $2,325,656 $0 $2,325,656
5. Q. ARE YOU SPONSORING ANY EXHIBITS TO YOUR PREPARED
DIRECT TESTIMONY?
A. Yes, I am sponsoring the following exhibit:
Exhibit Figueredo-Direct-1–Statement of Qualifications
II. TESTIMONY SUPPORTING STATEMENTS
6. Q. WHY HAS SIERRA REPLACED ANY VEHICLE AND FLEET
EQUIPMENT SINCE JUNE 1, 2016?
A. Sierra’s Fleet Services annually performs vehicle lifecycle analysis to gauge the
optimal replacement plan for each vehicle class to achieve the lowest total cost to
own and maintain these assets over their useful lives. Fleet Services works to
limit its capital expenditures for vehicle replacement by retaining these assets
through their full useful lifecycle. The average age of a Sierra vehicle is 9.1 years,
which compares favorably to the utility industry average of 6.3 years.
Figueredo– DIRECT 3
Page 55 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
7. Q. PLEASE DESCRIBE THE FINANCIAL ANALYSIS PERFORMED TO
DETERMINE WHETHER TO PURCHASE OR LEASE REPLACEMENT
VEHICLES AND OTHER FLEET EQUIPMENT.
A. Sierra’s Finance department uses a present worth of revenue requirement
(“PWRR”) model to assess the economic impact of different alternatives
including vehicle analysis. The PWRR model allows the Company to compare
the economic impact to the customer from buying versus leasing the vehicles, and
relies on inputs such as vehicle values, depreciation rates, capital costs, tax rates,
and lease contract terms. Between June 1, 2016 and December 31, 2018, 21 units
were purchased at a total cost of approximately $1 million. During the
certification period, no additional vehicles were purchased.
8. Q. PLEASE DESCRIBE THE FINANCIAL ANALYSIS PERFORMED TO
EVALUATE OPPORTUNITIES FOR BUYING VEHICLE AND FLEET
EQUIPMENT ASSETS UPON EXPIRATION OF EXISTING LEASES?
A. The same PWRR analysis is used to evaluate end-of-lease vehicle decisions.
Current asset values, lease expiration terms, sales tax rates, and depreciable life
information is incorporated into this analysis. Vehicle buyouts at the end of the
lease term were determined to result in the most favorable PWRR, allowing the
Company to avoid the higher costs associated with newer vehicles. During the
test period, a total of 60 units previously leased were purchased for approximately
$1.3 million. During the certification period, no lease agreements were bought
out, and so no leased vehicles were purchases.
Figueredo– DIRECT 4
Page 56 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
9. Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY?
A. Yes.
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
Figueredo– DIRECT 5
Page 57 of 250
Exhibit Figueredo-Direct-1 Page 1 of 1
QUALIFICATIONS OF WITNESS VICTOR FIGUEREDO
DIRECTOR, DELIVERY SUPPORT NV ENERGY
7155 LINDELL RD LAS VEGAS, NEVADA 89151
Mr. Figueredo has extensive utility industry experience and demonstrated capabilities in
vehicle/equipment fleet management, procurement, materials management, and operations
management. Mr. Figueredo’s background includes purchasing sourcing/negotiation
responsibilities, warehousing/logistic activities, and vegetation management. Mr. Figueredo
has 24 years of experience in the electric utility industry. Mr. Figueredo holds a Bachelor of
Science degree in Business Administration and Master’s degree in Business Administration.
Prior to joining NV Energy, Victor worked in the automotive manufacturing industry.
EDUCATION AND CERTIFICATIONS
Bachelor of Science, Business Administration, University of Nevada, Las Vegas, 1984
Master's in Business Administration, University of Detroit, 1991
Certified Purchasing Manager (C.P.M.), Institute of Supply Management
WORK HISTORY
NV Energy
Director, Electric Delivery Support Electric Delivery 12/13 - present
Director, Fleet Services Corporate Services 10/ 11 - 12/13
Director, Supply Chain Management Corporate Services 4/01 - 10/11
Manager, Corporate Purchasing Corporate Services 9/99 - 4/01
Manager, Inventory Management Corporate Services 7/96 - 9/99
Strategist, Materials Management Corporate Services 5/95 - 7/96
Chrysler Corporation
Senior Purchasing Agent Procurement & Supply 7/89 - 5/95
Material Coordinator Production Control 12/86 - 7/89
Page 58 of 250
Page 59 of 250
JIM DeFRATES
Page 60 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
Sierra Pacific Power Company d/b/a NV Energy
2019 General Rate Case Docket No. 19-06___
PREPARED DIRECT TESTIMONY OF
Jim DeFrates
Revenue Requirement
I. INTRODUCTION
1. Q. PLEASE STATE YOUR NAME, JOB TITLE, EMPLOYER AND BUSINESS
ADDRESS.
A. My name is Jim DeFrates. I am the Claims Manager for Nevada Power Company
d/b/a NV Energy (“Nevada Power”) and Sierra Pacific Power Company d/b/a NV
Energy (“Sierra” or the “Company,” and together with Nevada Power, the
“Companies”). My business address is 6226 West Sahara Avenue in Las Vegas,
Nevada. I am filing testimony on behalf of Sierra.
2. Q. PLEASE DESCRIBE YOUR PROFESSIONAL BACKGROUND AND
EXPERIENCE.
A. I have worked at the Company since 1995 and, in August 2013, I was named Claims
Manager. I have worked in the claims industry for more than 29 years. More details
regarding my professional background and experience are set forth in my Statement
of Qualifications, included as Exhibit DeFrates-Direct-1.
3. Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE PUBLIC
UTILITIES COMMISSION OF NEVADA (“COMMISSION”)?
DeFrates-DIRECT 1
Page 61 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
A. Yes I have. I have testified in Sierra’s 2016 general rate case ( Docket No. 16-
06006) and Nevada Power’s 2017 general rate case (Docket No. 17-06003) before
the Commission.
4. Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS
PROCEEDING?
A. I support the costs included in plant in service related to claims, as well as the
annualizations of test period costs for insurance premiums set forth on Schedule H-
CERT-22.
II. CLAIMS PLANT IN SERVICE
5. Q. WHAT COSTS ARE INCLUDED IN PLANT IN SERVICE FOR CLAIMS?
A. Since the close of the certification period in Sierra’s 2016 general rate case, the
Company experienced $2,189,250 in uncompensated costs to replace plant that was
damaged by third parties. The Company estimates that an additional $74,137 will
be expended during the certification period for this case, January 1, 2019 through
May 31, 2019. These costs reflect the costs incurred to replace damaged plant, over
and above the amounts collected from the individual(s) responsible for damaging
the plant. These costs are included in the plant additions provided by Ms. Ellen
Fincher in Exhibit Fincher-Direct-2.
6. Q. PLEASE PROVIDE AN EXAMPLE OF THE TYPES OF CLAIMS THAT
ARE INCLUDED IN THESE COSTS ASSOCIATED WITH CLAIMS
PROJECTS.
A. Any claim where the Company was unable to collect 100 percent of the repairs
from the responsible party is included in the cost. Some examples include: hit and
DeFrates-DIRECT 2
Page 62 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
run accidents (where the responsible party is never identified), car accidents where
the responsible party’s insurance is insufficient to cover the cost of repairing or
replacing damaged equipment, and incidents for which the responsible party is
uninsured and has no assets to pay the cost of repairing or replacing damaged
equipment.
7. Q. HOW DOES THE COMPANY PURSUE A RESPONSIBLE PARTY WHEN
COMPANY EQUIPMENT IS DAMAGED OR DESTROYED?
A. The Claims department is notified when a third party causes damage to Company
property and equipment. The cause of the damage is documented and the
responsible party identified. After the repair work is completed and the charges
make their way through accounting, an invoice is generated and sent to the
responsible party and/or their insurer. The claim is pursued with the responsible
party and/or their insurance company until a collection is made. Should collection
efforts fail, actions are filed against the responsible party in the appropriate court.
The amounts reflected above represent the uncollected costs of repairing or
replacing damaged Company property or equipment, after the reasonable
exhaustion of these remedies.
III. INSURANCE PREMIUM COSTS, SCHEDULE H-CERT-22
8. Q. PLEASE DESCRIBE THE INFORMATION REFLECTED ON SCHEDULE
H-CERT-22.
A. Schedule H-CERT-22 shows test period expense for insurance premiums as well
as annualizations of test period expense used to calculate revenue requirement. H-
CERT-22 shows a reduction in annualized costs of insurance of $125,000. These
DeFrates-DIRECT 3
Page 63 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
reductions show the continued cost-savings impacts of combining the Companies’
insurance coverage with Berkshire Hathaway Energy (“BHE”) coverage.
The most notable adjustment on Schedule H-CERT-22 is the removal of all costs
associated with Directors and Officers Liability Insurance from annualized
expense. This adjustment reflects the expiration of the “tail policy” that extended
coverage for the six years following the close of the BHE transaction. The end of
the residual period for the tail policy is December 19, 2019. Thus the costs
associated with this coverage have been removed from cost of service.
The decrease in the annualized cost of excess liability insurance is primarily due to
the post-acquisition consolidation of the Companies’ excess liability coverage
under BHE excess liability policies. BHE’s coverage is provided by the same
insurance carrier used by Nevada Power under the same policy form. Coverage is
identical with the exception of the amount of the self-insured retention, which
increased under BHE’s policy.
9. Q. DOES THIS COMPLETE YOUR TESTIMONY?
A. Yes, it does.
DeFrates-DIRECT 4
Page 64 of 250
Exhibit DeFrates-Direct-1 Page 1 of 1
JAMES A. DEFRATES CLAIMS MANAGER
NV Energy 6226 W. Sahara Avenue
Las Vegas, Nevada 89146 (702) 402-5172
My name is James A. DeFrates. My business address is 6226 W. Sahara Avenue, Las Vegas, Nevada. I am the Claims Manager for Nevada Power Company d/b/a NV Energy and for Sierra Pacific Power Company d/b/a NV Energy.
I graduated from the University of Nevada, Las Vegas in 1986 with a Bachelor of Science Degree in Hotel Administration. I have spent the majority of my career in the insurance claims industry working primarily as a field investigator, supervisor and/or manager.
I have been employed with NV Energy since February 1995 working entirely in the claims department, starting as a field claims investigator and rising to the Team Leader position in January 2009 and then to Claim Manager in August 2013.
Since becoming Claim Manager in August 2013, I am responsible for, among other things, the costs expended to replace plant that was damaged by third parties. These costs are associated with the replacement of capital assets where the company is unable to collect 100% from the responsible party. Our investigators work to collect 100% of our damages while occasionally, we are unable to collect all of our damages.
Page 65 of 250
Page 66 of 250
WILLIAM OLSEN
Page 67 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
Sierra Pacific Power Company d/b/a NV Energy
2019 General Rate Case Docket No. 19-06____
PREPARED DIRECT TESTIMONY OF
William Olsen
Revenue Requirement
I. INTRODUCTION
1. Q. PLEASE STATE YOUR NAME, OCCUPATION, BUSINESS ADDRESS
AND PARTY FOR WHOM YOU ARE FILING TESTIMONY.
A. My name is William Olsen. My current position is Vice President of Information
Technology and Chief Information Officer for Sierra Pacific Power Company
d/b/a/ NV Energy (“Sierra” or the “Company”) and Nevada Power Company d/b/a
NV Energy (“Nevada Power” and together with Sierra, the “Companies). My
business address is 6226 W Sahara Ave in Las Vegas, Nevada. I am filing testimony
on behalf of Sierra.
2. Q. PLEASE DESCRIBE YOUR BACKGROUND AND EXPERIENCE IN THE
UTILITY INDUSTRY.
A. I joined the Companies in June 1988 and have worked for the Company for
approximately 31 years in the Information Technology Department that entire time.
I hold a Bachelor’s Degree in Computer Information Systems from DeVry Institute
of Technology, now DeVry University. A more complete statement is set forth in
Exhibit Olsen-Direct-1.
Olsen-DIRECT 1
Page 68 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
3. Q. PLEASE DESCRIBE YOUR RESPONSIBILITIES AS VICE PRESIDENT
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
OF INFORMATION TECHNOLOGY.
A. As Vice President of Information Technology, my responsibilities include
developing strategy and then executing that strategy for Information Technology,
Telecommunications, Cyber Security, and Physical security for Sierra and Nevada
Power. I oversee direct reports in each of the above listed areas and for the
Information Technology Project Management Office. I coordinate with the other
business units to ensure that their technological needs are met in a cost-efficient,
secure manner. I am also the designated North American Electric Reliability
Council (“NERC”) Critical Infrastructure Protection (“CIP”) Senior Manager
responsible for overseeing and administering the CIP program.
4. Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE PUBLIC
UTILITIES COMMISSION OF NEVADA (“COMMISSION”)?
A. Yes.
5. Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY?
A. I provide support for information technology infrastructure and application
investment projects completed since Sierra’s last rate case (May 31, 2016) and
planned through the certification period (May 31, 2019).
I provide support for the technology infrastructure projects and processes with costs
greater than $1.0 million or where the aggregate of multiple similar projects or
programs exceed $1.0 million. These infrastructure projects include four
“Evergreen” projects and one other business operations support project. Sierra’s
share of the investments is $6,407,964, to the electric operations. The Table Olsen-
Olsen-DIRECT 2
Page 69 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
Direct-1 below provides the cost of each project, as of May 31, 2019 and the
allocated total costs to Sierra. Additional detail about the Evergreen concept is
provided in Exhibit Olsen-Direct-2.
TABLE OLSEN-DIRECT-1
PROJECT DESCRIPTION TOTAL ELECTRIC Network Infrastructure Evergreen $1,907,504 $1,587,272 AIX Disk Evergreen 1,221,789 1,016,675 Exchange, e-Vault and Lync Upgrade 1,008,372 839,086 Firewall/Appliance Evergreen 2,214,453 1,842,691 Infrastructure – Laptop PC Evergreen 1,348,652 1,122,240 Total $7,700,770 $6,407,964
I also provide support for four information technology applications projects
completed since the close of the certification period in Sierra’s last rate case through
the certification period (May 31, 2019). I provide descriptions of four significant
information technology projects with costs of approximately $1.0 million or more,
or where the aggregate of multiple similar projects or programs exceeds $1.0
million. These four projects total a combined $6,912,908 to the electric operations.
TABLE OLSEN-DIRECT-2
PROJECT DESCRIPTION TOTAL ELECTRIC Banner Data Reduction & Purge $2,982,019 $2,481,397 Portal Operations 1,133,133 942,902 UI Planner Implementation 2,562,746 2,132,512 T&D Work & Asset Mgmt Enh 1,629,690 1,356,097 Total $8,307,588 $6,912,908
Olsen-DIRECT 3
Page 70 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
6. Q. ARE YOU SPONSORING ANY EXHIBITS?
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
A. Yes, I am sponsoring the following Exhibits:
Exhibit Olsen-Direct-1 Statement of Qualifications
Exhibit Olsen-Direct-2 White Paper “Evergreen Process Benefits.”
II. INFORMATION TECHNOLOGY INFRASTRUCTURE PROJECTS
INFRASTRUCTURE PROJECT 1: NETWORK INFRASTRUCTURE EVERGREEN
7. Q. PLEASE DESCRIBE THE NETWORK INFRASTRUCTURE
EVERGREEN PROCESS.
A. The Network Infrastructure Evergreen process is a long-established ongoing
process addressing information technology growth in a structured and cost-
effective manner. The Network Infrastructure project ensures adequate application
performance and reliability through a scheduled technology refresh cycle. Funding
for this process is also managed through the standard capital budgeting process.
The costs identified here are an aggregate of three separate evergreen process
groupings. The share of the costs allocable to Sierra’s electric customers is
$1,587,272.
8. Q. WHAT WERE THE DRIVING FACTORS FOR ESTABLISHING THE
EVERGREEN PROCESS?
A. Prior to the creation of the Evergreen process, upgrades to accommodate
information technology needs and resources were handled reactively and on a case
by case-by-case basis. The degradation in application performance prior to
upgrades being suggested resulted in significant decreases in productivity and was
very disruptive to normal business operations and to the budgeting process.
Olsen-DIRECT 4
Page 71 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
Adoption of the Evergreen process has achieved significant benefits including
reduced costs, improved utilization of computing resources, budget predictability,
and an improved application performance life cycle. Specifically, the standardized
technology refresh cycle, as presented in the white paper entitled “Evergreen
Process Benefits,” attached hereto as Exhibit Olsen-Direct-2, produced the
following benefits:
• Improved energy efficiency
• Improved density/physical space utilization
• Virtualization functionality implementation
• Performance stability
• Predictable, simplified budgeting
• Maintenance savings
• Improved reliability and availability
• Enable new application functionality
• Non-disruptive operating system upgrades
• Address normal growth trends
Gartner, Inc., a leading information technology research and advisory firm,
advocates that infrastructure computing resources be replaced on a regular basis.
We continue to track research in this area to ensure that we are in harmony with
industry practices. In summary, the Evergreen process ensures an adequate
computing infrastructure to support all applications resulting in improved
productivity.
Olsen-DIRECT 5
Page 72 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
9. Q. HOW OFTEN DO YOU REVIEW THE RECOMMENDED REFRESH
SCHEDULE TO ENSURE EQUIPMENT IS NOT REPLACED PRIOR TO
THE END OF ITS USEFUL LIFE?
A. We review the refresh cycle schedule for these products approximately every three
years to ensure equipment is not being replaced prematurely. We have found our
current replacement schedule balances the cost of procurement and implementation
against that of operational effectiveness and loss of productivity through
performance degradation.
10. Q. WHEN WERE THE NETWORK INFRASTRUCTURE EVERGREEN
UPGRADES COMPLETED?
A. The network infrastructure evergreen process is managed in discrete, annual budget
groupings/projects. Network infrastructure upgrades are performed and
implemented throughout the year. Only network infrastructure components
identified as “used and useful” as of May 31, 2019 are included in plant in service.
INFRASTRUCTURE PROJECT 2: AIX DISK EVERGREEN
11. Q. PLEASE DESCRIBE THE AIX DISK EVERGREEN PROCESS.
A. Like the Network Infrastructure Evergreen projects, the AIX Disk Evergreen
process has been in place since 2000 to address information technology growth and
to ensure adequate application performance through a scheduled technology refresh
cycle. AIX disk is Tier 1 data storage for the Companies’ critical systems. Funding
for this process is managed through the standard capital budgeting process. The
costs identified here are the aggregate of four separate Evergreen process groupings
Olsen-DIRECT 6
Page 73 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
for disk technologies since the last rate cycle. The costs allocable to Sierra’s electric
operations are $1,016,675.
12. Q. WERE THE DRIVING FACTORS FOR ESTABLISHING THE AIX DISK
PROJECT THE SAME AS THE OTHER EVERGREEN PROJECTS?
A. Yes, the merits of the Evergreen process described in Q&A 8 above apply equally
to the AIX Disk Evergreen project. Prior to the creation of the Evergreen process,
upgrades to accommodate growth and ensure adequate application reliability and
performance were handled on a case-by-case basis, primarily in a reactive mode.
The degradation in performance prior to an upgrade being suggested resulted in
significant decreases in productivity and was very disruptive to normal business
operations and to the budgeting process.
13. Q. HOW OFTEN DO YOU REVIEW THE RECOMMENDED REFRESH
SCHEDULE TO ENSURE EQUIPMENT IS NOT REPLACED PRIOR TO
THE END OF ITS USEFUL LIFE?
A. The refresh cycle schedule for these products is reviewed approximately every three
years to ensure equipment is not being replaced prematurely. The most recent
recommendations and research from analysts and manufacturers is to accelerate
replacement schedules to reduce operating costs associated with electric usage. The
Company has found its current replacement schedule continues to appropriately
balance the cost of procurement and implementation against that of operation and
loss of productivity through performance degradation.
Olsen-DIRECT 7
Page 74 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
14. Q. WHEN WERE THE AIX DISK EVERGREEN UPGRADES COMPLETED?
A. The AIX Disk Evergreen process is managed in discrete, annual budget
groupings/projects based on separate disk storage technologies, high-end Storage
Area Network (“SAN”)-based storage and mid-range SAN and Network Attached
Storage-based storage to accommodate varying performance requirements. Disk
storage upgrades are performed and implemented throughout the year. Only disk
storage currently identified as “used and useful” is included in plant in service.
INFRASTRUCTURE PROJECT 3: EXCHANGE, e-VAULT AND LYNC UPGRADE
15. Q. PLEASE DESCRIBE THE EXCHANGE, e-VAULT AND LYNC UPGRADE.
A. Microsoft Exchange is the email system that the Companies use. As part of the
system, the Companies have vaulting capabilities through Veritas e-Vault for
saving emails for long term archiving. In most cases, email vaulting is used for
legal or compliance reasons. Microsoft Exchange is also integrated with Microsoft
Lync, which is used for internal messaging. Because the systems are interdependent
and closely tied, the scope of this project includes the software upgrade of these
three products and the underlining hardware. The Exchange environment was
upgraded from a 2010 to 2016 version, while e-Vault was upgraded from version
11 to version 12.3. Lync was upgraded to Skype for Business, version 2015, and
provided additional video conferencing functions. The project consisted of
hardware purchases, installation and configuration, as well as migrating internal
Sierra users to the upgraded platforms. The fax tool, Faxcom, was also upgraded to
comply with the Exchange 2016 environment, and minor upgrades to the phone
system were completed to integrate Skype for Business. The costs estimated
Olsen-DIRECT 8
Page 75 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
through the certification period allocable to Sierra’s electric operations are
$839,086.
16. Q. WHAT WERE THE DRIVING FACTORS FOR THE EXCHANGE, e-
VAULT AND LYNC UPGRADE PROJECT?
A. The driving factor for the Exchange, e-Vault and Lync upgrade project was
Microsoft’s decision to no longer support the then-current versions of Exchange, e-
Vault and Lync after January 2020. Upgrading the software to the newer versions
was necessary to ensure that cyber security patches are available upon release, to
improve capabilities and functionality associated with the new version, to continue
the tight integrations between Exchange and other desktop applications, and to
ensure support would be available to resolve problems should they arise.
17. Q. HOW OFTEN DO YOU REVIEW THE UPGRADE SCHEDULE TO
ENSURE SOFTWARE IS NOT REPLACED PRIOR TO THE END OF ITS
USEFUL LIFE?
A. The upgrade cycle for these products is reviewed approximately every five years to
ensure software is not being upgraded prematurely. Microsoft software lifecycle is
the driving factor for the timing of upgrades. To continue Microsoft support and
ensure system security, the next upgrade must be completed by October, 2025.
18. Q. WHEN WERE THE EXCHANGE, e-VAULT AND LYNC UPGRADES
COMPLETED?
A. The Exchange, e-Vault and Lync upgrades were completed on May 15, 2019.
Olsen-DIRECT 9
Page 76 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
INFRASTRUCTURE PROJECT 4: FIREWALL/APPLIANCE EVERGREEN
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
19. Q. PLEASE DESCRIBE THE FIREWALL/APPLIANCE EVERGREEN
PROCESS.
A. The Firewall/Appliance Evergreen process was put in place in the early 2000s to
address growth in the information technology needs and to ensure adequate
application performance through a scheduled technology refresh cycle. Funding for
this process is managed through the standard capital budgeting process. The costs
identified here are the aggregate of five separate evergreen process groupings for
disk technologies since the last rate cycle. The cost of the project allocable to
Sierra’s electric operations through December 31, 2018 was $1,742,191, with
$100,499 estimated through the close of the certification period.
20. Q. WERE THE DRIVING FACTORS FOR ESTABLISHING THE
EVERGREEN PROCESS FOR THIS PROJECT THE SAME AS FOR THE
OTHER EVERGREEN PROJECTS?
A. Yes.
21. Q. HOW OFTEN DO YOU REVIEW THE RECOMMENDED REFRESH
SCHEDULE TO ENSURE EQUIPMENT IS NOT REPLACED PRIOR TO
THE END OF ITS USEFUL LIFE?
A. The refresh cycle schedule for these products is reviewed approximately every three
years to ensure equipment is not being replaced prematurely. The most recent
recommendations and research from analysts and manufacturers is to accelerate
replacement schedules to reduce operating costs associated with electric usage. Our
current replacement schedule balances the cost of procurement and implementation
Olsen-DIRECT 10
Page 77 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
against that of operational needs and loss of productivity through performance
degradation.
22. Q. WHEN WERE THE FIREWALL/APPLIANCE UPGRADES IDENTIFIED
COMPLETED?
A. The Firewall/Appliance Evergreen process is managed in discrete, annual budget
groupings/projects based on separate Firewall and Appliance upgrades to
accommodate new technologies. Firewall and Appliance upgrades are performed
and implemented throughout the year. Only Firewall and Appliances currently
identified as “used and useful” are included in plant in service.
INFRASTRUCTURE PROJECT 5: LAPTOP AND PC REPLACEMENT EVERGREEN
23. Q. PLEASE DESCRIBE THE LAPTOP PC EVERGREEN PROCESS.
A. The Laptop and PC Evergreen has been in place since 2000, and addresses growth
in information technology needs through a scheduled technology refresh cycle.
Funding for this process is managed through the standard capital budgeting process.
The costs identified here are the aggregate of twelve separate evergreen process
groupings since the last rate cycle. The cost of the project allocable to Sierra’s
electric operations through December 31, 2018 was $964,101, with $158,139
estimated through the close of the certification period.
Olsen-DIRECT 11
Page 78 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
24. Q. WERE THE DRIVING FACTORS FOR ESTABLISHING THE
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
EVERGREEN PROCESS FOR THIS PROJECT THE SAME AS FOR THE
OTHER EVERGREEN PROJECTS?
A. Yes, the merits of the Evergreen process described in Q&A 8 above apply equally
to the Laptop and PC Evergreen project. Prior to the creation of the Evergreen
process, upgrades to accommodate growth and ensure adequate application
performance were handled on a case-by-case basis, primarily in a reactive mode.
25. Q. HOW OFTEN DO YOU REVIEW THE RECOMMENDED REFRESH
SCHEDULE TO ENSURE EQUIPMENT IS NOT REPLACED PRIOR TO
THE END OF ITS USEFUL LIFE?
A. The refresh cycle schedule for these products is reviewed approximately every three
years to ensure equipment is not being replaced prematurely. We have found our
current replacement schedule to balance the cost of procurement and
implementation against that of operational needs and loss of productivity through
performance degradation.
26. Q. WHEN WERE THE LAPTOP AND PC UPGRADES IDENTIFIED
COMPLETED?
A. The Evergreen process is managed in discrete, annual budget groupings/projects
based on separate laptop and PC upgrades to accommodate new technologies and
varying performance requirements. Laptop and PC upgrades are performed and
implemented throughout the year. Only laptops and PCs currently identified as
“used and useful” are included in plant in service.
Olsen-DIRECT 12
Page 79 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
III. INFORMATION TECHNOLOGY APPLICATIONS PROJECTS DESCRIPTIONS
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
APPLICATION PROJECT 1: THE BANNER DATA REDUCTION AND PURGE
27. Q. PLEASE DESCRIBE THE BANNER DATA REDUCTION AND PURGE
PROJECT (PHASE I AND II)
A. This project allowed the Companies to remove aged data from the Companies’
customer information system (“CIS”) in compliance with Company and legal
standards. The Banner CIS Application was put in place 18 years ago. Throughout
this time, it has accumulated over a billion rows of various forms of data. The
Banner CIS Application did not include an automated purge function. Due to the
volume of data stored within the system, a purge of obsolete data was needed to
satisfy a number of different business objectives including: compliance with
corporate records and retention policies; increased system performance and
usability; assistance in achieving Service Level Agreement (“SLA”) deadlines;
improvements in Banner jobs performance run times; reduced disk storage needs
and wait times to clone environments; and reduced exposure to data breaches and
tampering. The Banner Data Reduction project provided the engine and supporting
structure for the reduction in physical storage. It also provided the framework for
the successful completion of the Phases 1 and II of the Purge Process projects and
set the conditions for a rules-based support that defined the table hierarchy structure
that allows the purge process to occur. Banner Purge Phase I included the purge of
most of the financial transaction data and account-related data in addition to the
purge of some stand-alone table data. Banner Purge Phase II addressed the
requirements for purging data for customer-related records containing only a
customer code, accounts that have bad debt, and accounts in master summary
billing groups. Phase II also included mapping for the purge of several account-
Olsen-DIRECT 13
Page 80 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
based and standalone tables that were not included in Phase I. Actual expenditures
on this collection of projects allocable to Sierra’s electric operations were as
follows: Banner Data Reduction (PID 0010003592) $1,342,599; Phase I
(0010007781) $570,965; and Phase II (0010007145) $567,833.
28. Q. WHY WAS THE PROJECT NECESSARY?
A. Banner is the main repository for critical and operational data including billing and
customer information. Due to legal and corporate records and retention policies,
any records with no activity over a certain period of time (currently set at seven
years) need to be permanently removed from the system. This period of time needs
to be configurable such that the appropriate internal business stakeholders can
determine and modify the threshold for records retention. Implementing this
compliance item will minimize the Company’s exposure to data breaches, potential
penalties and lawsuits.
The Banner CIS Application is operated and maintained with a set of guidelines
and SLAs to ensure optimal system performance. Among these SLAs are
performance standards around the time it takes to process the Banner batch jobs.
Batch jobs need to be completed in less than 24 hours each day. From a maintenance
and support perspective, the growth in data volume has resulted in a need to
regularly increase the disk storage capacity and has impacted the processing time
needed to clone the data from production to the testing and training environments.
Purging this data can reduce and maintain the disk storage needs at a constant level,
enable faster data cloning times, and increase the accessibility of the data through
Banner forms.
Olsen-DIRECT 14
Page 81 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
Due to the highly complex nature of the Banner CIS Application, this project was
needed to insure the integrity of the system and table relationships as data is being
removed and purged. There were tables that had in excess of over one billion rows.
This data needed to be removed and purged for better system performance and to
satisfy retention requirements associated with NV Energy’s Records Management
Policy.
Compliance/audit requirements - The necessity of this project was to review the
relationship of Banner CIS Application tables for legal/compliance data and purge
the current Banner Data which is older than the criteria defined by the Record
management policy. This project helps minimize exposure to data breaches and
tampering, which helps protect both our customers from identity theft and the
Companies from potential penalties or lawsuits.
29. Q. WHAT ARE THE ACTUAL BENEFITS RESULTING FROM THE
PROJECT?
A. In addition to satisfying important compliance requirements, this project achieved
operational benefits, improving Banner batch job run time performance by reducing
the number of records and the overall database size. This project helped batch jobs
complete in less than 24 hours as a whole on a daily basis. Also, SLA processing
time was improved, disk space was reduced, and the demand of additional disk
space and the processing time for cloning production data to lower environments
was eased. As of April 11, 2019, 144.7 gigabytes of data have been purged from
the northern storage environment. Finally, the project has added functionality to
allow users to flag accounts that should be exempt from the data purging process.
This is necessary to maintain the data integrity for accounts that may be associated
Olsen-DIRECT 15
Page 82 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
with a legal hold, ongoing accounting analysis, billing investigations, or other
business activity that may still be pending.
30. Q. WHEN DID THE PROJECT GO INTO SERVICE?
A. The Phase I release was completed on June 8, 2018 and Phase II release was
completed on July 12, 2018.
APPLICATION PROJECT 2: PORTAL OPERATIONS
31. Q. PLEASE DESCRIBE THE PORTAL OPERATIONS PROGRAM
A. The portal operations program is an annual project that develops and upgrades the
underlying digital solutions platform and Electric Delivery leadership dashboard as
part of the digital solution energy portal that provides operational metrics accessible
to business units. The operational metrics within the application include safety,
financial, and operations specific to the business unit. This allows the operational
metrics to be available in one consolidated dashboard and with sufficient specificity
that is easily drillable to analyze and view the information allowing for better data-
driven decisions. This platform allows the information to be mobile-accessible and
is fully scalable to accommodate growth. Migration of platform and application
upgrades are performed and implemented throughout the year. The costs of four
related projects have been aggregated, and the costs allocable to Sierra’s electric
division is $942,902.
32. Q. WHY WAS THE PROJECT NECESSARY?
A. Prior to this platform and application, the operational performance information was
gathered, formatted and stored in disparate places, requiring users to expend
significant manual effort to compile when needed. The data was not visible to the
Olsen-DIRECT 16
Page 83 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
electric delivery employees, and so was not usable as a measurement against
targets, or available to quickly identify areas needing improvement and target
corrective actions. The project integrates data from multiple sources and transforms
data into information that provides timely and relevant information so that
corrective actions and decisions can be acted upon both by managements and
employees. It allows for measurement and improvement in key areas like
operational safety using indicators such as OSHA recordable events, crew audits,
preventable vehicle accidents, and environmental metrics (e.g., avian fatalities or
transformer leaks), financial performance (e.g., actual spend compared to
commitments), and it shows the performance for an operational area against the
Business Plan.
33. Q. WHAT ARE THE ACTUAL BENEFITS RESULTING FROM THE
PROJECT?
A. Benefits include a significant reduction in manual effort spent obtaining important
operational data, increased accuracy of performance information, and the ability to
assess in real-time critical success measures, allowing for focus on key areas
requiring corrective action. Information is now available for analysis that was not
previously possible. Annual upgrades to the platform and application are needed to
remain current with technology direction, enable new application functionality and
to ensure no degradation in application availability and performance.
Enhancements are also necessary to remain compliant with all security-related
initiatives.
Olsen-DIRECT 17
Page 84 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
34. Q. WHEN DID THE PROJECT GO INTO SERVICE?
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
A. This program includes multiple projects with multiple release dates since June 1,
2016. The last release during the test period went into service December 31, 2018.
APPLICATION PROJECT 3: UI PLANNER (UIRM NORTH)
35. Q. WHY WAS THE UIRM NORTH PROJECT NECESSARY?
A. With increased compliance requirements and focus on performance metrics, the
Companies identified a need to replace reliance on using personal applications (e.g.,
Microsoft Excel-based application) for core budget development, financial
analysis, and forecasting business needs with a system-based solution that would
improve the integrity of results, enhance efficiency, support additional functionality
and allow for centralized adjustments. The solution that was selected to accomplish
these goals was the Utilities International Responsibility Model or UIRM.
The UIRM solution has allowed the Companies to no longer rely on Microsoft
Excel for a significant portion of the budget development process. It provides a
uniform system with standardized calculation logic accessible to general users. The
solution reduced the likelihood of human errors more common to spreadsheet
applications such as formula inconsistencies, omitted cells, double counting of
cells, unintended user changes, etc. Moreover, by standardizing the process and
centrally handling all of the calculations separate from the user interface, the
integrity of results was improved.
The UIRM solution also helped to enhance efficiencies by reducing the amount of
manual labor required and automating the consolidation process. For example, the
system replaced our process of manually entering into Excel the labor budget at the
Olsen-DIRECT 18
Page 85 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
individual employee level. Instead, the system interfaces with the human resource
system database to directly provide information such as job description, wage rate,
employee name and other relevant data. This allows for the labor budget to be
centered on a less granular level such as each unique job code without losing the
individual data. As another example, the system can automatically consolidate the
budget across the business. This replaces the need for technical support personnel
to launch manual and much more time consuming processes each time budget
changes are made.
The UIRM project also provides additional functionality. It provides the ability to
leverage different system interfaces for different aspects of the budget and forecast
process (using the prior example, by headcount, labor by job code, and non-labor)
separately using interfaces that are tailored for each aspect. It automatically creates
new rows to add the appropriate overheads and to allocate costs across Companies.
It provides interactive reporting functionality to facilitate a wide variety of analysis.
The project also allows for global adjustments to be made centrally and have the
effects of those adjustments automatically update throughout the budget and
forecast. Examples of this functionality include changing inflationary rate
assumptions, labor overhead rates, and labor merit increases. Each of these
assumptions can be changed centrally and automatically flow throughout the
budget. This provides greater flexibility and significantly improves efficiency in
the event assumptions change after the initial preparation and consolidation of
financial data.
Olsen-DIRECT 19
Page 86 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
36. Q. WHAT WAS THE TOTAL COST OF THE PROJECT?
A. The cost of the project allocable to Sierra’s electric operations was $2,132,512. The
project was placed in-service on January 1, 2017.
37. Q. WHAT WORK WAS COMPLETED FOR THE PROJECT?
A. The UIRM was implemented in 2016 and used in the development of the
Company’s annual budget and associated 10-year business planning since.
APPLICATION PROJECT 4: T&D WORK AND ASSET MGMT ENH
38. Q. PLEASE DESCRIBE THE T&D WORK AND ASSET MANAGEMENT
ENHANCEMENT PROJECT.
A. The Transmission and Distribution (“T&D”) Work and Asset Management
Enhancement project supported the technology needs for distribution capital and
maintenance work done by Electric Delivery. Additionally, the project served the
needs of the maintenance work done by the gas delivery business unit. The project
implemented system improvements (capital enhancements) within the T&D Work
& Asset Management systems (Maximo, Ventyx, ESRI, Microstrategy). The costs
of four related projects have been aggregated, and the costs allocable to Sierra’s
electric division is $1,356,097.
39. Q. WHY WAS THE PROJECT NECESSARY?
A. The improvements implemented as part of the T&D Work and Asset Management
Enhancement project for both electric and gas delivery helped enhance the existing
software with additional functionality such that the software was able to perform
tasks which it was previously not designed to perform. In addition, the project
Olsen-DIRECT 20
Page 87 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
enabled both the electric and gas operations to launch new technology-based
initiatives that helped them keep pace with changing regulatory needs, safety
requirements and business processes.
40. Q. WHAT ARE THE ACTUAL BENEFITS RESULTING FROM THE
PROJECT?
A. The T&D Work and Asset Management Enhancement project provided both
electric and gas delivery businesses with better capabilities towards regulatory and
safety compliance by implementing identified initiatives in both these areas. The
project improved operational efficiency and customer satisfaction. New and
improved business process changes were also implemented that helped align
systems with the changing business environment. These improvements helped
build better controls and risk mitigation strategies.
41. Q. WHEN DID THE PROJECT GO INTO SERVICE?
A. The project included multiple releases between 2016 and 2018.
42. Q. DOES THIS CONCLUDE YOUR PREPARED DIRECT TESTIMONY?
A. Yes.
Olsen-DIRECT 21
Page 88 of 250
William R. Olsen, Vice President, Information Technologies and CIO
Page 89 of 250
EXHIBIT OLSEN-DIRECT-2
Page 90 of 250
Exhibit Olsen-Direct-2 Page 1 of 4
Evergreen Process Benefits White Paper
Executive Summary
NV Energy has had a process in place and active for approximately ten years for accommodating growth, increased performance requirements, and for maintaining the hardware infrastructure supporting all IT&T applications. This process is known as the "Evergreen Process" and stated simply is that we will replace infrastructure components during the 4th or 5th (depending on hardware type) year of their life at the company. This process provides numerous benefits as detailed in this whitepaper and reduces risk for the applications upon which the company depends to successfully deliver reliable, cost effective energy to our customers.
Background
Prior to the merger between Sierra Pacific Power Company and Nevada Power company, each company approached upgrades and technology replacements of infrastructure hardware on a case by case basis primarily in a reactive mode. IT&T individually justified each proposed change and brought them all to the budget committee for review and approval. At the time, Nevada Power supported approximately 50 servers and a limited number of routers and switches, Sierra Pacific supported approximately 30 servers and a similar number of switches and routers and the disk technology was limited and primarily self-contained in each server. However, even with these limited numbers, the budget committees indicated that it was difficult for them to manage so many individual requests, particularly when typically the hardware had reached the end of its useful life and was limiting the ability of the business units to perform the intended functions so the decision was generally obvious regarding approval anyway. They also felt like they were missing the forest for the trees by seeing only the detail spread throughout the year, but not the overall spend to maintain this computing infrastructure. To address these concerns and add predictability to the process, IT&T recommended implementing what is now known as the "Evergreen" process and engaged industry analysts in combination with our experience to determine the appropriate planned "useful" life for the various components that comprise the computing infrastructure. This planned useful life is reviewed regularly and adjusted as necessary as technology changes to prevent the early retirement of equipment.
Page 91 of 250
Exhibit Olsen-Direct-2 Page 2 of 4
After completing the research, we recommended a 4 or 5 year planned obsolescence (4 years for servers and PCs, and 5 years for network infrastructure equipment and disk subsystems). This recommendation was presented to the RAC (or equivalent) shortly following the merger and was adopted as an on-going process. The process was reviewed in 2004 and again in 2009 by the FP&A group as part of the budget cycles in that year regarding the requirement for business case documents to support budget requests and was reaffirmed as an on-going process justified by the need to maintain applications with accepted business cases in an acceptable manner following production implementation. Since that time we present the projected total spend to the Executive Management for approval as part of each year's capital budget process.
In the ensuing years since implementing this new funding model, the requirement to support new applications has caused the number of infrastructure components to balloon significantly to the point that we now support approximately 450 servers and have nearly doubled the number of switches and routers as at the time of the merger. The Evergreen Process has simplified the management of this much larger configuration and allowed us to become proactive in our management approach resulting in significantly less disruption to the business units due to limited computing resources.
Benefits
The implementation of a standardized technology refresh cycle has provided numerous benefits to the company including the following non-comprehensive list:
1) Improved energy efficiency - the most recent iterations of microprocessor from both Intel and IBM include energy efficiency as key design elements. This is accomplished through reduced die sizes, and multiple levels of reduced voltages and lower clock speeds. These technologies also allow better thermal control reducing cooling requirements. Together these and similar technologies increase processing capacity many fold while reducing power consumption by as much as 43% under load and as much as 75% when idle as compared to previous processor generations.
2) Improved density/physical space utilization - the most recent iterations of microprocessors from both Intel and IBM have placed multiple cores or processing engines on a single die while simultaneously reducing the amount of space required between components allowing for reduced die sizes. This means that there is nearly double and quadruple the processing power per chip for dual and quad core processors. This has allowed us to free a significant amount of physical space within the existing data centers while simultaneously increasing computing capacity
Page 92 of 250
Exhibit Olsen-Direct-2 Page 3 of 4
3) Virtualization functionality implementation - in addition to allowing IT to implement current technological advances in network and computer hardware, the evergreen process has allowed us to implement such new software based technologies such as virtualization. Because we can look at hardware replacement holistically rather than on a per component basis, we have been able to identify multiple systems scheduled for migration and use that pool of funding to support the creation of a virtual server farm. This server farm is now the default location for servers identified for replacement with limited spend on software licenses vs. the purchase of new hardware where the usage of that hardware may not be maximized. Using virtualization, we've been able to eliminate around 60 physical servers without any degradation in performance or service.
4) Performance stability - prior to the adoption of the evergreen process where a set, known life span was designated, applications ran on hardware until the computing resource constraints slowed performance to the point is wasn't just not optimal or minimally acceptable, but until the performance was so bad that the application was effectively non-functional. At which point, IT&T initiated the process of obtaining a replacement. Often this occurred mid-budget cycle forcing unplanned expenditures that needed to be re-allocated from approved projects. With the evergreen process active, this is no longer true, hardware upgrades and replacements are now scheduled in advance ensuring stable performance and go through the normal budget cycle, and as described in bullet 3 above improved utilization of the hardware is implemented through the use of virtual technologies.
5) Predictable, simplified budgeting - because there is a known life span for the hardware asset, replacements can be scheduled years in advance, simplifying the budget process and making it predictable. It also allows for flexibility in the replacement cycle allowing for early or delayed replacement if warranted based on usage since the money is managed as a pool allowing the hardware resource scheduling to be reprioritized as necessary.
6) Maintenance savings - as a result of the evergreen process implementation, we have been able to save on O&M expenditures by eliminating maintenance contracts that would otherwise be required. Because we have a steady flow of new resources entering the system throughout the year as a result of evergreen, we have dropped otherwise needed maintenance contracts knowing new hardware could be repurposed if necessary.
Page 93 of 250
Exhibit Olsen-Direct-2 Page 4 of 4
7) Improved reliability and availability - as with all manufactured components, computing hardware has an expected MTBF. This was one of the major inputs into the generation of the expected life span of the various systems. By pegging the expected life span to age of the product where failure becomes more likely, we are able to eliminate the majority of failures through planned replacements. This has made the system much more reliable through the significantly reduction in the number of unplanned outages. This has had a magnifying effect on availability as the recovery time necessary following an unplanned outage due to hardware failure is frequently 5 or more times the time required to necessary simply to replace the failed component.
8) Enable new application functionality - in 1975, Gordon Moore postulated what has now become known as Moore's Law where he predicted that computer processing power would double every 18 months. Intel and other microprocessor design and production companies have been able to meet that pace. Effectively, servers at the time of replacement following the evergreen recommended schedule are 4 times slower than the most recently released servers. Application creators are aware of and leverage this rapidly increasing capability by regularly adding new functionality that requires the additional power with each application upgrade. The evergreen process allows us to support these upgrades without delays associated with hardware procurement andsetup.
9) Non-disruptive OS upgrades - with the increasing capabilities of the processors themselves, Microsoft and IBM are regularly adding additional functionality into the operating system including better management and improved security capabilities. The evergreen process allows for the OS upgradesoccur during the transition from the old server to the new one facilitating non-disruptive testing and migration.
10) Address normal growth trends - at a bare minimum, as applications are utilized the amount of information stored increases requiring additional computing capacity to store and process this data. Additionally, continued process automation and customer and employee growth also spur a regular growth curve. The evergreen process allows us to add capacity to address this normal growth.
Conclusion
The evergreen process as implemented at NV Energy has allowed us to maintain the computing environment in a predictable, non-disruptive manner since adoption. The evergreen planned obsolescence schedule is reviewed periodically to ensure that we are in alignment with industry practices. Continuation of this process as adopted will allow us to continue to capture the benefits as detailed in this white paper.
Page 94 of 250
Page 95 of 250
SCOTT TALBOT
Page 96 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
Sierra Pacific Power Company d/b/a NV Energy
2019 General Rate Case Docket No. 19-06___
PREPARED DIRECT TESTIMONY OF
Scott Talbot
Revenue Requirement
1. Q. PLEASE STATE YOUR NAME, OCCUPATION, BUSINESS ADDRESS
AND PARTY FOR WHOM YOU ARE FILING TESTIMONY.
A. My name is Scott Talbot. I am the Director of Telecommunications (“Telecom”)
for Sierra Pacific Power Company d/b/a NV Energy (“Sierra” or the “Company”)
and Nevada Power Company d/b/a NV Energy (“Nevada Power” and, together with
Sierra, the “Companies”). My business address is 6100 Neil Road in Reno, Nevada.
I am filing testimony in this proceeding on behalf of Sierra.
2. Q. PLEASE DESCRIBE YOUR BACKGROUND AND EXPERIENCE IN THE
UTILITY INDUSTRY.
A. I have over six years of experience at Sierra and Nevada Power. A complete
description of my professional background and experience is included in my
Statement of Qualifications, Exhibit Talbot-Direct-1.
3. Q. PLEASE DESCRIBE YOUR RESPONSIBILITIES AS DIRECTOR,
TELECOMMUNICATIONS.
A. As Director of Telecommunications, my responsibilities include managing a staff
of engineers, technicians and professional staff that design, build and operate the
Companies’ telecommunications network and facilities. Telecommunication
Talbot-DIRECT 1
Page 97 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
facilities include telephone, fiber optic, microwave, power line carrier, wide area
networking, tele-protection and radio systems necessary to operate the Companies’
utility business and to control the operations of the electric (and gas) infrastructure.
4. Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE PUBLIC
UTILITIES COMMISSION OF NEVADA (“COMMISSION”)?
A. No, I have not.
5. Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY?
A. I support the reasonableness of Sierra’s investment in telecommunications
networks and facilities. My testimony specifically discusses the six individual
major projects under my responsibility listed in Table Talbot-Direct-1. Five of these
projects cost more than $1 million and one cost less than $1 million. The
telecommunications group has completed many capital projects less than $1 million
since May 31, 2016 that are not listed below.
Table Talbot-Direct-1
PROJECT DESCRIPTION TOTAL ELECTRIC Multi-Protocol Label Switching (MPLS) $4,701,199 $3,911,962 Southwest Microwave Path Upgrade $2,868,203 $2,868,203 Telecom Work and Asset Management $3,055,061 $2,542,177 LV to Reno Dense Wave Division Multiplexing (DWDM) $1,338,361 $1,113,677
Comm Battery & Charger Replacement $1,070,248 $890,575 Call Center Expansion $911,497 $758,475 Total $13,944,569 $12,085,069
Talbot-DIRECT 2
Page 98 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
6. Q. WHY ARE ONLY MAJOR PROJECTS SPECIFICALLY DISCUSSED IN
YOUR TESTIMONY?
A. Testimony-style descriptions of each and every project completed by the
telecommunications team since June 1, 2016, would take hundreds of pages, and
the documentation surrounding each project is so voluminous that its value at
hearing would be severely diminished. As I understand it, in general rate
proceedings the Commission wants to see prepared direct testimony addressing the
details of and supporting expenditures on major projects. In recent general rate
cases the Commission has accepted the $1.0 million demarcation as appropriate for
determining whether a project is “major.” While not addressed in detail in my
prepared direct testimony, my group has prepared project binders for smaller
projects completed since June 1, 2016. As has been the Companies’ practice for
many rate case cycles, those binders (now in electronic form) are available for
review on the day this general rate review filing is made.
7. Q. ARE YOU SPONSORING ANY EXHIBITS?
A. Yes. I am sponsoring the following Exhibits:
Exhibit Talbot-Direct-1 Statement of Qualifications
TELECOMMUNICATIONS PROJECT I: MULTI PROTOCOL LABEL SWITCHING CSY1094 AND CCO1048
8. Q. PLEASE DESCRIBE THE MULTI-PROTOCOL LABEL SWITCHING
PROJECT (“MPLS”).
A. This project involved the installation of a next-generation Ethernet/Internet
Protocol (IP)-based Wide Area Network (“WAN”) throughout Sierra’s service
territory. Upon completion of the northern project, the infrastructures in northern
Talbot-DIRECT 3
Page 99 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
and southern systems are consistent with one another and are able to serve as the
platform for delivering services such as telephone over internet - also called Voice
over Internet Protocol (“VoIP”), video and access control for substation security,
mobile radio communications, automated metering infrastructure, distribution
automation, and remote relay management for fault protection of electric
transmission lines. This project is part of an overall strategy to move the network to
a standardized IP platform.
9. Q. WHY WAS THE PROJECT NECESSARY?
A. The former northern Ethernet network was built on legacy synchronous optical
networking or “SONET” equipment, which became limited in its ability to
accommodate new applications and increasing bandwidth requirements. It is also
obsolete and discontinued equipment. The new MPLS WAN serves as a platform
that provides System Control the ability to isolate networks for distribution
automation and remote substation equipment access and isolation necessary for
North American Electric Reliability Corporation (“NERC”) compliance. Initiatives
such as NERC Critical Infrastructure Protection (“CIP”) compliance and the Land
Mobile Radio System Replacement depend on a reliable, secure and flexible
network. It also aligns NV Energy’s current network to industry standards to ensure
criteria of scalability, reliability and modularity. Deploying MPLS has allowed the
Companies’ Telecom department to transport more data for all aforementioned
applications using existing communications pipes in accordance with IP-based
technology.
Talbot-DIRECT 4
Page 100 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
10. Q. WHAT WAS THE TOTAL COST OF THIS PROJECT?
A. The total cost of the project was $4,701,199 (with AFUDC). The system was
completed December 31, 2018 and is used and useful in the provision of utility
service.
TELECOMMUNICATIONS PROJECT II: SOUTHWEST MICROWAVE PATH UPGRADE CCOA67
11. Q. PLEASE DESCRIBE THE SOUTHWEST MICROWAVE PATH
UPGRADE PROJECT.
A. The Southwest Microwave Path Upgrade project replaced and upgraded the
microwave and multiplexing equipment in Sierra’s southwest service territory
network, which includes Fort Churchill, Hawthorne and Tonopah, to increase
bandwidth, reliability and route redundancy of the communications network.
12. Q. WHY WAS THE PROJECT NECESSARY?
A. The project was required to increase bandwidth and provide redundancy for the
reliability of this portion of the communications network. The project provided
communication links, status control and data acquisition (SCADA)/remote terminal
unit (RTU) traffic, communication-aided relaying protection, phones, network
access and land mobile radio backhaul at substations and communication sites.
13. Q. WHAT WAS THE TOTAL COST OF THIS PROJECT?
A. The total cost of the project was $2,868,203 (with AFUDC). The system was
completed on July 31, 2017 and is used and useful in the provision of utility service.
Talbot-DIRECT 5
Page 101 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
TELECOMMUNICATIONS PROJECT III: TELECOM WORK AND ASSET MANAGEMENT CSY1097 AND CSY1479
14. Q. PLEASE DESCRIBE THE TELECOM WORK AND ASSET
MANAGEMENT (WAM) SYSTEM PROJECT.
A. The Telecom WAM project is a multi-year technology project divided into phases
to provide a strategic long-term solution for leveraging capital investments,
ensuring asset performance optimization through best practices, and provide
reductions in operational maintenance costs for the Telecom department.
Phase I laid the initial technology foundation by implementing the Trouble (outage)
related solution by establishing a Network Operations Center (“NOC”) for
centralized monitoring and diagnostics support. It provides for recording, tracking
and resolving trouble tickets. Asset data collection was also initiated to build a
Telecom asset repository database on the asset data model to provide tracking and
management of assets as well as serve as input to future WAM Telecom
implementations.
Phase II implements the capital construction business processes, and extends the
previously implemented IBM Maximo and Ventyx Service suite toolset to map all
aspects of Telecom’s capital business processes – from project initiation to design,
estimating, scheduling, construction, and closing on the already existing enterprise
WAM toolset of Maximo and Ventyx. The overarching goal of Phase II was to
develop consolidated capital processes which better serve internal customers,
improve workforce performance and streamline Telecom capital operations.
Talbot-DIRECT 6
Page 102 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
15. Q. WHY WAS THE PROJECT NECESSARY?
A. This project provided a technology-based solution to a centralized operations center
for monitoring alarms and response activities to maintain established operational
levels of services, and provided a view across multiple event monitoring and
incident management systems to quickly assess the impact of faults and/or incidents
on customers, infrastructure and operations. In Phases I and II, Telecom continued
to work on improving outdated work procedures that were heavily reliant on
manual processes, hand offs, paper documentation, manual document routing and
white board scheduling, all of which did not provide the work management and
asset tracking features required to better manage the substantial Telecom capital
work and growing asset base. Telecom Asset Maintenance Phase II also evaluated
existing capital work management and scheduling processes and, where beneficial,
reengineered those processes for implementing a single work and asset
management software system and a single scheduling software system to be utilized
by Telecom.
16. Q. WHAT WAS THE TOTAL COST OF THIS PROJECT?
A. Phase I was in service June 7, 2018 and the total cost at Sierra was $1,964,712 (with
AFUDC). Phase II appears in the plant schedules as a certification project and was
in service March 1, 2019 and the total cost at Sierra was $1,090,349 (with AFUDC).
All systems are used and useful and providing utility service.
Talbot-DIRECT 7
Page 103 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
TELECOMMUNICATIONS PROJECT IV: LAS VEGAS TO RENO DENSE WAVE DIVISION MULTIPLEXING CSY1257
17. Q. PLEASE DESCRIBE THE LAS VEGAS TO RENO DENSE WAVE
DIVISION MULTIPLEXING (“DWDM”) PROJECT.
A. The project involved engineering, procurement, and construction of the DWDM
optical fiber electronic systems. The DWDM technology allows for the
transmission of high amounts of data across existing fiber optic cabling systems
from Las Vegas to Reno, Nevada.
18. Q. WHY WAS THE PROJECT NECESSARY?
A. This project was necessary to increase the bandwidth for transporting information
between Las Vegas and Reno to support corporate IT disaster recovery of data
centers, high-speed voice and data exchange between the northern and southern
corporate energy system control centers, the 5-digit corporate internal voice dialing
telephone system, and the high-speed wide area IT networking systems.
19. Q. WHAT WAS THE TOTAL COST OF THIS PROJECT?
A. The total cost of the project was $1,338,361 (with AFUDC). The system was
installed on May 22, 2017 and is used and useful in the provision of utility service.
TELECOMMUNICATIONS PROJECT V: COMM BATTERY AND CHARGER REPLACEMENT CCO819
20. Q. PLEASE DESCRIBE THE COMM BATTERY AND CHARGER
REPLACEMENT ROJECT.
A. Batteries are utilized throughout the Telecom network to provide direct current
(“DC”) power to equipment and provide backup during electrical outages. The
Talbot-DIRECT 8
Page 104 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
project involves identifying and replacing batteries and associated equipment at
Telecom sites that have exceeded their lifetime effectiveness. This project was
estimated to be in service by May 31, 2019, but has been delayed. Costs associated
with this project to be removed at time of certification.
TELECOMMUNICATIONS PROJECT VI: CALL CENTER EXPANSION CSY918
21. Q. PLEASE DESCRIBE THE CALL CENTER EXPANSION PROJECT.
A. The Call Center Expansion project included three advanced applications to enhance
system features, functionality and performance. A multi-media application was
added to improve and streamline the processing of customer e-mail requests via the
call center agents. An application was installed to conduct surveys for key customer
feedback regarding satisfaction and caller experience. Lastly, a workforce
management (“WFM”) system was implemented. The WFM system is used to
create forecasts to plan appropriate staffing and for managing call center agent
work/schedules and performance. Ms. Follette discusses other aspects of the project
in her prepared direct testimony.
22 Q. WHAT WAS THE TOTAL COST OF THIS PROJECT?
A. The total cost of the project was $911,497 (with AFUDC). This project went into
service December 31, 2017 and is used and useful and providing utility service.
23. Q. DOES THIS CONCLUDE YOUR PREPARED DIRECT TESTIMONY?
A. Yes.
Talbot-DIRECT 9
Page 105 of 250
Exhibit Talbot-Direct-1
Page 1 of 1
QUALIFICATIONS OF WITNESS
Scott N. Talbot
Director, Telecommunications
NV Energy
6100 Neil Road
Reno, NV 89511
EDUCATION
University of Nevada – Reno
Master of Science, Electrical Engineering – 2001
Bachelor of Science, Electrical Engineering – 1996
Minor Business Administration - 1996
PROFESSIONAL EXPERIENCE
NV Energy, Reno, NV – 2013-Current
Director, Telecommunication, IT&T
Manage and direct the operation of NV Energy’s Telecommunications network Senior Project Manager, Electric Delivery
Manage the development and execution of large multi-discipline major projects
Supervisor Substation Operations
Supervise substation electricians during construction and maintenance projects – coordinate scheduling of crews to meet project in-service dates
Supervisor Telecommunications Engineering
Responsible for construction and maintenance of the telecommunication network
covering Northern NV
EM Research Inc., Reno, NV – 1996-2013
EM Research designs and manufactures components for communications systems within
commercial, military, and industrial applications
General Manager
Managed all divisions – Business Development, Sales & Marketing, Administration,
Materials, Engineering, Manufacturing, and Quality
Production Manager
Managed electromechanical assembly and test departments. Developed and maintained
production schedule to ensure on time delivery
Business Development and Marketing
Established and coordinated marketing approach with emphasis on professionalism,
consistency, and budget
Sales Manager
Supervised sales staff in all aspects of sales process – request for quote, creation of
product data sheet, quotation, quote follow-up, and order processing
Quality
Wrote qualification test plans, qualification test reports, acceptance test plans, and
acceptance test reports for several high profile program
Page 106 of 250
Page 107 of 250
MICHELLE FOLLETTE
Page 108 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
Sierra Pacific Power Company d/b/a NV Energy
2019 General Rate Case Docket No. 19-06___
PREPARED DIRECT TESTIMONY OF
Michelle Follette
Revenue Requirement
I. INTRODUCTION
1. Q. PLEASE STATE YOUR NAME, OCCUPATION, BUSINESS ADDRESS
AND PARTY FOR WHOM YOU ARE FILING TESTIMONY.
A. My name is Michelle Follette. I am Vice President, Customer Operations for NV
Energy, Inc. (“NV Energy”), Sierra Pacific Power Company d/b/a NV Energy
(“Sierra” the “Company”), and Nevada Power Company d/b/a NV Energy
(“Nevada Power” and, together with Sierra, the “Companies”). I work primarily
out of the corporate headquarters at 6226 W. Sahara Avenue in Las Vegas. I am
filing testimony in this proceeding on behalf of Sierra.
2. Q. PLEASE DESCRIBE YOUR BACKGROUND AND EXPERIENCE IN THE
UTILITY INDUSTRY.
A. I earned a Bachelor of Science in Communications and a minor in Business
Management from Weber State University. Later I went on to earn a Master of
Business Administration from Westminster College. I have worked in customer-
focused organizations within the utility industry for 23 years supporting major
accounts, customer & community affairs, customer marketing & support services,
customer service, and I am currently the Vice President of Customer Operations for
NV Energy. Additional information is available in Exhibit Follette-Direct-1.
Follette-DIRECT 1
Page 109 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
3. Q. PLEASE DESCRIBE YOUR RESPONSIBILITIES AS VICE PRESIDENT,
CUSTOMER OPERATIONS.
A. As Vice President, Customer Operations my responsibilities include overseeing
internal customer service functions and supporting other customer-facing services.
I manage budgetary, personnel, contract management, and resources for internal
functions including: billing, metering, customer contact centers, major account
management and customer programs and services. Customer-facing services
involve support and coordination with the government relations, corporate
communications, energy generation and delivery, and regulatory operations teams
to ensure customer service consistency and maintenance of constructive
relationships.
4. Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE PUBLIC
UTILITIES COMMISSION OF NEVADA (“COMMISSION”)?
A. No.
5. Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY?
A. My prepared direct testimony covers two topics. First, in Section II, I discuss the
cumulative customer service level metric, other customer satisfaction metrics and
customer satisfaction improvement plans. The cumulative customer service level
metric measures how quickly the customer contact center answers incoming phone
calls from customers. Next, in section III, I discuss the capital projects, with a cost
of approximately $1.0 million or where the aggregate of multiple similar projects
is approximately $1.0 million, related to customer operations projects completed
since the end of the certification period in Sierra’s last general rate case (June 1,
2016) and planned through the certification period for this general rate case (May
Follette-DIRECT 2
Page 110 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
31, 2019). Table 1 Follette Direct-1 below provides a summary of costs by
category as of December 31, 2018 and the forecasted cost thru May 31, 2019.
Table Follette Direct-1 Total as of Forecasted total
December 31, thru May 31, 2018 2019
Customer Applications 10,343,580 10,733,580 Advanced Service Metering Infrastructure 3,925,297 4,093,297
Total: 14,268,877 14,826,877
6. Q. ARE YOU SPONSORING ANY EXHIBITS?
A. Yes. I am sponsoring the following Exhibits:
Exhibit Follette-Direct-1 Statement of Qualifications
Exhibit Follette-Direct-2 NV Energy 2018 Service Quality & Metrics Report
II. CUMULATIVE CUSTOMER SERVICE LEVEL, OTHER CUSTOMER SERVICE METRICS, AND CUSTOMER SATISFACTION IMPROVEMENT PLANS
7. Q. HISTORICALLY, THE COMPANIES HAVE REPORTED THE
CUMULATIVE SERVICE LEVEL IN REGULATORY RATE REVIEW
FILINGS. WHY DOES THE COMPANY MEASURE AND REPORT ON
THE CUMULATIVE SERVICE LEVEL IN REGULATORY RATE
REVIEW FILINGS?
A. In 2013, the Commission directed Sierra to submit as part of its next rate review
filing its results on the cumulative service level metric. This requirement was issued
in connection with Sierra’s request for approval of short-term incentive plan costs
tied to customer-service levels. The Commission focused on the cumulative service
metric stating that “[a]nswering customer calls on a timely basis is an obligation
Follette-DIRECT 3
Page 111 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
expected from any regulated utility.”1 The Commission continued, “The
[cumulative service level] metric is one important indication of [the Company’s]
performance regarding customer service and should be included in evaluating
employee performance for purposes of [short term incentive payments].”2 While
the cumulative service level was not a specific measure in Sierra’s 2018 corporate
scorecard,3 the Company recognizes that it is an important mark against which
customer service may be measured. Therefore, the Company is reporting the
cumulative service level in connection with this regulatory rate review proceeding.
8. Q. PLEASE DESCRIBE THE CUMULATIVE CUSTOMER SERVICE LEVEL
METRIC.
A. The cumulative customer service level measures the percentage of incoming phone
calls that the Company’s customer contact center answers within a specific period
of time. The numerator in the fraction is the number of phone calls answered within
the specific timeframe, and the denominator is the total number of incoming phone
calls to the customer contact center. The following formula depicts the calculation:
X (number of phone calls answered within z seconds)
Y (total number of incoming phone calls received by customer care)
Fundamentally, this metric addresses how quickly the Company answers incoming
phone calls. In 2013, Sierra and Nevada Power measured cumulative service level
as a percentage of all calls answered within 60 seconds. In 2014, this metric was
tightened to the percentage of all calls answered within 30 seconds.
1 Modified Final Order, Docket No. 13-06002, at ¶ 320 2 Id. at ¶ 321 3 See, Prepared Direct Testimony of Jennifer Oswald for a discussion of Sierra’s 2018 corporate scorecard.
Follette-DIRECT 4
Page 112 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
9. Q. WHAT WAS SIERRA’S PERFORMANCE ON THE CUMULATIVE
SERVICE LEVEL METRIC IN 2018?
A. In 2018, Sierra’s cumulative customer service level was 80.25 percent, which
exceeds the corporate target of 80.00 percent. The following table shows Sierra’s
(and Nevada Power’s) historical cumulative service level results for the past five
years.
Table Follette Direct-2
Combined Cumulative Service Level
(percentage of all calls answered within 30 seconds)
2014 2015 2016 2017 2018
Nevada Power 79.42% 81.39% 82.06% 80.51% 82.02%
Sierra Pacific 86.17% 82.46% 81.00% 81.15% 80.25%
10. Q. WHAT OTHER METRICS DOES SIERRA USE TO ASSESS AND TRACK
CUSTOMER SERVICE PERFORMANCE?
A. In 2012, the Commission opened an investigation into Nevada Power’s “customer
service practices including, but not limited to, call center operations and compliance
with” Nevada’s utility consumer bill of rights.4 As the final order in that docket
notes, in 2004 the Commission ordered Nevada Power and Sierra to “utilize certain
data to measure the impact on quality of service . . . in each of their respective
general rate cases following the order.”5 In 2015, the Commission modified some
of those metrics. Recently, Sierra filed its 2018 Service Quality and Metrics Report
4 Notice of Investigation and Request for Comments, Docket No. 12-01005 at 1 (iss. Jan. 20, 2012). 5 Order, Docket No. 12-01005 at ¶ 2, fn. 1 (iss. Oct. 28, 2014).
Follette-DIRECT 5
Page 113 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
pursuant to the Commission’s 2015 order. A copy of that report is attached as
Exhibit Follette-Direct-2.
III. CUSTOMER OPERATIONS CAPITAL PROJECTS
11. Q. PLEASE LIST THE CUSTOMER OPERATIONS CAPITAL PROJECTS
THAT ARE INCLUDED IN PLANT IN SERVICE THROUGH DECEMBER
31, 2018, OR THAT WILL BE CLOSED TO PLANT IN SERVICE BY THE
END OF THE CERTIFICATION PERIOD, MAY 31, 2019.
A. Below I address the major capital projects that originated in the customer operations
area. These projects fall into two broad categories, but are all information
technology projects. Four projects fit within the first category, which I characterize
as “Customer Applications.” Those projects are:
• Customer Digital Experience (“CDX”)
• Customer Digital Enhancements
• Call Center System Improvements
• Electronic Work Queue Back-Office Workforce Management
(“WFM”)
Second, I address three projects within the Advanced Metering Infrastructure
category. Those projects are:
• Advanced Metering Infrastructure – Communication Technology
• Regional Network Interface Upgrade 4.2
• Advanced Metering Infrastructure Optimization – Electric Meters
Below I describe each project or program, identify the cost of each project or
program, and explain how the Company uses the functionality provided by the
project or program to provide electric service to customers and why the Company
completed the project.
Follette-DIRECT 6
Page 114 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
12. Q. WHY ARE ONLY MAJOR PROJECTS SPECIFICALLY DISCUSSED IN
YOUR TESTIMONY?
A. Testimony-style descriptions of each and every project completed by or for the
customer service team since June 1, 2016 would be so voluminous that its value at
hearing would be severely diminished. As I understand it, in general rate
proceedings the Commission wants to see prepared direct testimony addressing the
details of and supporting expenditures on major projects. In recent general rate
cases the Commission has accepted the $1.0 million demarcation as appropriate for
determining whether a project is “major.” While not addressed in detail in my
prepared direct testimony, my group has prepared project “binders” for smaller
projects completed since June 1, 2016. As has been the Companies’ practice for
many rate case cycles, those binders (now in electronic form) are available for
review on the day this general rate review filing is made.
A. Customer Digital Experience or CDX
13. Q. PLEASE DESCRIBE THE CDX PROJECT.
A. The purpose of the CDX is to be efficient, adaptive and proactive in the delivery of
digital experiences for customers, whose expectations have rapidly adapted to a
sophisticated digital retail and services marketplace. From 2014 – 2019, the
Companies experienced a 173 percent gain in unique customer monthly logins to
the customer interface MyAccount, where customers view and manage their energy
costs and perform services. Digital payments alone have reached 77 percent of all
payments received from customers on a monthly basis. In this same period, the
Companies’ corporate web site has experienced a threefold increase in website
usage, to 1.5 million sessions per month. The new CDX infrastructure implemented
within this project provides a single platform that delivers content and services in
Follette-DIRECT 7
Page 115 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
multiple digital channels: desktop, mobile, and app (Apple and Android), to enable
an energy services digital marketplace within the channels that customers are
accustomed to with other retail and service providers. The CDX project provides
the technical infrastructure and digital solutions that integrate people, processes,
and technology, thereby changing the way the Companies deliver digital energy
services for its customers. This project provides customers a state of the art digital
platform; enables an agile implementation of new or reinvented utility customer
experiences; proactively pushes personalized relevant and timely information;
becomes more predictive of our customers’ personalized needs and expectations;
and creates a dynamic and customer centric culture that fosters innovation and step
change improvement in the digital products and services expected by customers.
14. Q. WHAT TECHNOLOGY PLATFORMS ARE ASSOCIATED WITH THIS
PROJECT?
A. CDX includes the applications, infrastructure, and security necessary to implement
a new, responsive customer portal and mobile app. The ability to update the web,
MyAccount, and mobile experiences to the vision of CDX was limited due to the
age of the disparate, legacy technology stacks. The services, applications and
content in the three legacy technology stacks – Web, MyAccount, and Mobile –
have been redesigned and migrated to a new, consolidated technology architecture
that is an industry-standard portal framework stack that includes Adobe Experience
Manager and the Ionic platform infrastructure.
The new www.nvenergy.com is a responsive web mobile design configured on the
Adobe Experience Manager platform that enables customer facing desktop, mobile,
and app (Apple and Android) interfaces for digital end use. The communication
platform enables consistent and proactive communications across all channels (e.g.,
Follette-DIRECT 8
Page 116 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
text, email, outbound calling, and app push notification) through a single
communication gateway and provides tools for customers to sign up for and
manage proactive communication on various topics (e.g., payment notification,
billing notification, unusual usage, outage communication, energy management,
weekly energy summaries, etc.) through multiple channels (email, text, phone,
push, and social) through the communication gateway. The predictive analytics
model determines personalized next best actions and identifies program
opportunities for specific customers.
15. Q. DESCRIBE PROJECT IMPLEMENTATION PHASES AND THE KEY
VENDOR RESOURCES REQUIRED TO ASSIST WITH THE
COMPLETION OF EACH.
A. CDX was implemented in multiple phases consisting of discovery and design, build
and content migration, testing and promotion, and implementation. The Companies
worked with IBM to facilitate a discovery and design period during which insights
were drawn from customer research, workshops, and best practices/competitor
research including utilization of the JD Power - Utility Website Evaluation Study.
The new design was tested through focus groups in July 2016, after the initial
design and wireframes were completed. Adjustments were made based on this
customer research prior to the release of the design to the build stage of the project.
In June 2017, multi-day customer usability testing was executed that focused on
how customers could accomplish tasks commonly completed on energy utility
websites. Customer participants were asked to complete a series of tasks and
communicate their experiences. The feedback obtained from customers provided
an opportunity to make appropriate adjustments before product implementation.
Follette-DIRECT 9
Page 117 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
During the build and content migration phase, the Companies worked with Zilker
Technology to implement the user-interface (web and mobile), the back-office
processes, and the integrations necessary to realize the designed experiences.
Content migration and clean-up targeted approximately 1,000 existing
informational pages (e.g. Economic Development, Rates, and Energy Efficiency)
and 1,500 existing documents. Based on review with the various business unit
content owners, unneeded and outdated content was deleted and the remaining
content was refreshed. The final content was then transitioned into the look-and-
feel of the new CDX.
During the testing phase, the Companies worked with Cognizant to execute the
various stages of testing. System integration testing ensured that the build followed
the design. Testing validated that individual experiences delivered functionality
end-to-end. System testing validated that functionality was delivered across
multiple experiences end-to-end. User acceptance testing validated that users could
execute functionality across multiple experiences from the customer perspective.
Security testing validated that security vulnerabilities were identified and
addressed. Upon completion of the testing phase, the Companies made the CDX
experiences available to customers. The CDX experience was made available in an
initial go-live followed by agile promotions were incremental experiences and
enhancements were made available.
The Companies executed change management activities to ensure adoption of the
new digital capabilities. Employee training ensured customer facing employees
were properly trained and understood the customer impacts. Change leaders and
change champions served as advocates of the CDX program and helped promote
Follette-DIRECT 10
Page 118 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
the changes to the internal organization. Internal communications ensured the
remainder of the internal organization was aware of the CDX program and its
impact to the various departments and to customers. External communications
ensured that customers were aware of the new website and mobile app and the new
experiences.
16. Q. WHAT WAS THE TOTAL COST OF THE PROJECT?
A. The total cost of the CDX project was $6,256,368. Additional detail regarding the
costs of the project is set forth in Table Follette Direct-3 below.
Table Follette Direct-3 CDX Project
Cost Category As of December 31, 2018 Total Cost % of
Total Internal Labor $ 942,143 $ 942,143 15% External Services $ 4,621,944 $ 4,621,994 74%
Zilker Technology LLC $ 1,995,934 $ 1,995,934 32% IBM Corporation $ 1,053,336 $ 1,053,336 17% Cognizant Technology Solutions $ 1,036,849 $ 1,036,849 17% Yoh Services LLC/DCR Workforce Inc. $ 308,355 $ 308,355 5%
Subtotal of primary External Services 4,394,474 % of total: 95% Materials $ 227,742 $ 227,742 4% Internal Overheads $ 176,671 $ 176,671 3% Other Expense $ 71,102 $ 71,102 1% AFUDC $ 216,767 $ 216,767 3% Total $ 6,256,368 $ 6,256,368 100%
17. Q. DESCRIBE THE TYPE OF COSTS INCLUDED IN THE INTERNAL
LABOR, EXTERNAL SERVICES, AND MATERIALS CATEGORIES.
A. Internal labor includes direct (wages) and indirect (labor overheads) costs
associated with labor provided by Company employees. Internal labor costs are
comprised primarily of charges from the Information Technology group (60
Follette-DIRECT 11
Page 119 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
percent) and Customer Operations department (40 percent). These two
organizations worked collaboratively on project planning, design, implementation,
project management, and testing. Resources from Information Technology were
also involved in application development.
The external services cost category primarily includes vendor-provided
professional services and third party software related costs. Table Follette Direct-3
identifies the primary professional service vendors. Other professional service
vendors include Wipro and Kubra. Software related purchases account for three
percent of the external services category.
Project material costs primarily included servers and related equipment.
PowerEdge and Linux servers, and related hardware account for 82 percent of
material costs.
18. Q. WERE THE EXTERNAL SERVICE PROVIDERS SELECTED THROUGH
A COMPETITIVE PROCESS?
A. The primary external service providers, Zilker, IBM, Cognizant, Yoh Services and
DCR Workforce, were selected through a competitive selection process. Contracts
were awarded based on technical capabilities and pricing. Only the Kubra
relationship was not established through a competitive solicitation. Kubra has been
the Companies’ alert and notification provider since 2013. Due to the investment
of existing infrastructure and proprietary software, Kubra was the only provider
that could complete the required work.
Follette-DIRECT 12
Page 120 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
B. Customer Digital Enhancements
19. Q. PLEASE DESCRIBE THE CUSTOMER DIGITAL ENHANCEMENTS
PROGRAM.
A. The Customer Digital Enhancements Program was established after the
implementation of the CDX system/infrastructure. Akin to other large scale
systems like Banner, the Companies’ customer information system (CIS), the
Genesys Quality Management (“GQM”) call management system was initiated to
manage on-going enhancements to the CDX system. The 2018 and first quarter
2019 enhancements include security upgrades, content presentation changes, data
integrity administration, experience enhancements and the addition of new
experiences.
20. Q. PLEASE DESCRIBE THE CUSTOMER DIGITAL EXPERIENCE
IMPROVEMENTS CONTAINED WITHIN THE INITIAL LAUNCH OF
THE PROGRAM.
A. The initial launch of CDX in 2017 delivered a unified customer experience via a
single responsive infrastructure that included redesign of over 30 customer
experiences including the top customer transactions, predictive projections,
important notices and next-best action recommendations in a personalized
MyDashboard presentation layer. CDX enabled the delivery of content that is
optimized and personalized with a data-driven account feed for customer
messaging, outage status, program promotions, predictive bill information, online
feedback functionality, geo-location services, important notification services, and
implementation of secure authentication and log-in services. CDX included a
redesigned outage communications and reporting capability, a move center, smart
thermostat and energy assessment program enrollments, automatic monthly
Follette-DIRECT 13
Page 121 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
payment, equal payment plan, selected due date, simplified bill payments, and
usage presentation. In addition, the corporate website was redesigned and content
was migrated to the new portal platform.
21. Q. WHAT FUNCTIONALITY WAS DELIVERED THROUGH THIS
ENHANCEMENT PROGRAM?
A. During Q1 2018, CDX was enhanced to support the Assembly Bill 405 experience,
synchronization of Account Summary information with the Bill Statement,
migration of the Customer Service Representative (“CSR”) registration experience,
representation of gas usage on the dashboard, and auto-enrollment of accounts in
Bill Reminder and Payment Notice alerts.
During Q2 2018, CDX was modified to support the new Equal Payment Plan option
enrollment, storage of 10-day and 48-hour notices in the Account History, the
addition of fingerprint authentication in the mobile app, enhancements to the Smart
Thermostat enrollment process, outage/weather alerts, sign-up for and management
of payment arrangements, and communication of current and projected bill
amounts.
During Q3 2018, CDX was enhanced to support the Spanish language version of
the platform, Western Union credit card/debit card single payment sign-on, offering
the Equal Payment Plan to business accounts, introduction of the electric vehicle
comparison tool, and the addition of facial recognition authentication in the mobile
app.
Follette-DIRECT 14
Page 122 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
During Q4 2018, CDX was enhanced to support the My Energy Snapshot,
improved outage communications with decreased latency, a refreshed layout of
MyDashboard, a refreshed menu design for mobile app, introduction of an account
preferences tile, easy access to My Energy Snapshot from MyDashboard, and
refined layout for Profiles & Preferences.
During the first quarter of 2019, CDX was enhanced to support improvements in
the Projected Bill tile, representation of 7-day predictive bill forecast on the
dashboard, addition of a system performance reliability indicator, representation of
gas and net data on the My Energy Use by Appliance tile, messaging for the bill
forgiveness program, implementation of reCaptcha security service, and redesigned
homepage experience.
22. Q. WHAT WAS THE TOTAL COST OF THE ENHANCEMENT PROGRAM?
A. Through the end of the certification period, the total estimated cost of the Customer
Digital Enhancements program is $2,231,976. Additional detail regarding the costs
of the project is set forth in Table Follette Direct-4 below.
Table Follette Direct-4 Customer Digital Enhancements
Cost Category As of December 31, 2018
January 1, 2019 -May 31, 2019
Estimated Total Cost
Internal Labor $ 172,041 $ 27,334 $ 199,375 External Services $ 1,565,795 $ 367,161 $ 1,932,956 Internal Overheads $ 53,292 $ 9,804 $ 63,095 Other Expense $ 20,554 $ 2,916 $ 23,470 AFUDC $ 8,990 $ 4,091 $ 13,081 Total $ 1,820,672 $ 411,304 $ 2,231,976
Follette-DIRECT 15
Page 123 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
23. Q. WHAT EXTERNAL SERVICES WERE REQUIRED TO SUPPORT THIS
PROGRAM?
A. External service costs included contributions from Zilker for design and build
related services, Yoh Services provided technical support and project management,
and Cognizant contributed testing resources. Zilker’s costs account for 82 percent
of the estimated external services cost, nearly $1.6 million. Technical support and
project management services provided by Yoh Services are estimated to be
$174,000 through May 31, 2019, and Cognizant’s testing services are estimated to
be less than $100,000.
24. Q. WERE THE EXTERNAL SERVICE PROVIDERS SELECTED THROUGH
A COMPETITIVE PROCESS?
A. Yes, all of the external service providers were selected through competitive
sourcing.
25. Q. WHAT MEASURES WERE TAKEN TO CONTROL COSTS?
A. The enhancement implementation approach employed under this program was
designed to reduce costs. Potential enhancements were evaluated frequently based
on customer satisfaction survey results, system performance, customer behavior,
and operational processes. Quarterly enhancement plans were established to
manage program work, individual enhancements were scheduled and placed into
productions in a manner that leverage resources and created efficiencies.
Follette-DIRECT 16
Page 124 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
C. Call Center System Initiatives
26. Q. PLEASE DESCRIBE THE CALL CENTER SYSTEM INITIATIVES
PROGRAM.
A. The Call Center System Initiatives program included several routing system
improvements during the course of a three year period from 2016-2018. These
collectively included upgrades and additions to the contact center telephone system.
The following work was performed under this program:
a) Call-back System Expansion included the implementation of the Virtual
Hold Technology LLC (“Virtual Hold”) customer call back system as part
of the Genesys Disaster Recovery system in Reno. Servers and application
software were purchased, configured, installed and tested as part of this
project.
b) Contact Center Recording System Replacement replaced the existing
voice and screen recording system with a new product, Genesys Interactive
Recorder (“GIR”). Servers were purchased, configured, installed and tested
with the new software. Desktop application software was also upgraded and
modified to work with the new recording system.
c) Agent License Expansion involved the addition of CSR answering
positions. Software was purchased and configured for use in processing
calls.
d) Technology Refresh expanded and upgraded the Genesys server
infrastructure to provide increased testing environment capability and to
maintain current operating system/application software support levels.
e) Genesys Audit Software included the purchase and installation of
management/auditing software for the Genesys system.
Follette-DIRECT 17
Page 125 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
f) Call Analytics Training included purchase of training for administrative
staff on the operation of the Call Miner analytics system.
27. Q. WHY WAS THE PROGRAM NECESSARY?
A. The work was necessary due to operational and business needs. Details related to
each element of the program are as follows:
a) Call-back System Expansion – the Virtual Hold system was expanded to
ensure that customer service levels could be maintained when using the Reno
Disaster Recovery system as the production environment. The call-back
system acts as a “load balancer” during heavy call volume periods to ensure
that customers don’t experience extended hold and queueing times while
trying to reach an agent.
b) Contact Center Recording System Replacement – the existing recording
system, GQM was discontinued as a supported product by Genesys. It was
then necessary to replace the recording software with the GIR application and,
in addition, upgrade the desktop telephony software to a higher version of
Workspace Desktop Edition. Compliance and audit requirements necessitate
that all voice calls and screen video is captured and archived for specific time
intervals. In addition, these recordings are required for call analytics and agent
monitoring in support of quality assurance and coaching.
c) Agent License Expansion – the purpose of adding agent answering positions
via license expansion was to provide a quicker response to customer calls
related to billing inquiries.
d) Technology Refresh – it was necessary to add a second staging and testing
environment in order to expedite implementing various types of software call
processing enhancements. Additional Genesys servers were also purchased for
Follette-DIRECT 18
Page 126 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
migration to a new virtual machine (VM) chassis environment, which was
required due to upgrades by the IT Operating Services group.
e) Genesys Audit Software - the addition of management and auditing software
was necessary in order to facilitate auditing and configuration changes within
the Genesys Contact Center system. These capabilities enhance the stability of
the system.
f) Call Analytics Training - formal system training was required for Workforce
Optimization & Quality Management staff in order for them to adequately
perform their support role relative to maintaining customer service levels
28. Q. WHAT WAS THE TOTAL COST OF THE PROGRAM?
A. The total cost of the Call Center System Initiatives program was $1,279,581.
Additional detail regarding the cost of the program is set forth in Table Follette
Direct-5 below. Table Follette Direct-5
Call Center System Initiatives
Cost Category As of December 31, 2018 Total Cost
Internal Labor $ 189,956 $ 189,956 External Services $ 830,163 $ 773,587 Materials $ 161,580 $ 218,157 Internal Overheads $ 32,715 $ 32,715 Other Expenses $ 6,457 $ 6,457 AFUDC $ 58,709 $ 58,709 Total $ 1,279,581 $ 1,279,581
29. Q. WHAT COSTS ARE INCLUDED IN EXTERNAL SERVICES?
A. External services costs primarily include external professional services. This
program’s external services cost was divided between vendor professional services
and third party contractors. Aria Solutions, the Companies’ competitively selected
Follette-DIRECT 19
Page 127 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
call center system support vendor, and Virtual Hold account for 48.8 percent and
contractors used through the Companies’ competitively selected staffing providers
Yoh Services and DCR Workforce make up 41.7 percent of the total external
services costs.
30. Q. WHAT COSTS ARE INCLUDED IN MATERIALS?
A. Material costs include hardware and related charges. Material purchases were made
with competitively bid hardware suppliers including, Dell Marketing LP, Solutions
II Inc., SHI International Corp and CDW Direct.
D. Electronic Work Queue Back-Office WFM
31. Q. PLEASE DESCRIBE THE ELECTRONIC WORK QUEUE BACK-OFFICE
WFM PROJECT.
A. The Electronic Work Queue project provides the technical infrastructure to route
customer calls and back-office work tasks to both contact center and billing agents.
The Genesys Intelligent Work Distribution system alleviates manual tasks and
automatically distributes back-office work to employees located in the contact
center, business solutions center and the billing and credit operations department
via the Banner Customer Information Systems Electronic Work Queue module.
The Genesys system assigns tasks based on agent availability, skills, call volume,
real-time priorities and real time analytics. The NICE Real-Time Application
Monitoring tool monitors individual team member’s activities, allowing for process
standardization and monitoring, and improves forecasting capabilities with new
reporting functionality.
Follette-DIRECT 20
Page 128 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
32. Q. WHY WAS THIS PROJECT NECESSARY?
A. Back-office work load dedicated to general account administration, customer
inquiries, and billing and program administration continues to increase. The
Electronic Work Queue project delivered the infrastructure and functionality to
intelligently automate and monitor the routing process of work between multiple
teams located in different areas. The Electronic Work Queue project allows for
back-office work to be completed during slow periods around the clock, enabling
the Company to increase productive without increasing staff. Through monitoring
and tracking of back office work, this project also contributes to process
standardization of work which will improve training curriculum and generate
efficiencies.
33. Q. WHAT WAS THE TOTAL COST OF THE PROJECT?
A. The total cost of the Electronic Work Queue project was $986,958. Additional
detail regarding the costs of the program is set forth in Table Follette Direct-6
below.
Table Follette Direct-6 Electronic Work Queue
Cost Category As of December 31, 2018 Total Cost
Internal Labor $ 193,849 $ 193,849 External Services $ 685,989 $ 661,893 Materials $ 24,034 $ 48,130 Internal Overheads $ 27,217 $ 27,217 Other Expenses $ 1,195 $ 1,195 AFUDC $ 54,675 $ 54,675 Total $ 986,958 $ 986,958
Follette-DIRECT 21
Page 129 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
34. Q. WHAT COSTS ARE INCLUDED IN EXTERNAL SERVICES?
A. Software and external professional vendor services are included in this cost
category. Aria Solutions, the Companies’ competitively selected call center system
support vendor accounts for 51.9 percent of project costs, and Cognizant, also
selected through a competitive solicitation, accounts for 21.7 percent. Nice Systems
Inc. and PartnerSolve LLC make up the remaining 23.4 percent of the total external
services costs.
35. Q. WHAT BENEFITS DOES THE PROJECT DELIVER TO CUSTOMERS?
A. The Electronic Work Queue project delivered improved customer service at
reduced costs, mitigating future staffing increases through improved agent
utilization and departmental efficiencies. The system’s tracking and monitoring
capabilities will improve performance activity monitoring, and increase employee
accountability and coaching opportunities. Standardization for back-office work
improves processing times by reducing work task actions and will highlight training
opportunities that can be shared throughout the organization. The contact center
and back-office work forecasting and workforce optimization has improved as part
of the system automation.
E. Advanced Metering Infrastructure – Communication Technology
36. Q. PLEASE DESCRIBE THE ADVANCED METERING INFRASTRUCTURE
COMMUNICATION TECHNOLOGY PROJECT.
A. This project was implemented to fill identified communication gaps in the
Company’s Advanced Meter Infrastructure (“AMI”) network. These gaps were
primarily caused by terrain challenges and the resulting inability of existing tower-
gateway-based (“TGB”) infrastructure to communicate reliably with smart meters
Follette-DIRECT 22
Page 130 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
that were installed during the original meter deployment. Because some rural
customer meters could not effectively communicate with the TGBs, customer data
and meter reads were not being collected by the AMI network. Thus customer data
could not be made available for customer use on the Companies’ web portal, and
the billing meter reads continued to have to be collected manually. The project
included strategic installation of 25 compact TGBs throughout rural Nevada in
locations determined by a propagation study that optimized coverage of the AMI
radio frequency network. The new compact TGBs (also known as M400Bs) were
installed adjacent to Company-owned equipment on standard utility poles. The new
TGBs successfully enabled the Company to collect data, including meter readings,
from most of the customer meters that could not previously communicate with the
network.
37. Q. WHY WAS THIS PROJECT NECESSARY?
A. The need for this project became evident as customers in rural Nevada became more
familiar with the many benefits of the new smart meter system that were not
available because of communication issues. Company personnel were continuing
to drive to remote locations to read and service non-responsive AMI meters.
Therefore, to obtain additional operational savings, provide improved customer
service, and unlock the benefits of the AMI network, this project was budgeted,
planned and implemented.
38. Q. WHAT WAS THE TOTAL COST OF THE PROJECT?
A. The total actual cost of this project is $1,903,174. Additional detail regarding the
cost of the program is set forth in Table Follette Direct-7 below.
Follette-DIRECT 23
Page 131 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Table Follette Direct-7 Advanced Metering Infrastructure
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
Cost Category As of December 31, 2018 Total Cost
Internal Labor $ 287,346 $ 287,346 Materials $ 863,947 $ 863,947 External Services $ 491,191 $ 491,191 Internal Overheads $ 129,680 $ 129,680 Other Expenses $ 10,302 $ 10,302 AFUDC $ 120,708 $ 120,708 Total $ 1,903,174 $ 1,903,174
39. Q. WHAT WERE THE MAIN COST DRIVERS OF THE PROJECT?
A. The costs to deliver this project were relatively evenly distributed between
installation costs (internal labor, overheads and external service), and material
costs. Installation costs made up approximately 48 percent of total project costs and
included planning and design, construction, and project oversight from internal
labor and vendors. Project planning and design services included contributions
from Ascension Power Engineering and Sensus USA Inc. Installation of the units
was managed by internal crews and Titan Electrical Contracting, who completed
the pole replacements. Material costs account for 45 percent of the project total,
with the majority $702,650 spent on TGBs sourced through Sensus. Other material
costs included poles, transformers, cable and miscellaneous hardware to complete
the installation.
40. Q. WHAT EFFORTS WERE TAKEN TO REDUCE PROJECT COSTS?
A. Cost were avoided by leveraging the scalability of the Companies’ existing smart
meter network to expand the AMI coverage territory. Through software and radio
frequency compatibility, existing infrastructure and integrations were optimized,
which resulted in cost savings. Where possible, TGBs were located on existing
Follette-DIRECT 24
Page 132 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
poles or within owned facilities to avoid additional costs. Contractor services were
secured through a competitive solicitation, and work was coordinated to minimize
travel time and increase productivity levels.
41. Q. WHAT BENEFITS DOES THE PROJECT DELIVER TO CUSTOMERS?
A. The additional 25 TBGs deployed through this project have extended the
Company’s AMI coverage area. Customers within these areas can now fully utilize
the benefits of MyAccount including access or more timely access to real-time
consumption data, projected bill notifications, energy use by appliance, and remote
reconnection services. The larger coverage area eliminates the need to read meters
manually and reduces truck rolls required for routine and over-the-air work orders,
which translates into lower vehicle costs and the delivery of other customer services
more timely.
F. Regional Network Interface (RNI) System Upgrade 4.2
42. Q. PLEASE DESCRIBE THE REGIONAL NETWORK INTERFACE (RNI)
SYSTEM UPGRADE 4.2 PROJECT.
A. The Regional Network Interface is the heart of the AMI network. It acts as the
primary control and head-end system for the data flow from and to all electric smart
meter and gas module endpoints. Alarms, meter readings, and control signals are
all sent and received by this operationally critical application. The Company
entered into a long term agreement with Sensus, the AMI network vendor, which
allows it to maintain all necessary operational and security updates for the system.
To accomplish this, the Company regularly applies patches and configuration
changes, and then every 18 to 24 months the system must undergo a version update
to replace any defective (bugs) or obsolete code and enhance functional ability
Follette-DIRECT 25
Page 133 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
(application improvements), including compatibility with new endpoint hardware
(meters) development (future proofing). Additionally, the updated version supports
newly released Sensus devices and technology, which are targeted to complement
the Companies’ energy conservation initiatives as well as supporting an integrated
gas meter/module device. This update project will replace RNI version 3.168 with
version 4.2. Just prior to filing this general rate review application, the in-service
date for the RNI System Upgrade slipped into June 2019. Therefore, the costs
associated with this project will be removed from revenue requirement when the
certification filing is made.
43. Q. WHAT WAS THE TOTAL COST OF THE PROJECT?
A. The total estimated cost of this project is $1,246,765. Additional detail regarding
the cost of the program is set forth in Table Follette Direct-8 below.
Table Follette Direct-8 Regional Network Interface
Cost Category As of December 31, 2018
January 1, 2019 – May 31, 2019 Total Cost
Internal Labor $ 118,204 $ 58,976 $ 177,179 External Services $ 365,234 $ 230,182 $ 595,415 Materials $ 373,994 $ - $ 373,994 Internal Overheads $ 25,345 $ 5,778 $ 31,123 AFUDC $ 40,087 $ 28,966 $ 69,053 Total $ 922,863 $ 323,902 $ 1,246,765
44. Q. WHAT TYPE OF COSTS ARE INCLUDED IN THE EXTERNAL
SERVICES CATEGORY?
A. The majority, some 95.4 percent, of the estimated costs within the external services
category are associated with Sensus USA Inc., 54.5 percent, and Cognizant, 40.9
percent. The RNI system is a Sensus product, professional vendor services are
Follette-DIRECT 26
Page 134 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
required to complete the software upgrade. Cognizant supported the project with
project management and testing resources.
45. Q. WHAT MATERIAL PURCHASES WERE REQUIRED TO COMPLETE
THE UPGRADE?
A. Costs recorded in the material cost category include hardware and related software
and licenses. The upgrade from version 3.1 to 4.2 resulted in new database,
operating system, and storage requirements. Additional database, application, and
secondary storage servers were required to complete the project.
46. Q. WERE VENDOR SERVICES AND MATERIAL PURCHASES ACQUIRED
THROUGH COMPETITIVE MEANS?
A. Third party services and material purchases were acquired through competitive
sourcing events. The Sensus RNI system was selected as part of a competitive
request for proposal with the deployment of the AMI. Cognizant was awarded the
associated service contract in 2013 through a competitive bid. Material purchases
were placed through approved suppliers that were established competitively.
G. Advanced Metering Infrastructure Optimization – Electric Meters
47. Q. PLEASE DESCRIBE THE INVESTMENT IN ADVANCED METERING
INFRASTRUCTURE OPTIMIZATION – ELECTRIC METERS PROJECT.
A. In 2010, Sierra presented to the Commission, as part of its integrated resource plan,
a business case justifying a significant investment in the “smart grid.” Specifically,
the Company requested approval of an advanced metering infrastructure project
that all but eliminates the need to manually read meters, and manually initiate and
terminate service. The Commission approved the project, and the Company
Follette-DIRECT 27
Page 135 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
subsequently presented the costs associated with the project in regulatory rate
review proceedings. In consolidated Docket Nos. 14-05004 (involving Nevada
Power) and 14-05005 (involving Sierra), the Commission reviewed the costs
associated with the advanced service delivery project, as well as the operational
benefits captured for customers. After a thorough review of the costs by all
stakeholders, a stipulation was reached in which a small portion of the advanced
service delivery investment made by Sierra was reduced through a “one-time
permanent” adjustment. The balance of the investment was effectively determined
to be reasonable.
Since the close of the certification period in Sierra’s last general rate review
proceeding, the Company has continued to invest in AMI meters– approximately
$900,000 through the certification period in this general rate review proceeding.
These costs were managed following the same processes and procedures as the
project costs previously reviewed by the Commission.
48. Q. WHY WAS THIS PROJECT NECESSARY?
A. With the Commission’s approval of the AMI program, the Company adopted smart
meters as the standard meter offering. It is incumbent on the Company to ensure
that every eligible legacy meter is exchanged with a smart meter.
Follette-DIRECT 28
Page 136 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
49. Q. WHAT WAS THE TOTAL COST OF THE PROJECT?
A. The table below shows the actual costs associated with this project.
Table Follette Direct-9 AMI Optimization
Cost Category June 1, 2016 - December 31, 2018 Total Cost
Internal Labor $ 672,976 $ 672,976 External Services $ 63,724 $ 63,724 Materials $ 28,803 $ 28,803 Internal Overheads $ 132,946 $ 132,946 Other Expense $ 3,674 $ 3,674 Total $ 902,123 $ 902,123
50. Q. DOES THIS CONCLUDE YOUR PREPARED DIRECT TESTIMONY?
A. Yes.
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
Follette-DIRECT 29
Page 137 of 250
Exhibit Follette-Direct-1
QUALIFICATION OF WITNESS MICHELLE FOLLETTE
VICE PRESIDENT, CUSTOMER OPERATIONS 6226 WEST SAHARA AVENUE LAS VEGAS, NEVADA 89151
I have been an employee of NV Energy since April 2014 and initially joined NV Energy as Vice President, Customer Service. In November of 2018 I was promoted to Vice President, Customer Operations. Prior to NV Energy, I held a number of diverse roles within customer service at PacifiCorp including Director, Customer Service; Director, Customer Marketing & Support Services; Director, Customer & Community Affairs; Director, Oregon, Washington, California Industrial Accounts; and Director Utah Commercial & Industrial Accounts. My career within customer service in the utility industry spans more than two decades.
INDUSTRY EMPLOYMENT HISTORY
Vice President, Customer Operations – NV Energy • As Vice President, Customer Operations, my responsibilities include overseeing the operation of several
business units, including billing and credit, contact center, workforce optimization, customer information services, customer energy solutions, major accounts, customer programs and services, and meter services.
Vice President, Customer Service – NV Energy • As Vice President, Customer Service, my responsibilities included overseeing the operation of customer
service, including billing and credit, contact center, workforce optimization, and customer information services.
Director, Customer Service – PacifiCorp • As Director, Customer Service, my responsibilities included overseeing the operation of Pacific Power and
Rocky Mountain Power customer contact centers and related back office operations, planning and strategy.
Director, Customer Marketing & Support Services – PacifiCorp • As Director, Customer Marketing & Support Services, my responsibilities included overseeing the
operations of customer support services, implementation of a customer satisfaction improvement plan, commercial and industrial account billing and account services.
Director, Customer & Community Affairs - PacifiCorp • As Director, Customer & Community Affairs, my responsibilities included leading all customer and
community services activities including account managers and community representatives; resource allocation, contract negotiations, demand side management and customer satisfaction.
Director, Oregon, Washington, California Industrial Accounts – Pacific Power Director, Utah Commercial & Industrial Accounts – Rocky Mountain Power
• My responsibilities as Director of Industrial Accounts – Pacific Power and Commercial & Industrial Accounts – Rocky Mountain Power included overseeing the major accounts team, implementation of an account and community plan program, and the maintenance of account relationships.
EDUCATION • Westminster College, Master of Business Administration • Weber State University, Bachelor of Science, Major-Communications, Minor-Business Management
Page 138 of 250
EXHIBIT FOLLETTE-DIRECT- 2
Page 139 of 250
Exhibit Follette-Direct-2
May 3, 2019
Ms. Trisha Osborne, Assistant Commission Secretary Public Utilities Commission of Nevada Capitol Plaza 1150 East William Street Carson City, Nevada 89701-3109
Re: Docket No. 19-03040: Nevada Power Company d/b/a NV Energy’s and Sierra Pacific Power Company d/b/a NV Energy’s Annual Quality of Service and Metrics Report for Calendar Year 2018 - Errata
Dear Ms. Osborne:
On March 29, 2019 Nevada Power Company d/b/a NV Energy (“Nevada Power”) and Sierra Pacific Power Company d/b/a/ NV Energy (“Sierra Pacific” and, collectively, the “Companies”) filed their Annual Quality of Service and Metrics Report. It has been discovered that an incorrectly set variable caused some errors in the data. The corrections are on pages 4 and 19 in the report and should read as follows. Clean versions of these pages are attached.
Page 4 (top), continuation from page 3 are included in this Report to account for the 60 81 (52 70 at Nevada Power and 8 11 at Sierra) total participants in the FlexPay program as of December 31, 2018.
Page 19, first paragraph last sentence The initial metrics and reporting information that were contained in the May 31, 2016 Final Order in Docket Nos. 15-11003, 15-11004 and 15-11005 are included in this Report to account for the 60 81 (52 70 at Nevada Power and 8 11 at Sierra) total participants in the FlexPay program as of December 31, 2018.
Page 19, table The values in the table below for “Number of Participants in FlexPay Program” and “Average Length of Time in FlexPay Program (days)” have been updated along with the “Number of Disconnections for Non-Payment by Days/Hours/Average Before Reconnection (HH:MM)” for Nevada Power.
Page 140 of 250
Exhibit Follette-Direct-2Ms. Osborne May 3, 2019 Page 2 of 2
2018 NPC SPPC Overall
Number of Participants in FlexPay Program 70 52 11 8 81 60 Number of Service Disconnects 22 4 26
Number of Participants Who Obtained Good Credit Through FlexPay Program
0 0 0
Average Payment Amount $57.46 $69.95 $58.85 Number of Payments 479 60 539 Average Number of Payments 2.17 1.75 1.96 Number of Customer-Written Communications 0 0 0 Length of Time Customers Remain in FlexPay Program (days) 41 96 45 Average Length of Time in FlexPay Program (days) 78 85 64 79 76 84 Number of Disconnections for Non-Payment 22 4 26 Number of Service Reconnections after DNP 21 4 25
Number of Disconnections for Non-Payment by Days/Hours/Average Before Reconnection (HH:MM)
8:44 6:26[1] 6:15[2]
Gas Service Reconnection Dollar Amount and Frequency Incurred N/A 0 0
If additional information is required, please contact me at (775) 834-5823.
Sincerely,
/s/ LoreLei Reid LoreLei Reid Manager, Regulatory Services
[1] Longest Duration: 4 days, 17 hrs. | Shortest Duration: 15 min. [2] Longest Duration: 15 hrs. 15 min. | Shortest Duration: 45 min.
Page 141 of 250
Exhibit Follette-Direct-2
are included in this Report to account for the 81 (70 at Nevada Power and 11 at Sierra) total participants in the FlexPay program as of December 31, 2018.
In response to NV Energy’s 2017 Service Quality & Metrics Report, the Regulatory Operations Staff of the Commission (“Staff”) made the following recommendations that NV Energy accepted and has incorporated into this Report:
1. NV Energy has added to the Report the targeted achievement level for metrics for which NV Energy has established a targeted achievement level;
2. NV Energy has added discussion where customer service metric differs significantly from the prior year’s results; and
3. In reporting MSI customer satisfaction survey results data, for the MSI survey questions on Reliability (Questions 11 and 16), Safety (Question 20), and Being Easy to do Business With (Question 41), NV Energy in this Report calculates the results based solely on scores received in the 6-10 range by customers, rather than on scores received in the 5-10 range.
NV Energy 2018 Service Quality & Metrics Report 4| P a g e
Page 142 of 250
Exhibit Follette-Direct-2
FlexPay Program
The Optional FlexPay program was launched as a pilot in November 2017 to a small group of NV Energy employees to complete quality testing and ensure that all of the processes work as designed before external customers were invited to participate. A customer pilot of the program was rolled out to eligible customers in May 2018. A full scale launch of the FlexPay program is scheduled to occur in the second quarter of 2019. The initial metrics and reporting information that were contained in the May 31, 2016 Final Order in Docket Nos. 15-11004 and 15-11005 are included in this Report to account for the 81 (70 at Nevada Power and 11 at Sierra) total participants in the FlexPay program as of December 31, 2018.
2018 NPC SPPC Overall
Number of Participants in FlexPay Program 70 11 81 Number of Service Disconnects 22 4 26 Number of Participants Who Obtained Good Credit Through FlexPay Program
0 0 0
Average Payment Amount $57.46 $69.95 $58.85 Number of Payments 479 60 539 Average Number of Payments 2.17 1.75 1.96 Number of Customer-Written Communications 0 0 0 Length of Time Customers Remain in FlexPay Program (days)
41 96 45
Average Length of Time in FlexPay Program (days) 78 64 76 Number of Disconnections for Non-Payment 22 4 26 Number of Service Reconnections after DNP 21 4 25 Number of Disconnections for Non-Payment by Days/Hours/Average Before Reconnection (HH:MM)
8:441 6:152
Gas Service Reconnection Dollar Amount and Frequency Incurred
N/A 0 0
1 Longest Duration: 4 days, 17 hrs. | Shortest Duration: 15 min. 2 Longest Duration: 15 hrs. 15 min. | Shortest Duration: 45 min.
NV Energy 2018 Service Quality & Metrics Report 19| P a g e
Page 143 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Exhibit Follette-Direct-2
CERTIFICATE OF SERVICE
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
I hereby certify that I have served the filing for NEVADA POWER COMPANY
D/B/A NV ENERGY AND SIERRA PACIFIC POWER COMPANY D/B/A NV
ENERGY in Docket 19-03040 upon the persons listed below by electronic mail:
Tammy Cordova Michael Saunders Staff Counsel Attorney General’s Office Public Utilities Comm. of Nevada Bureau of Consumer Protection 1150 E. William Street 8945 W. Russell Road, Suite 204 Carson City, NV 89701-3109 Las Vegas, NV 89148 [email protected] [email protected]
Staff Counsel Division Attorney General’s Office Public Utilities Comm. of Nevada Bureau of Consumer Protection 9075 West Diablo Drive Suite 250 100 N. Carson St. Las Vegas, NV 89148 Carson City, NV 89701 [email protected] [email protected]
DATED this 3rd day of May, 2019.
/s/ Lynn D’Innocenti Lynn D’Innocenti Sr. Legal Admin Assistant Sierra Pacific Power Company Nevada Power Company
1 Page 144 of 250
Exhibit Follette-Direct-2
Page 145 of 250
Exhibit Follette-Direct-2
Page 146 of 250
Exhibit Follette-Direct-2
Page 147 of 250
Exhibit Follette-Direct-2
Page 148 of 250
Exhibit Follette-Direct-2
March 29, 2019
Ms. Trisha Osborne, Assistant Commission Secretary Public Utilities Commission of Nevada Capitol Plaza 1150 East William Street Carson City, Nevada 89701-3109
Re: 2018 Annual Service Quality & Metrics Report of Nevada Power Company d/b/a/ NV Energy and Sierra Pacific Power Company d/b/a/ NV Energy for Calendar Year 2018
Dear Ms. Osborne:
Enclosed for filing with the Public Utilities Commission of Nevada (“Commission”) please find the Annual Service Quality & Metrics Report of Nevada Power Company d/b/a NV Energy (“Nevada Power”) and Sierra Pacific Power Company d/b/a/ NV Energy (“Sierra Pacific” and, collectively, the “Companies”) for calendar year 2018. This report is filed pursuant to Ordering Paragraph 4 of the order issued by the Commission on October 14, 2015 in Docket No. 15-06064 (the “Order”).
In the Order, the Commission authorized the Companies to replace the annual quality of service reports previously filed in Docket No. 04-7009 with an annual informational filing with a revised set of customer service and customer satisfaction metrics.
The Order further provided that the annual information filing will be noticed for comments, and that the docket for the informational filing will be closed following the end of the comment period.
Please accept the attached report for filing. The report is accompanied by a draft public notice.
If additional information is required, please contact me at (775) 834-5823.
Sincerely,
/s/ LoreLei Reid LoreLei Reid Manager, Regulatory Services
Page 149 of 250
Exhibit Follette-Direct-2
REPORT
Page 150 of 250
Exhibit Follette-Direct-2
NV Energy 2018 Service Quality & Metrics Report
March 29, 2019
NV Energy 2018 Service Quality & Metrics Report 1 | P a g e
Page 151 of 250
Exhibit Follette-Direct-2
Overview of Report
Nevada Power Company d/b/a NV Energy (“Nevada Power”) and Sierra Pacific Power Company d/b/a NV Energy (“Sierra” and collectively, “NV Energy” or the “Companies”) submit this annual Service Quality & Metrics Report for 2018 (“Report”) pursuant to Ordering Paragraph 4 of the Order issued by the Public Utilities Commission of Nevada (the “Commission”) on October 14, 2015 in Docket No. 15-06064. This Report provides data on customer service performance of the Companies by providing the following metrics for the period 2014 through 2018:
Contact Center Metrics • Cumulative Service Level • Abandoned Calls Percentage • Percentage of Interactive Voice Response Calls
Billing and Metering Metrics • Percentage of Bills Mailed/Presented Within 7 Calendar Days of Meter Reading Date
Metering Metrics • Number of Meter Failures per 1,000 meters
Customer Payment Channels Metrics • Percentage of Payments Made Through All Payment Channels (including U.S. Mail,
Electronically, Shop & Pay locations, Payment Kiosks, and North Las Vegas (non-kiosk)) • Number of Kiosk Payments (North Las Vegas Office, Retail Locations and Overall)
Customer Programs and Services Metrics • Number and Percentage of Customers Signed Up For My Account • Number and Percentage of Customers that Have Elected for Paperless Billing • Number of Commission Staff-handled Complaints
FlexPay Program Metrics • Number of Participants in the FlexPay Program • Number of Service Disconnects • Number of Participants that Obtained Good Credit through the FlexPay Program • The Average Payment Amount • Number of Payments • Average Number of Payments • Methods of Payments • Number of Customer-written Communications • Number of Customers who Transfer back to Original Rate Schedules from the FlexPay
Program and their Reasons Why • Tracking and Reporting the Reduction in Required Deposits, Past Due Balances of
FlexPay Program Customers at the Time of Program Enrollment • Monthly Number of Calls Received by the Call Center Regarding the FlexPay Program • The Length of Time Customers Remain in the FlexPay Program
NV Energy 2018 Service Quality & Metrics Report 2 | P a g e
Page 152 of 250
Exhibit Follette-Direct-2
• The Average Length of Time in the FlexPay Program • The Specific Number of Disconnections for Non-payment • The Number of Service Reconnections after DNP • The Number of DNP by Days, Hours and Average before Reconnection • The Frequency of Disconnects on a Monthly Basis • The Geographic Breakdown of DNP by Zip Code • The Number of Deposit Arrangements and Payment Arrangements Entered into by
Participants Leaving the FlexPay Program • Gas Service Reconnection Dollar Amount and Frequency Incurred (Sierra only)
Reliability Metrics • Customer Average Interruption Duration Index (“CAIDI”) • System Average Interruption Frequency Index (“SAIFI”) • System Average Interruption Duration Index (“SAIDI”) • Natural Gas Dig-ins (Sierra only) • Natural Gas Leak Ratio (Sierra only)
Safety Metrics • OSHA Recordable Injuries – Corporate Overall • OSHA Recordable Injuries – Customer Operations • Preventable Vehicle Accidents – Corporate Overall • Preventable Vehicle Accidents – Customer Operations
MSI Customer Satisfaction Survey Results • Overall Customer Satisfaction (MSI Survey Question 1) • Restoring Electric Service (MSI Survey Question 11) • Providing Reliable Electric Service (MSI Survey Question 16) • Helping Customers Use Energy Safely (MSI Survey Question 20) • Being Easy to do Business With (MSI Survey Question 41)
The MSI Customer Satisfaction Survey Results are reported separately for residential and non-residential customers. The other metrics - Contact Center, Billing and Metering, Customer Payments, Customer Programs, Reliability and Safety – are not tracked separately by customer class.
This Report replaces the separate annual quality of service reports that Nevada Power and Sierra previously filed in Docket 04-7009.
The Optional FlexPay program was launched as a pilot in November 2017 to a small group of NV Energy employees to complete quality testing and ensure that all of the processes work as designed before external customers were invited to participate. A customer pilot of the program was rolled out to eligible customers in May 2018. A full scale launch of the FlexPay program is scheduled to occur in the second quarter of 2019. The initial metrics and reporting information that were contained in the May 31, 2016 Final Order from Docket Nos. 15-11003, 15-11004 and 15-11005
NV Energy 2018 Service Quality & Metrics Report 3 | P a g e
Page 153 of 250
Exhibit Follette-Direct-2
are included in this Report to account for the 60 (52 at Nevada Power and 8 at Sierra) total participants in the FlexPay program as of December 31, 2018.
In response to NV Energy’s 2017 Service Quality & Metrics Report, the Regulatory Operations Staff of the Commission (“Staff”) made the following recommendations that NV Energy accepted and has incorporated into this Report:
1. NV Energy has added to the Report the targeted achievement level for metrics for which NV Energy has established a targeted achievement level;
2. NV Energy has added discussion where customer service metric differs significantly from the prior year’s results; and
3. In reporting MSI customer satisfaction survey results data, for the MSI survey questions on Reliability (Questions 11 and 16), Safety (Question 20), and Being Easy to do Business With (Question 41), NV Energy in this Report calculates the results based solely on scores received in the 6-10 range by customers, rather than on scores received in the 5-10 range.
NV Energy 2018 Service Quality & Metrics Report 4 | P a g e
Page 154 of 250
Exhibit Follette-Direct-2
Table of Contents Customer Contact Center Metrics .........................................................................7
Cumulative Service Level ......................................................................................................................... 7 Abandoned Calls Percentage ................................................................................................................... 8 Percentage of Interactive Voice Response Calls ..................................................................................... 9
Billing and Metering Metrics................................................................................10 Percentage of Bills Mailed/Presented within 7 Calendar Days of Meter Reading Date (measured as a combined companies result)................................................................................................................... 10
General Meter Failures .........................................................................................11 Customer Payment Channels Metrics .................................................................13
Percentage of Payments Made Through All Payment Channels ......................................................... 13 Number of Kiosk Payments (North Las Vegas Office, Retail Locations and Overall) ........................ 14
Customer Programs and Services Metrics ..........................................................15 Number and Percentage of Customers Signed Up For My Account ................................................... 16 Number of Commission Staff-handled Complaints .............................................................................. 18
FlexPay Program....................................................................................................19 Number of Participants in FlexPay Program ....................................................................................... 19 Number of Service Disconnects ............................................................................................................. 19 Number of Participants Who Obtained Good Credit Through FlexPay Program .............................. 19 Average Payment Amount...................................................................................................................... 19 Number of Payments .............................................................................................................................. 19 Average Number of Payments................................................................................................................ 19 Number of Customer-Written Communications ................................................................................... 19 Length of Time Customers Remain in FlexPay Program (days) ......................................................... 19 Average Length of Time in FlexPay Program (days) ........................................................................... 19 Number of Disconnections for Non-Payment ....................................................................................... 19 Number of Service Reconnections after DNP ....................................................................................... 19 Number of Disconnections for Non-Payment by Days/Hours/Average Before Reconnection (HH:MM)................................................................................................................................................ 19 Gas Service Reconnection Dollar Amount and Frequency Incurred .................................................. 19 FlexPay Customers Methods of Payments (transactions) .................................................................... 20 Number of Customers Who Transfer Back to Original Rate Schedule and Reasons ......................... 20 Reduction in Required Deposits and Past Due Balances At Program Enrollment ............................. 20 Monthly Number of Calls Received by the Call Center Regarding the FlexPay Program.................. 21 Monthly Frequency of Disconnects ....................................................................................................... 21 Geographic Breakdown of Disconnections for Non-Payment by Zip Code......................................... 21 Number of Deposit Arrangements and Payment Arrangements Entered by Participants Leaving FlexPay Program ................................................................................................................................... 22
NV Energy 2018 Service Quality & Metrics Report 5 | P a g e
Page 155 of 250
Exhibit Follette-Direct-2
Reliability Metrics..................................................................................................23 Customer Average Interruption Duration Index (CAIDI) (reported in minutes)................................ 25 System Average Interruption Frequency Index (SAIFI) ...................................................................... 26 Natural Gas Dig-ins (Sierra only) ......................................................................................................... 28
Safety Metrics .........................................................................................................30 OSHA Recordable Injuries – Corporate Overall................................................................................... 31 OSHA Recordable Injuries – Customer Operations ............................................................................. 32 2018 Goal: Not to Exceed 1 Annual OSHA Recordable Injuries........................................................ 32 Preventable Vehicle Accidents – Corporate Overall ............................................................................. 33 Preventable Vehicle Accidents – Customer Operations ........................................................................ 34
Market Strategies International Customer Satisfaction Survey Results .........35 Overall Customer Satisfaction (MSI Survey Question 1) ..................................................................... 36 Providing Reliable Electric Service (MSI Survey Question 16) ........................................................... 38 Helping Customers Use Energy Safely (MSI Survey Question 20)...................................................... 39 Overall MSI Tables – Year over Year Comparison – Modeling Analysis and Index Scores............... 43
NV Energy 2018 Service Quality & Metrics Report 6 | P a g e
Page 156 of 250
Exhibit Follette-Direct-2
Customer Contact Center Metrics The following three metrics provide performance indicators for NV Energy’s contact centers. Cumulative Service Level is defined as the number of customer calls handled within a determined amount of seconds. In 2018, the annual goal was to answer 80% of inbound customer calls (includes a combination of live agent and automated calls) in 30 seconds or less. NV Energy measures performance daily, weekly and monthly against the target.
The Abandoned Calls Percentage is the percentage of calls that were not answered or where the customer disconnected/hung-up before the call was handled. There is not a targeted achievement level designated for this metric.
The Percentage of Interactive Voice Response (“IVR”) Calls is the number of overall incoming customer calls that are handled entirely by the IVR System and without the assistance of a customer service representative. There is not a targeted achievement level designated for this metric.
Cumulative Service Level
Cumulative Service Level (percentage of all calls answered within 60 seconds)
Cumulative Service (percentage of all calls answered within 30 seconds)
Level
2014 2015 2016 2017 2018 NPC 79.42% 81.39% 82.06% 80.51% 82.01% SPPC 86.17% 82.46% 81.00% 81.15% 80.26%
NV Energy 2018 Service Quality & Metrics Report 7 | P a g e
Page 157 of 250
Exhibit Follette-Direct-2
Abandoned Calls Percentage
Abandoned Calls Percentage 2014 2015 2016 2017 2018
NPC 1.82% 4.11% 4.21% 6.33% 4.49%1
SPPC 1.13% 3.02% 3.61% 5.07% 5.13%
1 The decrease in the percentage of abandoned calls at Nevada Power from 2017 to 2018 correlates to the increase in the Nevada Power Cumulative Service Level.
NV Energy 2018 Service Quality & Metrics Report 8 | P a g e
Page 158 of 250
Exhibit Follette-Direct-2
Percentage of Interactive Voice Response Calls
Percentage of Interactive Voice Response Calls 2014 2015 2016 2017 2018
NPC 31.00% 34.00% 38.00% 40.00% 42.00% SPPC 32.00% 36.00% 41.00% 45.00% 46.00%
NV Energy 2018 Service Quality & Metrics Report 9 | P a g e
Page 159 of 250
Exhibit Follette-Direct-2
Billing and Metering Metrics
The percentage of bills mailed within seven calendar days metric measures the percentage of customer bills that are mailed within seven calendar days from the date the meter is read.
Percentage of Bills Mailed/Presented within 7 Calendar Days of Meter Reading Date (measured as a combined companies result)
2018 Goal: 99.91% of All Bills Mailed/Presented within 7 Calendar Days of Meter Reading Date
Percentage of Bills Mailed/Presented within 7 Calendar Days of Meter Reading Date 2014 2015 2016 2017 2018
NV Energy 99.78% 99.77% 99.83% 99.93% 99.93%
NV Energy 2018 Service Quality & Metrics Report 10 | P a g e
Page 160 of 250
Exhibit Follette-Direct-2
General Meter Failures
The Meter Failure Metric represents the number of Automated Metering Infrastructure (AMI) meters that failed in the reporting year per 1,000 installed AMI meters. The numerator is the number of AMI meters that failed during the year, and the denominator is the number of installed AMI meters. The quotient of that calculation is then multiplied by 1,000 to calculate the number of AMI meter failures per 1,000 installed AMI meters. These figures exclude analog meters, and the rationale is discussed below. There are not targeted achievement levels designated for these metrics.
For the reporting period of January 1 to December 31, 2018, the Companies had a total installed ‘AMI meter’ population of 1,359,950. During the same period, the Companies logged a total of 722 AMI meter failures. Therefore, the Companies report a general AMI meter failure rate of 0.53 (< 1) per 1,000 meters. The breakdown is 0.39 at Nevada Power and 1.10 at Sierra.
Both operating utilities continue to maintain overall average annual general failure rates which outperform the ‘legacy meter’ industry-standard failure rate of 5 per 1000 (0.5%).
As of December 31, 2018, the Companies legacy meter population was estimated to be 3,038 meters. These meters represent the customers who received service under the Non-Standard Meter Option (“NSMO”) tariffs. At Nevada Power, 1,447 meters serve customers on the NSMO rate, and at Sierra, 1,591 meters serve customers on the NSMO rate. During 2018, the Companies’ installed legacy meter population decreased by 380 meters (11%). The decrease is due primarily to (1) customers leaving the NSMO rate and (2) the Companies’ continued efforts to exchange legacy meters with AMI meters. The Companies expect the number of legacy meters in-service to remain somewhat static in the coming year as nearly all current legacy meters are associated with NSMO accounts.
At Sierra, the AMI meter failure rate increased from 0.52 in 2017 to 1.10 in 2018. The increase is mostly attributed to meters which stopped communicating with the network and/or removed from service due to an error code reported by the meter.
NV Energy currently reports consumed meter events and high temperature alarm (“HTA”) monitoring metrics in Docket No. 14-09015. In the update NV Energy filed in that docket on March 15, 2019, it requested that the Commission close that docket and move the reporting of that information to the annual Service Quality & Metrics Report. If that request is granted, NV Energy will include the information in this report beginning next year.
NV Energy 2018 Service Quality & Metrics Report 11 | P a g e
Page 161 of 250
Exhibit Follette-Direct-2
Number of Meter Failures per 1,000 meters
Number of Meter Failures per 1,000 meters - NPC 2014 2015 20162 2017 2018
NPC 1.45 0.12 0.11 0.34 0.39
Number of Meter Failures per 1,000 meters - SPPC 2014 2015 20163 2017 2018
SPPC 4.60 1.35 0.07 0.52 1.10
2 2016 meter failure rate expressed as a weighted average for Nevada Power. 3 North meter failures was revised to reflect the removal of retired obsolete Itron ICON Gen 3 meters.
2016 meter failure rate expressed as a weighted average for Sierra.
NV Energy 2018 Service Quality & Metrics Report 12 | P a g e
Page 162 of 250
Exhibit Follette-Direct-2
Customer Payment Channels Metrics
The following information applies to the various payment channels offered by NV Energy and how customers utilized those payment channels from 2014 through 2018. NV Energy continues to observe an increase in the use of electronic payment channels and has continued to promote awareness of services such as MyAccount to meet this demand. In early 2013, the self-service payment kiosk option was introduced in southern Nevada, and was made available in northern Nevada in late 2014. A further breakdown of how the kiosk payment channel has been used is also provided below. As observed in previous years, the payments received through electronic channels continues to increase as other traditional methods such as mail and walk-in channels continue to decrease. These metrics are measured as a combined companies result, not broken out by utility, with the exception of the payment activity of the self-service payment kiosks that are located in the North Las Vegas office. There are not targeted achievement levels designated for these metrics.
Percentage of Payments Made Through All Payment Channels4
Percentage of Payments Made Through All Payment Channels 2014 2015 2016 2017 2018
Electronic Payments 62.00% 65.00% 68.00% 71.00% 74.00% U.S Mail 25.00% 23.00% 21.00% 19.00% 17.00% Walk-in / Shop & Pay 12.00% 10.00% 9.00% 8.00% 7.00% Branch Office 0.06% 0.01% 0.00% 0.00% 0.00% Kiosk Payments 1.38% 1.50% 1.52% 1.48% 1.50%
4 Due to rounding, the Percentage of Payments Made Through All Payment Channels may not equal 100%.
NV Energy 2018 Service Quality & Metrics Report 13 | P a g e
Page 163 of 250
Exhibit Follette-Direct-2
Number of Kiosk Payments (North Las Vegas Office, Retail Locations and Overall)
Number of Kiosk Payments - NV Energy 2014 2015 2016 2017 2018
Retail & NVE Locations (Other than NLV) 8,815 32,136 48,487 59,402 73,400 North Las Vegas (NLV) 177,710 169,661 156,793 142,965 133,073 Overall 186,525 201,797 205,280 202,367 206,473
NV Energy 2018 Service Quality & Metrics Report 14 | P a g e
Page 164 of 250
Exhibit Follette-Direct-2
Customer Programs and Services Metrics
NV Energy currently offers easily accessible technologies (MyAccount, mobile applications, outage notifications, paperless billing, etc.) to help customers use energy more efficiently, save money, and obtain information more easily. Historical participation rates in the My Account service offering as well as electronic or paperless billing enrollments are provided below.
Also, the number of complaints received by NV Energy through the Regulatory Operations Staff of the Commission (Commission Staff) are included. The historical number of Commission complaints provided below refer to only the complaints that were forwarded to the Companies for investigation and subsequent resolution by Commission Staff. Commission Staff handles a number of inquiries, referrals and complaints that are not forwarded to the Companies, and these types of interactions are not included in the results below. The complaints received by Commission Staff are used by NV Energy as opportunities for continuous process improvement. These complaints and observations are shared on a regular basis with internal and external stakeholders, and opportunities to address communications, processes or other contributing factors are examined and considered in order to contribute to the potential reduction of future complaints of the same nature. In 2018, Commission Staff fielded a total of 424 customer complaints about NV Energy statewide, this was a decrease of 61 complaints, or 12.58%, statewide as compared to 2017. In 2018, the top three complaint types received by Commission Staff were High Bills, Disconnection for Non-Payment and Payment Agreements.
The goal for all three of these metrics are established on a combined companies basis and not broken out by utility. The metrics for MyAccount participation and paperless billing are measured on a combined companies basis. The number of complaints received by Commission Staff and forwarded to NV Energy are reported separately by utility. For 2018, the goals or targeted annual outcomes have been added to the titles of each metric where applicable.
NV Energy 2018 Service Quality & Metrics Report 15 | P a g e
Page 165 of 250
Exhibit Follette-Direct-2
Number and Percentage of Customers Signed Up For My Account
2018 Goal: 750,000 Active Enrollments Number and Percentage of Customers Signed Up for MyAccount
2014 2015 2016 2017 2018 Customers 525,188 573,658 645,388 698,113 751,722 Percentage 42.76% 46.01% 50.96% 54.30% 57.50%
NV Energy 2018 Service Quality & Metrics Report 16 | P a g e
Page 166 of 250
Exhibit Follette-Direct-2
Number and Percentage of Customers that Have Elected Paperless Billing
2018 Goal: 30% Enrollment of Active Customers
Number and Percentage of Customers that Have Elected Paperless Billing 2014 2015 2016 2017 2018
Customers 189,901 214,001 293,850 343,274 419,729 Percentage 15.46% 17.16% 23.21% 26.70% 32.11%
NV Energy 2018 Service Quality & Metrics Report 17 | P a g e
Page 167 of 250
Exhibit Follette-Direct-2
Number of Commission Staff-handled Complaints
2018 Goal: 475 or less Commission Staff-Handled Complaints
Number of Commission Staff-handled Complaints 2014 2015 2016 2017 2018
NPC 646 533 571 389 309 SPPC 260 138 152 96 115 Overall 906 671 723 485 424
NV Energy 2018 Service Quality & Metrics Report 18 | P a g e
Page 168 of 250
Exhibit Follette-Direct-2
FlexPay Program
The Optional FlexPay program was launched as a pilot in November 2017 to a small group of NV Energy employees to complete quality testing and ensure that all of the processes work as designed before external customers were invited to participate. A customer pilot of the program was rolled out to eligible customers in May 2018. A full scale launch of the FlexPay program is scheduled to occur in the second quarter of 2019. The initial metrics and reporting information that were contained in the May 31, 2016 Final Order in Docket Nos. 15-11003, 15-11004 and 15-11005 are included in this Report to account for the 60 (52 at Nevada Power and 8 at Sierra) total participants in the FlexPay program as of December 31, 2018.
2018 NPC SPPC Overall
Number of Participants in FlexPay Program 52 8 60 Number of Service Disconnects 22 4 26 Number of Participants Who Obtained Good Credit Through FlexPay Program
0 0 0
Average Payment Amount $57.46 $69.95 $58.85 Number of Payments 479 60 539 Average Number of Payments 2.17 1.75 1.96 Number of Customer-Written Communications 0 0 0 Length of Time Customers Remain in FlexPay Program (days)
41 96 45
Average Length of Time in FlexPay Program (days) 85 79 84 Number of Disconnections for Non-Payment 22 4 26 Number of Service Reconnections after DNP 21 4 25 Number of Disconnections for Non-Payment by Days/Hours/Average Before Reconnection (HH:MM)
6:265 6:156
Gas Service Reconnection Dollar Amount and Frequency Incurred
N/A 0 0
5 Longest Duration: 4 days, 17 hrs. | Shortest Duration: 15 min. 6 Longest Duration: 15 hrs. 15 min. | Shortest Duration: 45 min.
NV Energy 2018 Service Quality & Metrics Report 19 | P a g e
Page 169 of 250
Exhibit Follette-Direct-2
2018 NPC SPPC Overall
FlexPay Customers Methods of Payments (transactions)
MyAccount (Mobile Application) 168 21 189 Western Union Speed Pay (Debit/Credit Card) 140 24 164
MyAccount (Desktop) 89 14 103 Kiosk 54 0 54 Ready Pay 23 0 23 Electronic Bank Bill Pay Payment 3 0 3 Electronic Check Payment 2 0 2 Phone - Interactive Voice Response Automated System 0 1 1
Overall 479 60 539
Number of Customers Who Transfer Back to Original Rate Schedule and Reasons
Customer Started Application Process But Did Not Complete Enrollment
377 30 407
Enrollment Prerequisites Not Completed 281 18 299
Customer Requested 52 3 55
FlexPay Enrolled But Service Never Activated At Address 10 0 10
Other/Prefer Not To Answer 6 2 8 Non-Payment or Fraud 6 0 6 Moved Out 5 0 5 New Customer Force Out 5 0 5 Unable To Manage Frequent Payments 4 0 4
Not As Convenient As Expected 1 2 3 Life Support or Elderly 1 0 1 Too Many Emails/Texts 1 0 1 Overall 749 55 804
Reduction in Required Deposits and Past Due Balances At Program Enrollment
Deposit Reduction $8,150.00 $1,315.00 $9,465.00
Past Due Balance Reduction $3,356.48 $480.41 $3,836.89
January 0 0 0 February 0 0 0 March 0 0 0
NV Energy 2018 Service Quality & Metrics Report 20 | P a g e
Page 170 of 250
Exhibit Follette-Direct-2
Monthly Number of Calls Received by the Call Center Regarding the FlexPay Program
2018 NPC SPPC Overall
April 0 0 0 May 7 3 10 June 2 1 3 July 5 0 5 August 7 1 8 September 7 2 9 October 6 6 12 November 6 1 7 December 15 4 19 Overall 55 18 73
Monthly Frequency of Disconnects
January 0 0 0 February 0 0 0 March 0 0 0 April 0 0 0 May 0 0 0 June 1 0 1 July 1 0 1 August 2 0 2 September 4 1 5 October 2 1 3 November 2 0 0 December 10 2 12 Overall 22 4 26
Geographic Breakdown of Disconnections for Non-Payment by Zip Code
89156 4 89118 3 89103 3 89031 3 89019 2 89101 1 89052 1 89139 1 89122 1 89117 1 89108 1 89014 1 89512 3 89509 1
NV Energy 2018 Service Quality & Metrics Report 21 | P a g e
Page 171 of 250
Exhibit Follette-Direct-2
2018 NPC SPPC Overall
Number of Deposit Arrangements 1 1 2 Deposit Arrangements and Payment Arrangements Entered by Participants Leaving FlexPay Program
Payment Arrangements 8 0 8
NV Energy 2018 Service Quality & Metrics Report 22 | P a g e
Page 172 of 250
Exhibit Follette-Direct-2
Reliability Metrics
Until 2014, NV Energy reported SAIDI and CAIDI in hours. When these reliability metrics were originally adopted by NV Energy, reporting of SAIDI and CAIDI in hours was common amongst most utilities. With NV Energy’s acquisition by Berkshire Hathaway Energy in 2014, the Companies formally transitioned to reporting in minutes as the unit of measure, which is now widely considered the industry standard and brought NV Energy into alignment with the other Berkshire Hathaway Energy companies. The following metrics pertain to the various reliability standards and historical results at NV Energy:
• CAIDI – Customer Average Interruption Index is the weighted average length of an interruption for customers affected during a specified time period.
• SAIFI – System Average Interruption Frequency Index is the average number of times a customer’s power is interrupted during a specified time period.
• SAIDI – System Average Interruption Duration Index is defined as the average duration of interruptions for customers served during a specified time period.
Calculations/Exclusions:
• Each of these reliability metrics are calculated using a database of outages that are greater than 5 minutes in duration, are designated as unplanned, and do not include ANY outages that occur on a Major Event Day (defined below).
• CAIDI and SAIDI are measured in duration of minutes (previously hours). • SAIFI is non-dimensional. It indicates the number of times a customer’s power is
interrupted.
Major Event Day:
• Since its acquisition by Berkshire Hathaway Energy, NV Energy has utilized the IEEE 1366 method for Major Event Days. This method, known as the 2.5 Beta Method, derives a daily threshold of SAIDI for classification as a Major Event Day.
• The calculation involves a 5 year daily average multiplied by 2.5 times the standard deviation over the same timeframe.
• The advantage of the 2.5 Beta Method is having a set threshold for each operating territory which means no guess work or grey areas.
• Prior to adopting the 2.5 Beta Method, NV Energy’s Major Event Day definition was a three tiered checklist:
At least 10% of the customer base in an operating region had to be affected by an outage.
At least one outage had to have a duration of at least 24 hours. Senior leadership had the power to overrule a declaration (Major Event Day
or not).
NV Energy 2018 Service Quality & Metrics Report 23 | P a g e
Page 173 of 250
Exhibit Follette-Direct-2
2018 vs 2017:
The reliability result in 2018 was better on a corporate level than in 2017, partly due to northern Nevada having mild winter storms compared to previous years. Southern Nevada experienced heavier than normal storm activity during the summer months as well as more cable failures than in 2017.
In southern Nevada, several cable failures contributed 6.3 minutes to SAIDI, downed wire outages contributed 3.9 minutes to SAIDI, vehicle-related outages contributed 3.2 minutes to SAIDI, and numerous outage events due to heavy winds and storms contributed 3.2 minutes to SAIDI.
In northern Nevada, storms contributed 7.1 minutes to SAIDI, vehicle-related outages contributed 3.2 minutes to SAIDI, downed wires contributed 3.8 minutes to SAIDI and bird/animal related outages contributed 2.3 minutes to SAIDI.
These 5 outage causes (cable failure, down wire, vehicle, heavy winds/storm, and bird/animal outage reasons) contributed to a little less than half of the total SAIDI for the Companies statewide. In 2018, the combined companies goal for SAIDI was 62 and the outcome was 71.
NV Energy 2018 Service Quality & Metrics Report 24 | P a g e
Page 174 of 250
Exhibit Follette-Direct-2
Customer Average Interruption Duration Index (CAIDI) (reported in minutes)
Customer Average Interruption Duration Index (CAIDI) 2014 2015 2016 2017 2018
NPC 82 85 86 92 96 SPPC 116 115 118 120 98
NV Energy 2018 Service Quality & Metrics Report 25 | P a g e
Page 175 of 250
Exhibit Follette-Direct-2
System Average Interruption Frequency Index (SAIFI)
System Average Interruption Frequency Index (SAIFI) 2014 2015 2016 2017 2018
NPC .39 .37 .52 .40 .46 SPPC 1.24 1.02 1.30 1.65 1.48
NV Energy 2018 Service Quality & Metrics Report 26 | P a g e
Page 176 of 250
Exhibit Follette-Direct-2
System Average Interruption Duration Index (SAIDI) (reported in minutes)
System Average Interruption Duration Index (SAIDI) 2014 2015 2016 2017 2018
NPC 32 32 44 37 44 SPPC 143 117 153 197 145
NV Energy 2018 Service Quality & Metrics Report 27 | P a g e
Page 177 of 250
Exhibit Follette-Direct-2
Natural Gas Dig-ins (Sierra only)
Gas Dig-Ins are defined as U.S. Department of Transportation reportable excavation leaks and damages.
Natural Gas Dig-ins (Sierra Only) 2014 2015 2016 2017 2018
SPPC 22 45 52 52 56
NV Energy 2018 Service Quality & Metrics Report 28 | P a g e
Page 178 of 250
Exhibit Follette-Direct-2
Natural Gas Leak Ratio (Sierra only)
The Leak Ratio is a five year average of underground Grade 1 and Grade 2 leaks, excluding leaks caused by excavation dig-ins. A Grade 1 leak is a leak that represents an existing or probable hazard to persons or property and requires immediate repair or continuous action until the condition is no longer hazardous. A Grade 2 leak is a leak that is recognized as being non-hazardous at the time of detection, but justifies scheduled repair based on probable future hazard. The five-year average is divided by a five year average of miles of main and services per 100 miles to determine the results reported below.
Natural Gas Leak Ratio (Sierra Only)
2014 2015 2016 2017 2018 SPPC 15.35 17.72 16.86 16.82 13.77
NV Energy 2018 Service Quality & Metrics Report 29 | P a g e
Page 179 of 250
Exhibit Follette-Direct-2
Safety Metrics
Safety is a core value at NV Energy, and the continual focus on safety positively impacts every area of the Companies. Employees recognize the corporate commitment to safety as well as the personal value in safety at work and home. NV Energy’s culture continues to focus and promote an injury free workplace and set the example of relentless safety practices in everything we do on the job and off. NV Energy sets aggressive annual goals for Occupational Safety and Health Administration (“OSHA”) Recordable Injuries and Preventable Vehicle Accidents (“PVAs”).
OSHA Recordable Injuries are injuries that required medical treatment beyond first aid. PVAs are vehicle accidents that based on investigation are determined to have been preventable. These results below for 2014 through 2018 are reported on a combined companies basis (not broken out by utility) as well as the specific safety results of the NV Energy Customer Operations department.
In 2018, there was a decrease in the number of OSHA Recordable Injuries as compared to 2017. NV Energy’s five-year average OSHA Recordable Injuries Rate is 0.79. This equates to less than 1 employee per every 100 experiencing an OSHA Recordable Injury, which is below the average rate for Electric and Gas Combination Utility companies of similar size.
The decrease in OSHA Recordable Injuries in 2018, as compared to 2017, can be attributed to the following facts:
• An increased safety awareness and commitment by employees as the result of safety training, management and labor involvement in our North and South Joint Safety Oversight Committees, and the use of Human Performance Improvement tools to support and improve employees’ abilities to accomplish their job tasks safely and efficiently.
• The majority of the 22 OSHA Recordable Injuries involved employees sustaining sprains, strains or small lacerations during the course of performing their regular job tasks. Root Cause Analyses were performed for all OSHA Recordable Injuries and correctable opportunities were identified to prevent future reoccurrence of these injuries. Two of the 22 OSHA Recordable Injuries were the result of third-party drivers striking NV Energy vehicles and injuring NV Energy employees in Non-Preventable Vehicle Accidents.
While NV Energy experienced a small increase in the number of PVAs from 2017 to 2018, the 19 PVAs in 2018 came in under the 5-year average of 20.8. Root Cause Analyses were performed for each vehicle accident, and the correctable opportunities were communicated throughout the Companies in order to promote the skills and attitude all employees need to demonstrate as professional drivers.
NV Energy 2018 Service Quality & Metrics Report 30 | P a g e
Page 180 of 250
Exhibit Follette-Direct-2
OSHA Recordable Injuries – Corporate Overall
2018 Goal: Not to Exceed 17 Annual OSHA Recordable Injuries
OSHA Recordable Injuries - Corporate Overall 2014 2015 2016 2017 2018
NV Energy 18 17 17 27 22
NV Energy 2018 Service Quality & Metrics Report 31 | P a g e
Page 181 of 250
Exhibit Follette-Direct-2
OSHA Recordable Injuries – Customer Operations
2018 Goal: Not to Exceed 1 Annual OSHA Recordable Injury
OSHA Recordable Injuries - Customer Operations 2014 2015 2016 2017 2018
NV Energy 0 1 1 1 2
NV Energy 2018 Service Quality & Metrics Report 32 | P a g e
Page 182 of 250
Exhibit Follette-Direct-2
Preventable Vehicle Accidents – Corporate Overall
2018 Goal: Not to Exceed More than 15 Annual Preventable Vehicle Accidents
Preventable Vehicle Accidents - Corporate Overall
2014 2015 2016 2017 2018
NV Energy 25 22 23 15 19
NV Energy 2018 Service Quality & Metrics Report 33 | P a g e
Page 183 of 250
Exhibit Follette-Direct-2
Preventable Vehicle Accidents – Customer Operations
2018 Goal: Not to Exceed More than 6 Annual Preventable Vehicle Accidents
Preventable Vehicle Accidents - Customer Operations 2014 2015 2016 2017 2018
NV Energy 2 4 1 6 4
NV Energy 2018 Service Quality & Metrics Report 34 | P a g e
Page 184 of 250
Exhibit Follette-Direct-2
Market Strategies International Customer Satisfaction Survey Results
NV Energy utilizes the market research firm Market Strategies International (“MSI”) to track and benchmark customer satisfaction among residential and small and medium-sized commercial customers. MSI is an independent market research firm with many clients and expertise across multiple service industries, including the energy industry. MSI has conducted research for NV Energy since 1994. MSI creates an energy industry benchmark and partners with the utility to provide evidence-based best practices, which, when used properly, have a proven track record of improving performance.
Customers are segmented by customer type (residential and small/medium commercial) and also by service territory (NV Energy North and NV Energy South). Customers are sampled on a random basis to comprise a statistically significant research tool. Customers are asked a series of questions and asked to provide a score on a scale of zero to 10. The results reported for the Overall Customer Satisfaction (Q1), Reliability (Q11 & Q16), Safety (Q20) and Being Easy to do Business With (Q41) questions are based on scores received in the 6-10 range.
Prior to the 2018 report, the results provided for all of the MSI questions except for the Overall Customer Satisfaction question were based on scores received from customers in the 5-10 range. For these specific questions, the 5-10 range for results was established in Docket 04-7009. Following NV Energy’s filing of the 2017 report, Staff requested that NV Energy modify its methodology and calculate and report MSI question results based solely on scores received from customers in the 6-10 range. The change to the 6-10 range as well as changes to historical data are reflected in this Report. In addition, each year MSI provides NV Energy an in-depth modeling report and identifies various drivers that contribute to overall customer satisfaction. The results provided in the tables labeled as “Satisfaction Index Scores” are the scores revealed following the in-depth modeling analysis and are based on a 100 point scale.
MSI’s opinion research includes, but is not limited to, perception of customer contact, contact center and web services, billing, energy delivery, price, energy efficiency, renewables and community relations. While there are other national benchmark surveys NV Energy monitors, MSI presents the most comprehensive and consistent approach, based on a reliable method of gathering customer opinion. Customers are surveyed over the phone and in late 2015, an online survey was introduced and implemented. The online survey has been included as a feedback mechanism through this provider on an ongoing basis.
NV Energy collects survey data from Residential and Small and Medium Commercial customers to measure and evaluate how customers perceive its performance as well as identify any opportunities for improvement across several areas including the following:
NV Energy 2018 Service Quality & Metrics Report 35 | P a g e
Page 185 of 250
Exhibit Follette-Direct-2
Overall Customer Satisfaction (MSI Survey Question 1)7
Q1. Based on your overall experience with NV Energy, how satisfied would you say you are with NV Energy?
7 MSI data provided for these tables are the overall average of scores received by all surveys conducted in that specific year.
NV Energy 2018 Service Quality & Metrics Report 36 | P a g e
Page 186 of 250
Exhibit Follette-Direct-2
Restoring Electric Service (MSI Survey Question 11)8
Q11. Restoring electric service when power outages occur.
8 MSI data provided for these tables are the overall average of scores received by all surveys conducted in that specific year.
NV Energy 2018 Service Quality & Metrics Report 37 | P a g e
Page 187 of 250
Exhibit Follette-Direct-2
Providing Reliable Electric Service (MSI Survey Question 16)9
Q16. Providing reliable electric service.
9 MSI data provided for these tables are the overall average of scores received by all surveys conducted in that specific year.
NV Energy 2018 Service Quality & Metrics Report 38 | P a g e
Page 188 of 250
Exhibit Follette-Direct-2
Helping Customers Use Energy Safely (MSI Survey Question 20)10
Q20. Helping customers use energy safely.
10 MSI data provided for these tables are the overall average of scores received by all surveys conducted in that specific year.
NV Energy 2018 Service Quality & Metrics Report 39 | P a g e
Page 189 of 250
Exhibit Follette-Direct-2
Being Easy to do Business with (MSI Survey Question 41)11
Q41. Being easy to do business with.
11 NV Energy added this information to the reported metrics at BCP’s suggestion. MSI data provided for these tables are the overall average of scores received by all surveys conducted in that specific year.
NV Energy 2018 Service Quality & Metrics Report 40 | P a g e
Page 190 of 250
Exhibit Follette-Direct-2
The following two tables summarize the various MSI questions by company and the percentage of satisfied scores received by year.12
Residential
Percentage of Total Satisfied Responses (Scores 6-10)
2014 2015 2016 2017 2018 MSI Survey Question
NPC SPPC NPC SPPC NPC SPPC NPC SPPC NPC SPPC
Overall Satisfaction 75% 85% 79% 88% 82% 87% 86% 93% 84% 90%
• Overall Customer Satisfaction (Question 1)
Reliability & Restoration
85% 89% 87% 87% 83% 86% 82% 87% 81% 86% • Restoring Electric Service (Question 11)
• Providing Reliable Electric Service (Question 16)
92% 92% 92% 93% 92% 92% 92% 92% 89% 91%
Customer Safety 74% 74% 74% 75% 70% 71% 64% 68% 65% 72%
• Helping Customers Use Energy Safely (Question 20)
Service Reputation 81% 84% 83% 87% 81% 85% 84% 87% 81% 85%
• Being Easy to do Business With (Question 41)
12 MSI data provided for these tables are the overall average of scores received by all surveys conducted in that specific year.
NV Energy 2018 Service Quality & Metrics Report 41 | P a g e
Page 191 of 250
Exhibit Follette-Direct-2
Commercial
Percentage of Total Satisfied Responses (Scores 6-10)
2014 2015 2016 2017 2018 MSI Survey Question
NPC SPPC NPC SPPC NPC SPPC NPC SPPC NPC SPPC
Overall Satisfaction 85% 84% 84% 89% 84% 89% 90% 89% 87% 87%
• Overall Customer Satisfaction (Question 1)
Reliability & Restoration
91% 88% 89% 93% 85% 90% 87% 90% 83% 87%
• Restoring Electric Service (Question 11)
95% 92% 96% 95% 93% 94% 94% 91% 91% 89%
• Providing Reliable Electric Service (Question 16)
Customer Safety 82% 72% 80% 80% 72% 78% 68% 72% 67% 68%
• Helping Customers Use Energy Safely (Question 20)
Service Reputation 87% 84% 88% 88% 83% 87% 85% 84% 85% 84%
• Being Easy to do Business With (Question 41)
NV Energy 2018 Service Quality & Metrics Report 42 | P a g e
Page 192 of 250
Exhibit Follette-Direct-2
Overall MSI Tables – Year over Year Comparison – Modeling Analysis and Index Scores
The tables below show the results by year for the various categories. The scores provided below are on a 100 index scale and are results from the annual modeling analysis.
Residential
Satisfaction Index Score (0-100)
2014 2015 2016 2017 2018 MSI Survey Question
NPC SPPC NPC SPPC NPC SPPC NPC SPPC NPC SPPC
Service Reputation 75 82 78 81 77 79 78 80 79 79
• Being easy to do business with • Being responsive to customer needs • Constantly improving the way they do business
Management Reputation 74 81 76 82 70 74 71 76 76 77
• Being a company you can trust
• Being well-managed
Price and Value 69 78 72 77 69 76 68 75 72 75
• In general, considering the value you receive, would you describe NV Energy’s electric prices as…?
Understanding Rates 69 75 72 75 57 68 56 67 60 66
• Helping customer understand the relationship between their usage and what they are charged • Reasonableness of Electric Rates
Financial Assistance13 76 80 77 79 75 77 N/A N/A N/A N/A
• Offering assistance to customers who are having financial difficulties • Offering flexible bill payment plans to people who get behind paying their energy bills
Energy Efficiency 67 74 73 75 69 72 72 73 75 76
• Providing helpful tips on how to save money and conserve energy
Community Relations 63 70 69 71 66 68 70 71 75 74
• Involved in community activities • Helping local economy by retain and attract business and jobs
Managing Rates 60 73 64 73 58 67 57 67 62 67
• Keeping electric rates as low as possible • Controlling costs while maintaining quality service
Billing/Cost 70 78 74 75 82 85 82 85 82 83
• Informing customers about what the utility is doing to keep overall energy costs low
13 Financial Assistance was not included in the 2017 & 2018 MSI customer survey.
NV Energy 2018 Service Quality & Metrics Report 43 | P a g e
Page 193 of 250
Exhibit Follette-Direct-2
Commercial
Satisfaction Index Score (0-100)
2014 2015 2016 2017 2018 MSI Survey Question
NPC SPPC NPC SPPC NPC SPPC NPC SPPC NPC SPPC
Price and Value 74 78 74 79 72 78 70 73 75 75
• In general, considering the value you receive, would you describe NV Energy’s electric prices as…?
Understanding Rates 74 72 72 76 60 69 62 67 65 66
• Helping customer understand the relationship between their usage and what they are charged • Reasonableness of Electric Rates
Financial Assistance14 78 75 79 80 76 79 N/A N/A N/A N/A
• Offering assistance to customers who are having financial difficulties • Offering flexible bill payment plans to people who get behind paying their energy bills
Energy Efficiency 72 68 70 75 69 75 70 71 70 74
• Providing helpful tips on how to save money and conserve energy
Community Relations 71 69 71 73 67 71 71 71 75 74
• Involved in community activities • Helping local economy by retain and attract business and jobs
Managing Rates 66 68 65 74 56 70 63 67 66 67
• Keeping electric rates as low as possible • Controlling costs while maintaining quality service
14 Financial Assistance was not included in the 2017 & 2018 MSI customer survey.
NV Energy 2018 Service Quality & Metrics Report 44 | P a g e
Page 194 of 250
Exhibit Follette-Direct-2
DRAFT NOTICE
Page 195 of 250
Exhibit Follette-Direct-2
PUBLIC UTILITIES COMMISSION OF NEVADA DRAFT NOTICE
(Applications, Tariff Filings, Complaints and Petitions)
Page 1 of 1
Pursuant to Nevada Administrative Code (“NAC”) 703.162, the Commission requires that a draft notice be included with all applications, tariff filings, complaints and petitions. Please include ONE COPY of this form with your filing. (Completion of this form may require the use of more than one page.)
A title that generally describes the relief requested (see NAC 703.160 (5)(a)):
Informational filing by Nevada Power Company d/b/a NV Energy and Sierra Pacific Power Company d/b/a NV Energy of their Annual Service Quality & Metrics Report
The name of the applicant, complainant, petitioner, or the name of the agent for the applicant, complainant or petitioner (see NAC 703.160 (5)(b)):
Nevada Power Company d/b/a NV Energy and Sierra Pacific Power Company d/b/a NV Energy.
A brief description of the purpose of the filing or proceeding, including, without limitation, a clear and concise introductory statement that summarizes the relief requested or the type of proceeding scheduled AND the effect of the relief or proceeding upon consumers (see NAC 704.160 (5)(c)):
The filing submits the Annual Service Quality & Metrics Report of Nevada Power Company and Sierra Pacific Power Company for calendar year 2018. This is an informational filing of customer service and customer satisfaction metrics that does not request any relief.
A statement indicating whether a consumer session is required to be held pursuant to Nevada Revised Statute (“NRS”) 704.069 (1):1
A consumer session is not required.
If the draft notice pertains to a tariff filing, please include the tariff number AND the section number(s) or schedule number(s) being revised.
Not applicable.
1 NRS 704.069 states in pertinent part: 1. The Commission shall conduct a consumer session to solicit comments from the public in any matter pending before the Commission pursuant to NRS 704.061 to 704.110 inclusive, in which: (a) A public utility has filed a general rate application, an application to recover the increased cost of purchased fuel, purchased power, or natural gas purchased for resale or an application to clear its deferred accounts; and (b) The changes proposed in the application will result in an increase in annual gross operating revenue, as certified by the applicant, in an amount that will exceed $50,000 or 10 percent of the applicant’s annual gross operating revenue, whichever is less.
Page 196 of 250
Exhibit Follette-Direct-2
CERTIFICATE OF SERVICE
Page 197 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Exhibit Follette-Direct-2
CERTIFICATE OF SERVICE
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
I hereby certify that I have served the foregoing Annual Quality of Service Report
Informational Filing for NEVADA POWER COMPANY D/B/A NV ENERGY AND
SIERRA PACIFIC POWER COMPANY D/B/A NV ENERGY in Docket 19-03___ upon
the persons listed below by electronic mail:
Tammy Cordova Staff Counsel Public Utilities Comm. of Nevada 1150 E. William Street Carson City, NV 89701-3109 [email protected]
Michael Saunders Attorney General’s Office Bureau of Consumer Protection 10791 W. Russell Road, Suite 204 Las Vegas, NV 89148 [email protected]
Staff Counsel Division Public Utilities Comm. of Nevada 9075 West Diablo Drive Suite 250 Las Vegas, NV 89148 [email protected]
Attorney General’s Office Bureau of Consumer Protection 100 N. Carson St. Carson City, NV 89701 [email protected]
DATED this 29th day of March, 2019.
/s/ Lynn D’Innocenti Lynn D’Innocenti Sr. Legal Admin Assistant Sierra Pacific Power Company Nevada Power Company
1 Page 198 of 250
Page 199 of 250
JENNIFER OSWALD
Page 200 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
Sierra Pacific Power Company d/b/a NV Energy
2019 General Rate Case Docket No. 19-06___
PREPARED DIRECT TESTIMONY OF
Jennifer Oswald
Revenue Requirement
I. INTRODUCTION
1. Q. PLEASE STATE YOUR NAME, OCCUPATION, AND BUSINESS
ADDRESS.
A. My name is Jennifer Oswald. I am Senior Vice President, Human Resources
and Corporate Services for NV Energy, Inc. and its two operating subsidiaries,
Nevada Power Company d/b/a NV Energy (“Nevada Power”) and Sierra
Pacific Power Company d/b/a NV Energy (“Sierra” or the “Company” and
together with Nevada Power the “Companies”). My primary business address
is 6226 West Sahara Avenue in Las Vegas, Nevada. I am filing testimony on
behalf of Sierra.
2. Q. WHAT ARE YOUR PRIMARY RESPONSIBILITIES AS SENIOR
VICE PRESIDENT, HUMAN RESOURCES AND CORPORATE
SERVICES FOR NEVADA POWER AND SIERRA?
A. I am responsible for human resources and the corporate services functions,
which include procurement, corporate records, support services, property
management, interior services, and facilities maintenance.
Oswald-DIRECT 1
Page 201 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
3. Q. PLEASE DESCRIBE YOUR PROFESSIONAL BACKGROUND AND
EXPERIENCE.
A. I hold a Bachelor’s Degree in Business Administration from the University of
Delaware. I joined Nevada Power and Sierra in 2003, and have since held
various positions within the human resources area, which include management
of compensation and benefits programs as well as maintenance of human
resource systems and records. I assumed responsibility for the corporate
services functions in January 2015, and the procurement function in 2016. My
Statement of Qualifications is set forth in Exhibit Oswald-Direct-1.
4. Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE PUBLIC
UTILITIES COMMISSION OF NEVADA (“COMMISSION”)?
A. Yes, I have testified in a number of proceedings before the Commission. My most
recent general rate case (“GRC”) testimony was in Nevada Power’s 2017 GRC
filing, consolidated Docket Nos. 17-06003 and 17-06004.
5. Q. WHAT IS THE PURPOSE OF YOUR PREPARED DIRECT
TESTIMONY?
A. I address test and certification period costs associated with the Company’s
employee compensation programs (including programs governing executive
compensation), benefits and retirement programs. When referring to the
combination of these programs, costs or expenses in my testimony, I use the
term “human resources” programs, costs or expenses. Sierra has included the
most recent cost information for human resources programs in the calculations
of revenue requirement for this filing. These costs and expenses include
incentive compensation not tied to performance against financial matrices. I
Oswald-DIRECT 2
Page 202 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
also sponsor Schedule H-CERT-16, which documents the removal of the Long
Term Incentive Plan (“LTIP”) expense from cost of service.
I also support the category of investment in plant in service related to my
responsibility over the corporate services function. I describe in detail the one
major project undertaken by the organization since June 1, 2016, the extension
of Ampere Drive to improve large vehicle access and safety to the Ohm
Operations Center.
6. Q. DO OTHER WITNESSES PROVIDE PREPARED TESTIMONY
RELATING TO HUMAN RESOURCES EXPENSE?
A. Yes. Ms. Lisa Holder sponsors testimony addressing the reasonableness of test
and certification period costs associated with compensation programs,
including the 2.55 percent pay increase for non-represented employees
(formerly known as management, professional, administrative, and technical
or “MPAT” employees) effective in December 2018. Ms. Michelle Follette
addresses information requested by the Commission in Sierra’s last general
rate review proceeding regarding cumulative customer service level metrics,
to assist in the evaluation of Short-Term Incentive Plan (“STIP”) benefits. Ms.
Mary Beth Collins and I co-sponsor the payroll proforma, Schedule H-CERT-
17 (Payroll, Benefits, and Pension Expense annualization). H-CERT-17
reflects the annualized benefits, pension and payroll costs including a portion
of STIP. Mr. Michael Behrens supports Schedule K-4 (“Analysis of Account
926 - Employee Pensions and Benefits for the Recorded Test Year Ended
December 31, 2018”).
Oswald-DIRECT 3
Page 203 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
7. Q. ARE YOU SPONSORING ANY EXHIBITS WITH YOUR
TESTIMONY?
A. Yes. I am sponsoring the following exhibits:
• Exhibit Oswald-Direct-1 Statement of Qualifications
• Exhibit Oswald-Direct-2 Summary of Non-Cash Compensation
• Exhibit Oswald-Direct-3 2018 Short Term Incentive Plan Summary
• Exhibit Oswald-Direct-4 2018 Corporate Scorecard Third Quarter
• Exhibit Oswald-Direct-5 2018 Corporate Scorecard Fourth Quarter
II. SUMMARY OF SIERRA’S HUMAN RESOURCES COSTS
8. Q. PLEASE SUMMARIZE SIERRA’S APPROACH IN CALCULATING
REVENUE REQUIREMENT FOR HUMAN RESOURCES EXPENSES
IN A GENERAL RATE CASE.
A. As does Nevada Power, Sierra prepares its revenue requirement calculations
using annualized human resources expense as of the certification date, in this
case May 31, 2019. The annualized Nevada jurisdictional amounts shown in
the revenue requirement calculation are $57.5 million (payroll), $9.9 million
(benefits), and $3.2 million (pension). These figures are as shown in Statement
H-CERT-17.1 A portion of jurisdictionalized STIP expense ($2.1 million) is
included in the revenue requirement calculation.2
1 The $57.5 million annualized payroll expense encompasses the $2.1 million of jurisdictionalized STIP expense. 2 Sierra has not included the portion of STIP expense related to the financial matrices (16.7 percent) in the calculation of revenue requirement.
Oswald-DIRECT 4
Page 204 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
9. Q. GENERALLY, HOW ARE LABOR COSTS CHARGED AND
ALLOCATED?
A. As described in more detail by Ms. Collins, where possible, labor costs are
directly charged. Where appropriate (i.e., where an activity is performed on
behalf of one or more divisions), labor costs are allocated between Nevada
Power, the gas and electric divisions of Sierra, and NV Energy, Inc. Payroll
costs are also designated as capital expenditures or operation and maintenance
(“O&M”) expense. Payroll costs incurred to complete capital projects are
charged to those specific capital projects. Payroll costs not associated with
capital projects are charged to O&M and then are allocated between Nevada
jurisdictional expense and Federal Energy Regulatory Commission (“FERC”)
jurisdictional expense. While the compensation programs I address in my
prepared testimony apply to all payroll costs (capital and O&M, Nevada and
FERC jurisdictional), the payroll costs reflected in the payroll proforma (H-
CERT-17) in this GRC represent the total O&M payroll allocable to Sierra’s
retail jurisdiction.
10. Q. FOR THE PURPOSE OF COMPENSATION DECISIONS, HOW ARE
EMPLOYEES CATEGORIZED?
A. For purposes of compensation, the Company groups its employees into the
following categories.
Represented employees (formerly referred to as Bargaining Unit employees)
are represented by the International Brotherhood of Electric Workers Local
Union 1245 (“Local 1245”) at Sierra and International Brotherhood of
Oswald-DIRECT 5
Page 205 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
Electrical Workers Local Union 396 at Nevada Power. As of December 31,
2018, there were 507 Local 1245 regular employees at Sierra.3
Non-represented employees are not represented by a union. As of December
31, 2018, there were 1,195 non-represented regular employees at NV Energy,
Inc., Nevada Power and Sierra, which include non-exempt entry-level
employees to executive level employees and officers. As of December 31,
2018, NV Energy, Inc., Nevada Power and Sierra employed 21 officers.
11. Q. WHAT IS THE TOTAL O&M ELECTRIC PAYROLL, PENSION AND
BENEFITS EXPENSE IN THIS CASE AND HOW DOES THIS
AMOUNT COMPARE WITH THE AMOUNTS REFLECTED IN
PRIOR DOCKETS?
A. As reflected in Schedule H-CERT-17, the total annualized Nevada
jurisdictional O&M payroll, benefits and pension expense estimate as of May
31, 2019, is $70.6 million (“2019 Total O&M Payroll”).4 This amount is $3.35
million greater than demonstrated in Sierra’s last GRC, Docket No. 16-06006.
As reflected in Schedule H-CERT-16, the portion of total annualized LTIP
expense estimate as of May 31, 2019 that has been removed from the revenue
requirement of retail electric customers is $994,000. Overall, the total costs
for O&M payroll, benefits and pension from H-CERT-17 and H-CERT-16
have increased just $1.673 million or 2.4 percent over total annualized O&M
payroll, benefits and pension expense demonstrated in 2016. The difference is
attributable to the portion of LTIP expense excluded in the calculation as well
as a slight increase in O&M payroll and benefits costs offset by a decrease in
3 A “regular” employee can be a full or part time employee. The term does not include temporary workers or student interns, for example. 4 This total does not include LTIP expense as represented on H-CERT-16.
Oswald-DIRECT 6
Page 206 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
pension costs in H-CERT-17. Annualized payroll costs are estimated through
the certification period, May 31, 2019.
Figure Oswald-Direct-1 compares the 2019 Total O&M Payroll with total
O&M payroll, benefits, and pension costs requested for recovery in Sierra’s
most recent general rate cases.
FIGURE OSWALD-DIRECT-1 SIERRA’S O&M PAYROLL, PENSION, BENEFITS EXPENSE5
H-CERT-17 Payroll Expense
Benefits Pension
Total
2019
$ 57,508 $ 9,920 $ 3,185 $ 70,613
2016
$ 54,620 $ 8,834 $ 3,809 $ 67,263
Variance
$ 2,888 $ 1,086 $ (624) $ 3,350
H-CERT-16 LTIP $ - $ 1,677 $ (1,677)
Total H-CERT-17 & H-CERT-16 $ 70,613 $ 68,940 $ 1,673
12. Q. HOW HAS SIERRA BEEN ABLE TO ACHIEVE THE TOTAL O&M
PAYROLL RESULTS INDICATED ABOVE?
A. The 2019 Total Payroll is a function of several variables: wages, benefits cost,
pension cost and headcount. As demonstrated above, Sierra has successfully
managed these variables to control total payroll, benefits and pension costs.
Although total payroll expense has increased slightly, cost increases have been
mitigated with careful management of salary and benefits expenses. This
shows that the salary increases for non-represented employees (necessitated to
keep pace with the market) and pay increases for represented employees
5 In Figure-Oswald-Direct-1, LTIP expense is not included in any of the annual cost calculations.
Oswald-DIRECT 7
Page 207 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
governed by the collective bargaining agreement with Local 1245, continue to
be offset through efficiency gains. The reasonableness of Sierra’s wage and
salary levels are supported by detailed benchmarking data and reflect
competitive market rates for utility employees as I describe below, and as Ms.
Holder addresses as well.
13. Q. GENERALLY, HOW DO LOCAL, REGIONAL AND NATIONAL
ECONOMIC CONDITIONS IMPACT SIERRA’S HUMAN
RESOURCES COSTS?
A. The Company competes for talent here, locally, as well as regionally and
nationally. Depending on the position, the primary employment market can be
local, regional or national. Managing human resources costs requires
understanding and tailoring compensation and benefits packages to the
relevant employment market. Positions requiring key skills continue to
demand a market rate that is specific to each position, and market rates for
skilled positions have continued to increase, albeit modestly, over the past
three years. Moreover, attracting and retaining top talent remains a high
priority, and Sierra must maintain competitive pay levels, as determined by
the appropriate markets (local, regional and national), in order to do so. In
order to maintain competitive compensation levels for our employees without
increasing costs for our customers, we strive to capture efficiency gains.
While the Company recruits for experienced critical positions primarily from
regional and national markets, the Company is committed to supporting the
local employment market as well. In 2018, the Company hired 10 additional
temporary student interns at Sierra, for a total of 27, converted one existing
Oswald-DIRECT 8
Page 208 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
intern to a full-time employee, and filled an additional 69 positions externally,
with 89 percent (or 62 new hires) from local northern Nevada markets.
14. Q. HAS THE COMPANY APPROPRIATELY MANAGED ITS HUMAN
RESOURCES COSTS?
A. Yes. Test period costs in this case reflect Sierra’s diligence in managing
human resources costs without compromising service quality or reliability.
Initiatives to control test period human resources costs include the following:
• As a result of attrition, the Company conducted reorganizations that
resulted in some position consolidation and headcount reduction. Total
headcount at Sierra, including NV Energy regular employees
(excluding Local 396) decreased from 1,765 in 2016 to 1,701 in 2018,
a reduction of 3.6 percent.
• The Company has lowered STIP costs for non-represented employees
from years prior by paying less than or equal to the payout target of
100 percent.
• Several retirees and terminations have been backfilled with lower-level
positions or less-experienced candidates resulting in a decrease in base
salaries.
• The Company continually reassesses staffing needs and analyzes
competitive compensation data for all new positions.
• A number of cost management measures related to employee benefits
have been taken to better align our expenses with our financial targets
and economic projections. The Company has:
Oswald-DIRECT 9
Page 209 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
o Implemented consumer-driven health plans for Local 1245
employees effective January 1, 2015.
o Effective January 2015, replaced non-represented new hire
employees’ eligibility in the cash balance pension plan with a 4
percent contribution to the 401(k) program.
o Effective January 2017, replaced Local 1245 new hire employees’
eligibility in the cash balance pension plan with a 4 percent
contribution to the 401(k) program.
o Conducted a Request for Proposal (“RFP”) for dental plan
providers, which realized a cost savings from our current dental
care provider.
o Conducted an RFP for vision plan providers, which realized a cost
savings from our current vision care provider.
o Conducted an RFP for life insurance program administrators
resulting in a cost savings.
In short, the Company is continuing to reduce human resources costs while
maintaining the critical skills needed to continue to provide safe and reliable
service to our customers.
15. Q. HOW IS THE REMAINDER OF YOUR TESTIMONY ORGANIZED?
A. Part III provides an overview of Sierra’s overall compensation programs and
policies. In part IV, I support the prudence of the STIP program. In Part V, I
support the prudence of other cash compensation programs. In Part VI, I
support the prudence of Sierra’s non-cash compensation programs. In Part VII,
I address Sierra’s pension program, including the restoration plan.
Oswald-DIRECT 10
Page 210 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
III. OVERVIEW OF COMPENSATION PROGRAMS AND POLICIES
16. Q. PLEASE DESCRIBE SIERRA’S OVERALL COMPENSATION
PHILOSOPHY.
A. Sierra strives to achieve a median position as compared to its competitors for
the total compensation program, which includes cash and non-cash benefits
provided to employees in return for their services. We offer competitive total
compensation that includes a market competitive base wage; competitive
variable pay for performance; a competitive package of employee benefits
(medical/dental/vision, wellness, educational reimbursement, service awards
and retirement programs); competitive programs to protect employees and
their families against catastrophic economic loss in the event of large health
care, disability, or death (life insurance, disability insurance, accidental death
and dismemberment insurance, business travel accident insurance); and post-
employment benefits. This combination of compensation and benefits targeted
at median permits Sierra to attract and retain qualified and motivated
employees, and to provide safe, reliable and reasonably-priced service to our
customers.
Sierra’s compensation plan also takes into account the critical need to retain
top industry-specific talent. While efficiency and cost reduction measures are
always a priority, our compensation plan must continue to keep the future
needs of Sierra’s customers in mind. The Company uses a comprehensive
workforce planning approach across the business units. By combining the
forecast of workload needs with employee demographics, the business units
can effectively manage and mitigate risks to the organization and ensure that
we secure an adequate workforce to meet customer demands, maintain safety
Oswald-DIRECT 11
Page 211 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
and deliver cost-effective, reliable electric and gas service. Maintaining a
competitive compensation program to retain the existing talent pool is a top
priority.
17. Q. HOW ARE TOTAL COMPENSATION LEVELS DETERMINED?
A. The Company’s philosophy is to fairly compensate its workforce for the value
of the work provided. Without a balanced compensation program, recruitment,
retention, motivation and productivity are jeopardized. The goal is to provide
a competitive compensation program at the median level of what an employee
could receive at another company.
To ensure competitive compensation, the Company starts with an evaluation
of the current market value of positions based on the knowledge, skills and
talents required of a fully competent incumbent. Sierra does this by using
regional, national, and industry-specific benchmarking data, in order to
achieve what is termed “external equity” in the industry literature. In addition,
the Company evaluates internal equity – the relative worth of each job
category within Sierra when comparing the required level of job competencies,
training, experience, responsibilities and accountability of one job to another.
The compensation program is also designed to encourage collaboration and
focus on corporate goals, most importantly excellent customer service.
Further, the compensation program is designed to reward employees who
drive results through strong individual performance.
Oswald-DIRECT 12
Page 212 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
18. Q. PLEASE SUMMARIZE THE COMPONENTS OF THE TOTAL
COMPENSATION PROGRAM THAT ARE AVAILABLE TO
SIERRA’S EMPLOYEES.
A. The elements of the total compensation package that are included in this case
are as follows:
Base Pay. All employees receive base pay.
STIP. All non-represented employees are eligible to participate in the
STIP. STIP payments are based on corporate goals target of 100 percent and
vary from year to year depending upon the achievement of Company-wide
goals and a combination of the achievement of business unit or departmental
goals and the individual employee’s performance. As I describe in some detail
below, Company-wide goals are aligned with the following six core principles:
Customer Service, Employee Commitment, Environmental Respect,
Regulatory Integrity, Operational Excellence, and Financial Strength. In 2018,
all eligible employees were assigned an individual performance rating. STIP
payments were only paid to eligible employees with performance ratings of
“performing well” or higher.
LTIP. Most non-represented employees at the director-level and
above are eligible to participate in the LTIP. The LTIP payments are based on
a corporate goals target of 100 percent and vary from year to year depending
upon the achievement of Company-wide goals, which are aligned with the six
core principles.
Safety Bonus. All Local 1245 represented employees are eligible to
participant in the Safety Bonus program. If safety objectives are achieved,
employees can earn up to a 2 percent lump sum bonus.
Oswald-DIRECT 13
Page 213 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
Retirement Plans. All employees hired prior to 2017 are eligible to
participate in Sierra’s pension and 401(k) programs. Sierra has a traditional
defined benefit pension program (for some legacy employees) but moved to a
cash balance pension program beginning in 2008 for non-represented
employees and in 2011 for Local 1245 employees. Effective January 1, 2015,
for non-represented new hires and January 1, 2017, for Local 1245 new hires,
the Company discontinued cash balance pension eligibility and instead offers
a defined contribution to the 401(k) plan. Certain key employees also
participate in supplemental retirement plans due to Internal Revenue Service
(“IRS”) limitations imposed upon tax qualified pension plans. The
supplemental programs include a “restoration plan” and a “supplemental
executive retirement program” or “SERP.” Benefit accruals under the SERP
were frozen as of December 31, 2014. SERP costs are not reflected in the
revenue requirement calculated in this case.
Other Cash Compensation. Signing, retention, other bonuses,
severances and relocation are offered to individual employees based upon
unique circumstances. There were no severance costs for Sierra during the test
year.
Non-Cash Compensation. All employees receive non-cash
compensation, which is comprised of medical, dental, vision, life insurance,
accidental death and dismemberment insurance, business travel accident
insurance, disability insurance, and other benefit programs and recognition
available to employees. Exhibit Oswald-Direct-2 is a summary of the non-
cash compensation programs available to Sierra’s employees.
Oswald-DIRECT 14
Page 214 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
IV. VARIABLE PAY PROGRAMS INCLUDING STIP, SAFETY BONUSES AND
LTIP PLANS
19. Q. WHY DO THE COMPANIES OFFER VARIABLE PAY TO
EMPLOYEES?
A. Variable pay or “pay for performance” programs differ from other forms of
compensation. With variable pay, each eligible employee and the Company as
a whole must re-earn this reward every year. Variable pay programs
incentivize individuals to drive positive results, have economic advantages,
and help with recruitment, retention, motivation, and communication of
important priorities. I discuss these advantages below.
Economics. One of the most significant advantages of variable pay is
the transfer of a portion of an employee’s fixed cost, in the form of a salary, to
a variable cost that is only incurred if the employee and the Company achieve
desired results. When variable costs are aligned with performance, they serve
as a driver of desired results. The conversion of what would otherwise have
been fixed costs into variable costs is significant, because variable pay awards
do not compound like base pay adjustments do. If strong corporate and
individual performance is not sustained, variable pay can be reduced or
eliminated. Escalation rates can be better managed over time and quickly
adapted to changing market pressures.
Recruitment and Retention. Variable pay programs provide the
Companies with the flexibility to offer a fair and attractive individual
compensation packages, which is critical to attract, engage and retain talented
employees. Variable pay targets compensation dollars in the right way,
ensuring top performers that they will have the opportunity to be rewarded for
their performance. With variable pay among the types of compensation
Oswald-DIRECT 15
Page 215 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
offered, the Companies are able to attract high performers who are confident
of their abilities. Retention of talent also is improved with variable pay
programs in that there is a clear communication of what is expected from
eligible employees—they know exactly where to target their efforts and
exactly what achievements will be rewarded. Gallup research has shown that
clear understanding of expectations and recognition for performance are
strongly linked to employee engagement.
Motivation and Business Goals. The motivational potential of
variable pay is stronger than that of other forms of compensation. Variable pay
that is tied to defined objectives and standards allows the organization to pay
for performance at every level by providing a sharp focus on its priorities. The
Companies’ variable pay programs focus non-represented employees on the
six core principles, including customer service, employee commitment, and
operational excellence while also rewarding them for strong individual
performance results that impact Company goals. The Safety Bonus program
focuses our represented employees on essential Company and employee safety
objectives. When employees understand how their contributions impact the
organization’s success, and when they know that this is being measured, they
are more likely to see themselves as partners in reaching defined goals.
Variable pay reinforces successful employees and provides a scorecard to
enable individuals to continuously evaluate and improve results. By including
individual and organization-wide goals within the incentive system, variable
pay motivates employees to collaborate and achieve results.
Communication. Variable pay is one of the strongest signals an
organization can send to its employees about what is important. Programs like
the STIP and LTIP serve to cascade measures and goals from the top of the
Oswald-DIRECT 16
Page 216 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
organization downward, to move individuals into alignment with and
commitment to the Company’s articulated priorities and strategy. Through the
balanced scorecard process, corporate and business unit strategies become
more focused and aligned. Targets are clear and uncompromised. Objectives
are fully understood and implemented. Key priorities can be identified,
optimized, and adequately funded. The variable pay plan provides a roadmap
to employees about what is expected of them. It communicates to employees
that their work is valued and that a high performance culture will be rewarded.
By continually measuring results, high quality feedback can be provided so
that employees know how they are doing and how they can impact results and
rewards.
20. Q. HAVE STUDIES CONFIRMED THAT VARIABLE PAY ACHIEVES
THESE OBJECTIVES?
A. Yes. A wide body of research supports the view that variable pay works when
applied correctly. According to a recent study conducted by Salary.com,
Organizations Embracing Variable Pay (Salary.com January 8, 2019),
organizations with a formal pay-for-performance philosophy are more than
twice as likely to have above average or excellent employee engagement. A
pay-for-performance philosophy contributes to employee engagement by
clearly tying employee or company achievement of performance goals to
tangible financial rewards. These programs also enable employees to see a
clear connection between the work they do every day and the success of the
company as a whole. They can also facilitate more frequent conversations
about individual and company performance.
Oswald-DIRECT 17
Page 217 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
In Designing and Managing Incentive Compensation Programs (Society for
Human Resources Management January 12, 2018) the author notes that when
applied to the corporate setting, incentive compensation programs enable
organizations to produce targeted results by rewarding employees who are
responsible for those results. The article also highlights that while incentive
compensation programs are primarily used to promote efficiency and
productivity of the workforce, organizations can also use them to enhance
employee recruitment, engagement, retention and employer branding.
21. Q. IS IT COMMON FOR EMPLOYERS IN TODAY’S MARKETPLACE
TO PUT A PORTION OF CASH COMPENSATION AT RISK?
A. Yes. Most organizations use variable pay as a significant element of their total
rewards package. According to World at Work’s 2018-2019 Salary Budget
Survey, the use of variable pay remained steady at 85 percent in 2018, with a
combination of awards based on both organization and/or unit success and
individual performance continuing to be the most prevalent types of variable
pay program.
22. Q. ARE ALL OF SIERRA’S FULL TIME EMPLOYEES ELIGIBLE TO
PARTICIPATE IN THE STIP?
A. No. As discussed below, Sierra renegotiated the terms of its incentive program
with represented employees. Only Sierra’s non-represented employees are
eligible to participate in the STIP. Represented employees participate in the
Safety Bonus program, through which they are eligible to earn up to a 2
percent lump sum, which began in 2016.
Oswald-DIRECT 18
Page 218 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
23. Q. PLEASE DESCRIBE THE STIP.
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
A. The Company’s STIP provides the opportunity for non-represented employees
to earn an incentive award based on achievement of Company-wide goals
related to the six core principles as well as individual performance.
Incentive awards are calculated using an eligible target percentage associated
with each job and salary band, ranging from 5 percent for non-exempt
employees to 20 percent for directors and increased percentages for officers.
Figure Oswald-Direct-2 provides the 2018 target STIP rates. For 2018, if
goals were met, the percentage is applied to the employee’s base pay to
determine the incentive compensation. STIP is not paid to an individual
employee unless corporate goals are achieved and the individual employee’s
performance is rated “performing well” or higher. STIP awards are determined
each year and do not increase an employee’s base pay.
FIGURE OSWALD -DIRECT-2 2018 TARGET STIP RATES
Non Exempt 5-10% Exempt Individual Contributor 6-25% Team Leader 12.5-15% Manager 15-25% Director 20% Executives (Level eliminated in 2019)
20-35%
Vice Presidents 20-50%
Senior Vice Presidents 40-75% CEO 100%
Oswald-DIRECT 19
Page 219 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
24. Q. IS SIERRA SEEKING TO INCLUDE ANY PORTION OF LTIP COSTS
Nev
ada
Pow
er C
ompa
ny a
nd S
ierr
a Pa
cific
Pow
er C
ompa
ny
d/b
/a N
V E
nerg
y
IN ITS CALCULATION OF REVENUE REQUIREMENT?
A. No. The Company is not seeking to include any portion of LTIP costs in its
revenue requirement calculation. This approach is consistent with the
Commission’s determination in Nevada Power’s last general rate review
proceeding, Docket No. 17-06003.
25. Q. WHAT WERE THE STIP GOALS DURING THE TEST PERIOD IN
THIS CASE?
A. The 2018 STIP Summary is provided as Exhibit Oswald-Direct-3. The STIP
goals for 2018 are reflected on the 2018 corporate scorecard, which is provided
as Exhibit Oswald-Direct-4.
26. Q. DO THE COMPANIES RE-EVALUATE VARIABLE PAY GOALS
EVERY YEAR?
A. Yes. Even the best-designed plan must be continually evaluated and refreshed
for appropriateness. The Company’s STIP program requires continual
attention to ensure that corporate, departmental and individual goals remain
aligned. Our compensation organization is not bashful in proposing
improvements, responding to changing economic conditions, and focusing on
more effective organizational strategies. As I discussed above, the corporate
scorecard is focused on the six core principles: Customer Service, Employee
Commitment, Environmental Respect, Regulatory Integrity, Operational
Excellence and Financial Strength. The goals associated with each core
principle are cascaded down from the CEO to vice-president level scorecards
for each business unit which are then cascaded down to director or manager
Oswald-DIRECT 20
Page 220 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
level scorecards at the department level. Leaders engage in quarterly
discussions with their non-represented employees at the individual contributor
level to ensure that individual employees see and are in alignment with overall
priorities, strategy, and how their individual performance will impact results.
As noted above, variable pay awards for individual contributors are earned
based on both business unit and/or department scorecard results, which align
with corporate goals and individual performance contributions.
27. Q. YOU EMPHASIZE THAT CORPORATE GOALS ALIGN WITH THE
COMPANIES’ CORE STRATEGIC OBJECTIVE – PROVIDING
IMPROVED CUSTOMER EXPERIENCE WHILE SAFELY AND
RELIABLY DELIVERING AFFORDABLE ENERGY PRODUCED IN
AN ENVIRONMENTALLY FRIENDLY AND SUSTAINABLE
MANNER. DOES ALIGNMENT OF INDIVIDUAL PERFORMANCE
WITH THESE OBJECTIVES DRIVE PERFORMANCE THAT
BENEFITS CUSTOMERS?
A. Yes, the Companies’ corporate goals – and therefore its variable pay programs
– are designed to reward performance, both individually and Company-wide,
that benefit customers. All corporate goals support the six core principles and
are measured through key performance indicators that are designed to drive
performance that benefits customers.
• The customer service goals focus on delivering reliability, dependability,
fair prices and exceptional service to our customers and are measured
through J.D. Power residential/business survey results, Market Strategies
International survey results, and Mastio key account survey results. In
addition, a customer satisfaction improvement plan has been developed to
Oswald-DIRECT 21
Page 221 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
maintain employee focused on continuous improvement of customer
focus/service.
• The employee commitment goals are measured through OSHA recordable
incidents, preventable vehicle accidents and employee training and
development. The primary focus of safety metrics is to ensure the health
and welfare of our employees. In addition, by reducing employee injuries
and preventable vehicle accidents, costs decrease for our customers in the
form of equipment repair, insurance premiums, medical claim costs and
non-productive time away from work. The employee training and
development metric ensures employees have the training and tools they
need to progress in their careers with the Company, deliver results and
improve business performance.
• The environmental respect goal focuses on reductions in CO2 emissions,
which keeps employees focused on greater efficiency, fewer
environmental impacts and lower operating costs, all actions that benefit
customers.
• The regulatory integrity goals benefit our customers by ensuring
transparency and accountability regarding all regulatory matters including,
but not limited to, rate-setting and policy making.
• The operational excellence is measured by the system average interruption
duration for electric outages and generation fleet availability for gas and
coal plants. Both of these measures improve service and control costs for
our customers. Additional performance indicators have been added to
increase focus on physical and cyber security to ensure we protect our
customers and customer data and operating assets effectively. In addition,
Oswald-DIRECT 22
Page 222 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
a grid resiliency plan has been developed to ensure we can effectively
deliver services to our customers.
28. Q. DID THE COMPANY ACHIEVE THE CORPORATE GOALS SET
DURING 2018?
A. The Company achieved 82.8 percent of the corporate scorecard goals. The
corporate scorecard results are provided as Exhibit Oswald-Direct-4.
29. Q. DESCRIBE THE FORECASTED PERFORMANCE RESULTS
REFLECTED ON THE 2018 CORPORATE SCORECARD.
A. The key performance indicators reflected on the corporate scorecard are
defined across the six core principles. Performance results for each core
principle are described below.
• Customer Service received a weight of 16.7 percent. The goals included
seven key performance indicators measuring customer satisfaction
through various residential and commercial customer surveys. Results for
the J.D. Power business, Market Strategies International commercial
south, Market Strategies International residential south, and Mastio key
accounts met or exceeded the targets established for 2018. J.D. Power
residential, Market Strategies International commercial north, and Market
Strategies International residential north did not meet the 2018 target
performance level. The customer satisfaction improvement plan was on
track for successful implementation. This performance resulted in a score
of 12.7 percent for customer service.
• Employee Commitment received a weight of 16.7 percent. The safety
goals included key metrics to improve the OSHA incident rate and number
Oswald-DIRECT 23
Page 223 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
of preventable vehicle accidents. An additional target was set to enhance
employee training and development plans. The Company met or exceeded
performance related to each goal other than the improved OSHA incident
rate resulting in a score of 9.5 percent.
• Environmental Respect received a weight of 16.6 percent with a single
key performance indicator focused on CO2 emissions. The Company met
or exceeded its environmental respect goal at 16.6 percent. Again, more
efficient, environmentally friendly operations reduce operating costs.
• Regulatory Integrity received a weight of 16.7 percent. The goals
included achievement of allowed return on equity and delivery of balanced
outcomes in regulatory and legislative environments. The Company met
or exceeded its regulatory integrity goals and scored 16.7 percent.
Similarly, each of these key regulatory goals improves efficiency and
benefits customers.
• Operational Excellence received a weight of 16.6 percent. The goals
included system average interruption duration for electric outages and
generation fleet availability for gas and coal plants which are intended to
improve service and control costs for our customers. Key performance
indicators were also measured related to gas incidents, cybersecurity and
grid resilience plans. The Company successfully met its operational
excellence goals, with the exception of the System Average Interruption
Duration Index (SAIDI) and reportable gas incidents. This performance
resulted in a score of 10.6 percent for operational excellence.
• Financial Performance received a weight of 16.7 percent. The costs
associated with this metric are not included in the revenue requirement
calculated in this case.
Oswald-DIRECT 24
Page 224 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
30. Q. PLEASE IDENTIFY THE O&M PORTION OF THE STIP COSTS
THAT ARE INCLUDED IN THE CALCULATION OF REVENUE
REQUIREMENT IN THIS CASE.
A. The revenue requirement calculations in this filing reflects 66.1 percent of
STIP costs paid in December 2018.
Sierra’s calculated annual revenue requirement includes the jurisdictional
component of $2.1 million for STIP expense. This request is a calculated
figure reflecting a portion of the STIP amount paid in December 2018.
31. Q. HOW IS THE STIP FUNDING LEVEL CALCULATED?
A. The STIP is funded at an aggregate payout of 100 percent of target assuming
achievement of incentive plan goals. The 100 percent target payout is then
modified based on forecasted corporate scorecard results. STIP was funded at
82.8 percent for 2018.
32. Q. WHEN ARE PERFORMANCE RESULTS EVALUATED TO
DETERMINE FUNDING FOR THE STIP?
A. The evaluation of corporate scorecard results for determination of incentive
plan funding is completed using results as of September 30, 2018. The funding
level recommendation is based on year-end forecasted results. The forecasted
results and initial funding recommendations in early October allow time for
the preparation, review and analysis of STIP awards for eligible employees.
Monthly performance updates continue to be prepared and reviewed to ensure
that there are no significant deviations from the funding recommendation prior
to final approval on any STIP payments in early December.
Oswald-DIRECT 25
Page 225 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
33. Q. HOW DO THE YEAR-END PERFORMANCE RESULTS COMPARE
TO THE SEPTEMBER FORECAST?
A. The fourth quarter and final scorecard for 2018 is provided as Exhibit
Oswald-Direct-5. With two exceptions, fourth quarter performance equaled
forecasted performance from the September scorecard. Results from J.D.
Power were lower than forecasted, and preventable vehicle accidents were
higher.
Although the J.D. Power business goal fell short of the 2018 target, the
Companies achieved a ranking in 57.6 percentile, a significant improvement
from 2017 performance. In 2017, the Company ranked 69th out of 86 total
companies resulting in a percentile ranking of 80.2 percent. In 2018, the
Company ranked 49th out of 85 total companies resulting in a percentile
ranking of 57.6 percent.
Based on the favorable performance year-over-year related to the J.D. Power
business survey score and the sustained high-level performance year-over-
year related to preventable vehicle incidents there was no modification made
to the incentive plan funding level based on a review of the final 2018
corporate scorecard results.
34. Q. PLEASE COMPARE THE 2018 STIP PAYOUT WITH THE
AMOUNTS PAID IN PRIOR YEARS.
A. Figure Oswald-Direct-3 shows the STIP amounts paid in 2012-2018.
Oswald-DIRECT 26
Page 226 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Figure Oswald-Direct-3STIP Payout Summary 2012-2018 (Total Company)
($Millions)
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
STIP/Safety Bonus Represented Non-represented
Total STIP/Safety
Bonus Payout Plan Year
Payout Year Employees
Total Payout $ Employees
Total Payout $
2012 2013 611 1.8 1,221 17.9 19.7
2013 2013 584 1.1 1,216 15.1 16.2
2014 2014 1,296 1.8 1,145 14.8 16.6
2015 2015 1,271 1.8 1,217 15.1 16.9
2016 2016 1,251 1.8 1,222 13.8 15.6
2017 2017 1,241 2.5 1,215 13.2 15.7
2018 2018 1,256 2.5 1,207 13.8 16.3
- Total Payout $ includes both STIP and Safety Bonuses. - Employees who have transferred to/from represented positions may receive prorated STIP
payments. - Data includes any prorated STIP payouts made to retirees. - In 2013 – there were two payouts 1) Spring 2013 payout for 2012 STIP program. Fourth
quarter 2013, acquisition of Company resulted in 2013 STIP payout occurring in December at 90% of target.
35. Q. IS THE LEVEL OF STIP COSTS INCLUDED IN THE REVENUE
REQUIREMENT CALCULATIONS IN THIS CASE REASONABLE,
AND DOES IT REPRESENT A RECURRING EXPENSE?
A. Yes. The payout under the STIP program is based on the Company’s
performance on the objective corporate scorecard metrics and, if goals are
achieved, would be funded and paid only up to the target of 100 percent.
Consistent with prior Commission orders, the Company is not requesting STIP
Oswald-DIRECT 27
Page 227 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
payout related to the financial strength metrics. STIP and Safety Bonuses are
variable pay based on Company, business unit and/or department, and
individual performance, and are paid as a percentage of base salaries. Thus,
there will be variances in costs year over year. Nevertheless, total target
compensation levels are representative and competitive, as measured by the
benchmarking data reflected within Ms. Holder’s testimony.
V. OTHER CASH COMPENSATION PROGRAMS
36. Q. PLEASE DESCRIBE SIERRA’S OTHER CASH COMPENSATION
PROGRAMS.
A. Sierra pays signing, retention and other bonuses, and severances and
relocation expenses to its employees, based upon particular circumstances.
Severance expense is not included in the payroll proforma, Schedule H-CERT-
17. Relocation costs and retention payments for non-executives are included
in the revenue requirement calculation for this case.
37. Q. WHAT IS THE RECORDED COST LEVEL THAT SIERRA IS
REQUESTING IN THIS CASE FOR THIS CATEGORY OF
EXPENSE?
A. Sierra is requesting the test year expense level of $44,000 which includes
$34,000 of relocation costs and $10,000 of retention payments for non-
executives.
Oswald-DIRECT 28
Page 228 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
VI. NON-CASH COMPENSATION PROGRAMS
38. Q. PLEASE DESCRIBE THE NON-CASH COMPONENT OF THE
COMPENSATION PROGRAM.
A. Exhibit Oswald-Direct-2 lists the Company’s non-cash compensation
programs.
39. Q. WHAT ARE THE TOTAL NON-CASH COMPENSATION COSTS
FOR THE TEST PERIOD?
A. Test period costs associated with the major programs are summarized in
Figure Oswald-Direct-4, below.
FIGURE OSWALD-DIRECT-4 O&M NON-CASH COMPENSATION COSTS (OTHER THAN PENSION AND OPEB6)SIERRA’S RECORDED COSTS FOR THE PERIOD JANUARY 1 – DECEMBER 31, 2018
Long/Short Term Disability $458,493 Educational Reimbursement $59,710 Life and Accident Insurance $234,471 Medical / Dental / Vision* $11,743,352 401(k) $7,796,433 Executive Benefits $16,979 Service Awards $101,730 Wellness $114,051
*Medical / Dental / Vision insurance expense is annualized on Schedule H-CERT-17, page 5.
40. Q. ARE THE NON-CASH COMPENSATION COSTS REASONABLE?
A. Yes. Sierra has taken cost savings initiatives and carefully managed its benefit
program costs since the Company’s last general rate case (Docket No. 16-
06006) resulting in a decrease in non-cash compensation of $1,955,978. Major
drivers of this decrease are cost reductions associated with leveraging BHE
6 Defined in Part VII below.
Oswald-DIRECT 29
Page 229 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
mass to achieve lower costs per plan, as well as the redesign of the medical
programs from traditional to consumer-driven plans.
VII. PENSION PROGRAM AND OTHER POST EMPLOYMENT BENEFITS
(“OPEB”)
41. Q. PLEASE GENERALLY DESCRIBE THE PENSION AND OPEB
PROGRAMS THAT ARE AVAILABLE TO NV ENERGY
EMPLOYEES.
A. Most employees serve under a defined benefit pension plan. Certain long-
tenured employees are covered under a traditional benefit formula based on
years of service and the employee’s highest compensation for a period prior to
retirement. The majority of employees are covered under a cash balance
formula. Beginning in January 2015 for non-represented employees, and
beginning in January 2017 for Local 1245 employees, new hires are no longer
offered a defined benefit pension plan. For those new hires no longer offered
the defined benefit pension plan, they instead receive a defined Company
contribution of 4 percent in the Companies’ 401(k) plan.
The Company continues to offer a 401(k) plan to all employees. Some key
employees also participate in Restoration Plans due to IRS limitations imposed
upon tax qualified pension plans. As noted above, some officers also
participate in a SERP, although benefit accruals under the SERP were frozen
as of December 2015. SERP is not included in the revenue requirement
calculation in this case. Generally, all employees hired before April 1, 2008
who meet certain age and service criteria are eligible for retiree medical and
life insurance benefits.
Oswald-DIRECT 30
Page 230 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
42. Q. WHAT COSTS DOES SIERRA PROPOSE TO INCLUDE IN ANNUAL
REVENUE REQUIREMENTS FOR PENSION AND OPEB EXPENSE?
A. Annualized jurisdictional pension and OPEB expense as of May 31, 2019, is
estimated at $3.0 million, as shown on Schedule H-CERT-17, page 5 of 5. The
actual amounts will be certified.
43. Q. HOW DO THESE PENSION AND OPEB COSTS COMPARE WITH
PRIOR YEARS?
A. As shown in Figure Oswald-Direct-1, this category of expense has decreased
by $0.7 million since Docket 16-06006.
44. Q. WHAT IS THE RESTORATION PLAN?
A. The Pension Restoration plan was adopted July 7, 1989, and was amended and
restated effective January 1, 2009. The Deferred Compensation Plan (formerly
the 401(k) Restoration Plan) was adopted on January 1, 1996, and was
amended and restated effective June 30, 2009. Generally, the purpose of the
restoration plans is to restore retirement benefits that cannot be paid under the
qualified pension plans and 401(k) plans due to IRS limitations. The Pension
Restoration Plan was closed to new entrants in December 2015.
45. Q. WHAT ARE THE RESTORATION PLAN COSTS THAT THE
COMPANY IS REQUESTING FOR RECOVERY IN THIS CASE?
A. The annualized jurisdictionalized Restoration Plan costs that the Company is
requesting for recovery in this case are $219,000.
Oswald-DIRECT 31
Page 231 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
46. Q. IS THE LEVEL OF RESTORATION PLAN EXPENSE INCLUDED IN
THE REVENUE REQUIREMENT CALCULATION REASONABLE,
AND DOES IT REPRESENT A RECURRING EXPENSE?
A. Yes, the costs of the Restoration Plan are reasonable, and are a recurring
expense that the Company will continue to incur in order to maintain
competitive pay packages for its employees.
47. Q. HAS THE COMMISSION PREVIOUSLY ALLOWED RECOVERY OF
RESTORATION PLAN COSTS IN RATES?
A. Yes. Restoration Plan costs were allowed recovery in rates in Sierra’s last
general rate case, Docket No. 16-06006.
VIII. AMPERE DRIVE EXTENSION
48. Q. IN ADDITION TO YOUR RESPONSIBILITIES OVER THE HUMAN
RESOURCES AREA, ARE YOU ALSO RESPONSIBLE FOR THE
COSTS INCURRED BY THE CORPORATE SERVICES FUNCTION?
A. Yes, I am. My responsibility over the corporate services function includes
oversight over procurement, corporate records, support services, property
management, interior services, and facilities maintenance.
49. Q. DID THE CORPORATE SERVICES FUNCTION COMPLETE ANY
MAJOR CAPITAL PROJECTS SINCE JUNE 2016?
A. Yes, one project, involving the extension of Ampere Drive at the Ohm
Operations Center is considered a “major” capital project. I address this
project in some detail below.
Oswald-DIRECT 32
Page 232 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
50. Q. WHY DO YOU ONLY ADDRESS “MAJOR” CAPITAL PROJECTS IN
YOUR PREPARED TESTIMONY?
A. Testimony-style descriptions of each and every project completed by the
corporate service organization since June 1, 2016, would take hundreds of
pages, and the documentation surrounding each project is so voluminous that
its value at hearing would be severely diminished. As I understand it, in
general rate proceedings the Commission wants to see prepared direct
testimony addressing the details of and supporting expenditures on major
projects. In recent general rate cases the Commission has accepted the $1
million demarcation as appropriate for determining whether a project is
“major.” While not addressed in detail in my prepared direct testimony, my
group has prepared project “binders” for smaller projects completed since June
1, 2016. As has been the Companies’ practice for many rate case cycles, those
binders (now in electronic form) are available for review on the day this
general rate review filing is made.
51. Q. PLEASE DESCRIBE THE AMPERE DRIVE EXTENSION PROJECT.
A. Ampere Drive runs east-west on the southern edge of the Ohm Operations Center.
The Ohm Operations Center first went into service in the mid-1960s and houses
electric lines and substation construction and maintenance, the gas operations
group, design services, system protection, standards, and meter operations.
Anticipating that expansion of the Ohm Operations Center would eventually be
necessary, Sierra acquired 18.84 acres of land to the west of the existing Ohm
Operations Center in 2013. Sierra had been leasing five acres of this property for
many years, using it as an outdoor materials storage area. The purchase provided
Oswald-DIRECT 33
Page 233 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
Sierra with long-term control of the property and flexibility to expand the Ohm
Operations Center in the future.
Prior to the completion of the Ampere Drive Extension Project, the portion of
Ampere Drive traversing the 18.84 acres acquired in 2013 was unimproved. Thus
all traffic seeking to access the commercial enterprises on Ampere Drive had to
enter and exit the area to the north on either Ohm Place or Edison Way. The
previous owner recognized the need to eventually finish Ampere Drive and
provide access to the area from Rock Boulevard to the west. A parcel map for
this property, recorded by the former owner in 2005, required that right of way
improvements to Ampere Drive must be completed prior to the issuance of a
building permit for any construction on any of the parcels making up the 18.84
acres.
In 2017, in preparation for the eventual redevelopment and expansion of the Ohm
Operations Center, Sierra undertook the design and construction of the Ampere
Drive extension. The design and construction of all Ampere Drive improvements,
to the City of Reno’s design standards, including all underground utilities, curb,
gutter, street lighting, landscaping, roadway and internal charges, cost $1,557,583
and required approximately one year to complete. The Ampere Drive extension
is used and useful in service providing utility service to customers. The extension
of Ampere Drive enhances both public and Company safety by allowing
Company vehicles improved access to the southern part of the Ohm campus and
reducing our reliance on the Mill Street access point, a very heavily trafficked
Oswald-DIRECT 34
Page 234 of 250
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Nev
ada
Pow
er C
ompa
ny
and
Sier
ra P
acifi
c Po
wer
Com
pany
d/
b/a
NV
Ene
rgy
roadway. The majority of the heavy vehicle parking and materials storage at Ohm
is on the south end of the campus and nearest to the Ampere Drive extension.
CONCLUSION
52. Q. DOES THIS CONCLUDE YOUR PREPARED DIRECT TESTIMONY?
A. Yes.
Oswald-DIRECT 35
Page 235 of 250
Exhibit Oswald-Direct-1 Page 1 of 2
Jennifer L. Oswald, CEBS, CCP Vice President, Human Resources and Corporate Services
I have been employed by Nevada Power and Sierra for over ten years and have more than fifteen years of human resources experience. Currently, I report to the President and CEO and oversee human resources and corporate services. I am responsible for planning, designing, and executing human resources services and programs that are aligned with functional business strategies. I also am responsible for corporate service functions which includes corporate records, support services, property management, interior services, facilities maintenance and corporate security.
Employment History
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy
Vice President, Human Resources and Corporate Services (2015-2016)
Responsible for planning, designing, and executing HR services and programs that are aligned with functional business strategies. Responsible for corporate service functions which includes corporate records, support services, property management, interior services, facilities maintenance and corporate security.
Vice President, Human Resources (2013-2015)
Responsible for planning, designing, and executing HR services and programs that are aligned with functional business strategies.
Director, Compensation, Benefits & HR Records Management (2013)
Responsible for the design, planning and implementation of corporate-wide compensation and benefit programs including health and welfare and retirement plans. Responsible for HR records management and compliance with corporate records retention policies. Implemented executive compensation programs and defined procedures; Prepared various reports and other materials for board meetings; Served as HR lead for CD&A and other executive compensation disclosure.
Manager, Compensation & HR Records Management (2011–2013)
Responsible for the planning and implementation of corporate-wide compensation and incentive programs. Responsible for HR records management and compliance with corporate records and retention policies. Supported administration of executive compensation programs; Served as subject matter expert for CD&A and other executive compensation disclosure.
Compensation Staff Analyst (2010–2011)
Responsible for day-to-day administration of compensation programs. Served as internal subject matter expert on executive compensation and benefit programs; Approved pay rates and organizational design changes as a result of promotion requests and new hires; reviewed pay actions for internal/external equity and compliance with company policy and budget; conducted comprehensive salary analyses to validate internal jobs with market data, which
Page 236 of 250
Exhibit Oswald-Direct-1 Page 2 of 2
included base compensation, overtime, and variable pay; Participated in cross-functional team for annual proxy disclosure and 10-K preparation.
Compensation Senior Analyst (2007–2010)
Responsible for day-to-day administration of compensation programs for non-represented employees. Approved pay rates and organizational design changes as a result of promotion requests and new hires; reviewed pay actions for internal/external equity and compliance with company policy and budget; conducted comprehensive salary analyses to validate internal jobs with market data, which included base compensation, overtime, and variable pay; Participated in cross-functional team for annual proxy disclosure and 10-K preparation.
Benefits Senior Analyst (2003–2007)
Responsible for day-to-day administration of defined benefit retirement plan and defined contribution 401(k) plan. Managed vendor relationships; Served as project manager for defined benefit plan conversion and implementation of retirement plan administration system; Managed personalized total rewards statement design, production and distribution for 3,000 employees; Provided input and review of communications materials including annual open enrollment guides, posters, meeting formats and vendor visits; Conducted enrollment meetings for employee groups; Coordinated complete review and approval of summary plan descriptions and enrollment material for new hires; Trained entry level benefit analysts to ensure compliance with ERISA, plan documents and company policy.
Pension Benefit Guarantee Corporation (PBGC) 1996–2003
Supervisor/Senior Administrator/Junior Administrator
Managed daily operations of eight entry level, junior and senior administrators in servicing 22 pension plans. Coordinated resources to complete quarterly processing objectives and reporting to regional and corporate management; Served as training liaison between corporate headquarters and regional office in design and facilitation of various programs; Served as training and technical expert for staff of 50 administrators, supervisors and managers.
Education & Professional Development B.S. in Business Administration, University of Delaware Certified Employee Benefits Specialist, International Foundation/Wharton School of the University of Pennsylvania Compensation Management Specialist, International Foundation/Wharton School of the University of Pennsylvania Certified Compensation Professional, World at Work Certified Benefits Professional, World at Work Senior Professional in Human Resources, HR Certification Institute Member, World at Work Member, Southern Nevada Compensation & Benefits Association Member, Society for Human Resources Management
Page 237 of 250
EXHIBIT OSWALD-DIRECT- 2
Page 238 of 250
NV En
ergy ‐Non
Cash Co
mpe
nsation
Docket
No.
NPC
17‐xxxxx
Prog
ram
Sum
mary
Exhibit O
swald‐Direct‐2
Officer/Executive
Non
‐rep
resented
Local 396
Local 124
5 Med
ical/D
ental/Vision
Same as
non
‐rep
resented
Co
verage
effe
ctive on
Date of
Hire
. Plan
options
includ
e He
alth
Re
imbu
rsem
ent A
ccou
nt (H
RA) P
lan
and He
alth
Savings
Accou
nt (H
SA)
Plan.
Coverage
effe
ctive the first
of the
mon
th
following Da
te of H
ire. Plan
options
includ
e He
alth
Reimbu
rsem
ent A
ccou
nt
(HRA
) Plan with
Health
y Living, H
RA
with
out H
ealth
y Living
and
Health
Savings
Accoun
t (HS
A) Plan with
Health
y Living.
Coverage
effe
ctive the first
of the
mon
th fo
llowing Da
te of H
ire. Plan
op
tions
includ
e He
alth
Reimbu
rsem
ent
Accoun
t (HR
A) Plan and He
alth
Savings
Accoun
t (HS
A) Plan.
Basic Life
Insurance
Company ‐paid
Same as
non
‐rep
resented
; grandfathe
red em
ployees
receive Up to
3.0
times
ann
ual
base
pay
(maxim
um
$1,750
,000
; (minim
um $50
,000
)
1.5 tim
es ann
ual base pay up
to a
maxim
um of $
1,50
0,00
0 (m
inim
um
bene
fit of $
50,000
). New
hire
s as o
f Janu
ary 20
15, 1.0
times
ann
ual base
pay.
1.4 tim
es ann
ual base pay up
to a
maxim
um of $
1,00
0,00
0 (m
inim
um
bene
fit of $
46,000
)
$50,00
0
Basic Ac
cide
ntal
Death
& Dismem
berm
ent (AD
&D)
Company ‐paid
Same as
non
‐rep
resented
1.5 tim
es ann
ual base pay up
to a
maxim
um of $
1,50
0,00
0 (m
inim
um
bene
fit of $
50,000
). New
hire
s as o
f Janu
ary 20
15, not
covered
.
1.4 tim
es ann
ual base pay up
to a
maxim
um of $
1,00
0,00
0 (m
inim
um
bene
fit of $
46,000
)
No Co
verage
Busine
ss Travel A
cciden
t Insuran
ce
Company ‐paid
Same as
non
‐rep
resented
; be
nefit
is $1 million for O
fficers. De
ath be
nefit
of $
500,00
0 in
the
even
t of a
cciden
tal death
while
traveling ou
tside regularly
assigne
d work locatio
n on
com
pany
business.
Death be
nefit
of $
500,00
0 in
the even
t of
accide
ntal
death
while
traveling ou
tside
regularly
assigne
d work locatio
n on
company
business.
Death be
nefit
of $
500,00
0 in
the even
t of
acciden
tal death
while
traveling
outside regularly
assigne
d work locatio
n on
com
pany
business.
Supp
lemen
tal Life
Insurance (Optiona
l) Em
ployee
‐paid with
after‐tax
dollars; G
ives
the
employee
the op
portun
ity to
receive additio
nal
insurance protectio
n.
Same as
non
‐rep
resented
. Co
verage
available in
increm
ents
of
0.5 up
to 5
times
ann
ual base pay to
a maxim
um of $
1,25
0,00
0; Coverage
for spo
use and children also
available.
Coverage
available in
increm
ents
of 0
.5
up to
5 times
ann
ual base pay to
a
maxim
um of $
1,00
0,00
0; Coverage for
spou
se and
children also
available.
Coverage
available in
increm
ents
of 0
.5
up to
5 times
ann
ual base pay to
a
maxim
um of $
1,25
0,00
0; Coverage for
spou
se and
children also
available.
Supp
lemen
tal A
D&D
(Optiona
l) Em
ployee
‐paid with
pre‐tax
dollars
Same as
non
‐rep
resented
. Em
ployee
can
cho
ose a de
ath be
nefit
of
$25
,000
to $50
0,00
0 in
the even
t of
acciden
tal death; fam
ily coverage
is available.
Not
available.
Not
available.
Page 239 of 250
Revised 04
/201
7 Page
1 of 4
NV En
ergy ‐Non
Cash Co
mpe
nsation
Docket
No.
NPC
17‐xxxxx
Prog
ram
Sum
mary
Exhibit O
swald‐Direct‐2
Officer/Executive
Non
‐rep
resented
Local 396
Local 124
5 Sh
ort‐Term
Disab
ility
(STD
) De
signe
d to
replace an
employee's pay in
the even
t that
serio
us injury
or p
rolonged
illness p
revents the
m from
working.
Same as
non
‐rep
resented
. Th
e am
ount
of b
enefits
the em
ployee
receives
is equ
al to
100
% of p
ay fo
r up
to 8
weeks
and
80%
for u
p to
the
next
18 weeks.
The am
ount
of b
enefit the em
ployee
receives
is 55%
‐75%
of b
ase pay based on
the em
ployee's weeks
of service
at the
tim
e of
disa
bility.
The am
ount
of b
enefits
the em
ployee
receives
is equ
al to
100
% of p
ay fo
r up
to 4
weeks
and
80%
for u
p to
the ne
xt
22 weeks.
Long
‐Term
Disab
ility
(LTD
) Co
mpany ‐paid
for n
on‐rep
resented
and
Local
124
5;
Employee
paid by
Local
396
. Em
ployees a
re eligible
for 6
0%
of base pay plus
bon
us to
a
maxim
um of $
14,000
/mon
th
less
other
disa
bility paym
ents
they
are
eligible
to re
ceive.
Employees a
re eligible
for 6
0% of
base
pay
to a
maxim
um of
$10,00
0/mon
th less
other
disa
bility
paym
ents
they
are
eligible
to re
ceive.
Employees a
re eligible
for 6
0% of b
ase
pay to
a m
axim
um of $
10,000
/mon
th less
othe
r disa
bility paym
ents
they
are
eligible
to
receive.
Employees a
re eligible
for 6
0% of b
ase
pay to
a m
axim
um of $
10,000
/mon
th
less
other
disa
bility paym
ents
they
are
eligible
to re
ceive.
Health
Care Flexible
Spe
nding Ac
coun
t (FSA)
Allows e
mployees to set a
side tax‐free
dollars
to pay
for
eligible
health
care expe
nses
not
covered
by their h
ealth
care
plan.
Same as
non
‐rep
resented
. Up to
$2,55
0 contrib
ution annu
ally.
Up to
$2,55
0 contrib
ution annu
ally.
Up to
$2,55
0 contrib
ution annu
ally.
Dep
ende
nt Care Flexible
Spe
nding Ac
coun
t (FSA)
Allows e
mployees to set a
side tax‐free
dollars
to pay
for
eligible
dep
ende
nt care expe
nses
for q
ualified
depe
nden
ts to
enable the em
ployee
and
spou
se to
work
(e.g. child
or e
lder
care).
Same as
non
‐rep
resented
. Up to
$5,00
0 contrib
ution annu
ally.
Up to
$5,00
0 contrib
ution annu
ally.
Up to
$5,00
0 contrib
ution annu
ally.
Retirem
ent P
lan
Tax‐qu
alified
, non
‐con
tributory de
fined
ben
efit pe
nsion
plan
that
covers e
ligible
employees u
nder
all grou
ps.
Same as
non
‐rep
resented
. De
pend
ing on
the date
of
participation in
the plan, ben
efits
are
either
calculated un
der a
tradition
al
plan
form
ula using years o
f service
and fin
al average
earnings o
r a cash
balance form
ula using an
earnings
cred
it pe
rcen
tage
plus interest
accrual. Effective Janu
ary 20
15, new
hires n
o longer
eligible
for retire
men
t plan.
Depe
nding on
the date
of p
articipation in
the plan, ben
efits
are
eith
er calculated
unde
r a tradition
al plan form
ula using
years o
f service
and
final average
earnings
or a cash
balance
form
ula using
an earnings c
redit p
ercentage plus
interest
accrual. Effe
ctive Janu
ary 20
16,
new
hire
s no longer
eligible
for
retirem
ent p
lan.
Depe
nding on
the date
of p
articipation
in th
e plan, ben
efits
are
eith
er
calculated
und
er a
tradition
al plan
form
ula using years o
f service
and
final
average earnings
or a cash
balance
form
ula using an
earnings c
redit
percen
tage
plus interest a
ccrual.
Effective Janu
ary 20
17, new
hire
s no
longer
eligible
for retire
men
t plan.
Retirem
ent R
estoratio
n Plan
Not
App
licable.
Not
App
licable.
Provides
a ben
efit substantially
equ
al to
the diffe
rence
betw
een the am
ount
that
wou
ld have be
en payable
un
der the
Retire
men
t Plan,
in th
e absence of
laws
limiting
pen
sion be
nefits a
nd earnings that m
ust b
e considered
in calculatin
g pe
nsion be
nefits,
and
the
amou
nt actually
payable
und
er th
e Re
tirem
ent P
lan.
Employees w
hose
com
pensation exceed
s the
IRS annu
al com
pensation
limit,
as w
ell as tho
se th
at participate in
the 401(k)
Restoratio
n Plan
are eligible. Effe
ctive De
cembe
r 31,
201
5, plan closed
to new
entrants.
Accruals on
going for current
participants.
Page 240 of 250
Revised 04
/201
7 Page
2 of 4
NV En
ergy ‐Non
Cash Co
mpe
nsation
Docket
No.
NPC
17‐xxxxx
Prog
ram
Sum
mary
Exhibit O
swald‐Direct‐2
Officer/Executive
Non
‐rep
resented
Local 396
Local 124
5 Su
pplemen
tal Executiv
e Re
tirem
ent P
lan (SER
P)
Limite
d to
key
employees.
4/1/08
frozen
to new
entrants.
12
/31/20
15, frozen accruals.
Not
App
licable.
Not
App
licable.
Not
App
licable.
401(k)
/ (V
olun
tary
Investmen
t) Plan
A tax‐de
ferred
long
‐term
savings p
rogram
which
offe
rs
an investmen
t program
with
a su
bstantial tax
advantage. Sa
me as
non
‐rep
resented
Em
ployer
match
of 1
00%
on the first
6%
of e
mployee
con
tributions. N
ew
hires a
s of 1
/1/15 receive an
additio
nal 4%
employer
con
tribution
replacing cash
balance
participation.
Employer
match
of 1
00%
on the first
6%
of
employee
con
tributions. N
ew hire
s as
of 1/1/16 receive an
add
ition
al 4%
em
ployer
con
tribution replacing cash
balance participation.
Employer
match
of 1
00%
on the first
6%
of
employee
con
tributions. (50
% m
atch
on
the first
6%
for tho
se with
the utility
discou
nt). New
hire
s as o
f 1/1/17
receive an
add
ition
al 4%
employer
contrib
ution replacing cash
balance
participation.
401(k)
Restoratio
n Plan
A de
ferred
com
pensation plan
supp
lemen
ting be
nefits
payable un
der the
401(k) P
lan.
Directors a
nd abo
ve in
a sa
lary
grade
19 or
highe
r are
eligible.
Not
App
licable.
Not
App
licable.
Employ
ee Assistance Prog
ram
(EAP
) Same for a
ll grou
ps.
The Co
mpany
provide
s an EA
P service to
help em
ployees a
nd th
eir fam
ily m
embe
rs handle difficult situatio
ns. EA
P coun
selors
are
experienced
in dealing
with
personal issue
s such as
finances, fam
ily re
latio
nships, stress,
substance abuse,
and
care of
family
mem
bers
Adop
tion Assistan
ce
To su
pport a
decision
to ado
pt a
child
und
er th
e age of
12
. Same as
non
‐rep
resented
. Co
mpany
will
provide
up to
$2,00
0 pe
r ado
pted
child
to m
itigate
expe
nses.
Not
Available.
Not
Available.
Worker's
Com
pensation
Company
is a
self‐insured em
ployer.
Same for a
ll grou
ps.
Program
provide
s employees w
ho have job‐related injury
or illness w
ith m
edical
care,
disa
bility be
nefits,
and
rehabilitation services.
LEAR
NING
& DEV
ELOPM
ENT
Opp
ortunitie
s to grow
and
develop
through a combinatio
n of
com
pany
‐spo
nsored
training, develop
men
t program
s and
edu
catio
nal reimbu
rsem
ent.
Tuition
Reimbu
rsem
ent
Same as
non
‐rep
resented
. Em
ployees receive
100
% of tuitio
n,
lab fees
& boo
ks. An
nual
limit for full‐
time em
ployees is $
5,25
0; part‐tim
e em
ployees is $
2,62
5.
Employees receive
100
% of tuitio
n.
Books a
nd lab fees
at a
com
bine
d maxim
um of $
50 per
cou
rse.
Ann
ual lim
it for full‐tim
e em
ployees is $
2,00
0. ($
4,00
0 for d
esigne
rs)
Employees receive
100
% of tuitio
n.
Books a
re covered
at 5
0% and
lab fees
at
100
%. A
nnual lim
it for full‐tim
e em
ployees is $
2,50
0; part‐tim
e em
ployees is $
1,25
0.
Page 241 of 250
Revised 04
/201
7 Page
3 of 4
NV En
ergy ‐Non
Cash Co
mpe
nsation
Docket
No.
NPC
17‐xxxxx
Prog
ram
Sum
mary
Exhibit O
swald‐Direct‐2
Officer/Executive
Non
‐rep
resented
Local 396
Local 124
5 WORK
ENVIRO
NMEN
T A work en
vironm
ent that sup
ports h
igh pe
rformance, bust a
lso re
cognize
s diverse
personal needs
through the following programs:
Pa
id Tim
e Off
(PTO
)*
For v
acation,
sick
leave,
fune
ral leave, fam
ily illness o
r pe
rson
al app
ointmen
ts.
Same as
non
‐rep
resented
. Effective Janu
ary 20
16, employees
accrue
per
pay
period with
an initial
rate
of 1
8 days
(ann
ually), plus
0.58
days
for e
ach year
of service.
Employees a
ccrue annu
ally
includ
es a
flat
am
ount
equ
al to
22 days
, increasin
g based on
a years
of service
sche
dule.
Employees a
ccrue annu
ally
includ
es a
fla
t amou
nt equ
al to
21 days
, increasin
g based on
a years
of service
sche
dule.
Holidays
Same as
non
‐rep
resented
. 10
Holidays p
er year
11 Holidays p
er year
10 Holidays p
er year
*Other
leave prog
rams m
ay be available un
der the
provisio
ns of the
CBA
(e.g. Fam
ily Sick Leave,
Fun
eral
Leave, etc.).
Page 242 of 250
Revised 04
/201
7 Page
4 of 4
EXHIBIT OSWALD-DIRECT- 3
Page 243 of 250
Exhibit-Oswald-Direct-3
2018 Plan Summary
NV Energy Short-Term Incentive
Partnership Plan
January 1, 2018
Philosophy
NV Energy provides the competitive compensation and benefit plans needed to attract and
retain talented and skilled employees. Short-term incentive pay is an integral component of
these compensation and benefit plans.
Eligibility
You are eligible to participate in the Short-Term Incentive Partnership plan if you are a
non-represented, full-time or part-time employee and were hired prior to September 1,
2018. You are not eligible if, at the time of payout, you are a temporary employee or an
employee represented by a bargaining unit.
Individual Performance Goals
NV Energy has established corporate goals for 2018. The performance goals are tied
directly to our core principles of Customer Service, Employee Commitment and Safety,
Environmental Respect, Regulatory Integrity, Operational Excellence and Financial Strength.
As an individual employee, you will have goals that support not only your functional
organization’s goals and performance plans, but through a “line of sight”, also support the
NV Energy corporate goals for this year. Your individual goals will be approved by your
supervisor and documented in the ePerformance software application. These individual
performance goals will be the basis for your 2018 performance appraisal. It is recommended
that you review your performance relative to these goals on a periodic basis with your
supervisor.
The Short-Term Incentive Partnership Plan Award
The budget for short-term incentive awards will be established based on performance related
to the 2018 corporate goals. Your individual award amount will be determined by your
supervisor based on your individual performance. If your performance is rated “Performing
Well” or higher, you are eligible for an award. Eligibility does not determine the amount of the
award; all individual awards and amounts are allocated at the discretion of your supervisor and
management/leadership team.
Short-term incentive awards and payments will likely not be made if the corporate goals are
not achieved or if you have not met your individual goals and performance objectives.
For employees who started during the plan year, a prorated amount may be paid based on
the number of months worked and the completion of individual goals and performance
objectives.
Page 244 of 250
Exhibit-Oswald-Direct-32018 Plan Summary
NV Energy Short-Term Incentive Partnership Plan
January 1, 2018
Page 2
If you retire or become disabled during a plan year in which a payout is made and you
meet the conditions of retirement (as defined by the company), you may receive an award
at the discretion of management, reflective of achievement of goals, company and
individual performance, and other factors.
If you leave NV Energy prior to the end of the plan year for any reason other than
retirement or disability, no award will be paid.
Term, Amendment and Termination of the Plan
This plan is discretionary and can be terminated or modified by NV Energy with or
without cause or notice.
This plan, and any award hereunder, is not a contract of employment and nothing in this
document is intended to guarantee a fixed term of employment, a specific level of
income, an award or any other terms or conditions of employment.
2
Page 245 of 250
EXHIBIT OSWALD-DIRECT- 4
Page 246 of 250
NV
Ener
gy –
Cau
dill/
Can
non
Third
Qua
rter
201
8 Sc
orec
ard
Wei
ght
Key P
erfo
rman
ce In
dica
tor
2018
Tar
get
2018
YTD
Act
ual
2018
For
ecas
t Sc
ore
by C
ore
Prin
cipl
e Pe
rcen
tile
Perc
entil
e Pe
rcen
tile
Stat
us
1
2.0%
J.
D. P
ower
resi
dent
ial
35.0
35
.6
35.6
N
ot A
chie
ved
2.
0%
J.D
. Pow
erbu
sine
ss
45.0
30
.7
-O
n tra
ck
1.
0%
Mar
ket S
trate
gies
Inte
rnat
iona
l com
mer
cial
- no
rth
20.0
44
.6
-N
ot o
n tra
ck
1.0%
M
arke
t Stra
tegi
es In
tern
atio
nal c
omm
erci
al -
sout
h 33
.0
27.5
-
On
track
1.0%
M
arke
t Stra
tegi
es In
tern
atio
nal r
esid
entia
l - n
orth
1.
0 8.
1 -
Not
on
track
1.0%
M
arke
t Stra
tegi
es In
tern
atio
nal r
esid
entia
l - s
outh
19
.0
17.2
-
On
track
2.0%
M
astio
key
acc
ount
2.
0 2.
0 2.
0 Ac
hiev
ed
6.
7%
Exec
ute
cust
omer
sat
isfa
ctio
n im
prov
emen
tpla
n Su
cces
sful
impl
emen
tatio
n Ex
ecut
ion
unde
rway
Ac
hiev
e O
n tra
ck
12
.70%
2 5.
0%
OSH
A in
cide
nt ra
te -
outs
ide
elec
tric
deliv
ery
0.30
0.
54
0.41
N
ot o
n tra
ck
2.2%
O
SHA
inci
dent
rate
-el
ectri
c de
liver
y onl
y 1.
48
1.96
1.
71
Not
on
track
7.2%
Pr
even
tabl
e ve
hicl
e ac
cide
nts
15
11
≤15
On
track
2.3%
En
hanc
e fra
mew
orks
and
pla
ns fo
r em
ploy
ee e
ngag
emen
t, tra
inin
g an
d de
velo
pmen
t D
emon
stra
te e
nhan
cem
ent
100%
C
ompl
eted
Ac
hiev
ed
9.
50%
3 16
.6%
C
O2 e
mis
sion
s (lb
s/M
Wh)
87
0 86
8 87
0 O
n tra
ck
16
.60%
4 8.
4%
Achi
eve
allo
wed
retu
rn o
n eq
uity
9.
6%
-10
.4%
**
On
track
8.3%
D
elive
r bal
ance
d ou
tcom
es in
regu
lato
ry a
nd le
gisl
ative
env
ironm
ents
* Ba
lanc
ed o
utco
mes
Ta
x rat
ere
duct
ion
impl
emen
ted;
Ac
hiev
e O
n tra
ck
al
tern
ative
rate
mak
ing
decl
arat
oryo
rder
is
sued
; int
egra
ted
reso
urce
pla
n fil
ed
16.7
0%
5
3.0%
SA
IDI (
min
utes
) 62
.0
54.6
72
.0
Not
on
track
3.0%
G
ener
atio
n eq
uiva
lent
ava
ilabi
lity f
acto
r – g
as
92.5
%
95.0
%
92.5
%
On
track
3.0%
G
ener
atio
n eq
uiva
lent
ava
ilabi
lity f
acto
r – c
oal
92.9
%
94.8
%
92.9
%
On
track
3.0%
Ze
ro re
porta
ble
gas
inci
dent
s 0
1 1
Not
Ach
ieve
d
1.6%
N
o ph
ysic
al o
r cyb
erse
curit
y eve
nts
that
impa
ct o
pera
tions
0
0 0
On
track
1.5%
Ad
vanc
e cy
bers
ecur
itypo
st c
ertif
icat
ion
and
phys
ical
sec
urity
of a
sset
s Ac
hiev
e pl
ans
post
cer
tific
atio
n IS
O 2
7001
rece
rtific
atio
n au
dita
chie
ved
Achi
eve
Achi
eved
1.5%
D
elive
rgrid
resi
lienc
e im
plem
enta
tion
plan
mile
ston
es
Dec
embe
r 31,
201
8 Al
l req
uire
d su
bmitt
als
com
plet
ed;
Dec
embe
r 31,
2018
O
n tra
ck
ad
ditio
nal s
pare
pro
cure
men
t und
erw
ay
10.6
0%
6 10
.0%
N
et in
com
e (N
VE H
oldi
ngs)
$3
35.8
m
$311
.1m
$3
43.5
m
On
track
3.3%
O
pera
tions
and
mai
nten
ance
exp
ense
(201
8 ex
clud
es e
nerg
y effi
cien
cyco
sts)
$4
84.8
m
$360
.6m
$4
84.6
m
On
track
1.7%
C
apita
l exp
endi
ture
low
er th
an d
epre
ciat
ion
expe
nse
excl
udin
g gr
owth
<1
.0x
0.61
x 0.
81x
On
track
1.7%
Ac
hiev
e fa
ll 20
17 p
lan
targ
ets
for o
pera
tions
and
mai
nten
ance
exp
ense
in fa
ll 20
18 p
lan
$484
.1m
(201
9)
Rou
nd 1
$42
8.6m
$4
28.6
m (2
019)
O
n tra
ck
16
.70%
*D
eliver
on commitm
ents
made through NV En
ergy
2.0
and
the Strategic R
eposition
ing plan
**Po
st earnings sharing at
Nevada Po
wer
Com
pany
Year‐to
‐date S
corecard
Total
82.8
0%
1
Page 247 of 250
EXHIBIT OSWALD-DIRECT- 5
Page 248 of 250
1
NV
Ener
gy –
Cau
dill/
Can
non
Dec
embe
r 201
8 Sc
orec
ard
Wei
ght
Key
Per
form
ance
Indi
cato
r 20
18 T
arge
t 2
018
Actu
al
Sta
tus
Sco
re b
y C
ore
Pri
ncip
le
Per
cent
ile
Per
cent
ile
2.0%
J.
D. P
ower
resi
dent
ial
35.0
35
.6
Not
Ach
ieve
d
2.0%
J.
D. P
ower
bus
ines
s 45
.0
57.6
N
ot A
chie
ved
1.
0%
Mar
ket S
trate
gies
Inte
rnat
iona
l com
mer
cial
- no
rth
20.0
44
.6
Not
Ach
ieve
d
1.0%
M
arke
t Stra
tegi
es In
tern
atio
nal c
omm
erci
al -
sout
h 33
.0
27.5
Ac
hiev
ed
1.
0%
Mar
ket S
trate
gies
Inte
rnat
iona
l res
iden
tial -
nor
th
1.0
8.1
Not
Ach
ieve
d
1.0%
M
arke
t Stra
tegi
es In
tern
atio
nal r
esid
entia
l - s
outh
19
.0
17.2
Ac
hiev
ed
2.
0%
Mas
tio k
ey a
ccou
nt
2.0
2.0
Achi
eved
6.7%
E
xecu
te c
usto
mer
satis
fact
ion
impr
ovem
ent p
lan
Suc
cess
ful i
mpl
emen
tatio
n S
ucce
ssfu
lly im
plem
ente
d Ac
hiev
ed
10
.7%
2 5.
0%
OS
HA
inci
dent
rate
-ou
tsid
e el
ectri
c de
liver
y 0.
30
0.47
N
otAc
hiev
ed
2.2%
O
SH
A in
cide
nt ra
te -
elec
tric
deliv
ery
only
1.
48
1.71
N
ot A
chie
ved
7.
2%
Pre
vent
able
veh
icle
acc
iden
ts
15
19
Not
Ach
ieve
d
2.3%
E
nhan
ce fr
amew
orks
and
pla
ns fo
r em
ploy
ee e
ngag
emen
t, tra
inin
g an
d de
velo
pmen
t D
emon
stra
te e
nhan
cem
ent
100%
Ac
hiev
ed
2.
3%
3 16
.6%
C
O2 e
mis
sion
s (lb
s/M
Wh)
87
0 86
2 Ac
hiev
ed
16
.6%
4 8.
4%
Achi
eve
allo
wed
retu
rn o
n eq
uity
9.
6%
10.4
%
Achi
eved
8.3%
D
eliv
er b
alan
ced
outc
omes
in re
gula
tory
and
legi
slat
ive
envi
ronm
ents
* B
alan
ced
outc
omes
Ta
x ra
te ri
deri
mpl
emen
ted;
decl
arat
ory
Achi
eved
orde
r iss
ued;
inte
grat
ed re
sour
ce p
lan
appr
oved
16
.7%
5
3.0%
S
AID
I (m
inut
es)
62.0
71
.2
Not
Ach
ieve
d
3.0%
G
ener
atio
n eq
uiva
lent
ava
ilabi
lity
fact
or –
gas
92
.5%
94
.4%
Ac
hiev
ed
3.
0%
Gen
erat
ion
equi
vale
nt a
vaila
bilit
y fa
ctor
– c
oal
92.9
%
95.4
%
Achi
eved
3.0%
Ze
ro re
porta
ble
gas
inci
dent
s 0
1 N
ot A
chie
ved
1.
6%
No
phys
ical
or c
yber
secu
rity
even
ts th
at im
pact
ope
ratio
ns
0 0
Achi
eved
1.5%
Ad
vanc
e cy
bers
ecur
ity p
ost c
ertif
icat
ion
and
phys
ical
sec
urity
of a
sset
s Ac
hiev
e pl
ans
post
cer
tific
atio
n IS
O27
001
rece
rtific
atio
n au
dita
chie
ved
Achi
eved
1.5%
D
eliv
er g
rid re
silie
nce
impl
emen
tatio
n pl
an m
ilest
ones
D
ecem
ber 3
1, 2
018
Com
plet
ed
Achi
eved
10.6
%
6
10.0
%
Net
inco
me
(NVE
Hol
ding
s)
$335
.8m
$3
17.5
m
Not
Ach
ieve
d
3.3%
O
pera
tions
and
mai
nten
ance
exp
ense
(201
8 ex
clud
es e
nerg
y ef
ficie
ncy
cost
s)
$484
.8m
$4
83.8
m
Achi
eved
1.7%
C
apita
l exp
endi
ture
low
er th
an d
epre
ciat
ion
expe
nse
excl
udin
g gr
owth
<1
.0x
0.75
x Ac
hiev
ed
1.
7%
Achi
eve
fall
2017
pla
n ta
rget
s fo
r ope
ratio
ns a
nd m
aint
enan
ce e
xpen
se in
fall
2018
pla
n $4
84.1
m (2
019)
$4
64.0
m
Achi
eved
6.7%
*D
eliver
on commitm
ents
made through NV En
ergy
2.0
and
the strategic repo
sitioning
plan
Year
-end
Tot
al
63.6
%
1
Page 249 of 250
Page 250 of 250